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| {{#Wiki_filter:N Nebraska Public Power District Always there when you need us 50.90 NLS2011071 September 16, 2011 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001 | | {{#Wiki_filter:}} |
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| ==Subject:==
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| Nebraska Public Power District - Cooper Nuclear Station Docket No. 50-298, License No. DPR-46 License Amendment Request for Implementing a 24-Month Fuel Cycle and Adoption of TSTF-493, Revision 4, Option A
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| ==References:==
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| : 1. Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991.
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| : 2. Letter from the Technical Specifications Task Force to U.S. Nuclear Regulatory Commission, dated July 31, 2009, "Transmittal of TSTF-493, Rev.
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| 4, 'Clarify Application of Setpoint Methodology for LSSS Functions."'
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| ==Dear Sir or Madam:==
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| The purpose of this letter is for the Nebraska Public Power District (NPPD) to request from the Nuclear Regulatory Commission (NRC) an amendment to Facility Operating License DPR-46 under the provisions of 10 CFR 50.4 and 10 CFR 50.90 to revise the Cooper Nuclear Station (CNS) Technical Specifications (TS) to support operation with 24-month fuel cycles, in accordance with the guidance of Generic Letter 91-04 (Reference 1). Additionally, NPPD is including with this License Amendment Request an amendment to incorporate the NRC-approved TSTF-493, Revision 4, to be consistent with Option A (Reference 2). The availability of this TS improvement was announced in the FederalRegister on May 11, 2010 (75 FR 26294).
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| The 24-month fuel cycle proposed changes largely consist of revising certain TS Surveillance Requirement frequencies from 18 months to 24 months. However, changes are also proposed for the TS Allowable Values of two instrument functions to support the longer surveillance interval.
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| The TSTF-493, Revision 4, Option A proposed amendment would revisethe TS by adding requirements to assess channel performance during testing that verifies instrument channel setting values established by the plant-specific setpoint methodology. NPPD has determined from the No Significant Hazards Consideration determination that these changes do not involve a significant hazard.
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| NPPD requests approval of the proposed amendment by September 16, 2012, to facilitate implementation during the Fall 2012 refueling outage, allowing for an approximate one year review by the NRC. Once approved, the amendment will be implemented within 60 days.
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| COOPER NUCLEAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax:. (402) 825-5211 www.nppd.com
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| NLS2011071 Page 2 of 3 provides a description of the TS changes, the basis for the amendment, the No Significant Hazards Consideration evaluation pursuant to 10 CFR 50.91 (a)(1), and the Environmental Impact evaluation pursuant to 10 CFR 51.22. Attachment 2 provides the proposed changes to the current CNS TS in marked up format. For ease of review, they are grouped in two sections, those TS changes associated with a 24-month fuel cycle, and the TS changes accommodating TSTF-493, Revision 4, Option A. Attachment 3 provides the final typed TS pages to be issued with the amendment. Attachment 4 provides conforming changes to the TS Bases for information. Attachments 5 and 6, and Enclosure 1, are included in accordance with Reference 1. Attachment 5 provides the evaluation of the 24-month review findings. provides a list of affected channels for 24-month fuel cycle changes by TS section, including instrument make, model, and range. Enclosure 1 provides a summary of the methodology and assumptions used to determine the rate of instrument drift with time, based upon historical plant calibration data.
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| The proposed TS changes have been reviewed by the necessary safety review committees (Station Operations Review Committee and Safety Review and Audit Board). Amendments to the CNS Facility Operating License through Amendment 238 issued July 27, 2011, have been incorporated into this request. This request is submitted under affirmation pursuant to 10 CFR 50.30(b).
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| By copy of this letter and its attachments, the appropriate State of Nebraska official is notified in accordance with 10 CFR 50.91(b)(1). Copies are also being provided to the NRC Region IV office and the CNS Senior Resident Inspector in accordance with 10 CFR 50.4(b)(1).
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| Should you have any questions concerning this matter, please contact Mike Boyce, CNS Strategic Initiatives Project Manager, at (402) 825-5100.
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| I declare under penalty of perjury that the foregoing is true and correct.
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| Executed on:
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| Sincerely, Brian J. O'Grady $
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| Vice President - Nuclear and Chief Nuclear Officer
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| /WV Attachments Enclosure
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| NLS2011071 Page 3 of 3 cc: Regional Administrator w/Attachments and Enclosure USNRC - Region IV Cooper Project Manager w/Attachments and Enclosure USNRC - NRR Project Directorate IV-1 Senior Resident Inspector w/Attachments and Enclosure USNRC - CNS Nebraska Health and Human Services w/Attachments and Enclosure Department of Regulation and Licensure NPG Distribution w/o Attachments or Enclosure CNS Records w/Attachments and Enclosure
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| ATTACHMENT 3 LIST OF REGULATORY COMMITMENTSC 4 4
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| ATTACHMENT 3 LIST OF REGULATORY COMMITMENTSN Correspondence Number: NLS2011071 The following table identifies those actions committed to by Nebraska Public Power District (NPPD) in this document. Any other actions discussed in the submittal represent intended or planned actions by NPPD. They are described for information only and are not regulatory commitments. Please notify the Licensing Manager at Cooper Nuclear Station of any questions regarding this document or any associated regulatory commitments.
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| COMMITMENT COMMITTED DATE COMMITMENT NUMBER OR OUTAGE None
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| _ __ _ _ _ _ ~I __ I __
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| 4 4 4 4 I PROCEDURE 0.42 REVISION 27 . PAGE 19 OF 26 1
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| NLS2011071 Page 1 of 35 Attachment 1 License Amendment Request for Implementing a 24-Month Fuel Cycle and Adoption of TSTF-493, Revision 4, Option A Cooper Nuclear Station; Docket No. 50-298, DPR-46 1.0 Summary Description 2.0 Detailed Description 2.1 Proposed Changes 2.2 Need for Changes 2.3 Technical Specification Bases Changes 3.0 Technical Evaluation 3.1 Generic Letter 91-04 Changes 3.2 TSTF-493, Revision 4, Option A Changes 3.3 Other 24-Month Fuel Cycle Considerations 4.0 Regulatory Safety Analysis 4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 No Significant Hazards Consideration 4.4 Conclusion 5.0 Environmental Consideration 6.0 References
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| NLS2011071 Page 2 of 35 1.0
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| ==SUMMARY==
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| DESCRIPTION This letter is a request to the Nuclear Regulatory Commission (NRC) to amend Facility Operating License DPR-46 for Cooper Nuclear Station (CNS). The requested change affects certain Technical Specification (TS) Surveillance Requirement (SR) frequencies that are specified as "18 months" by revising them to "24 months" in accordance with the guidance of Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991 (Reference 6.1).
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| As a result of these SR changes, the Nebraska Public Power District (NPPD) is proposing two changes to TS Allowable Values. Also consistent with this guidance, certain other Administrative Controls TS changes are made:
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| - TS 5.5.2, "Systems Integrity Monitoring Program," testing frequencies are changed from 18 months to 24 months for integrated leak test requirements and the applicability of SRs 3.0.2 and 3.0.3.
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| - TS 5.5.7, "Ventilation Filter Testing Program (VFTP)," testing frequencies are changed from 18 months to 24 months.
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| - TS 5.5.13, "Control Room Envelope Habitability Program," pressure measurements are changed from 18 months to 24 months.
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| Additionally, the proposed amendment would revise the Technical Specifications by applying additional testing requirements to applicable instrument Functions, listed in Technical Specifications Task Force (TSTF) Improved Standard Technical Specifications (STS) Change Traveler TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS [limiting safety system settings] Functions," Attachment A, "Identification of Functions to be Annotated with the TSTF-493 Footnotes" (Reference 6.2). Attachment A contains Functions related to those variables that have a significant safety function, as defined in Title 10 of the Code of FederalRegulations (10 CFR) Section 50.36(c)(1)(ii)(A), thereby ensuring instrumentation will function as required to initiate protective systems or actuate mitigating systems at values equal to or more conservative than the point assumed in applicable safety analyses. These TS changes are made by the addition of individual surveillance Note requirements to applicable instrument Functions in accordance with Option A of TSTF-493, Revision 4. This change is consistent with Option A of NRC-approved Revision 4 to TSTF-493. The availability of this TS improvement was announced in the FederalRegister on May 11, 2010 (75 FR 26294).
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| As demonstrated in this submittal, the proposed changes do not adversely impact safety.
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| With respect to the 24-month fuel cycle changes, the proposed changes are similar to the license amendment issued for River Bend Station on August 31, 2010. NPPD is requesting approval of this change by September 16, 2012, allowing an approximate one year review by the NRC. Approval by this date will support scheduling and planning the subsequent refueling outage based on 24-month surveillance frequency requirements for SRs that must be performed during plant shutdown conditions. Once approved, NPPD will implement the amendment within 60 days.
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| NLS2011071 Page 3 of 35 2.0 DETAILED DESCRIPTION 2.1 Proposed Changes 2.1.1 Changes For 24-Month Fuel Cycle To accommodate a 24-month fuel cycle for CNS, certain surveillance frequencies that are specified as "18 months" are being revised to "24 months." The proposed changes were evaluated in accordance with the guidance provided in NRC GL 91-04.
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| The following SR frequencies are being revised to 24 months:
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| TS 3.1.7 SLC System SR 3.1.7.8 Verify flow through one SLC subsystem from pump into reactor pressure vessel.
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| SR 3.1.7.9 Verify all heat traced piping between storage tank and pump suction is unblocked.
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| TS 3.1.8 SDV Vent and Drain Valves SR 3.1.8.3 Verify each SDV vent and drain valve:
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| : a. Closes in < 30 seconds after receipt of an actual or simulated scram signal; and
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| : b. Opens when the actual or simulated scram signal is reset.
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| TS 3.3.1.1 RPS Instrumentation SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST.
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| SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.
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| SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| SR 3.3.1.1.14 Verify Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is > 29.5% RTP.
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| SR 3.3.1.1.15 Verify the RPS RESPONSE TIME is within limits.
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| TS 3.3.1.2 SRM Instrumentation SR 3.3.1.2.7 Perform CHANNEL CALIBRATION.
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| TS 3.3.2.1 Control Rod Block Instrumentation SR 3.3.2.1.6 Verify the RWM is not bypassed when THERMAL POWER is <
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| 9.85% RTP.
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| SR 3.3.2.1.7 Perform CHANNEL FUNCTIONAL TEST.
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| NLS2011071 Page 4 of 35 TS 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation SR 3.3.2.2.2 Perform CHANNEL CALIBRATION. The Allowable Value shall be -<54.0 inches.
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| SR 3.3.2.2.3 Perform LOGIC SYSTEM FUNCITONAL TEST including valve actuation.
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| TS 3.3.3.1 PAM Instrumentation SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of each required PAM Instrumentation channel except for the Primary Containment H 2 and 02 Analyzers.
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| TS 3.3.3.2 Alternate Shutdown System SR 3.3.3.2.2 Verify each required control circuit and transfer switch is capable of performing the intended function.
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| SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each required instrumentation channel.
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| TS 3.3.4.1 ATWS-RPT Instrumentation SR 3.3.4.1.2 Perform CHANNEL CALIBRATION. The Allowable Values shall be:
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| : a. Reactor Vessel Water Level - Low Low (Level 2): > -42 inches; and
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| : b. Reactor Pressure - High: < 1072 psig.
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| SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST including breaker actuation.
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| TS 3.3.5.1 ECCS Instrumentation SR 3.3.5.1.4 Perform CHANNEL CALIBRATION.
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| SR 3.3.5.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.5.2 RCIC System Instrumentation SR 3.3.5.2.4 Perform CHANNEL CALIBRATION.
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| SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.6.1 Primary Containment Isolation Instrumentation SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.
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| SR 3.3.6.1.5 Calibrate each radiation detector.
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| SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.6.2 Secondary Containment Isolation Instrumentation SR 3.3.6.2.3 Perform CHANNEL CALIBRATION.
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| SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| NLS2011071 Page 5 of 35 TS 3.3.6.3 LLS Instrumentation SR 3.3.6.3.4 Perform CHANNEL CALIBRATION.
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| SR 3.3.6.3.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.7.1 CREF System Instrumentation SR 3.3.7.1.3 Perform CHANNEL CALIBRATION.
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| SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.8.1 LOP Instrumentation SR 3.3.8.1.2 Perform CHANNEL CALIBRATION.
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| SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.8.2 RPS Electric Power Monitoring SR 3.3.8.2.1 Perform CHANNEL CALIBRATION. The Allowable Values shall be:
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| : a. Overvoltage < 131 V with time delay set to < 3.8 seconds.
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| : b. Undervoltage > 109 V, with time delay set to < 3.8 seconds.
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| : c. Underfrequency > 57.2 Hz, with time delay set to < 3.8 seconds.
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| SR 3.3.8.2.2 Perform a system functional test.
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| TS 3.4.3 SRVs and SVs SR 3.4.3.2 Verify each SRV opens when manually actuated.
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| TS 3.5.1 ECCS - Operating SR 3.5.1.8 Verify, with reactor pressure < 165 psig, the HPCI pump can develop a flow rate > 4250 gpm against a system head corresponding to reactor pressure.
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| SR 3.5.1.9 Verify each ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.
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| SR 3.5.1.10 Verify the ADS actuates on an actual or simulated automatic initiation signal.
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| SR 3.5.1.11 Verify each ADS valve opens when manually actuated.
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| TS 3.5.2 ECCS - Shutdown SR 3.5.2.5 Verify each required ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.
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| TS 3.5.3 RCIC System SR 3.5.3.4 Verify, with reactor pressure < 165 psig, the RCIC pump can develop a flow rate > 400 gpm against a system head corresponding to reactor pressure.
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| SR 3.5.3.5 Verify the RCIC System actuates on an actual or simulated automatic initiation signal.
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| NLS2011071 Page 6 of 35 TS 3.6.1.1 Primary Containment SR 3.6.1.1.2 Verify drywell to suppression chamber bypass leakage is equivalent to a hole < 1.0 inch in diameter.
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| TS 3.6.1.3 PCIV S SR 3.6.1.3.7 Verify each automatic PCIV actuates to the isolation position on an actual or simulated isolation signal.
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| SR 3.6.1.3.8 Verify a representative sample of reactor instrumentation line EFCVs actuate to the isolation position on an actual or simulated instrument line break.
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| SR 3.6.1.3.9 Remove and test the explosive squib from each shear isolation valve of the TIP System.
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| SR 3.6.1.3.11 Verify each inboard 24 inch primary containment purge and vent valve is blocked to restrict the maximum valve opening angle to 600.
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| TS 3.6.1.6 LLS Valves SR 3.6.1.6.1 Verify each LLS valve opens when manually actuated.
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| SR 3.6.1.6.2 Verify the LLS System actuates on an actual or simulated automatic initiation signal.
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| TS 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers SR 3.6.1.7.3 Verify the full open setpoint of each vacuum breaker is <0.5 psid.
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| TS 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers SR 3.6.1.8.3 Verify the opening setpoint of each required vacuum breaker is < 0.5 psid.
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| TS 3.6.4.1 Secondary Containment SR 3.6.4.1.4 Verify each SGT subsystem can maintain > 0.25 inch of vacuum water gauge in the secondary containment for 1 hour at a flow rate <
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| 1780 cfm.
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| TS 3.6.4.2 SCIVs SR 3.6.4.2.3 Verify each automatic SCIV actuates to the isolation position on an actual or simulated actuation signal.
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| TS 3.6.4.3 SGT System SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual or simulated initiation signal.
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| SR 3.6.4.3.4 Verify the SGT units cross tie damper is in the correct position, and each SGT room air supply check valve and SGT dilution air shutoff valve can be opened.
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| NLS2011071 Page 7 of 35 TS 3.7.2 SW System and UHS SR 3.7.2.4 Verify each SW subsystem actuates on an actual or simulated initiation signal.
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| TS 3.7.3 REC System SR 3.7.3.4 Verify each REC subsystem actuates on an actual or simulated initiation signal.
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| TS 3.7.4 CREF System SR 3.7.4.3 Verify the CREF System actuates on an actual or simulated initiation signal.
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| TS 3.7.7 Main Turbine Bypass System SR 3.7.7.2 Perform a system functional test.
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| SR 3.7.7.3 Verify the TURBINE BYPASS SYSTEM RESPONSE TIME is within limits.
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| TS 3.8.1 AC Sources - Operating SR 3.8.1.8 Verify automatic and manual transfer of unit power supply from the normal offsite circuit to the alternate offsite circuit.
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| SR 3.8.1.9 Verify each DG operates for > 8 hours:
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| : a. For > 2 hours loaded > 4200 kW and < 4400 kW; and
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| : b. For the remaining hours of the test loaded > 3600 kW and <
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| 4000 kW.
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| SR 3.8.1.10 Verify interval between each sequenced load is within + 10% of nominal timer setpoint.
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| SR 3.8.1.11 Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal:
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| : a. De-energization of emergency buses;
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| : b. Load shedding from emergency buses; and
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| : c. DG auto-starts from standby condition and:
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| : 1. energizes permanently connected loads in < 14 seconds,
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| : 2. energizes auto-connected emergency loads through the timed logic sequence,
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| : 3. maintains steady state voltage > 3950 V and < 4400 V,
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| : 4. maintains steady state frequency >_ 58.8 Hz and < 61.2 Hz, and
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| : 5. supplies permanently connected and auto-connected emergency loads for > 5 minutes.
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| NLS2011071 Page 8 of 35 TS 3.8.4 DC Sources - Operating SR 3.8.4.6 Verify:
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| : a. Each required 125 V battery charger supplies> 200 amps at >
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| 125 V for > 4 hours; and
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| : b. Each required 250 V battery charger supplies> 200 amps at >
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| 250 V for > 4 hours.
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| SR 3.8.4.7 Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.
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| The following additional TS changes are proposed to accommodate a 24-month fuel cycle:
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| TS 3.3.5.1 ECCS Instrumentation Table 3.3.5.1-1 Function 2.d, Reactor Pressure - Low (Recirculation Discharge Valve Permissive), requires a change to the upper limit TS Allowable Value. The TS Allowable Value is being changed from "< 221 psig" to "< 246 psig."
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| TS 3.3.6.3 LLS Instrumentation Table 3.3.6.3-1 Function 2, Low-Low Set Pressure Setpoints, require changes to the Low and High opening and closing TS Allowable Values. The Low opening pressure is changed from "> 995 psig and < 1035 psig" to "> 996.5 psig and <- 1010 psig."
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| The Low closing pressure is changed from "> 855 psig and < 895 psig" to "> 835 psig and < 875.5 psig." The High opening pressure is changed from "> 1005 psig and
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| < 1045 psig" to "> 996.5 psig and < 1040 psig." The High closing pressure is changed from "> 855 psig and < 895 psig" to "> 835 psig and < 875.5 psig."
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| TS 5.5.2 Systems Integrity Monitoring Program A change is proposed to Administrative Controls Section 5.5.2, "Systems Integrity Monitoring Program," to address changes to 18-month frequencies that are specified in that section. This change revises the following subsection to change "18 months" to "24 months":
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| The program shall include the following:
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| : b. Integrated leak test requirements for each system at 18 month intervals or less.
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| The provisions of SR 3.0.2 and SR 3.0.3 are applicable at the 18 month Frequency for performing system leak test activities.
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| NLS2011071 Page 9 of 35 TS 5.5.7 Ventilation Filter Testing Program (VFTP)
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| A change is proposed to Administrative Controls Section 5.5.7, "Ventilation Filter Testing Program (VFTP)," to address changes to 18-month frequencies that are specified in that section. This change revises the following subsections to change "18 months" to "24 months":
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| The VFTP shall establish the required testing of Engineered Safety Feature (ESF) filter ventilation systems. Tests described in Specifications 5.5.7.a, 5.5.7.b, and 5.5.7.c shall be performed once per 18 months for standby service or after 720 hours of system operation; and, following significant painting, fire, or chemical release concurrent with system operation in any ventilation zone communicating with the system.
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| Tests described in Specifications 5.5.7.d and 5.5.7.e shall be performed once per 18 months.
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| TS 5.5.13 Control Room Envelope Habitability Program A change is proposed to Administrative Controls Section 5.5.13, "Control Room Envelope Habitability Program," to address changes to 18-month frequencies that are specified in that section. This change revises the following subsection to change "18 months" to "24 months":
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| The program shall include the following elements:
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| : d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by the CREF System, operating at the flow rate required by the Ventilation Filter Testing Program, at a Frequency of 18 months. The results shall be trended and used as part of the periodic assessment of the CRE boundary.
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| 2.1.2 TSTF-493, Revision 4, Option A Changes NPPD proposes to add TSTF-493, Revision 4, Option A TS surveillance Notes with changes to setpoint values to CNS instrumentation Functions.
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| NPPD has reviewed the model safety evaluation (SE) referenced in the Federal Register Notice of Availability published on May 11, 2010 (75 FR 26294). As described herein, NPPD has concluded that the justifications presented in TSTF-493, Revision 4, Option A, and the model SE prepared by the NRC staff for Option A are applicable to CNS and support these changes to the CNS Technical Specifications.
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| NLS2011071 Page 10 of 35 NPPD is proposing variations or deviations from the TS changes described in TSTF-493, Revision 4, or the NRC staff's model SE referenced in the Notice of Availability. Specifically, because the CNS TS are based on an earlier version of NUREG-1433, "Standard Technical Specifications - General Electric Plants, BWR/4," the level of detail and content of the CNS Bases for TS 3.3.1 is different from that provided in NUREG-1433, Revision 3, requiring modification of the Bases changes in TSTF-493-A, Revision 4, Option A. NPPD also notes that the Model SE refers to ISA-$67.04-1994 Part 2. NPPD does not use this standard in calculating safety-related setpoints. Rather, NPPD uses the NRC-approved General Electric Instrument Setpoint Methodology, which is in general agreement with ISA-$67.04-1982. The Model SE also refers to compliance with 10 CFR 50 Appendix A, General Design Criteria (GDC) 13 and 20. CNS design predated the issuance of 10 CFR 50 Appendix A. The CNS licensing basis is to the analogous 1967 draft GDCs.
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| 2.2 Need for Changes The shift from an 18-month fuel cycle to a 24-month fuel cycle is a CNS strategic initiative. It is expected to increase the CNS capacity factor throughout the plant's operating life, and reduce cumulative radiological occupational exposure due to less frequent refueling outages.
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| At a pre-submittal public meeting with the NRC on October 19, 2010 regarding the 24-month fuel cycle License Amendment Request (LAR), it was determined that it would be appropriate for NPPD to combine the 24-month fuel cycle TS changes with a LAR implementing TSTF-493, Revision 4, Option A. The background for this application is adequately addressed by the NRC Notice of Availability published in the FederalRegister on May 11, 2010 (75 FR 26294).
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| 2.3 Technical Specification Bases Changes Revised TS Bases are provided in Attachment 4 for NRC information. These Bases revisions will be part of LAR implementation pursuant to TS 5.5.10, "Technical Specifications (TS) Bases Control Program," following issuance of the amendment.
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| ==3.0 TECHNICAL EVALUATION==
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| 3.1 Generic Letter 91-04 Changes In NRC GL 91-04, the NRC provided generic guidance for evaluating a 24-month surveillance test interval for TS SRs that are currently performed at 18-month intervals. This section defines each step outlined by the NRC in the GL and provides a description of the methodology used by NPPD to complete the evaluation for each specific TS SR frequency being extended from 18 months to 24 months. The methodology utilized in the CNS drift analysis, as summarized in Enclosure 1, is similar to the methodology used for previous plant submittals, such as the River Bend
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| NLS2011071 Page 11 of 35 Station, Perry Nuclear Power Plant, and Edwin I. Hatch Nuclear Power Plant LARs.
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| There have been minor revisions incorporated into the CNS drift design guide based on NRC comments or Requests for Additional Information from previous 24-month fuel cycle extension submittals, such as the addition of the requirement that 30 samples are generally required to produce a statistically significant sample set.
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| The proposed TS changes based on the GL have been divided into two categories.
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| The categories are: (1) changes to surveillances other than channel calibrations, identified as "Non-Calibration Changes"; and (2) changes involving the channel calibration frequency identified as "Calibration Changes." For each component having a surveillance interval extended, historical surveillance test data and associated maintenance records were reviewed in evaluating the effect on safety. In addition, the licensing basis was reviewed for functions associated with each revision to ensure it was not invalidated. Based on the results of these reviews, it is concluded that there is no adverse effect on plant safety due to increasing the surveillance test intervals from 18 months to 24 months, with the continued application of SR 3.0.2, which allows a 25% extension (i.e., grace period up to 30 months) to SR frequencies.
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| Additionally, to support the above channel calibration changes to a 24-month frequency, some setpoint analysis revisions were required. For two Instrument Functions, TS Allowable Value changes were required (see Sections 3.1.3 and 3.1.4).
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| Revisions to CNS setpoint calculations have been developed, and affected calibration and functional test procedures will be revised as part of implementation, to reflect the new 30-month drift values. The revised setpoint calculations were developed in accordance with NEDC-31336, "General Electric Instrument Setpoint Methodology" (Reference 6.3). These calculations determined the instrument uncertainties and setpoints for the affected function. The setpoints were determined in a manner suitable to establish limits for their application. As such, the setpoints ensure that sufficient margins are maintained in the applicable safety analyses to confirm the affected instruments are capable of performing their intended design function.
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| 3.1.1 Non-Calibration Changes GL 91-04 identifies three steps to evaluate non-calibration changes:
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| STEP 1: Licensees should evaluate the effect on safety of an increase in 18-month surveillance intervals to accommodate a 24-month fuel cycle. This evaluation should support a conclusion that the effect on safety is small.
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| EVALUATION Each non-calibration SR frequency being changed has been evaluated with respect to the effect on plant safety. The methodology utilized to justify the conclusion that
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| NLS2011071 Page 12 of 35 extending the testing interval has a minimal effect on safety was based on the fact that the function/feature is:
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| (1) Tested on a more frequent basis during the operating cycle by other plant programs; (2) Designed to have redundant counterparts or be single failure proof; or (3) Highly reliable.
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| A summary of the evaluation of the effect on safety for each non-calibration SR frequency being changed is presented in Attachment 5.
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| STEP 2: Licensees should confirm that historical plant maintenance and surveillance data support this conclusion.
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| EVALUATION The surveillance test history of the affected SRs has been evaluated. This evaluation consisted of a review of available surveillance test results and associated maintenance records for at least five cycles of operation. This included SRs performed up to and including the Fall 2009 refueling outage; although in some cases SRs performed in 2010 and 2011 were also included in the evaluation when older records could not be readily retrieved. With the extension of the testing frequency to 24 months, there will be a longer period between each surveillance performance. If a failure that results in the loss of the associated safety function should occur during the operating cycle, and would only be detected by the performance of the 18-month TS SR, then the increase in the surveillance testing interval could reduce the associated function availability.
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| In addition to evaluating these surveillance failures, potential common failures of similar components tested by different surveillances were also evaluated. This additional evaluation determined whether there is evidence of repetitive failures among similar plant components. These common component failures have been further evaluated to determine if there was an impact on plant reliability. The evaluation determined that current plant programs are adequate to ensure system reliability. The surveillance failures that are detailed in Attachment 5 exclude failures that:
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| (a) Did not impact a TS safety function or TS operability; (b) Are detectable by required testing performed more frequently than the 18-month surveillance being extended; or (c) The cause can be attributed to an associated event such as a preventative maintenance task, human error, previous modification, or previously existing design deficiency; or that were subsequently re-performed successfully with no intervening corrective maintenance (e.g., plant conditions or malfunctioning measurement and test equipment may have caused aborting the test performance).
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| NLS2011071 Page 13 of 35 These categories of failures are not related to potential unavailability due to testing interval extension, and are therefore not listed or further evaluated in this submittal.
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| This review of surveillance test history validated the conclusion that the impact, if any, on system availability will be minimal as a result of the change to a 24-month testing frequency. Specific SR test failures, and justification for this conclusion, are discussed in Attachment 5.
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| STEP 3: Licensees should confirm that assumptions in the plant licensing basis would not be invalidated on the basis of performing any surveillance at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle.
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| EVALUATION As part of the evaluation of each affected SR, the impact of the changes against the assumptions in the CNS licensing basis was reviewed. In general, testing interval changes have no impact on the plant licensing basis. In some cases, the change to a 24-month fuel cycle may require a change to licensing basis information as described in the Updated Safety Analysis Report (USAR). However, since no changes requiring NRC review and approval have been identified, the USAR changes associated with fuel cycle extension to 24 months will be drafted in accordance with CNS procedures that implement 10 CFR 50.59, "Changes, tests and experiments,"
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| and will be submitted in accordance with 10 CFR 50.71, "Maintenance of records, making of reports," paragraph (e).
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| The performance of surveillances extended for a 24-month fuel cycle will be trended as a part of the Maintenance Rule Program. Degradation in performance will be evaluated to verify that the degradation is not due to the extension of surveillance or maintenance activities.
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| 3.1.2 Calibration Changes GL 91-04 identifies seven steps for the evaluation of instrumentation calibration changes.
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| STEP 1: Confirm that instrument drift as determined by as-found and as-left calibration data from surveillance and maintenance records has not, except on rare occasions, exceeded acceptable limits for a calibration interval.
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| EVALUATION The effect of longer calibration intervals on the TS instrumentation was evaluated by performing a review of the surveillance test history for the affected instrumentation including, where appropriate, an instrument drift study. In performing the historical evaluation, the recorded channel calibration data for associated instruments for at
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| NLS2011071 Page 14 of 35 least five operating cycles were retrieved. This included SRs performed up to and including the Fall 2009 refueling outage; although in some cases SRs performed in 2010 and 2011 were also included in the evaluation when older records were not readily retrievable. By obtaining this past recorded calibration data, an acceptable basis for drawing conclusions about the expectation of satisfactory performance can be made.
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| The failure history evaluation described in Attachment 5 provides the instances where TS Allowable Values have been exceeded. Attachment 5 provides the basis for the conclusion that these failures are acceptable relative to this criterion.
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| STEP 2: Confirm that the values of drift for each instrument type (make, model, and range) and application have been determined with a high probability and a high degree of confidence. Provide a summary of the methodology and assumptions used to determine the rate of instrument drift with time based upon historical plant calibration data.
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| EVALUATION A listing of the instrument make, model, and range affected by this submittal is provided in Attachment 6. The effect of longer calibration intervals on the TS instrumentation was evaluated by performing an instrument drift study. In performing the drift study, the recorded channel calibration data for associated instruments from at least five operating cycles prior to and including the Fall 2009 refueling outage was typically retrieved; although in some cases SRs performed in 2010 and 2011 were also included in the evaluation when older records were not readily retrievable. By obtaining this past recorded calibration data, analyses were performed to determine a statistically valid representation of instrument drift.
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| The methodology used to perform the drift analysis is consistent with the methodology utilized by other utilities requesting transition to a 24-month fuel cycle.
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| The methodology is also based on Electric Power Research Institute (EPRI) TR-103335, "Statistical Analysis of Instrument Calibration Data," and is summarized in Enclosure 1.
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| STEP 3: Confirm that the magnitude of instrument drift has been determined with a high probability and a high degree of confidence for a bounding calibration interval of 30 months for each instrument type (make, model number, and range) and application that performs a safety function.
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| Provide a list of the channels by TS section that identifies these instrument applications.
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| NLS2011071 Page 15 of 35 EVALUATION In accordance with the methodology described in Enclosure 1, the magnitude of instrument drift has been determined with a high degree of confidence and a high degree of probability (at least 95/95) for a bounding calibration interval of 30 months for each instrument make, model, and range. For instruments not in service long enough to establish a projected drift value, or where an insufficient number of calibrations have been performed to utilize the statistical methods (i.e., fewer than 30 calibrations for any given group of instruments), the SR frequency is proposed to be extended to a 24-month interval based on justification obtained from analysis as presented in Enclosure 1. The list of affected channels by TS section, including instrument make, model, and range, is provided in Attachment 6.
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| STEP 4: Confirm that a comparison of the projected instrument drift errors has been made with the values of drift used in the setpoint analysis. If this results in revised setpoints to accommodate larger drift errors, provide proposed TS changes to update trip setpoints. If the drift errors result in revised safety analysis to support existing setpoints, provide a summary of the updated analysis conclusions to confirm that safety limits and safety analysis assumptions are not exceeded.
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| EVALUATION The projected drift values were compared to the design allowances as calculated in the associated instrument setpoint analyses. Values were incorporated into the projected existing setpoint calculation design allowances, and the analysis of the setpoint, allowable value, and/or analytical limit was reviewed. Revised setpoint calculations were developed, as necessary, to accommodate appropriate drift values.
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| In all but two cases, the 30-month projected drift value for an instrument function could be accommodated within the existing or revised setpoint analysis. In these cases, the SR frequencies were changed to "24 months," with no changes necessary to the TS Allowable Value or licensing basis analytical limit. However, for two TS Instrument Functions, changes were required to TS Allowable Values (see Sections 3.1.3 and 3.1.4).
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| As necessary, revised CNS setpoint calculations have been developed, and affected calibration and functional test procedures will be revised as part of implementation, to reflect the new 30-month drift values. The revised setpoint calculations were developed in accordance with NEDC-31336. These calculations determined the instrument loop uncertainty and setpoints for the affected function. The setpoints were determined in a manner suitable to establish limits for their application. As such, the revised setpoints ensure that sufficient margins are maintained in the applicable safety analyses to confirm the affected instruments are capable of performing their intended design function.
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| NLS2011071 Page 16 of 35 STEP 5: Confirm that the projected instrument errors caused by drift are acceptable for control of plant parameters to effect a safe shutdown with the associated instrumentation.
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| EVALUATION As discussed in the previous sections, the calculated drift values have been compared to drift allowances in the CNS design basis. For instrument loops that provide process variable indication only, an evaluation was performed as described in Attachment 5 to verify that the instruments can still be effectively utilized to perform a plant safe shutdown. In no cases were changes to safe shutdown analyses required to support any change to a 24-month frequency.
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| STEP 6: Confirm that all conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations.
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| EVALUATION Applicable surveillance test procedures are being reviewed and acceptance criteria updated to incorporate the necessary changes resulting from any revision to setpoint calculations. Any necessary changes resulting from the reviews will be incorporated into the instrument surveillance procedures as part of implementation of the 24-month surveillance test frequency. Existing plant processes ensure that the conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations.
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| STEP 7: Provide a summary description of the program for monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and its effect on safety.
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| EVALUATION Instruments with TS calibration surveillance frequencies extended to 24 months will be monitored and trended. TS calibrations will be subject to TSTF-493 controls, either through direct application of the surveillance Notes, or as described in the TS Bases. Accordingly, these instrument channels will be monitored and trended as described in Section 3.2. This will identify occurrences of instruments found outside of their TS Allowable Value and instruments whose performance is not as assumed in the drift or setpoint analysis. When as-found conditions are outside the TS Allowable Value, an evaluation will be performed in accordance with the CNS corrective action program to determine if the assumptions made to extend the calibration frequency are still valid and to evaluate the effect on plant safety. Evaluations of mechanical
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| NLS2011071 Page 17 of 35 components will be completed under the auspices of the Maintenance Rule, 10 CFR 50.65.
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| 3.1.3 Emergency Core Cooling System (ECCS) Instrumentation Criterion 44 of the 1967 draft GDC, to which NPPD is committed, specifies that at least two ECCS be provided, preferably of different design principles, that will limit the clad metal-water reaction to negligible amounts for all sizes of breaks in the reactor coolant pressure boundary, including the double-ended rupture of the largest pipe. The CNS ECCS is designed to limit clad temperature to below 2200'F over the entire credible spectrum of postulated design basis reactor coolant system breaks.
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| This capability is available concurrently with the loss of all offsite AC power. The ECCS themselves are designed to various levels of component redundancy such that no single active component failure in addition to the accident can prevent adequate core cooling.
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| Low reactor pressure signals are used as permissives for Recirculation Discharge Valve closure. This ensures that the Low Pressure Coolant Injection (LPCI) subsystems inject into the proper location assumed in the safety analysis. The Reactor Pressure - Low is one of the Functions assumed to be operable and capable of closing the valve during a design basis Loss-of-Coolant Accident (LOCA). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| There are minimum and maximum TS Allowable Values associated with the Recirculation Discharge Valve Permissive. The minimum TS Allowable Value is chosen to be high enough that the valves close prior to when LPCI injection flow into the core is required. The maximum TS Allowable Value is chosen to be low enough to avoid excessive differential pressures across the Recirculation Discharge Valve.
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| The Reactor Pressure - Low signals are initiated from four pressure switches that sense the reactor dome pressure. The results of the drift analysis indicated that the projected 30-month drift values for these pressure switches exceeded the drift allowance provided in the current setpoint calculation and were outside the maximum TS Allowable Values of < 221 psig. Accordingly, a revised TS Allowable Value of
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| < 246 psig is proposed. The upper analytical limit for this function is a maximum of 200 psid across the Recirculation Discharge Valve throughout the closing stroke following a LOCA. In consideration of the dynamic changes in reactor steam dome and drywell pressures during the valve stroke time, NPPD has analyzed that the valve differential pressure analytical limit is well bounded by reactor steam dome pressures of up to 263 psig. Accordingly, the revised TS Allowable Value of < 246 psig remains bounded by the analytical limit of 200 psid across the Recirculation Discharge Valve when closing following a LOCA.
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| NLS2011071 Page 18 of 35 3.1.4 Low-Low Set (LLS) Instrumentation NUREG-0737 Item II.K.3.16 observed that the most likely cause of a small break LOCA was from the opening of a Safety Relief Valve (SRV) where the SRV failed to reset. A reduction in this likelihood could be achieved by minimizing the number of times individual SRVs must recycle in performance of the system relief function. In addition, as part of the Mark I Containment Program, there was concern for potential high thrust loads on the discharge piping and the high frequency pressure loading on the containment. The LLS logic and instrumentation is designed to mitigate the above concerns. Upon initiation, the LLS logic will assign preset opening and closing setpoints to two preselected SRVs. These setpoints are selected such that the LLS SRVs will stay open longer (with a minimum blowdown range of 90 psi between SRV opening and closing); thus, releasing more steam to the suppression pool, and hence more energy (and time) will be required for repressurization and subsequent SRV openings.
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| One SRV is designated as the High LLS valve. Two pressure switches input into the LLS logic for this valve for opening and closing, respectively. A second SRV is designated as the Low LLS valve. Two different pressure switches similarly input into the LLS logic for opening and closing. The High LLS SRV is designed to open at a higher reactor pressure than the Low LLS SRV. Both SRVs are designed to close at the same pressure.
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| The results of the drift analysis indicated that the projected 30-month drift values for these pressure switches exceeded the drift allowance provided in the current setpoint calculation and were outside the current opening and closing TS Allowable Values for the High and Low LLS SRVs. Accordingly, revised TS Allowable Values are proposed as follows:
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| LLS Existing Opening Revised Opening Existing Closing Revised Closing Analytical Limit SRV Allowable Value Allowable Value Allowable Value Allowable Value (psig)
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| (psig) (psig) (psig) (psig)
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| High > 1005 and < 1045 > 996.5 and < 1040 > 855 and < 895 >835 and:<875.5 Open < 1050 Close > 825 Low >995 and:< 1035 >996.5 and < 1010 > 855 and < 895 > 835 and < 875.5 Open < 1050 Close > 825 As shown, these revised TS Allowable Values remain bounded by their respective Analytical Limits and the 90 psi blowdown criterion.
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| 3.2 TSTF-493, Revision 4, Option A Changes The Technical Analysis for this application is described in TSTF-493 as referenced in the NRC Notice of Availability published in the FederalRegister on May 11, 2010 (75 FR 26294). Plant-specific information related to the Technical Analysis is
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| NLS2011071 Page 19 of 35 described below to document that the content of TSTF-493, Revision 4, Option A, is applicable to CNS.
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| 3.2.1 Use of the Term "Limiting Trip Setpoint" The term "Limiting Trip Setpoint" (LTSP) is CNS terminology for the setpoint value calculated by means of the plant-specific setpoint methodology documented in the Updated Safety Analyses Report (USAR) or a document incorporated by reference into the USAR. The actual trip setpoint may be more conservative than the LTSP.
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| The LTSP is the LSSS' which is required to be in the TSs by 10 CFR 50.36.
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| The LTSP is the least conservative value to which the instrument channel is adjusted to actuate. The Allowable Value2 (AV) is derived from the LTSP. The LTSP is the limiting setting for an operable channel trip setpoint considering all credible instrument errors associated with the instrument channel. The LTSP is the least conservative value (with an as-left tolerance (ALT)) to which the channel must be reset at the conclusion of periodic testing to ensure that the analytical limit (AL) will not be exceeded during an anticipated operational occurrence or accident before the next periodic surveillance or calibration. It is impossible to set a physical instrument channel to an exact value, so a calibration tolerance is established around the LTSP.
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| Therefore, an instrument adjustment is considered successful if the LTSP as-left instrument setting is within the setting tolerance (i.e., a range of values around the LTSP). The Nominal Trip Setpoint (NTSP) is the LTSP with margin added. The NTSP is as conservative as or more conservative than the LTSP.
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| 3.2.2 Addition of Channel Performance Surveillance Notes to TS Instrumentation Functions The determination to include surveillance Notes for specific Functions in the TS is based on these Functions being automatic protective devices related to variables having significant safety functions as delineated by 10 CFR 50.36(c)(1)(ii)(A). There are two surveillance Notes added to the TSs regarding the use of TS AVs for operability determinations and for assessing channel performance. Evaluation of Exclusion Criterion, (Section 3.2.3 below) discusses the principles applied to determine which Functions are to be annotated with the two surveillance Notes. The list of affected Functions is provided in Section 3.2.3.
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| : 1. 10 CFR 50.36(c)(1 (II)(a) states: "Limiting safety system settings for nuclear reactors are settings for automatic protective devices related to those variables having significant safety functions."
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| : 2. The instrument setting "Allowable Value" is a limiting value of an instrument's as-found trip setting used during surveillances. The AV is more conservative than the Analytical Limit (AL) to account for applicable instrument measurement errors consistent with the plant-specific setpoint methodology. If during testing, the actual instrumentation setting is less conservative than the AV, the channel is declared inoperable and actions must be taken consistent with the TS requirements.
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| NLS2011071 Page 20 of 35 Surveillance Note 1 states, "If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service."
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| Surveillance Note 2 states:
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| The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
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| Setpoint calculations establish an LTSP based on the AL of the Safety Analysis to ensure that trips or protective actions will occur prior to exceeding the process parameter value assumed by the Safety Analysis calculations. These setpoint calculations also calculate an allowed limit of expected change (i.e., the as-found tolerance (AFT)) between performances of the surveillance test for assessing the value of the setpoint setting. The least conservative as-found instrument setting value that a channel can have during calibration without requiring performing a TS remedial action is the setpoint AV. Discovering an instrument setting to be less conservative than the setting AV indicates that there may not be sufficient margin between the setting and the AL. TSs [channel calibrations, channel functional tests (with setpoint verification), and trip unit calibrations,] are performed to verify channels are operating within the assumptions of the setpoint methodology calculated LTSP and that channel settings have not exceeded the TS AVs. When the measured as-found setpoint is non-conservative with respect to the AV, the channel is inoperable and the actions identified in the TSs must be taken.
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| The first surveillance Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its AFT but conservative with respect to the AV. Evaluation of channel performance will verify that the channel will continue to perform in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology.
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| The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service.
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| Verifying that a trip setting is conservative with respect to the AV when a surveillance test is performed does not by itself verify the instrument channel will operate properly in the future. Although the channel was operable during the previous surveillance interval, if it is discovered that channel performance is outside the performance predicted by the plant setpoint calculations for the test interval, then the design basis for the channel may not be met, and proper operation of the channel
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| NLS2011071 Page 21 of 35 for a future demand cannot be assured. Surveillance Note 1 formalizes the establishment of the appropriate AFT for each channel. This AFT is applied about the LTSP or about any other more conservative setpoint. The AFT ensures that channel operation is consistent with the assumptions or design inputs used in the setpoint calculations and establishes a high confidence of acceptable channel performance in the future. Because the AFT allows for both conservative and non-conservative deviation from the LTSP, changes in channel performance that are conservative with respect to the LTSP will also be detected and evaluated for possible effects on expected performance.
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| To implement surveillance Note 2 the ALT for some instrumentation Function channels is established to ensure that realistic values are used that do not mask instrument performance. Setpoint calculations assume that the instrument setpoint is left at the LTSP within a specific ALT (e.g., 25 psig +/- 2 psig). A Tolerance band is necessary because it is not possible to read and adjust a setting to an absolute value due to the readability and/or accuracy of the test instruments or the ability to adjust potentiometers. The ALT is normally as small as possible considering the tools and the objective to meet an as low as reasonably achievable calibration setting of the instruments. The ALT is considered in the setpoint calculation. Failure to set the actual plant trip setpoint to the LTSP (or more conservative than the LTSP), and within the ALT, would invalidate the assumptions in the setpoint calculation because any subsequent instrument drift would not start from the expected as-left setpoint.
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| It should be noted that TS Table 3.3.1.1-1 currently applies footnotes (c) and (d),
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| similar to those proposed in this amendment request, to SR 3.3.1.1.10 and SR 3.3.1.1.12 for Function .b, "Average Power Range Monitors - Neutron Flux -
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| High (Flow-Biased)." These footnotes are deleted and replaced with the TSTF-493 Note 1 and Note 2 as footnotes (a) and (b). The requirements specified in the current notes are encompassed in the proposed TSTF-493 notes.
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| 3.2.3 Evaluation of Exclusion Criterion Exclusion criteria are used to determine which Functions do not need to receive the proposed footnotes, as discussed in TSTF-493, Revision 4. Instruments are excluded from the additional requirements when their functional purpose can be described as (1) a manual actuation circuit, (2) an automatic actuation logic circuit, or (3) an instrument function that derives input from contacts which have no associated sensor or adjustable device. Many permissives or interlocks are excluded if they derive input from a sensor or adjustable device that is tested as part of another TS function.
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| The list of affected Functions identified in the tables below was developed on the principle that all Functions in the affected TSs are included unless one or more of the exclusion criterion apply. If the excluded functions differ from the list of excluded functions in TSTF-493, Revision 4, a justification for deviation is provided in the Excluded Functions table.
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| NLS2011071 Page 22 of 35 The following tables provide the results of applying the three exclusion criteria (and other optional inclusions as allowed by the TSTF) by identifying instrumentation Functions, by TS Table, for which surveillance Notes 1 and 2 apply and for those instrumentation Functions which do not require the surveillance Notes.
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| Table 1 Functions Required To Be Annotated Functions Required to be Annotated NUREG-1433 CNS TS Table 3.3.1.1-1. "Reactor Protection System Table 3.3. 1. 1-1, "Reactor Protection System Instrumentation" Instrumentation" Functions Functions
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| : 1. Intermediate Range Monitors 1. Intermediate Range Monitors
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| : a. Neutron Flux - High a. Neutron Flux - High
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| : 2. Average Power Range Monitors 2. Average Power Range Monitors
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| : a. Neutron Flux - High, Setdown a. Neutron Flux - High (Startup)
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| : b. Flow Biased Simulated Thermal Power - High b. Neutron Flux - High (Flow Biased)
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| : c. Fixed Neutron Flux - High c. Neutron Flux - High (Fixed)
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| : d. Downscale d. Downscale
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| : 3. Reactor Vessel Steam Dome Pressure - High 3. Reactor Vessel Pressure - High
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| : 4. Reactor Vessel Water Level - Low, Level 3 4. Reactor Vessel Water Level - Low (Level 3)
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| : 6. Drywell Pressure - High 6. Drywell Pressure - High
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| : 7. Scram Discharge Volume Water Level - High
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| : a. Level Transmitter
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| : 9. Turbine Control Valve Fast Closure, Trip Oil Pressure - 9. Turbine Control Valve Fast Closure, DEH Trip Oil Low Pressure - Low Table 3.3.2.1-1, "Control Rod Block Instrumentation" Table 3.3.2. 1-1, "Control Rod Block Instrumentation" Functions Functions
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| : 1. Rod Block Monitor 1. Rod Block Monitor
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| : a. Low Power Range - Upscale a. Low Power Range - Upscale
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| : b. Intermediate Range - Upscale b. Intermediate Power Range - Upscale
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| : c. High Power Range - Upscale c. High Power Range - Upscale Specification 3.3.4.1, "EOC-RPT Instrumentation" "EOC-RPT Instrumentation" not specified in CNS TS.
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| : 1. Trip Units NA
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| : 3. Turbine Control Valve - Fast Closure, Trip Oil Pressure - NA Low Table 3.3.5.1-1, "Emergency Core Cooling System Table 3.3.5.1-1, "Emergency Core Cooling System Instrumentation" Functions Instrumentation" Functions I. Core Spray System 1. Core Spray System
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| : a. Reactor Vessel Water Level - Low Low Low, Level a. Reactor Vessel Water Level - Low Low Low (Level 1 1)
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| : b. Drywell Pressure - High b. Drywell Pressure - High
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| : d. Core Spray Pump Discharge Flow - Low (Bypass) d. Core Spray Pump Discharge Flow - Low (Bypass)
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| (If valve locked open, Function can be removed from TS)
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| : 2. Low Pressure Coolant Injection (LPCI) System 2. Low Pressure Coolant Injection (LPCI) System
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| : a. Reactor Vessel Water Level - Low Low Low Level a. Reactor Vessel Water Level - Low Low Low (Level I I)
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| : b. Drywell Pressure - High b. Drywell Pressure - High
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| : g. Low Pressure Coolant Injection Pump Discharge g. Low Pressure Coolant Injection Pump Discharge Flow - Low (Bypass) (If valve locked open, Flow - Low (Bypass)
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| Function can be removed from TS)
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| NLS2011071 Page 23 of 35 Functions Required to be Annotated NUREG-1433 CNS TS
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| : 3. High Pressure Coolant Injection (HPCI) System 3. High Pressure Coolant Injection (HPCI) System
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| : a. Reactor Vessel Water Level - Low Low, Level 2 a. Reactor Vessel Water Level - Low Low (Level 2)
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| : b. Drywell Pressure - High b. Drywell Pressure - High
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| : c. Reactor Vessel Water Level - High, Level 8 c. Reactor Vessel Water Level - High (Level 8) (This (Optional to include surveillance Notes or not) Function is not assumed to function in the CNS
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| : d. Condensate Storage Tank Level - Low (If Safety Analyses and is excluded from the surveillance mechanical device, excluded from surveillance Notes)
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| Notes) d. Emergency Condensate Storage Tank (ECST) Level -
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| : e. Suppression Pool Water Level - High (If mechanical Low (This is a mechanical device, and is excluded device, excluded from surveillance Notes) from surveillance Notes)
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| : f. High Pressure Coolant Injection Pump Discharge e. Suppression Pool Water Level - High (This is a Flow - Low (Bypass) (If valve locked open, mechanical device, and is excluded from surveillance Function can be removed from TS)(If mechanical Notes) device, excluded from surveillance Notes) f. High Pressure Coolant Injection Pump Discharge Flow - Low (Bypass)
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| : 4. Automatic Depressurization System (ADS) Trip System 4. Automatic Depressurization System (ADS) Trip System A A a. Reactor Vessel Water Level - Low Low Low (Level
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| : a. Reactor Vessel Water Level - Low Low Low, Level 1)
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| I NUREG-1433 Function 4.b. not specified in CNS TS
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| : b. Drywell Pressure - High c. Reactor Vessel Water Level - Low (Level 3)
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| : d. Reactor Vessel Water Level - Low, Level 3 (Confirmatory)
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| (Confirmatory)
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| : 5. ADS Trip System B 5. ADS Trip System B
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| : a. Reactor Vessel Water Level - Low Low Low, Level a. Reactor Vessel Water Level - Low Low Low (Level 1 1)
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| : b. Drywell Pressure - High NUREG-1433 Function 5.b. not specified in CNS TS)
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| : d. Reactor Vessel Water Level - Low, Level 3 c. Reactor Vessel Water Level - Low, Level 3 (Confirmatory) (Confirmatory)
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| Table 3.3.5.2-1, "Reactor Core Isolation Cooling System Table 3.3.5.2-1, "Reactor Core Isolation Cooling System Instrumentation" Functions Instrumentation" Functions
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| : 1. Reactor Vessel Water Level - Low Low, Level 2 1. Reactor Vessel Water Level - Low Low (Level 2)
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| : 2. Reactor Vessel Water Level - High, Level 8 - (Optional to 2. Reactor Vessel Water Level - High (Level 8) (This include surveillance Notes or not) Function is not assumed to function in the CNS Safety Analyses and is excluded from the surveillance Notes)
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| : 3. Condensate Storage Tank Level - Low (If mechanical 3. Emergency Condensate Storage Tank (ECST) Level - Low device, excluded from surveillance Notes) (This is a mechanical device, and is excluded from surveillance Notes)
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| : 4. Suppression Pool Water Level - High (If mechanical NUREG-1433 Function 4 not specified in CNS TS device, excluded from surveillance Notes)
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| Table 2 Excluded Functions Excluded Functions NUREG-1433 CNS TS Table 3.3.1.1 - 1. "Reactor Protection System Table 3.3.1.1-1, "Reactor Protection System Instrumentation" Instrumentation" Functions Functions
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| : 1. Intermediate Range Monitors 1. Intermediate Range Monitors
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| : b. lnop (Interlock excluded from surveillance Notes) b. Inop (Interlock excluded from surveillance Notes)
| |
| : 2. Average Power Range Monitors 2. Average Power Range Monitors
| |
| : e. Inop (Interlock excluded from surveillance Notes) e. Inop (Interlock excluded from surveillance Notes)
| |
| : 5. Main Steam Isolation Valve - Closure (Mechanical device 5. Main Steam Isolation Valve - Closure (Mechanical device excluded from surveillance Notes) excluded from surveillance Notes)
| |
| | |
| NLS2011071 Page 24 of 35 Excluded Functions NUREG-1433 CNS TS
| |
| : 7. Scram Discharge Volume Water Level - High 7. Scram Discharge Volume Water Level - High
| |
| : a. Resistance Temperature Detector (Mechanical b. Level Switch (Mechanical device excluded from device excluded from surveillance Notes) surveillance Notes)
| |
| : b. Float Switch (Mechanical device excluded from Note: CNS Function 7.a. requires the addition of the two surveillance Notes) Notes. CNS Function 7.a. uses a level transmitter.
| |
| NUREG-1433 Function 7.a. not specified in CNS TS
| |
| : 8. Turbine Stop Valve - Closure (Mechanical device 8. Turbine Stop Valve - Closure (Mechanical device excluded excluded from surveillance Notes) from surveillance Notes)
| |
| : 10. Reactor Mode Switch - Shutdown Position (Manual 10. Reactor Mode Switch - Shutdown Position (Manual actuation excluded from surveillance Notes) actuation excluded from surveillance Notes)
| |
| : 11. Manual Scram (Manual actuation excluded from 11. Manual Scram (Manual actuation excluded from surveillance Notes) surveillance Notes)
| |
| Table 3.3.2.1-1, "Control Rod Block Instrumentation" Table 3.3.2. 1-1, "Control Rod Block Instrumentation" Functions Functions
| |
| : 1. Rod Block Monitor 1. Rod Block Monitor
| |
| : d. Inop (Interlock excluded from surveillance Notes) d. Inop (Interlock excluded from surveillance Notes)
| |
| : e. Downscale (Not part of RPS or ECCS excluded from e. Downscale (Not part of RPS or ECCS excluded from surveillance Notes) surveillance Notes)
| |
| : f. Bypass Time Delay (Permissive or interlock excluded from surveillance Notes if it derives input NUREG- 1433 Function I.f. not specified in CNS TS from a sensor or adjustable device that is tested as part of another TS function.)
| |
| : 2. Rod Worth Minimizer (Not part of RPS or ECCS 2. Rod Worth Minimizer (Not part of RPS or ECCS excluded excluded from surveillance Notes) from surveillance Notes)
| |
| : 3. Reactor Mode Switch - Shutdown Position (Manual 3. Reactor Mode Switch - Shutdown Position (Manual actuation excluded from surveillance Notes) actuation excluded from surveillance Notes)
| |
| Specification 3.3.4. 1 "EOC-RPT Instrumentation" "EOC-RPT Instrumentation" not specified in CNS TS.
| |
| : 2. Turbine Stop Valve - Closure (Mechanical component NA excluded from surveillance Notes)
| |
| Table 3.3.5.1-1, "Emergency Core Cooling System Table 3.3.5.1-1. "Emergency Core Cooling System Instrumentation" Functions Instrumentation" Functions
| |
| : 1. Core Spray System 1. Core Spray System
| |
| : c. Reactor Steam Dome Pressure - Low (Injection c. Reactor Pressure - Low (Injection Permissive)
| |
| Permissive) (Actuation logic excluded from (Actuation logic excluded from surveillance Notes) surveillance Notes) e. Core Spray Pump Start - Time Delay Relay (Manual
| |
| : e. Manual Initiation (Manual actuation excluded from component excluded from surveillance Notes) surveillance Notes)
| |
| NUREG-1433 Function L.e. not specified in CNS TS
| |
| | |
| NLS2011071 Page 25 of 35 Excluded Functions NUREG-1433 CNS TS
| |
| : 2. Low Pressure Coolant Injection (LPCI) System 2. Low Pressure Coolant Injection (LPCI) System
| |
| : c. Reactor Steam Dome Pressure - Low (Injection c. Reactor Pressure - Low (Injection Permissive)
| |
| Permissive) (Actuation logic excluded from , (Actuation logic excluded from surveillance Notes) surveillance Notes) d. Reactor Pressure - Low (Recirculation Discharge
| |
| : d. Reactor Steam Dome Pressure - Low (Recirculation Valve Permissive) (Actuation logic excluded from Discharge Valve Permissive) (Actuation logic surveillance Notes) excluded from surveillance Notes) e. Reactor Vessel Shroud Level - Level 0 (Actuation
| |
| : e. Reactor Vessel Shroud Level - Level 0 (Actuation logic excluded from surveillance Notes) logic excluded from surveillance Notes) f. Low Pressure Coolant Injection Pump Start - Time
| |
| : f. Low Pressure Coolant Injection Pump Start - Time Delay Relay Delay Relay Pumps B,C (Permissive or interlock excluded Pumps A,B,D (Permissive or interlock excluded from surveillance Notes. It derives input from a from surveillance Notes if it derives input from a sensor or adjustable device that is tested as part of sensor or adjustable device that is tested as part another TS function).
| |
| of another TS function). Pump A, D (Permissive or interlock excluded Pump C (Permissive or interlock excluded from from surveillance Notes. It derives input from a surveillance Notes if it derives input from a sensor or adjustable device that is tested as part of sensor or adjustable device that is tested as part another TS function).
| |
| of another TS function).
| |
| : h. Manual Initiation (Manual actuation excluded from NUREG-1433 Function 2.h. not specified in CNS TS surveillance Notes)
| |
| : 3. High Pressure Coolant Injection (HPCI) System 3. High Pressure Coolant Injection (HPCI) System
| |
| : g. Manual Initiation (Manual actuation excluded from c. Reactor Vessel Water Level - High (Level 8) (This surveillance Notes) Function is not assumed to function in the CNS Safety Analyses and is excluded from the surveillance Notes)
| |
| : d. Emergency Condensate Storage Tank (ECST) Level -
| |
| Low (This is a mechanical device, and is excluded from surveillance Notes)
| |
| : e. Suppression Pool Water Level - High (This is a mechanical device, and is excluded from surveillance Notes)
| |
| NUREG-1433 Function 3.g. not specified in CNS TS
| |
| : 4. Automatic Depressurization System (ADS) Trip System 4. Automatic Depressurization System (ADS) Trip System A A b. Automatic Depressurization System Initiation Timer
| |
| : c. Automatic Depressurization System Initiation Timer (Actuation logic excluded from surveillance Notes)
| |
| (Actuation logic excluded from surveillance Notes) d. Core Spray Pump Discharge Pressure - High
| |
| : e. Core Spray Pump Discharge Pressure - High (Actuation logic excluded from surveillance Notes)
| |
| (Actuation logic excluded from surveillance Notes) e. Low Pressure Coolant Injection Pump Discharge
| |
| : f. Low Pressure Coolant Injection Pump Discharge Pressure - High (Actuation logic excluded from Pressure - High (Actuation logic excluded from surveillance Notes) surveillance Notes)
| |
| : g. Automatic Depressurization System Low Water NUREG-1433 Functions 4.g and 4.h not specified in Level Actuation Timer (Actuation logic excluded CNS TS from surveillance Notes)
| |
| : h. Manual Initiation (Manual actuation excluded from surveillance Notes)
| |
| | |
| NLS2011071 Page 26 of 35 Excluded Functions NUREG-1433 CNS TS
| |
| : 5. ADS Trip System B 5. ADS Trip System B
| |
| : c. Automatic Depressurization System Initiation Timer b. Automatic Depressurization System Initiation Timer (Actuation logic excluded from surveillance Notes) (Actuation logic excluded from surveillance Notes)
| |
| : e. Core Spray Pump Discharge Pressure - High d. Core Spray Pump Discharge Pressure - High (Actuation logic excluded from surveillance Notes) (Actuation logic excluded from surveillance Notes)
| |
| : f. Low Pressure Coolant Injection Pump Discharge e. Low Pressure Coolant Injection Pump Discharge Pressure - High (Actuation logic excluded from Pressure - High (Actuation logic excluded from surveillance Notes) surveillance Notes)
| |
| : g. Automatic Depressurization System Low Water Level Actuation Timer (Actuation logic excluded NUREG-1433 Functions 5.g and 5.h not specified in from surveillance Notes) CNS TS
| |
| : h. Manual Initiation (Manual actuation excluded from surveillance Notes)
| |
| Table 3.3.5.2-1, "Reactor Core Isolation Cooling System Table 3.3.5.2-1. "Reactor Core Isolation Cooling System Instrumentation" Functions Instrumentation" Functions
| |
| : 5. Manual Initiation (Manual actuation excluded from 2. Reactor Vessel Water Level - High (Level 8) (This surveillance Notes) Function is not assumed to function in the CNS Safety Analyses and is excluded from the surveillance Notes)
| |
| : 3. Emergency Condensate Storage Tank (ECST) Level - Low (This is a mechanical device, and is excluded from surveillance Notes)
| |
| NUREG-1433 Function 5. not specified in CNS TS 3.3 Other 24-Month Fuel Cycle Considerations 3.3.1 Source Term The reactor core source term is being re-evaluated to support the transition to 24-month fuel cycles. The current source term is based on the GE14 fuel with an 18-month fuel cycle. The new source term is based on GNF2 fuel with a 24-month fuel cycle. The new source term will affect the calculated doses of certain design basis accidents (LOCA and Fuel Handling Accident), and the radiation received by environmentally qualified electrical equipment. The effects on these analyses are being evaluated under the provisions of 10 CFR 50.59, and are not part of this application.
| |
| 3.3.2 18-Month Surveillances Not Being Changed During the evaluation of 18-month SRs it was determined that certain SRs were not eligible to be extended to 24 months. These SR frequencies will be maintained at 18 months as part of this submittal:
| |
| TS 3.8.4 DC Sources - Operatinp, SR 3.8.4.3 Verify battery cells, cell plates, and racks show no visual indication of physical damage or abnormal deterioration that degrades battery performance.
| |
| SR 3.8.4.4 Remove visible corrosion and verify battery cell to cell and terminal connections are coated with anti-corrosion material.
| |
| | |
| NLS2011071 Page 27 of 35 SR 3.8.4.5 Verify battery connection resistance meets the limits specified in Table 3.8.4-1.
| |
| SR 3.8.4.8 Verify battery capacity is > 90% of the manufacturer's rating when subjected to a performance discharge test or a modified performance discharge test [when battery shows degradation, or has reached 85%
| |
| of expected life with capacity of < 100% of manufacturer's rating].
| |
| 4.0 REGULATORY SAFETY ANALYSIS NRC GL 91-04 provides generic guidance for evaluating a 24-month surveillance test interval for TS SRs. This request for a license amendment provides the CNS-specific evaluation of each step outlined by the NRC in GL 91-04, including necessary changes to TS allowable Values, and provides a description of the methodology used by NPPD to complete the evaluation for each specific TS SR being revised. NPPD has determined that the proposed changes do not require any exemptions or relief from regulatory requirements, other than the TS, and do not affect conformance with any draft GDC differently than described in the CNS USAR, as described below.
| |
| With respect to TSTF-493, Revision 4, Option A, a description of the proposed TS change and its relationship to applicable regulatory requirements were published in the Federal Register Notice of Availability on May 11, 2010 (75 FR 26294). NPPD has reviewed the NRC staff s model SE published as part of the Notice of Availability and concluded that the regulatory evaluation section is applicable to CNS.
| |
| 4.1 Applicable Regulatory Requirements/Criteria Construction of CNS predated the 1971 issuance of 10 CFR 50, Appendix A, "General Design Criteria for Nuclear Power Plants." CNS USAR Appendix F, "Conformance to AEC Proposed General Design Criteria," describes that CNS is designed to conform to the proposed GDC published in the July 11, 1967, Federal Register, except where commitments were made to specific 1971 GDC. It notes that the Atomic Energy Commission accepted CNS conformance with these proposed GDC.
| |
| The following is a discussion of the applicable regulations, the draft GDC from USAR Appendix F, and other applicable regulatory criteria, along with a discussion of continued conformance.
| |
| 4.1.1 10 CFR 50.36, Technical Specifications Regulatory requirement 10 CFR 50.36, "Technical Specifications," provides the content required in licensee TS. Specifically, 10 CFR 50.36(c)(3) requires that the TS include surveillance requirements. The proposed SR frequency changes and application of the TSTF-493 Notes continue to support the requirements of 10 CFR 50.36(c)(3) to assure that the necessary quality of systems and components is
| |
| | |
| NLS2011071 Page 28 of 35 maintained, that facility operation will be within safety limits, and that the limiting conditions for operation are met.
| |
| 4.1.2 Applicable Draft General Design Criteria Draft GDC 25 - Demonstration of Functional Operability of Protection Systems "Means shall be included for testing protection systems while the reactor is in operation to demonstrate that no failure or loss of redundancy has occurred."
| |
| Since the physical configuration, design, and TS Allowable Values of the reactor protection system instrumentation functions are not changed, the extension of certain surveillance frequencies to 24 months has no impact on this criterion, and it continues to be satisfied. Application of the TSTF-493 surveillance Notes provides conservative assurance of instrumentation functionality, so conformance with this draft GDC is not adversely affected.
| |
| Draft GDC 38 - Reliability and Testability of Engineered Safety Features "All engineered safety features shall be designed to provide high functional reliability and ready testability. In determining the suitability of a facility for a proposed site, the degree of reliance upon and acceptance of the inherent and engineered safety afforded by the systems, including engineered safety features, will be influenced by the known and the demonstrated performance capability and reliability of the systems, and by the extent to which the operability of such systems can be tested and inspected where appropriate during the life of the plant."
| |
| Extending certain engineered safety feature SR frequencies to 24 months does not affect physical configuration, or design of the engineered safety features or associated instrumentation functions. Application of the TSTF-493 surveillance Notes provides conservative assurance of engineered safety feature instrumentation functionality.
| |
| Accordingly, continued conformance to this draft GDC is maintained.
| |
| Draft GDC 46 - Testing of Emergency Core Cooling System Components "Design provisions shall be made so that active components of the emergency core cooling systems, such as pumps and valves, can be tested periodically for operability and required functional performance."
| |
| Extending certain ECCS SR frequencies to 24 months does not affect physical configuration, or design of ECCS components. This draft GDC is not applicable to implementation of TSTF-493. Accordingly, continued conformance to this draft GDC is maintained.
| |
| | |
| NLS2011071 Page 29 of 35 Draft GDC 47 - Testing of Emergency Core Cooling Systems "A capability shall be provided to test periodically the delivery capability of the emergency core cooling systems at a location as close to the core as is practical."
| |
| Extending certain ECCS SR frequencies to 24 months does not affect physical configuration, or design of the ECCS. This draft GDC is not applicable to implementation of TSTF-493. Accordingly, continued conformance to this draft GDC is maintained.
| |
| Draft GDC 48 - Testing of Operational Sequence of Emergency Core Cooling Systems "A capability shall be provided to test under conditions as close to design as practical the full operational sequence that would bring the emergency core cooling systems into action, including the transfer to alternate power sources."
| |
| Extending certain ECCS SR frequencies to 24 months, including certain changes to TS Allowable Values, does not affect physical configuration, or design of the ECCS or associated instrumentation functions. Application of the TSTF-493 surveillance Notes provides conservative assurance of ECCS instrumentation functionality.
| |
| Accordingly, continued conformance to this draft GDC is maintained.
| |
| Draft GDC 57 - Provisions for Testing of Isolation Valves "Capability shall be provided for testing functional operability of valves and associated apparatus essential to the containment function for establishing that no failure has occurred and for determining that valve leakage does not exceed acceptable limits."
| |
| Extending certain Primary Containment Isolation Valves (PCIV) SR frequencies to 24 months does not affect physical configuration, or design of the PCIVs or associated Primary Containment isolation instrumentation functions. This draft GDC is not applicable to implementation of TSTF-493. Accordingly, continued conformance to this draft GDC is maintained.
| |
| Draft GDC 64 - Testing of Air Cleanup Systems "A capability shall be provided for in situ periodic testing and surveillance of the air cleanup systems to ensure (a) filter bypass paths have not developed and (b) filter and trapping materials have not deteriorated beyond acceptable limits."
| |
| Extending certain air cleanup system testing frequencies to 24 months does not affect physical configuration, or design of these systems. The review of the surveillance history of the air cleanup systems has demonstrated the extension of the testing
| |
| | |
| NLS2011071 Page 30 of 35 frequencies from 18 months to 24 months will not result in filter bypass paths during plant operation. This draft GDC is not applicable to implementation of TSTF-493.
| |
| Accordingly, continued conformance to this draft GDC is maintained.
| |
| Draft GDC 65 - Testing of Operational Sequence of Air Cleanup Systems "A capability shall be provided to test under conditions as close to design as practical the full operational sequence that would bring the air cleanup systems into action, including the transfer to alternate power sources and the design air flow delivery capability."
| |
| Extending certain air cleanup system testing frequencies to 24 months does not affect physical configuration, or design of the air cleanup systems or associated actuation instrumentation functions. This draft GDC is not applicable to implementation of TSTF-493. Accordingly, continued conformance to this draft GDC is maintained.
| |
| 4.2 Precedent In NRC GL 91-04, the NRC provided generic guidance for evaluating a 24-month surveillance test interval for TS SRs that are currently performed at 18-month intervals. The methodology utilized in the CNS drift analysis and scope of this License Amendment Request is similar to previously approved applications. There have been minor revisions incorporated into the CNS drift design guide based on NRC comments or Requests for Additional Information from previous 24-month fuel cycle extension submittals. The most recent applicable precedent is cited:
| |
| River Bend Station - License Amendment 168, dated August 31, 2010 There are no approved precedents for TSTF-493, Revision 4, Option A. However, the following submittal is currently under NRC review:
| |
| Vogtle Electric Generating Plant - Letter dated March 3, 2011 (ADAMS Accession Number ML110660458) 4.3 No Significant Hazards Consideration 10 CFR 50.91 (a)(1) requires that licensee requests for operating license amendments be accompanied by an evaluation of no significant hazard posed by issuance of the amendment. Nebraska Public Power District (NPPD) has evaluated this proposed amendment with respect to the criteria given in 10 CFR 50.92(c). The following is the evaluation required by 10 CFR 50.91(a)(1).
| |
| NPPD is requesting an amendment of the Operating License for the Cooper Nuclear Station (CNS) to revise Technical Specification (TS) surveillance and testing requirements to accommodate a 24-month fuel cycle. Additionally, NPPD is
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| | |
| NLS2011071 Page 31 of 35 requesting an amendment to adopt Technical Specifications Task Force (TSTF) 493, Revision 4, Option A.
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| 4.3.1 Generic Letter 91-04 Changes (24-Month Fuel Cycle)
| |
| Nebraska Public Power District (NPPD) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:
| |
| : 1. Do the proposed changes involve a significant increase in the probability or consequences of an accident previously evaluated?
| |
| Response: No.
| |
| The proposed TS changes involve a change in the surveillance testing intervals and certain TS Allowable Values to facilitate a change in the operating cycle length. The proposed TS changes do not physically impact the plant. The proposed TS changes do not degrade the performance of, or increase the challenges to, any safety systems assumed to function in the accident analysis.
| |
| The proposed TS changes do not impact the usefulness of the surveillance and testing requirements in evaluating the operability of required systems and components, or the way in which the surveillances are performed. In addition, the frequency of surveillance testing and TS Allowable Values are not considered initiators of any analyzed accident, nor do revisions to the frequency or TS Allowable Values introduce any accident initiators. Therefore, the proposed change does not involve a significant increase in the probability of an accident previously evaluated.
| |
| The consequences of a previously evaluated accident are not significantly increased. The proposed changes to surveillance frequencies do not affect the performance of any equipment credited to mitigate the radiological consequences of an accident. The changes to the TS Allowable Values remain bounded by their associated analytical limits. Evaluation of the proposed TS changes demonstrated that the availability of credited equipment is not significantly affected because of other more frequent testing that is performed, the availability of redundant systems and equipment, and the high reliability of the equipment. Historical review of surveillance test results and associated maintenance records did not find evidence of failures that would invalidate the above conclusions.
| |
| Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
| |
| | |
| NLS2011071 Page 32 of 35
| |
| : 2. Do the proposed changes create the possibility of a new or different kind of accident from any accident previously evaluated?
| |
| Response: No.
| |
| The proposed TS changes involve a change in the surveillance testing intervals and certain changes to TS Allowable Values to facilitate a change in the operating cycle length. The proposed TS changes do not introduce any failure mechanisms of a different type than those previously evaluated, since there are no physical configuration or design changes being made to the facility.
| |
| No new or different equipment is being installed. No installed equipment is being operated in a different manner. As a result, no new failure modes are being introduced. Although certain instrument setpoints and TS Allowable Values are being revised, the way surveillance tests are performed remains unchanged. The TS Allowable Values remain bounded by their associated analytical limits. A historical review of surveillance test results and associated maintenance records indicated there was no evidence of any failures that would invalidate the above conclusions.
| |
| Therefore, the proposed change does not create the possibility of a new or different kind of accident ,from any previously evaluated.
| |
| : 3. Do the proposed changes involve a significant reduction in a margin of safety?
| |
| Response: No.
| |
| The proposed TS changes involve a change in the surveillance testing intervals and certain TS Allowable Values to facilitate a change in the operating cycle length. The impact of these changes on system availability is not significant, based on other more frequent testing that is performed, the existence of redundant systems and equipment, and overall system reliability. The revised TS Allowable Values remain bounded by their associated analytical limits.
| |
| Evaluations have shown there is no evidence of time dependent failures that would impact the availability of the systems. The proposed changes do not significantly impact the condition or performance of structures, systems, and components relied upon for accident mitigation. The proposed changes do not result in any hardware changes or in any changes to the analytical limits assumed in accident analyses. Existing operating margin between plant conditions and actual plant setpoints is not significantly reduced due to these changes. The proposed changes do not significantly impact any safety analysis assumptions or results.
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| | |
| NLS2011071 Page 33 of 35 Therefore, the proposed change does not involve a significant reduction in a margin of safety.
| |
| Based on the responses to the above questions, NPPD concludes that the proposed amendment with respect to GL 91-04-related changes presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c) and, accordingly, a finding of "no significant hazards consideration" is justified.
| |
| 4.3.2 TSTF-493, Revision 4, Option A Changes Nebraska Public Power District (NPPD) has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:
| |
| : 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
| |
| Response: No.
| |
| The proposed change adds test requirements to TS instrument functions related to those variables that have a significant safety function to ensure that instruments will function as required to initiate protective systems or actuate mitigating systems at the point assumed in the applicable safety analysis.
| |
| Surveillance tests are not an initiator to any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased. The systems and components required by the TS for which surveillance tests are added are still required to be operable, meet the acceptance criteria for the surveillance requirements, and be capable of performing any mitigation function assumed in the accident analysis.
| |
| Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
| |
| : 2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
| |
| Response: No.
| |
| The change does not involve a physical alteration of the plant, i.e., no new or different type of equipment will be installed. The change does not alter assumptions made in the safety analysis but ensures that the instruments perform as assumed in the accident analysis. The proposed change is consistent with the safety analysis assumptions.
| |
| | |
| NLS2011071 Page 34 of 35 Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.
| |
| : 3. Does the proposed amendment involve a significant reduction in a margin of safety?
| |
| Response: No.
| |
| The proposed change adds test requirements that will assure that (1) technical specifications instrumentation Allowable Values will be limiting settings for assessing instrument channel operability and (2) will be conservatively determined so that evaluation of instrument performance history and the as-left tolerance (ALT) requirements of the calibration procedures will not have an adverse effect on equipment operability. The testing methods and acceptance criteria for systems, structures, and components, specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis including the Updated Safety Analysis Report. There is no impact to safety analysis acceptance criteria as described in the plant licensing basis because no change is made to the accident analysis assumptions.
| |
| Therefore, the proposed change does not involve a significant reduction in a margin of safety.
| |
| Based on the above, NPPD concludes that the proposed amendment to adopt TSTF-493, Revision 4, Option A presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of"no significant hazards consideration" is justified.
| |
| 4.4 Conclusion In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
| |
| | |
| ==5.0 ENVIRONMENTAL CONSIDERATION==
| |
| | |
| The proposed change would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, and would change an inspection or surveillance requirement. However, the proposed change does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.
| |
| | |
| NLS2011071 Page 35 of 35 Accordingly, the proposed change meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed change.
| |
| | |
| ==6.0 REFERENCES==
| |
| | |
| 6.1 NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991 6.2 Letter from the Technical Specifications Task Force to U.S. Nuclear Regulatory Commission, dated July 31, 2009, "Transmittal of TSTF-493, Rev. 4, 'Clarify Application of Setpoint Methodology for LSSS Functions."'
| |
| 6.3 NEDC-31336P-A, September 1996, "General Electric Instrument Setpoint Methodology."
| |
| | |
| NLS2011071 Page 1 of 59 Attachment 2 Proposed Technical Specification Revisions (Markup)
| |
| Cooper Nuclear Station, Docket No. 50-298, DPR-46 Revised Technical Specification Pages Associated With a 24-Month Fuel Cycle 3.1-22 3.3-60 3.6-24 3.1-26 3.3-62 3.6-33 3.3-5 3.3-65 3.6-37 3.3-12 3.3-68 3.6-40 3.3-18 3.4-7 3.7-5 3.3-21 3.5-5 3.7-7 3.3-24 3.5-6 3.7-10 3.3-27 3.5-10 3.7-15 3.3-30 3.5-12 3.8-7 3.3-36 3.5-13 3.8-8 3.3-38 3.6-2 3.8-9 3.3-45 3.6-14 3.8-17 3.3-50 3.6-15 3.8-18 3.3-56 3.6-19 5.0-7 3.3-59 3.6-22 5.0-11 5.0-18 Revised Technical Specification Pages Associated With TSTF-493, Revision 4, Option A 3.3-6 3.3-7 3.3-8 3.3-19 3.3-37 3.3-38 3.3-39 3.3-40 3.3-41 3.3-42 3.3-46
| |
| | |
| SLC System 3.1.7
| |
| .9 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.1.7.6 Verify each SLC subsystem manual valve in 31 days the flow path that is not-locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.
| |
| SR 3.1.7.7 Verify each pump develops a flow rate In accordance
| |
| > 38.2 gpm at a discharge pressure with the 1300 psig. Inservice Testing Program SR 3.1.7.8 Verify flow through one SLC subsystem from 1-8-.Inth-s on a pump into reactor pressure vessel. STAGGERED TEST BASIS U 2 SR 3.1.7.9 Verify all heat traced piping between 1.8. onths storage tank and pump suction is unblocked AND Once within 24 hours after solution temperature is restored within the limits of Figure 3.1.7-2 K-)
| |
| Cooper 3.1-22 Amendment No. 178
| |
| | |
| SDV Vent and Drain Valves 3.1.8 SURVEILLANCE REOUIREMENTS SURVEILLANCE REOUIREMENTS K)J SURVEILLANCE FREQUENCY SR 3.1.8.1 ------------------- NOTE --------------------
| |
| Not required to be met on vent and drain valves closed during performance of SR 3.1.8.2.
| |
| Verify each SDV vent and drain valve is 31 days open.
| |
| SR 3.1.8.2 Cycle each SDV vent and drain valve to the 92 days fully closed and fully open position.
| |
| '24 SR 3.1.8.3 Verify each SDV vent and drain valve:
| |
| : a. Closes in < 30 seconds after receipt of an actual or simulated scram signal; and U b. Opens when the actual or simulated scram signal is reset.
| |
| Cooper 3.1-26 Amendment No. 178
| |
| | |
| RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST.
| |
| I SR 3.3.1.1.12 NOTES ----------------------------
| |
| ----------------------------- 241
| |
| : 1. Neutron detectors are excluded.
| |
| : 2. For Function 1, not required to be performed when entering MODE 2 from MODE 1 until 12 hours after entering MODE 2.
| |
| Perform CHANNEL CALIBRATION. onths 24 SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST. 1-8.o~nths 24 SR 3.3.1.1.14 Verify Turbine Stop Valve - Closure and Turbine 1-8-&onnths Control Valve Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is > 29.5% RTP.
| |
| SR 3.3.1.1.15 NOTE -----------------------------
| |
| Neutron detectors are excluded. ,2-4]
| |
| Verify the RPS RESPONSE TIME is within limits.
| |
| Cooper 3.3-5 Amendment No. 231 1
| |
| | |
| SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| K>J SURVEILLANCE FREQUENCY SR 3.3.1.2.4 ---------------- NOTE -------------------
| |
| Not required to be met with less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies in the associated core quadrant.
| |
| Verify count rate is > 3.0 cps with a 12 hours during signal to noise ratio > 2:1. CORE ALTERATIONS AND 24 hours SR 3.3.1.2.5 Perform CHANNEL FUNCTIONAL TEST and 7 days determination of signal to noise ratio.
| |
| J SR 3.3.1.2.6 ------------------NOTE -------------------
| |
| Not required to be performed until 12 hours after IRMs on Range 2 or below.
| |
| Perform CHANNEL FUNCTIONAL TEST and 31 days determination of signal to noise ratio.
| |
| SR 3.3.1.2.7 -- - - NOTES --------------
| |
| : 1. Neutron detectors are excluded.
| |
| : 2. Not required to be performed until 12 hours after IRMs on Range 2 or below.
| |
| 24 Perform CHANNEL CALIBRATION. +6- o-nths K)J Cooper 3.3-]2 Amendment No. 178
| |
| | |
| Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.2.1.5 ---------------------------- NOTE ---------------
| |
| Neutron detectors are excluded.
| |
| Perform CHANNEL CALIBRATION. 184 days
| |
| ~rn SR 3.3.2.1.6 Verify the RWM is not bypassed when THERMAL 1.8.onths POWER is < 9.85% RTP.
| |
| 4-SR 3.3.2.1.7 ----------------------------- NOTE --------------
| |
| Not required to be performed until 1 hour after reactor mode switch is in the shutdown position.
| |
| 24 Perform CHANNEL FUNCTIONAL TEST. 41-8-onths SR 3.3.2.1.8 Verify control rod sequences input to the RWM are Prior to declaring in conformance with BPWS. RWM OPERABLE following loading of sequence into RWM Cooper 3.3-18 Amendment No. 231
| |
| | |
| Feedwater and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 SURVEILLANCE REQUIREMENTS
| |
| <2
| |
| -----------.----.....------------.--- NOTE -------------------------------------
| |
| When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided feedwater and main turbine high
| |
| -water level trip capability is maintained.
| |
| SURVEILLANCE FREQUENCY SR 3.3.2.2.1 Perform CHANNEL CHECK. 24 hours
| |
| ~r-SR 3.3.2.2.2 Perform CHANNEL CALIBRATION. The 1-8-ont hs Allowable Value shall be < 54.0 inches.
| |
| SR 3.3.2.2.3 Perform LOGIC SYSTEM FUNCTIONAL TEST including valve actuation.
| |
| oJ K)
| |
| Cooper 3.3-21 Amendment No. 178
| |
| | |
| PAM Instrumentation 3.3.3.]
| |
| SURVEILLANCE REQUIREMENTS K)-
| |
| SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK on each required 31 days PAM Instrumentation channel.
| |
| SR 3.3.3.1.2 Perform CHANNEL CALIBRATION of the 92 days Primary Containment H2 and 02 Analyzers.
| |
| I SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of each 18to-nths required PAM Instrumentation channel except for the Primary Containment H2 and 02 Analyzers.
| |
| -J Cooper 3.3-24 Amendment No. 178
| |
| | |
| Alternate Shutdown System 3.3.3.2 SURVEILLANCE REQUIREMENTS (continued*
| |
| K> (continuedl SURVEILLANCE FREQUENCY 24 SR 3.3.3.2.2 Verify each required control circuit and 14*.onths transfer switch is capable of performing the intended function.
| |
| 4-SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each 18 onths required instrumentation channel.
| |
| Cooper 3.3-27 Amendment No. 178
| |
| | |
| ATWS-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS
| |
| -.-------------.......--------------- NOTE -------------------------------------
| |
| When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains ATWS-RPT trip capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days F*
| |
| SR 3.3.4.1.2 Perform CHANNEL CALIBRATION. The 1.-onths Allowable Values shall be:
| |
| : a. Reactor Vessel Water Level -Low Low (Level 2): > -42 inches; and
| |
| : b. Reactor Pressure -High: < 1072 psig.
| |
| 24 SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST 8-o~nths including breaker actuation.
| |
| Ku Cooper . 3.3-30 Amendment No. 178
| |
| | |
| ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS
| |
| *----------NOTES---
| |
| : 1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry Into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Functions 3.c and 3.f; and (b) for up to 6 hours for Functions other than 3.c and 3.1 provided the associated Function or the redundant Function maintains ECCS Initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK. 12 hours SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.1.3 Perform CHANNEL CALIBRATION. 92 days
| |
| ý24 SR 3.3.5.1.4 Perform CHANNEL CALIBRATION. 48%nths 24 SR 3.3.5.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 148onths Amendrnent ?,i 33.3-36
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1.1 (page 2 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES REQUIRED REFERENCED OR OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 2. LPCI System (continued)
| |
| : b. DDywell Pressure - High 1,2.3 SR 3.3.5.1.2 < 1.84 psig SR 3.3.5.1.4 SR 3.3.5.1.5 C
| |
| : c. Reactor Pressure - Low 1.2.3 4 SR 3.3.5.1.2 > 291 psig (Injection Permissive) SR 3.3.5.1.4 and SR 3.3.5.1.5
| |
| * 436 psig 4 (2). 5 (a) SR 3.3.5.1.2
| |
| * 291 psig SR 3.3.5.1.4 and SR 3.3.5.1.5 < 436 psig C
| |
| : d. Reactor Pressure - Low 1 (c). 2 (c). SR 3.3.5.1.2 a 199 psig (Recirculalion Discharge SR 3.3.5.1.4 Valve Permissive) 3 (c) SR 3.3.5.1.5 B
| |
| : e. Reactor Vessel Shroud 1.2,3 2 SR 3.3.5.1.1 > -193.19 Level - Level 0 C SR 3.3.5.1.2 Inches SR 3.3.5.1.4 SR 3.3.5.1.5
| |
| : f. Low Pressure Coolant 1.2.3, 1 per pump SR 3.3.5.1.2 Injection Pump Start - SR 3.3.5.1.4 Time Delay Relay 4 (a) ,5 (a) SR 3.3.5.1.5 Pumps B.C
| |
| > 4.5 seconds and
| |
| < 5.5 seconds Pumps A.D
| |
| < 0.5 second (continued)
| |
| (a) When associated ECCS subsystem(s) are required lobe OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| (c) With associated recirculaion pump discharge valve open.
| |
| Cooper 3.3-38 Amendment 218
| |
| | |
| RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS K)
| |
| ------- --- -------- ------ - NOTES ------ -------
| |
| : 1. Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Function 2; and (b) for up to 6 hours for Functions I and 3 provided the associated Function maintains RCIC initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.2.3 Perform CHANNEL CALIBRATION. 92 days
| |
| -I OA SR 3.3.5.2.4 Perform CHANNEL CALIBRATION. Wonths 1*
| |
| 24 SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 144oonth s Cooper 3.3-45 Amendment No. 178
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS K)
| |
| - -------------------------- NOTES ------------------------------------
| |
| : 1. Refer to Table 3.3.6.1-I to determine which SRs apply for each Primary Containment Isolation Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains isolation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.1.] Perform CHANNEL CHECK. 12 hours SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.1.3 Perform CHANNEL CALIBRATION. 92 days 9
| |
| SR 3.3.6.1.4 -NOTE---------
| |
| For Function 2.d, radiation detectors are excluded.
| |
| 24 Perform CHANNEL CALIBRATION. 4O- onths 24 SR 3.3.6.1.5 Calibrate each radiation detector.
| |
| 1'onths SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.
| |
| Cooper 3.3-50 Amendment No. 17B
| |
| | |
| Secondary Containment Isolation Instrumentation
| |
| *3.3.6.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days O)A SR 3.3.6.2.3 Perform CHANNEL CALIBRATION. Ao nth S 24 SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL "TEST. ; o~nth s
| |
| ~~~~2 K)
| |
| Cooper 3,.3-56 Amendment No. 178
| |
| | |
| LLS Instrumentation 3.3.6.3 SURVEILLANCE REQUIREMENTS
| |
| ------------------------------------- NOTES ------------------------------------
| |
| : 1. Refer to Table 3.3.6.3-I to determine which SRs apply for each Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains LLS initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.3.1 Perform CHANNEL FUNCTIONAL TEST for 92 days portion of the channel outside primary containment.'
| |
| SR 3.3.6.3.2 ------------------NOTE--------------
| |
| Only required to be performed prior to entering MODE 2 during each scheduled outage > 72 hours when entry is made into primary containment.
| |
| U Perform CHANNEL FUNCTIONAL TEST for 92 days portions of the channel inside primary containment.
| |
| SR 3.3.6.3.3 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.3.4 Perform CHANNEL CALIBRATION. 141 onths 24 SR 3.3.6.3.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 1-8-onths KU Cooper 3.3-59 Amendment No. 178
| |
| | |
| LLS Instrumentation 3.3.6.3 TabLe 3.3.6.3-1 (page 1 of 1)
| |
| Low-Lov Set Instrumentation REQUIRED CHANNELS PER SURVEILLANCE ALLOWABLE FUNCT1ON FUNCTION REQUIREHENTS VALUE 1996.5 psig 1010 psig
| |
| : 1. Reactor Pressure -High 1 per LLS valve SR 3.3.6.3.3 : 1050 psig 835 psig SR 3.3.6.3.4 875.5 psig SR 3.3.6.3.5
| |
| : 2. Lou-Low Set Pressure Setpoints 2.per LLS valve SR 3.3.6.3.3 Low:
| |
| SR 3.3.6.3.4 Open ý5ps SR 3.3.6.3.5 < 05 s and Ctose I High:
| |
| Open 2ý10 s and < 05p4 close and ~63pl
| |
| : 3. Discharge Line Pressure Switch 1 per SRV SR 3.3.6.3.1 > 25 psig and SR 3.3.6.3.2 S55 psis 1996.5 psig SR 3.3.6.3.4 SR 3.3.6.3.5 11040 psig 835 psig 875.5 psig Cooper 3.3-60 Amendment No. ]78
| |
| | |
| CREF System Instrumentation 3.3.7.1 U_)
| |
| SURVEILLANCE REQUIREMENTS
| |
| .... .................... .... NOTES .-- -
| |
| : 1. Refer to Table 3.3.7.1-1 to determine which SRs apply for each CREF Function.
| |
| : 2. When a channel is placed in an Inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may.be delayed for up to 6 hours provided the associated Function maintains CREF initiation capability.
| |
| ...... - -o..........---.............- ............
| |
| SURVEILLANCE FREQUENCY SR 3.3.7.1.1 Perform C1HANNEL CHECK. 12 hours SR 3.3.7.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.7.1 3 Perform CHANNEL CALIBRATION. 2Z4
| |
| ,j SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. onths Cooper 3.3-62 Amendment No. 187
| |
| | |
| LOP Instrumentation 3.3.8.1
| |
| /..-, .
| |
| SURVEILLANCE REQU IREMENTS
| |
| : 1. Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function.
| |
| : 2. When a channel Is placed In an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours provided the associated Function maintains DG initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.8.1.1 Perform CHANNEL FUNCTIONAL TEST. 31 days 24 SR 3.3.8.1.2 Perform CHANNEL CALIBRATION. 1-8o~nths 24 SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST. 1-8-onth~s Amendment .,2n3_33_ 3.3-65
| |
| | |
| RPS Electric Power Monitoring 3.3.8.2 CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and DA Initiate action to fully insert Immediately associated Completion all insertable control rods Time of Condition A or B in core cells containing not met in MODE 5 with one or more fuel any control rod withdrawn assemblies.
| |
| from a core cell containing one or more fuel assemblies.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 24 SR 3.3.8.2.1 Perform CHANNEL CALIBRATION. The Allowable Uýon~tts Values shall be:
| |
| : a. Overvollage < 131 V with time delay set to
| |
| _ 3.8 seconds.
| |
| : b. Undervoltage 2. 109 V, with time delay set to
| |
| < 3.8 seconds.
| |
| : c. Underfrequency 2_57.2 Hz, with time delay set to < 3.8 seconds.
| |
| 24 SR 3.3.8.2.2 Perform a system functional test. 49t-onths Amendment 213 3.3-68
| |
| | |
| SRVs and SVs 3.4.3 SURVEILLANCE REQUIREMENTS K>
| |
| SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift setpoints In accordance of the SRVs and SVs are as follows: with the Inservice Number of Setpoint Testing Program' SRVs (Dsia) 2 1080 +/- 32.4 3 1090 +/- 32.7 3 1100 +/- 33.0 Number of Setpoint SVs (osig) 3 1240 +/- 37.2 Following testing, lift settings shall be within +/- 1%.
| |
| I-. SR 3.4.3.2 NOTE -----------------
| |
| _J Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| - F24 Verify each SRV opens when manually actuated.
| |
| Cooper 3.4-7 Amendment No. 178
| |
| | |
| ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| K>
| |
| SURVEILLANCE FREQUENCY SR 3.5.1.6 Verify the following ECCS pumps develop the In accordance specified flow rate against a system head with the corresponding to the specified reactor Inservice pressure. Testing SYSTEM HEAD Program NO. CORRESPONDING OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF Core Spray 4720 gpm 1 113 psig LPC I k 15,000 gpm 2 20 psig SR 3.5.1.7 ------------------- NOTE --------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| .9 Verify, with reactor pressure < 1020 and
| |
| > 920 psig, the HPCI pump can develop a 92 days flow rate > 4250 gpm against a system head corresponding to reactor pressure.
| |
| SR 3.5.1.8 ------------------- NOTE ------.-------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| -- 24]
| |
| Verify, with reactor pressure < 165 psig, 141 onths the HPCI pump can develop a flow rate
| |
| > 4250 gpm against a system head corresponding to reactor pressure.
| |
| (continued)
| |
| KU Cooper 3.5-5 Amendment No. 178
| |
| | |
| ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.1.9
| |
| ...... .....---- ..... NOTES-..... .....-..
| |
| : 1. For HPCJ only, not required lo be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| : 2. Vessel Injection/spray may be excluded.
| |
| Verify each ECCS injection/spray subsystem ont24 actuates on an actual or simulated automatic initiation signal.
| |
| onths SR 3.5.1.10 Valve actuation may be excluded.
| |
| Verify the ADS actuates on an actual or simulated automatic initiation signal.
| |
| +
| |
| 24 SR 3.5.1.11 Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify each ADS valve opens when manually 48'onths actuated.
| |
| Amendment 2a.U 3,5-6 2._-
| |
| | |
| ECCS - Shutdown 3.5.2
| |
| ' SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY
| |
| -- -i-ý SR 3.5.2.4 Verify each required ECCS pump develops (he specified In accordance flow rate against a system head corresponding to the with the specified reactor pressure, Inservice SYSTEM HEAD Testing NO. CORRESPONDING Program OF TO A REACTOR SYSTEM FLOW RATE PUME.S PRESSURE OF CS _4720 gpm 1 _113 psig LPCI > 7700 gpm > 20 psig
| |
| +
| |
| SR 3.5.2.5 Vessel Injection/spray may be excluded.
| |
| I24 Verify each required ECCS injection/spray subsystem 4 o-nt-hs actuates on an actual or simulated automatic Initiation signal.
| |
| Amendment 213 3.5-10
| |
| | |
| RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System piping is filled 31 days with water from the pump discharge valve to the injection valve.
| |
| SR 3.5.3.2 Verify each RCIC System manual, power 31 days operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| SR 3.5.3.3 ----------------- NOTE ---------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| J Verify, with reactor pressure _<1020 psig and > 920 psig, the RCIC pump can develop a 92 days flow rate > 400 gpm against a system head corresponding to reactor pressure.
| |
| SR 3.5.3.4 -------------------- NOTE --------------------
| |
| Not required to be performed until 12 hours after reactor steam-pressure and flow are adequate to perform the test.
| |
| 24 Verify, with reactor pressure < 165 psig, Mli-n oths the RCIC pump can develop a flow rate
| |
| > 400 gpm against a system head corresponding to reactor pressure.
| |
| (continued)
| |
| Cooper 3.5-12 Amendment No. 178
| |
| | |
| RCIC System 3.5.3 SURVEILLANCE REOUIREMENTS (continued)
| |
| K>/
| |
| SURVEILLANCE FREQUENCY
| |
| .1--
| |
| SR 3.5.3.5 -----..............-
| |
| NOTES -------------------
| |
| : 1. Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| : 2. Vessel injection may be excluded.
| |
| -F24]
| |
| Verify the RCIC System actuates on an 1A-&inths actual or simulated automatic initiation signal.
| |
| U Cooper 3.5-13 Amendment No. 178
| |
| | |
| Primary Containment 3.6.1:1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.1.1 Perform required visual examinations and leakage In accordance rate testing except for primary containment air lack with the Primary testing, In accordance with the Primary Containment Containment Leakage Rate Testing Program. Leakage Rate Testing Program 24 SR 3.6.1.1.2 Verify drywell to suppression chamber bypass 4 o-nths leakage is equivalent to a hole < 1.0 inch In diameter, AND
| |
| ......NOTE-....-
| |
| Only required after Iwo consecutive lests
| |
| .°. . fall and continues until two consecutive tests pass 9 months Amendment 213 33.6-2
| |
| | |
| PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.6.1.3.6 Verify the isolation time of each MSIV is In accordance
| |
| > 3 seconds and < 5 seconds. with the Inservice testing Program I'~A I SR 3.6.1.3.7 Verify each automatic PCIV actuates to the "onth s isolation position on an actual or simulated isolation signal.
| |
| 24 SR 3.6.1.3.8 Verify a representative sample of reactor 448 onths instrumentation line EFCVs actuate to the isolation position on an actual or simulated instrument line break.
| |
| 24 SR 3.6.1.3.9 Remove and test the explosive squib from each 4-4 onths on a shear isolation valve of the TIP System. STAGGERED TEST BASIS SR 3.6.1.3.10 Verify leakage rate through each Main Steam line In accordance is < 106 scfh when tested at > 29 psig. with the Primary Containment Leakage Rate Testing Program (continued)
| |
| Cooper 3.6-14 Amendment No. 234
| |
| | |
| PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY 24 SR 3.6.1.3.11 Verify each inboard 24 inch primary containment 4-8-onths' purge and vent valve is blocked to restrict the maximum valve opening angle to 60'.
| |
| SR 3.6.1.3.12 Verify leakage rate through the Main Steam In accordance Pathway is < 212 scfh when tested at ?_29 psig. with the Primary Containment Leakage Rate Testing Program Cooper 3.6-15 Amendment No. 234
| |
| | |
| LLS Valves 3.6.1.6 SURVEILLANCE REQUIREMENTS K)j SURVEILLANCE FREQUENCY SR 3.6.1.6.1 ------------------ NOTE-------------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| 24 Verify each LLS valve opens when manually 141o-onth s actuated.
| |
| SR 3.6.1.6.2 NOTE----------------
| |
| Valve actuation may be excluded.
| |
| 24 Verify the LLS System actuates on an 14-onths actual or simulated automatic initiation signal.
| |
| J2 Cooper 3.6-19 Amendment No. 178
| |
| | |
| Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7
| |
| -A-..
| |
| SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY 24 SR 3.6.1.7.3 Verify the full open setpoint of each ý o~n ths vacuum breaker is < 0.5 psid.
| |
| J Cooper 3.6-22 Amendment No. 178
| |
| | |
| Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.8.1 ------------------NOTE -------------------
| |
| Not required to be met for vacuum breakers that are open during Surveillances.
| |
| Verify each vacuum breaker is closed. 14 days K)d SR 3.6.1.8.2 Perform a functional test of each 31 days required vacuum breaker.
| |
| ýýý24 SR 3.6.1.8.3 Verify the opening setpoint of each 1--nths required vacuum breaker is < 0.5 psid.
| |
| Uj Cooper 3.6-24 Amendment No. 178
| |
| | |
| Secondary Containment 3.6.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2 Initiate action to suspend OPDRVs.
| |
| Immediately I SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1.1 Verify secondary containment vacuum is. 24 hours
| |
| > 0.25 Inch of vacuum water gauge.
| |
| SR 3.6.4.1.2 Verify all secondary containment equipment 31 days hatches are closed and sealed.
| |
| SR 3.6.4.1.3 Verify one secondary containment access door in 31 days each access opening Is closed.
| |
| hA I SR 3.6.4.1.4 Verify each SGT subsystem can maintain W&o-nths on a
| |
| > 0.25 Inch of vacuum water gauge In the STAGGERED secondary containment for 1 hour at a flow rate TEST BASIS
| |
| < 1780 dm.
| |
| Cooper 3.6-33 Amendment 22
| |
| | |
| SCIVs 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1
| |
| : 1. Valves and blind flanges in high radiation areas maybe verified by use of administrative means.
| |
| : 2. Not required to be met for SCIVs that are open under administrative controls.
| |
| 31 days Verify each secondary containment isolation manual valve and blind flange that Is not looked, sealed, or otherwise secured and is required to be closed during accident conditions Is closed.
| |
| I SR 3.6.4.2.2 Verify the isolation time of each power operated In accordance automatic SCIV is within limits, with the Inservice Testing Program
| |
| ~rn SR 3.6.4.2.3 Verify each automatic SCIV actuates to the Wt&o-nt hs Isolation position on an actual or simulated actuation signal.
| |
| Cooper 3.6-37 Amendment No. 1.80.U 202
| |
| | |
| SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.2 Initiate action to Immediately suspend OPDRVs.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for_> 10 continuous 31 days hours with heaters operating.
| |
| SR 3.6.4.3.2 Perform required SGT filter testing In accordance In accordance with the Ventilation Filter Testing Program (VFTP). with the VFTP SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual 4-.o =....-
| |
| or simulated Initiation signal.
| |
| ~rn SR 3.6.4.3.4 Verify the SGT units cross tie damper Is in the 48.*o-nths correct position, and each SGT room air supply check valve and SGT dilution air shutoff valve can be opened.
| |
| Amendment 222 3.6-40
| |
| | |
| SW System and UHS 3.7.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| K2 SURVEILLANCE FREQUENCY 1-SR 3.7.2.3 ------------------- NOTE --------------------
| |
| Isolation of flow to individual components does not render SW System inoperable.
| |
| Verify each SW subsystem manual, power 31 days operated, and automatic valve in the flow paths servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| SR 3.7.2.4 Verify each SW subsystem actuates on an 19-;o :nthhs actual or simulated initiation signal.
| |
| ~~2 A7~2 Cooper 3.7-5 Amendment No. 178
| |
| | |
| REC System 3.7.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1
| |
| : 1. SR 3.0.1 is not applicable when both Service Water backup subsystems are OPERABLE.
| |
| : 2. REC system leakage beyond limits by Itself Is only a degradation of the REC system and does not result In the REC system being Inoperable.
| |
| Verify the REC system leakage Is within limits. 24 hours SR 3.7.3.2 Verity the temperature of the REC supply water is 24 hours
| |
| < 100*F.
| |
| SR 3.7.3.3 ---------........---.
| |
| Isolation of flow to Individual components does not render REC System inoperable.
| |
| Verify each REC subsystem manual, power 31 days operated, and automatic valve in the flow paths servicing safety related cooling loads, that is not locked, sealed, or otherwise secured in position, Is In the correct position.
| |
| SR 3.7.3.4 Verity each REC subsystem actuates on an ; ths actual or simulated initiation signal.
| |
| Cooper 3.7-7 Amendment No. 232
| |
| | |
| CREF System 3.7.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.4.1 Operate the CREF System for> 15 minutes. 31 days SR 3.7.4.2 Perform required CREF filter testing in accordance In accordance with the Ventilation Filter Testing Program (VFTP). with the VFTP.
| |
| SR 3.7.4.3 Verify the CREF System actuates on an actual or 1.8.onths simulated initiation signal.
| |
| SR 3.7.4.4 Perform required CRE unfiltered air inleakage testing In accordance in accordance with the Control Room Envelope with the Control Habitability Program. Room Envelope Habitability Program Cooper 3.7-10 Amendment No. 230
| |
| | |
| Main Turbine Bypass System 3.7.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify operation of each main turbine 31 days bypass valve.
| |
| F*
| |
| SR 3.7.7.2 Perform a system functional test. 48*o-nths SR 3.7.7.3 Verify the TURBINE BYPASS SYSTEM RESPONSE 14;oonth s TIME is within limits.
| |
| 7)
| |
| Cooper 3.7-15 Amendment No. 178
| |
| | |
| AC Sources-Operating 3.8.1 w)_ SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.7 -------------------NOTE ---------------
| |
| All DG starts may be preceded by an engine prelube period.
| |
| Verify each DG starts from standby 184 days condition and achieves, in < 14 seconds, voltage ; 3950 V and.frequency z 58.8 Hz, and after steady state conditions are reached, maintains voltage t 3950 V and
| |
| * 4400 V and frequency ý 58.8 Hz and 561.2 Hz.
| |
| SR 3.8.1.8 NOTE -------------------
| |
| This Surveillance shall not be performed in MODE I or 2. However, credit may be taken for unplanned events that satisfy this SR.
| |
| -2_4_
| |
| J~ Verify automatic and manual transfer 1-& o t-h s of unit power supply from the normal offsite circuit to the alternate offsite circuit.
| |
| (continued)
| |
| Cooper 3.8-7 Amendment No. 178
| |
| | |
| AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.9
| |
| : 1. Momentary transients outside the load and power factor ranges do not Invalidate this test.
| |
| : 2. This Surveillance shall not be performed In MODE I or 2. However, credit may be taken for unplanned events that satisfy this SR.
| |
| : 3. If performed with DG synchronized with offsite power, the surveillance shall be performed at a power factor < 0.89. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.
| |
| 24 Verify each DG operates for > 8 hours: 1~--onths 11
| |
| : a. For > 2 hours loaded > 4200 kW and < 4400 kW; and
| |
| : b. For the remaining hours of the test loaded >
| |
| 3600 kW and < 4000 kW.
| |
| SR 3.8.1.10 --------
| |
| NOTES This Surveillance shall not be performed in MODE 1, 2 or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| 24 Verify interval between each sequenced load is within 4tonths
| |
| + 10% of nominal timer setpoint.
| |
| (continued)
| |
| Cooper 3.8-8 Amendment No. 237
| |
| | |
| AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.11 - NOTES--------------
| |
| : 1. All DG starts may be preceded by an engine prelube period.
| |
| : 2. This Surveillance shall not be performed in MODE 1, 2, or 3.
| |
| However, credit may be taken for unplanned events that satisfy this SR.
| |
| 24 Verify, on an actual or simulated loss of 1 onths offslte power signal in conjunction with an actual or simulated ECCS initiation signal:
| |
| : a. De-energization of emergency buses;
| |
| : b. Load shedding from emergency buses; and
| |
| : c. DG auto-starts from standby condition and:
| |
| _) 1. energizes permanently connected loads in
| |
| * 14 seconds,
| |
| : 2. energizes auto-connected emergency loads through the timed logic sequence,
| |
| : 3. maintains steady state voltage
| |
| : 3950 V and : 4400 V,
| |
| : 4. maintains steady state frequency a 58.8 Hz and : 61.2 Hz, and
| |
| : 5. supplies permanently connected and auto-connected emergency loads for k 5 minutes.
| |
| K>
| |
| Cooper 3.8-9 Amendment No. 178
| |
| | |
| DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage on floal charge Is: 7 days
| |
| : a. > 125 V for the 125 V batteries; and
| |
| : b. _ 250 V for the 250 V batteries.
| |
| SR 3.8.4.2 Verify no visible corrosion at battery terminals and 92 days connectors.
| |
| OR Verify battery connection resistance meets the limits specified In Table 3.8.4-1. I SR 3.8.4.3 Verify battery cells, cael plates, and racks show no 18 months visual Indication of physical damage or abnormal deterioration that degrades battery performance.
| |
| SR 3.8.4.4 Remove visible corrosion and verify battery cell to 18 months cell and terminal connections are coated with anti-corrosion material.
| |
| SR 3.8.4.5 Verify battery connection resistance meets the limits 18 months specified In Table 3.8.4-1.
| |
| 24 SR 3.8.4.6 Verify: 18- onths
| |
| : a. Each required 125 V battery charger supplies >
| |
| 200 amps at _:125 V for > 4 hours; and
| |
| : b. Each required 250 V battery charger supplies >
| |
| 200 amps at > 250 V for > 4 hours.
| |
| (continued)
| |
| Cooper D.8-17 Amendment No. 236
| |
| | |
| 1-11, DC Sources"- Operating 3.8.4 SURVEILLANCE REQUIREMENTS (cbntinued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.4.7 -NOTES--
| |
| : 1. The modified performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test in SR 3.8.4.7 once per 60.months.
| |
| : 2. This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| 24 Verify battery capacity Is adequate to supply, and 44-t.onths maintain In OPERABLE status; the required emergency loads for the design duty cycle when subjected to a battery service test.
| |
| SR 3.8.4.;8 This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit maybe taken for unplanned events that satisfy this SR.
| |
| Verify battery capacity Is > 90% of the manufacturer's 60 months rating when subjected to a performance discharge test or a modified performance discharge test. AND 18 months when battery shows degradation or has reached 85%
| |
| of expected life with capacity
| |
| < 100% of manufacturer's rating 24 months when battery has reached 85% of the expected life with capacity
| |
| >_100% of manufacturer's
| |
| -rating Coopr 38-18Amedmen No 23 Cooper 3.8-18 Amendment No. 236
| |
| | |
| Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.1 Offsite Dose Assessment Manual (ODAM) (continued) markings in the margin of the affected pages, clearly indicatinv the area of the page that was changed, and shall indicate the date (i.e., month and year) the change was implemented.
| |
| 5.5.2 Systems IntegrityMonitoring Program This program provides controls to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to levels as low as practicable. The systems include the Core Spray, High Pressure Coolant Injection, Residual Heat Removal, and Reactor Core Isolation Cooling. The program shall include the following:
| |
| : a. Preventive maintenance and periodic visual inspection requirements; and r-, b. Integrated leak test requirements for each system at 19 month intervals or less.
| |
| The provisions of SR 3.0.2 and SR 3.0.3 are applicable at the 0 --- *M&month Frequency for performing system leak test activities.
| |
| 5.5.3 Post Accident Sampling This program provides controls that ensure the capability to obtain and analyze reactor coolant, radioactive gases, and particulates in plant gaseous effluents and containment atmosphere samples under accident conditions. The program shall include the following:
| |
| : a. Training of personnel;
| |
| : b. Procedures for sampling and analysis; and
| |
| : c. Provisions for maintenance of sampling and analysis equipment.
| |
| (continued)
| |
| Cooper 5.0-7 Amendment No. 178
| |
| | |
| Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.7 Ventilation Filter Testing Program (VFTP)
| |
| The VFTP shall establish the required testing of Engineered Safety Feature (ESF) filter 24lation systems. Tests described in Specifications 5.5.7.a, 5.5.7.b, and 5.5.7.c shall be performed once p S-&
| |
| months for standby service or after 720 hours of system operation; and, following significant painting, fire, or chemical release concurrent with system operation in any ventilation zone communicating with the system.
| |
| Tests described in Specifications 5.5.7.a and 5.5.7.b shall be performed after each complete or partial replacement of the HEPA filter train or charcoal adsorber filter; and after any structural maintenance on the system housing.
| |
| Tests described in Specifications 5.5.7.d and 5.5.7.e shall be performed once per
| |
| ---- * & months.
| |
| The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.
| |
| : a. Demonstrate for each of the ESF systems that an inplace test of the HEPA fitters shows a penetration and system bypass < 1% when tested in accordance with Regulatory Guide 1.52, Revision 2, Section C.5.c, and ASME N510-1989 at the system conditions specified below.
| |
| ESF Ventilation System Flowrate (cfm)
| |
| SGT System 1602 to 1958 Control Room Emergency 810 to 990 Filter System
| |
| : b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass < 1% when tested in accordance with Regulatory Guide 1.52, Revision 2, Section C.5.d, and ASME N510-1989 at the system conditions specified below.
| |
| ESF Ventilation System Flowrate (cfm' SGT System 1602 to 1958 Control Room Emergency 810 to 990 Filter System (continued)
| |
| Cooper 5.0-11 Amendment 228 1
| |
| | |
| Programs and Manuals 5.5 5.5 Programs and Manuals
| |
| .,3 Control Room Envelope Habitability Program (continued) personnel receiving radiation exposures in excess of either (a) 5 rem whole body or its equivalent to any part of the body for the duration of the loss-of-coolant accident, or (b) 5 rem total effective dose equivalent (TEDE) for the duration of the fuel handling
| |
| .iccident. The program shall include the following elements:
| |
| : a. The definition of the CRE and CRE boundary.
| |
| : b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.
| |
| C. Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C,2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors,"
| |
| Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0. No exceptions to Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0, are proposed.
| |
| : d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by the CREF System, operating at the flow rate required by the Ventilation Filter Testing Program, at a Frequency of 44*onthS. The results shall be trended and used as part of the periodic assessment of the CRE boundary.
| |
| : e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.
| |
| : f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered air inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.
| |
| 5.0-18 Amendment No. 230 Cooper
| |
| | |
| INSERTS
| |
| <INSERT 1>
| |
| If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| <INSERT 2>
| |
| The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 1 of 3)
| |
| /I-- Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 1. Intermediate Range Monitors
| |
| : a. Neutron 2 3 SR 3.3.1.1.1 < 121/125 Flux - High SR 3.3.1.1.3 divisions of full SR 3.3.1.1.4 scale SR 3.3.1.1.5 SR 3.3.1.1.6 SR 3.3.1.1.121 ()b SR 3.3.1.1.13 SR 3.3.1.1.15 3 H SR 3.3.1.1.1 < 121/125 SR 3.3.1.1.3 divisions of full SR 3.3.1.1.4 scale SR 3.3.1.1.12C+ ()b SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : b. Inop 2 3 G SR 3.3.1.1.3 NA SR 3.3.1.1.4 SR 3.3.1.1.13 3 H SR 3.3.1.1.3 NA SR 3.3.1.1.4 SR 3.3,1.1.13
| |
| : 2. Average Power Range Monitors a, Neutron 2 2 G SR 3.3.1.1.1
| |
| * 14.5% RTP Flux - High SR 3.3.1.1.3 (Startup) SR 3.3.1.1.4 SR 3.3.1.1.6 SR 3.3.1.1.8 SR 3.3.1.1.10<cZA;ý SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : b. Neutron 1 2 F SR 3.3..1.1 < 0.75 W Flux-High SR 3.3.1.1.2 +62.0%
| |
| (Flow Biased) SR 3.3.1.1.4 RTP*b)
| |
| SR 3.3.1.1.7 SR 3.3.1.1.8 SR 3.3.1.1.9 (a) <INSERT 1> SR 3.3.1.1.12 , ab (b) <INSERT 2> SR 3.3.1.1.13 SR 3.3.1.1.15 (continued)
| |
| (c) ~ .(a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.
| |
| .)4b) 10.75 W + 62.0% - 0.75 AW] RTP when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating."
| |
| (e) itthe as taund aStPOcin is OutSIdo its nradclnod as tOUnd1 toloranGo. then the channel shall be evaluated to verily tnat it is funtRionin as required_ before returingFO the channel to es.ice
| |
| == I Jb L d__ dLLd AI*
| |
| (d) The ;nsirurnsrm cranne! aipalrnt sarch ne reosetct a value that s wthnn tnh sin caac arouno mnn rNmina iTrip ý-epoini (NTlSP) at the ,cmpletlonof the..... rillanc;i
| |
| . .hai..iss the chan el shall he de-lared inoperable. q3tointp s more edar..atlvo than- the NoTS-P amiaccoptablo proeided that the 2s-found n -retto anetapply to the actual seloint Wplomcrntad in the Survaitlanac procadurGAc tA_ conf0irm_ý_
| |
| tha channel pedoFrmance. The NTSP1 and-the methodologisusdt dsts.FrmirA the asfWound and as lef . tolerFanAs
| |
| .. . . . . . . re.. . cocAifloAd
| |
| . .. . In station procedures v imolaemntina the GE= Setpoont Methodoloqy Per NEUC 31336P A approved in IS Amondment 178 SEN, Section Miti" Cooper 3.3-6 Amendment No. 231 I
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)
| |
| Reactor Protecticon System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REOUIRED SURVEILLANCE ALLOWJABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 2. Average Power Range Monitors (continued)
| |
| : c. Neutron Flux--High 1 2 F SR 3.3.1.1.1 < 120.0% RIP (Fixed) SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.104-EaE)(b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : d. Downscale 1 2 F SR 3.3.1.1.4 > 3.0%RTP SR 3.3.1.1.8 SR 3.3.1.1.9*-*4aI(j.
| |
| SR 3.3.1.1.13
| |
| : e. Inop 1.2 2 G SR 3.3.1.1.4 'NA SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.13
| |
| : 3. Reactor Vessel 1,2 2 G SR 3.3.1.1.4 < 1050 psig Pressure -High SR 3.3.1.1.9 SR 3.3.1.1.124-- ýaE(b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 4. Reactor Vessel Vater 1,2 2 G SR 3.3.1.1.1 > 3 inches Level -Low (Level 3) SR 3.3.1.1.4 SR 3.3.1.1.9 SR 3.3.1.1.121 SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 5. Main Steam IsoLation 1 4 F SR 3.3.1.1.4 < 10% cLosed Valve -Cloture SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 6. Drywell Pressure -High 1,2 2 G SR 3.3.1.1.4 < 1.84 psig SR 3.3.1.1.9 SR 3.3.1.1.12*-9H SR 3.3.1.1.13 SR 3.3.1.1.15 (continued)
| |
| (a) <INSERT 1>
| |
| (b)<ISERT2 >
| |
| KJ Cooper 3.3-7 Amendment No. 178
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 3 of 3)
| |
| Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 7. Scram Discharge Volume Water Level - High
| |
| : a. Level Transmitter 1,2 2 G SR 3.3.1.1.4 < 90 Inches SR 3.3.1.1.9 _ _
| |
| SR 3.3.1.1.1 (
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15 2 H SR 3.3.1.1.4 < 90 Inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : b. Level Switch 1,2 2 G SR 3.3.1.1.4 < 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15 2 H SR 3.3.1.1.4 <90 inches SR 3.3.1.1.9 SR 3.3,1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 8. Turbine Stop > 29.5% RTP 2 E SR 3.3.1.1.4 < 10% closed Valve - Closure SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15
| |
| : 9. Turbine Control Valve > 29.5% RTP 2 E SR 3.3.1.1.4 > 1018 psig Fast Closure, DEH Trip SR 3.3.1.1.9 _
| |
| Oil Pressure - Low SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15
| |
| : 10. Reactor Mode 1,2 G SR 3.3.1.1,11 NA Switch - Shutdown SR 3.3.1.1.13 Position H SR 3.3,1.1.11 NA SR 3.3.1.1.13
| |
| : 11. ManualScram 1,2 1 G SR 3.3.1.1.9 NA SR 3.3.1.1.13 (a) INSERT 11 H SR 3.3.1.1.9 NA (b) <INSERT 2> SR 3.3.1.1.13 (a ) With any control rod withdrawn from a core cell containing one or more fuel assemblies.
| |
| Cooper 3.3-8 Amendment No. 231
| |
| | |
| Control Rod Block Instrumentation 3.3.2.1 Table 3.3.2.1-1 (page 1 of 1)
| |
| Control Rod Block Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS REQUIREMENTS VALUE
| |
| : 1. Rod Block Monitor
| |
| : a. Low Power Range - Upscale (a) 2 SR 3.3.2.1.1 (h-)4-4 SR 3.3.2.1.4 _,_
| |
| SR 3.3.2.1.5'4 (b)()
| |
| b, Intermediate Power Range - Upscale (W)i (d 2 SR 3.3.2.1.1 N-), H SR 3.3.2.1.44 SR 3.3.2.1.5 -bE D
| |
| : c. High Power Range - Upscale 2 SR 3.3.2.1.1 SR 3.3.2.14 SR 3.3.2.1.4 (c
| |
| : d. Inop 2 SR 3.3.2.1.1 NA
| |
| : e. Downscale M4,0-ff5-J]2 SR 3.3.2.1.1 > 92/125 SR 3.3.2.1.5 divisions of full scale
| |
| : 2. Rod Worth Minimizer SR 3.3.2.1.2 NA SR 3.3.2.1.3 SR 3.3.2.1.6 SR 3.3.2.1.8
| |
| : 3. Reactor Mode Switch - Shutdown Position (g.4.-'[J 2 SR 3.3.2.1.7 NA (b) <INSERT1>
| |
| (c) <INSERT 2>[
| |
| * (a) THERMAL POWER > 27.5% and - 62.5% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| (d ) THERMAL POWER > 62.5% and < 82.5% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| e)(r) THERMAL POWER > 82.5% and < 90% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| (---* (d) THERMAL POWER > 90% RTP and MCPR < 1.40 and no peripheral control rod selected.
| |
| (g--*(e) THERMAL POWER > 27.5% and < 90% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| -(h)- (-) With THERMAL POWER < 9.85% RTP.
| |
| (I)- (g-) Reactor mode switch in the shutdown position.
| |
| ~h-) Less than or equal to the Allowable Value specified in the COLR.
| |
| Cooper 3.3-19 Amendment No. 231
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page I of 6)
| |
| Emergency Core Cooling Syslem Instrumentatlon APPLICABLE CONDITIONS MODES REQUIRED REFERENCED OR OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 1. Core Spray System
| |
| : a. Reactor Vessel Water 1,2.3. 4 (b) 0 SR 33.5.1.1 > -113 inches Level - Low Low Low SR 3.3.5.12 (Level 1) 4(a). 5(a) SR 3.3.5.1.24--F SR 3.3.5.1,5
| |
| : b. Drywell Pressure- High 1.2,3 4 (b) 8 SR 3.3.5.1.2 < 1.84 psig SR 3.3.5.1.4.4-SR 3.3.5.1.5 EE
| |
| : c. Reactor Pressure- Low 1,2,3 4 C SR 3.3.5.1.2 > 291 psig (Injection Permissive) " SR 3.3.5.1.4 and SR 3.3.5.1.5 < 436 psig 4(a), 5(a) SR 3.3.5.1.2 > 291 psig SR 3.3.5.1.4 and SR 3.3.5.1.5 < 436 psig
| |
| : d. Core Spray Pump 1.2,3. 1 per pump E SR 3.3.5.1.2 '1370 gpm Discharge Flow- Low SR 3.3.5.1.44 (Bypas) 4 (a), 5 (a) SR 3.3.5.1.5 (c)(d)
| |
| : e. Care Spray Pump 1,2,3, 1 per pump C SR 3.3.5.1.2 > 9 seconds Start-Time Delay Relay SR 3.3.5.1.4 and 4 (a) 5 (a) SR 3.3.5.1.5 11 seconds
| |
| : 2. Low Pressure Coolant Injection ILPCI) System
| |
| : a. Reactor Vessel Water 1.2,3. 4 SR 3.3.5.1.1 .>-113 Inches Level - Low Low Low SR 3.3.5.1.2 (Level 1) 4 (a), 5 (a) SR 3.3.5.1,:.* C)(d)
| |
| SR 3.3.5.1.5 (conlinued)
| |
| (a) When associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| (b) Also required to Initiate (he associated diesel generator (DG).
| |
| (c) <INSERT 1>
| |
| (d) <INSERT 2>]
| |
| Coope~r 3.3-37 Amendment 218
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1.1 (page 2 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES REQUIRED REFERENCED OR OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE 2, LPCI System (continued)
| |
| : b. Drywell Pressure - High 1.2.3 4 a SR 3.3.5.1.2- < 1.84 psig SR 3.3.5.1.4 - "
| |
| SR 3.3.5.1.5
| |
| : c. Reactor Pressure - Low 1.2.3 4 C SR 3.3.5.1.2 >291 psig (Injection Permissive) SR 3.3.5.1.4 and SR 3.3.5.1.5 < 436 pslg 4(3), 5 (a) 4 B SR 3.3.5.1.2 > 291 pslg SR 3.3.5.1.4 and SR 3.3.5.1.5 _436 psig
| |
| : d. Reactor Pressure - Low 14.2 4 C SR 3.3.5.1.2 _ 199 psig (Recirculation Discharge SR 3.3.5.1.4 and Valve Permissive) SR 3.3.5.1.5 <221 psig
| |
| : e. Reactor Vessel Shroud 1.2.3 2 B SR 3.3.5.1.1 >-193.19 Level - Level 0 SR 3.3.5.1.2 Inches SR 3.3.5.1.4 SR 3.3.5.1.5
| |
| : f. Low Pressure Coolant 1.2,3. 1 per pump C SR 3.3.5.1.2 Injection Pump Start - SR 3.3.5.1.4 Time Delay Relay 4 (a). 5(a) SR 3.3.5.1.5 Pumps B.C
| |
| > 4.5 seconds and
| |
| '5.5 seconds Pumps A.0 (c) <INSERT 1> 0.5 second (d) <INSERT 2> (continued) 4 a) When associated ECCS subsystem(s) are required lobe OPERABLE per LCO 3.5.2. ECCS - Shuldown. I With associated recirculation pump discharge valve open.
| |
| Cooper 3.3-38 Amendment 218
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 6)
| |
| Emergency Core Cooling System Instrumenlation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 2. LPCI System (continued)
| |
| : g. Low Pressure 1,2.3, 1 per E SR 3.3.5.1.2 > 2107 9pm Coolant Injection Pump subsystem SR 3.3.5.1.4 -
| |
| Discharge Flow- Low 4 (a), 5 (a)
| |
| SR 3.3.5.1.5 (Bypass)
| |
| : 3. High Pressure Coolant Injection (HPCI) System
| |
| : a. Reactor Vessel Water 1. 4 SR 3.3.5.1.1 >-42inches Level - Low Low SR 3.3.5.1.2 (Level 2) 2 SR 3.3.5.1. 4 SR 3.3.5.1.5 1
| |
| : b. Drywell Pressure - High 4 B SR 3.3.5.1.2 < 1.84 psig SR 3.3.5.1.4 2 SR 3.3.5.1.5 c, Reactor Vessel Water Level - High (Level 8) b3 1 2 C SR 3.3.5.1.1 < 54 Inches SR 3.3.5.1.2 2N , SR 3.3.5.1.4 SR 3.3.5.1.5 d, Emergency Condensate 1 .' 'J) 2 D SR 3.3.5.1.2 23 inches Storage Tank (ECST) (* SR 3.3.5.1.3 Level - Low 2 SR 3.3.5.1.5
| |
| : e. Level - High Pool Water Suppression ~ 1 d)Ld 2 D SR 3.3.5.1.2 SR 3.3.5.1.4
| |
| < 4 Inches 2 ,3 SR 3.3.5.1.5 (c) <INSERT 1>
| |
| (d) <INSERT 2> (continued)
| |
| (a) When the associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| E With reactor steam dome pressure > 150 psIg.
| |
| Cooper 3.3-39 Amendment 218
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 4 of 6)
| |
| K> Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS M4DOES OR REQUIRED REFERENCED OTHER CHANNELS FROM4 SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 3. HPCI System (continued)
| |
| : f. High Pressure Coolant 1.A=I 1 E SR 3.3.5.1.2 > 490 gpn Injection Pump SR 3.3.5.1.4 Discharge Flowu-Low SR 3.3.5.1.5 (Bypass)
| |
| : 4. Automatic Depressurization System (ADS) Trip System A
| |
| : a. Reactor Level--LowVessel Low Water Low 2 SR SA 3.3.5.1.1 3.3.5 1.2 > -113 Tnches (Level 1) 2 SR SR 3.3.5.1.4 3.3.5.1.5 4
| |
| : b. Automatic - 1 SR 3.3.5.1.2 _ 109 seconds Depressurization 2 SR 3.3.5.1.4 System Initiation SR 3.3.5.1.5 Timer (
| |
| C. Reactor Vessel Water 1I1 F SR 3.3.5.1.1 > 3 inches Level -Lou (Level 3) SR 3.3.5.1.2 (Confirmatory) 2W, 3(X SR 3.3.5.1.4 SR 3.3.5.1.5
| |
| : d. Core Spray Pump 1, 1"--2 G SR 3.3.5.1.2 > 108 psig Discharge 2 - r- SR 3.3.5.1.4 Cnd Pressure -High 2 , 3 SR 3.3.5.1.5 < 160 psig (c)<INSERT iI SERT 2>
| |
| 1 (continued) 4414with reactor steam dome pressure > 150 psig.
| |
| K)J Cooper 3.3-40 Amendment No. 178
| |
| | |
| ECCS Instrumentati on 3.3.5.1 Table 3.3.5.1-1 (page 5 of 6)
| |
| -_J Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 4. ADS Trip System A (continued)
| |
| ,. Low Pressure Coolant G,1' SR 3.3.5.1.2 > 108 psig injection Pump - SR 3.3.5.1.4 and Discharge 3 SR 3.3.5.1.5 _ 160 psig Pressure -High
| |
| : 5. ADS Trip System B
| |
| : a. Reactor vessel Vater L-,31 2(. FJ SR 3.3.5.1.1 >_-113 Inches Level -Low Low Low SR 3.3.5.1.2 (Level 1) SR 3.3.5.1.4 M SR 3.3.5.1.5 I(c)(d)
| |
| : b. Automatic 1,*.I- I G SR 3.3.5.1.2 _ 109 seconds Depressurization SR 3.3.5.1.4 System Initiation k SR 3.3.5.1.5 Timer M 4:. Reactor Vessel Water It F SR 3.3.5.1.1 > 3 inches Level -Low, Level 3 SR 3.3.5.1.2 (Confirmatory) 3C) SR 3.3.5.1.44 SR 3.3.5.1.5 I(c)(d)
| |
| : d. Core Spray Pump 2 G SR 3.3.5.1.2 > 108 psig Discharge I Ad SR 3.3.5.1.4 and Pressure--High Z SR 3.3.5.1.5 < 160 psig (c) <INSERT 1>
| |
| (d) <INSERT 2>
| |
| .tth reactor steam dome pressure > 150 psig.
| |
| wdi)
| |
| Cooper 3.3-41 Amendment No. 178
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 6 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 5. ADS Trip System 9 (continued)
| |
| : e. Low Pressure Coolant 4 G SR 3.3.5.1.2 1¶08 psig InjectionPump SR 3.3.5.1.4 ;nd Discharge SR 3.3.5.1.5 1 160 psig Pressure -High
| |
| (-d4 Vith reactor steam dome pressure > 150 psig.
| |
| K)
| |
| Cooper 3.3-42 Amendment No. 178
| |
| | |
| RCIC System Instrumentation 3.3.5.2 Table 3.3.5.2-1 (page 1 of 1)
| |
| Reactor Core Isolation Cooling System instrumentation CONDITIONS REQUIRED REFERENCED CHANNELS FROM REQUIRED SURVEILLANCE ALLOUABLE FUNCTION PER FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 1. Reactor Vessel Water 4 B SR 3.3.5.2.1 > -42 inches Level -Low Low (Level 2) SR 3.3.5.2.2 SR 3.3.5.2.4 10- - I SR 3.3.5.2.5I
| |
| : 2. Reactor Vessel Water 2 C SR 3.3.5.2.1 < 54 inches LeveL -Nigh (Level 8) SR 3.3.5.2.2 SR 3.3.5.2.4 SR 3.3.5.-.5
| |
| : 3. Emergency Condensate 2 D SR 3.3.5.2.2 > 23 inches
| |
| ,;torage Tank: (ECST) SR 3.3.5.2.3 ILevel -Low SR 3.3.5.2.5 (a) <INSERT 1>
| |
| (b) <INSERT 2>
| |
| J.
| |
| Cooper 3.3-46 Amendment No. 178
| |
| | |
| NLS2011071 Page 1 of 57 Attachment 3 Proposed Technical Specification Revisions (Re-Typed)
| |
| Cooper Nuclear Station, Docket No. 50-298, DPR-46 Revised Technical Specification Pages 3.1-22 3.3-37 3.3-68 3.6-37 3.1-26 3.3-38 3.4-7 3.6-40 3.3-5 3.3-39 3.5-5 3.7-5 3.3-6 3.3-40 3.5-6 3.7-7 3.3-7 3.3-41 3.5-10 3.7-10 3.3-8 3.3-42 3.5-12 3.7-15 3.3-12 3.3-45 3.5-13 3.8-7 3.3-18 3.3.46 3.6-2 3.8-8 3.3-19 3.3-50 3.6-14 3.8-9 3.3-21 3.3-56 3.6-15 3.8-17 3.3-24 3.3-59 3.6-19 3.8-18 3.3-27 3.3-60 3.6-22 5.0-7 3.3-30 3.3-62 3.6-24 5.0-11 3.3-36 3.3-65 3.6-33 5.0-18
| |
| | |
| SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.1.7.6 Verify each SLC subsystem manual valve in the flow 31 days path that is not locked, sealed, or otherwise secured in position, is in the correct position or can be aligned to the correct position.
| |
| SR 3.1.7.7 Verify each pump develops a flow rate > 38.2 gpm at In accordance a discharge pressure > 1300 psig. with the Inservice Testing Program SR 3.1.7.8 Verify flow through one SLC subsystem from pump 24 months on a into reactor pressure vessel. STAGGERED TEST BASIS SR 3.1.7.9 Verify all heat traced piping between 24 months storage tank and pump suction is unblocked.
| |
| AND Once within 24 hours after solution temperature is restored within the limits of Figure 3.1.7-2 Cooper 3.1-22 Amendment No.
| |
| | |
| SDV Vent and Drain Valves 3.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY S R 3.1.8.1 ---------------------- NOTE -------------------------------
| |
| Not required to be met on vent and drain valves closed during performance of SR 3.1.8.2.
| |
| Verify each SDV vent and drain valve is open. 31 days SR 3.1.8.2 Cycle each SDV vent and drain valve to the fully 92 days closed and fully open position.
| |
| SR 3.1.8.3 Verify each SDV vent and drain valve: 24 months
| |
| : a. Closes in < 30 seconds after receipt of an actual or simulated scram signal; and
| |
| : b. Opens when the actual or simulated scram signal is reset.
| |
| Cooper 3.1-26 Amendment No.
| |
| | |
| RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.1.1.12 -------------------- NOTES---------------
| |
| : 1. Neutron detectors are excluded.
| |
| : 2. For Function 1, not required to be performed when entering MODE 2 from MODE 1 until 12 hours after entering MODE 2.
| |
| Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.1.14 Verify Turbine Stop Valve - Closure and Turbine 24 months Control Valve Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is > 29.5% RTP.
| |
| SR 3.3.1.1.15 -------------------- NOTE---------------
| |
| Neutron detectors are excluded.
| |
| Verify the RPS RESPONSE TIME is within limits. 24 months Cooper 3.3-5 Amendment No.
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 1 of 3)
| |
| Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 1. Intermediate Range Monitors
| |
| : a. Neutron 2 3 G SR 3.3.1.1.1 < 121/125
| |
| . Flux - High SR 3.3,1.1.3 divisions of full SR 3.3.1.1.4 scale SR 3.3.1.1.5 SR 3.311.1.6 SR 3 .3 , . 1. / -, b' SR 3.3.1.1.13 SR 3.3.1.1.15 5 (c) 3 H SR 3.3.1.1.1 < 121/125 SR 3.3.1.1.3 divisions of full SR 3.3.1.1.4 scale SR 3.3.1.1.12(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : b. Inop 2 3 G SR 3.3.1.1.3 NA SR 3.3.1.1.4 SR 3.3.1,1.13 5 (c) 3 H SR 3.3.1.1.3 NA SR 3.3.1.1.4 SR 3.3.1.1.13
| |
| : 2. Average Power Range Monitors
| |
| : a. Neutron 2 2 G SR 3.3.1.1.1 < 14.5% RTP Flux - High SR 3.3.1.1.3 (Startup) SR 3.3.1.1.4 SR 3.3.1.1.6 SR 3.3.1.1.8 SR 3.3.1.1.10(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : b. Neutron 1 2 F SR 3.3.1.1.1 < 0.75 W Flux-High (Flow SR 3.3.1.1.2 + 62.0%
| |
| Biased) SR 3.3.1.1.4 RTP(d)
| |
| SR 3.3.1.1.7 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.10(a'b)
| |
| SR 3.3.1.1.12(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15 (continued)
| |
| (a) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (b) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| (c) With any control rod withdrawn from a core cell containing one or more fuel assemblies, (d) [0.75 W + 62.0% - 0.75AW] RTP when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating."
| |
| Cooper 3.3-6 Amendment No.
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)
| |
| Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 2. Average Power Range Monitors (continued)
| |
| : c. Neutron Flux - 1 2 F SR 3.3.1.1.1 < 120.0% RTP High (Fixed) SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.10(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : d. Downscale 1 2 F SR 3.3.1.1.4 > 3.0% RTP SR 3.3.1.1.8 SR 3.3.1.1.9(a'b)
| |
| SR 3.3.1.1.13
| |
| : e. Inop 1,2 2 G SR 3.3.1.1.4 NA SR 3.3.1.1.8 SR 3.3.1.1.9 SR 3.3.1.1.13
| |
| : 3. Reactor Vessel 1,2 2 G SR 3.3.1.1.4 < 1050 psig Pressure - High SR 3.3.1.1.9 SR 3.3.1.1.12(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 4. Reactor Vessel Water 1,2 2 G SR 3.3.1.1.1 > 3 inches Level - Low (Level 3) SR 3.3.1.1.4 SR 3.3.1.1.9 SR 3.3.1.1.12(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 5. Main Steam Isolation 1 4 F SR 3.3.1.1.4 < 10% closed Valve - Closure SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 6. Drywell 1,2 2 G SR 3.3.1.1.4 < 1.84 psig Pressure - High SR 3.3.1.1.9 SR 3.3.1.1.12(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15 (continued)
| |
| (a) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (b) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| Cooper 3.3-7 Amendment No.
| |
| | |
| RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 3 of 3)
| |
| Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION D.1 REQUIREMENTS VALUE
| |
| : 7. Scram Discharge Volume Water Level - High
| |
| : a. Level Transmitter 1,2 G SR 3.3.1.1.4 < 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12(a'b)
| |
| SR 3.3.1.1.13 SR 3.3.1.1.15 5 (c) H SR 3.3.1.1.4 < 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : b. Level Switch 1,2 G SR 3.3.1.1.4 < 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15 5 (c) H SR 3.3.1.1.4 < 90 inches SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.15
| |
| : 8. Turbine Stop > 29.5% RTP 2 E SR 3.3.1.1.4 < 10% closed Valve - Closure SR 3.3.1.1.9 SR 3.3.1.1.12 SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15
| |
| : 9. Turbine Control Valve > 29.5% RTP 2 E SR 3.3.1.1.4
| |
| * 1018 psig Fast Closure, DEH SR 3.3.1.1.9 Trip Oil SR 3.3.1.1.12(a'b)
| |
| Pressure - Low SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15
| |
| : 10. Reactor Mode 1,2 G SR 3.3.1.1.11 NA Switch - Shutdown SR 3.3.1.1.13 Position 5 (c) 1 H SR 3.3.1.1.11 NA SR 3.3.1.1.13 11, Manual Scram 1,2 G SR 3.3.1.1.9 NA 1 SR 3.3.1.1.13 5 (c) H SR 3.3.1.1.9 NA SR 3.3.1.1.13 (a) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (b) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual, (c) With any control rod withdrawn from a core cell containing one or more fuel assemblies.
| |
| Cooper 3.3-8 Amendment No.
| |
| | |
| SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.1.2.4 - ------------------ NOTE ---------------
| |
| Not required to be met with less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies in the associated core quadrant.
| |
| Verify count rate is > 3.0 cps with a signal to noise 12 hours during ratio > 2:1. CORE ALTERATIONS AND 24 hours SR 3.3.1.2.5 Perform CHANNEL FUNCTIONAL TEST and 7 days determination of signal to noise ratio.
| |
| SR 3.3.1.2.6 --------------------- NOTE---------------
| |
| Not required to be performed until 12 hours after IRMs on Range 2 or below.
| |
| Perform CHANNEL FUNCTIONAL TEST and 31 days determination of signal to noise ratio.
| |
| SR 3.3.1.2.7 -------------------- NOTES----------------
| |
| : 1. Neutron detectors are excluded.
| |
| : 2. Not required to be performed until 12 hours after IRMs on Range 2 or below.
| |
| Perform CHANNEL CALIBRATION. 24 months Cooper 3.3-12 Amendment No.
| |
| | |
| Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.2.1.5 -------------------- NOTE---- ------------
| |
| Neutron detectors are excluded.
| |
| Perform CHANNEL CALIBRATION. 184 days SR 3.3.2.1.6 Verify the RWM is not bypassed when THERMAL 24, months POWER is < 9.85% RTP.
| |
| SR 3.3.2.1.7 --------------------- NOTE - -----------------
| |
| Not required to be performed until 1 hour after reactor mode switch is in the shutdown position.
| |
| Perform CHANNEL FUNCTIONAL TEST. 24 months SR 3.3.2.1.8 Verify control rod sequences input to the RWM are Prior to declaring in conformance with BPWS. RWM OPERABLE following loading of sequence into RWM Cooper 3.3-18 Amendment No.
| |
| | |
| Control Rod Block Instrumentation 3.3.2.1 Table 3.3.2.1-1 (page 1 of 1)
| |
| Control Rod Block Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS CHANNELS REQUIREMENTS VALUE
| |
| : 1. Rod Block Monitor
| |
| : a. Low Power Range - Upscale (a) 2 SR 3.3.2.1.1 (j)
| |
| SR 3.3.2.1.4 SR 3.3.2.1. 5 (b)(c)
| |
| : b. Intermediate Power Range - Upscale (d) 2 SR 3.3.2.1.1 (j)
| |
| SR 3.3.2.1.4 SR 3.3.2.1.5(b)(c)
| |
| : c. High Power Range - Upscale (e),(f) 2 SR 3.3.2.1.1 (1)
| |
| SR 3.3.2.1.4 SR 3.3.2.1.5(b)(c)
| |
| : d. Inop (A(g) 2 SR 3.3.2.1.1 NA
| |
| : e. Downscale (f(g) 2 SR 3.3.2.1.1 > 92/125 SR 3.3.2.1.5 divisions of full scale
| |
| : 2. Rod Worth Minimizer 1 (h), 2 (h) 1 SR 3.3.2.1.2 NA SR 3.3.2.1.3 SR 3.3.2.1.6 SR 3.3.2.1.8
| |
| : 3. Reactor Mode Switch - Shutdown Position (i) 2 SR 3.3.2.1.7 NA (a) THERMAL POWER > 27.5% and < 62.5% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| (b) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (c) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| (d) THERMAL POWER > 62.5% and < 82.5% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| (e) THERMAL POWER > 82.5% and < 90% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| (f) THERMAL POWER > 90% RTP and MCPR < 1.40 and no peripheral control rod selected.
| |
| (g) THERMAL POWER > 27.5% and < 90% RTP and MCPR < 1.70 and no peripheral control rod selected.
| |
| (h) With THERMAL POWER < 9.85 RTP.
| |
| (i) Reactor mode switch in the shutdown position.
| |
| () Less than or equal to the Allowable Value specified in the COLR.
| |
| Cooper 3.3-19 Amendment No.
| |
| | |
| Feedwater and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 SURVEILLANCE REQUIREMENTS
| |
| ---------------------- NOTE ------------------------------------------------
| |
| When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided feedwater and main turbine high water level trip capability is maintained.
| |
| SURVEILLANCE FREQUENCY SR 3.3.2.2.1 Perform CHANNEL CHECK. 24 hours SR 3.3.2.2.2 Perform CHANNEL CALIBRATION. The Allowable 24 months Value shall be < 54.0 inches.
| |
| SR 3.3.2.2.3 Perform LOGIC SYSTEM FUNCTIONAL TEST 24 months including valve actuation.
| |
| Cooper 3.3-21 Amendment No.
| |
| | |
| PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK on each required PAM 31 days Instrumentation channel.
| |
| SR 3.3.3.1.2 Perform CHANNEL CALIBRATION of the Primary 92 days Containment H2 and 02 Analyzers.
| |
| SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of each 24 months required PAM Instrumentation channel except for the Primary Containment H2 and 02 Analyzers.
| |
| Cooper 3.3-24 Amendment No.
| |
| | |
| Alternate Shutdown System 3.3.3.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.3.2.2 Verify each required control circuit and transfer 24 months switch is capable of performing the intended function.
| |
| SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each 24 months required instrumentation channel.
| |
| Cooper 3.3-27 Amendment No.
| |
| | |
| ATWS-RPT Instrumentation 3.3.4.1 SURVEILLANCE REQUIREMENTS
| |
| ------------------------NOTE -------------------------------
| |
| When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains ATWS-RPT trip capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.4.1.2 Perform CHANNEL CALIBRATION. The Allowable 24 months Values shall be:
| |
| : a. Reactor Vessel Water Level - Low Low (Level 2): > -42 inches; and
| |
| : b. Reactor Pressure - High: < 1072 psig.
| |
| SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST 24 months including breaker actuation.
| |
| Cooper 3.3-30 Amendment No.
| |
| | |
| ECCS Instrumentation 3.3.5.1 SURVEILLANCE REQUIREMENTS
| |
| ----------------------------- NOTES -------------------------------
| |
| : 1. Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Functions 3.c and 3.f; and (b) for up to 6 hours for Functions other than 3.c and 3.f provided the associated Function or the redundant Function maintains ECCS initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.5.1.1 Perform CHANNEL CHECK. 12 hours SR 3.3.5.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.1.3 Perform CHANNEL CALIBRATION. 92 days SR 3.3.5.1.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-36 Amendment No.
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 1 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES REQUIRED REFERENCED OR OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 1. Core Spray System
| |
| : a. Reactor Vessel 1,2,3, 4 (b) B SR 3.3.5.1.1 > -113 inches Water Level - Low SR 3.3.5.1.2 Low Low (Level 1) 4 (a), 5 (a) SR 3.3.5.1.4(c)(d)
| |
| SR 3.3.5.1.5
| |
| : b. Drywell Pressure- 1,2,3 4 (b) B SR 3.3.5.1.2
| |
| * 1.84 psig High SR 3.3.5.1. 4 (c)(d)
| |
| SR 3.3.5.1.5
| |
| : c. Reactor Pressure- 1,2,3 4 C SR 3.3.5.1.2
| |
| * 291 psig and Low (Injection SR 3.3.5.1.4 Permissive) SR 3.3.5.1.5 < 436 psig 4 (a), 5 (a) 4 B SR 3.3.5.1.2 > 291 psig and SR 3.3.5.1.4 SR 3.3.5.1.5 < 436 psig
| |
| : d. Core Spray Pump 1,2,3, 1 per pump E SR 3.3.5.1.2 > 1370 gpm Discharge Flow - SR 3.3.5.1. 4 (c)(d)
| |
| Low 4 (a), 5 (a) SR 3.3.5.1.5 (Bypass)
| |
| : e. Core Spray Pump 1,2,3, 1 per pump C SR 3.3.5.1.2 > 9 seconds Start-Time Delay SR 3.3.5.1.4 and Relay 4 (a), 5 (a) SR 3.3.5.1.5 < 11 seconds
| |
| : 2. Low Pressure Coolant Injection (LPCI) System
| |
| : a. Reactor Vessel 1,2,3, 4 B SR 3.3.5.1.1 > -113 inches Water Level - Low SR 3.3.5.1.2 Low Low (Level 1) 4 (a), 5 (a) SR 3.3.5.1.4(c SR 3.3.5.1.5 (continued)
| |
| (a) When associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| (b) Also required to initiate the associated diesel generator (DG).
| |
| (c) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (d) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| Cooper 3.3-37 Amendment No.
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 2 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES REQUIRED REFERENCED OR OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 2. LPCI System (continued) 1,2,3 4 B SR 3.3.5.1.2 < 1.84 psig
| |
| : b. Drywell Pressure - SR 3 .3.5.1. 4 (c)(d)
| |
| High SR 3.3.5.1.5
| |
| : c. Reactor Pressure - 1,2,3 4 C SR 3.3.5.1,2 > 291 psig and Low (Injection SR 3.3.5.1.4 Permissive) SR 3.3.5.1.5 < 436 psig 4 (a), 5 (a) B SR 3.3.5.1.2 > 291 psig and SR 3.3.5.1.4 SR 3.3.5.1.5 <436 psig
| |
| : d. Reactor Pressure - 1 (e), 2 (e), 4 C SR 3.3.5.1.2 > 199 psig and Low (Recirculation SR 3.3.5.1.4 < 246 psig Discharge Valve 3 (e) SR 3.3.5.1.5 Permissive)
| |
| : e. Reactor Vessel 1,2,3 2 B SR 3.3.5.1.1 >-193.19 Shroud Level - SR 3.3.5.1.2 inches Level 0 SR 3.3.5.1.4 SR 3.3.5.1.5
| |
| : f. Low Pressure 1,2,3, 1 per pump C SR 3.3.5.1.2 Coolant Injection SR 3.3.5.1.4 Pump Start -Time 4 (a), 5 (a) SR 3.3.5.1.5 Delay Relay Pumps B,C > 4.5 seconds and
| |
| < 5.5 seconds Pumps A,D < 0.5 second (continued)
| |
| (a) When associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| (c) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (d) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| (e) With associated recirculation pump discharge valve open.
| |
| Cooper 3.3-38 Amendment No.
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 2. LPCI System (continued) 1,2,3, 1 per E SR 3.3.5.1.2 >2107 gpm
| |
| : g. Low Pressure subsystem SR 3 .3.5.1. 4 (c)(d)
| |
| Coolant Injection 4 (a), 5 (a) SR 3.3.5.1.5 Pump Discharge Flow - Low (Bypass)
| |
| : 3. High Pressure Coolant Injection (HPCI) System
| |
| : a. Reactor Vessel 1, 4 B SR 3.3.5.1.1 >-42 inches Water Level - Low SR 3.3.5.1.2 Low (Level 2) 2(0, 3(f) SR 3.3.5.1. 4 (c)(d)
| |
| SR 3.3.5.1.5
| |
| : b. Drywell Pressure - 1, 4 B SR 3.3.5.1.2 < 1.84 psig High SR 3 .3.5.1. 4 (c)(d) 2(A, 3(0 SR 3.3.5.1.5
| |
| : c. Reactor Vessel 1, 2 C SR 3.3.5.1.1 < 54 inches Water Level - High SR 3.3.5.1.2 (Level 8) 2(A, 3(f) SR 3.3.5.1.4 SR 3.3.5.1.5
| |
| : d. Emergency 1, 2 D SR 3.3.5.1.2 > 23 inches Condensate SR 3.3.5.1.3 Storage Tank 2(0, 3(f) SR 3.3.5.1.5 (ECST) Level -
| |
| Low
| |
| : e. Suppression Pool 1, 2 D SR 3.3.5.1.2 < 4 inches Water Level - High SR 3.3.5.1.4 2(0, 3(f) SR 3.3.5.1.5 (continued)
| |
| (a) When the associated ECCS subsystem(s) are required to be OPERABLE per LCO 3.5.2, ECCS - Shutdown.
| |
| (c) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (d) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| (f) With reactor steam dome pressure > 150 psig.
| |
| Cooper 3.3-39 Amendment No.
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 4 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 3. HPCI System (6ontinued) 1, 1 E SR 3.3.5.1.2 > 490 gpm
| |
| : f. High Pressure SR 3 .3.5.1. 4(c)(d) -
| |
| Coolant Injection 2(0, 3(0 SR 3.3.5.1.5 Pump Discharge Flow - Low (Bypass)
| |
| : 4. Automatic Depressurization System (ADS) Trip System A 1, 2 F SR 3.3.5.1.1 > -113 SR 3.3.5.1.2 inches
| |
| : a. Reactor Vessel 2(f0, 3(f) SR 3.3.5.1. 4 (c)(d)
| |
| Water Level - Low SR 3.3.5.1.5 Low Low (Level 1)
| |
| : b. Automatic 1, 1 G SR 3.3.5.1.2 < 109 seconds Depressurization SR 3.3.5.1.4 System Initiation 2(0, 3(0 SR 3.3.5.1.5 Timer
| |
| : c. Reactor Vessel 1, 1 F SR 3.3.5.1.1 > 3 inches Water Level - Low SR 3.3.5.1.2 (Level 3) 2(D, 3(A SR 3.3.5.1.4(c)(d)
| |
| (Confirmatory) SR 3.3.5.1.5
| |
| : d. Core Spray Pump 1, 2 G SR 3.3.5.1.2 > 108 psig and Discharge SR 3.3.5.1.4 < 160 psig Pressure- High 2(D, 3(0 SR 3.3.5.1.5 (continued)
| |
| (c) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (d) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| (f) With reactor steam dome pressure > 150 psig.
| |
| Cooper 3.3-40 Amendment No.
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 5 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 4. ADS Trip System A (continued)
| |
| : e. Low Pressure 1, 4 G SR 3.3.5.1.2 > 108 psig and Coolant Injection SR 3.3.5.1.4 < 160 psig Pump Discharge 2(A, 3(f) SR 3.3.5.1.5 Pressure - High
| |
| : 5. ADS Trip System B
| |
| : a. Reactor Vessel 1, 2 F SR 3.3.5.1.1 >-113 inches Water Level - Low SR 3.3.5.1.2 Low Low (Level 1) 2(A, 3(A SR 3.3.5.1. 4 (c)(d)
| |
| SR 3.3.5.1.5
| |
| : b. Automatic 1, 1 G SR 3.3.5.1.2 < 109 seconds Depressurization SR 3.3.5.1.4 System Initiation 2(f), 3(f SR 3.3.5.1.5 Timer
| |
| : c. Reactor Vessel 1, 1 F SR 3.3.5.1.1 > 3 inches Water Level - Low, SR 3.3.5.1.2 Level 3 2(0, 3(f) SR 3.3.5.1. 4 (c)(d)
| |
| (Confirmatory) SR 3.3.5.1.5
| |
| : d. Core Spray Pump 1, 2 G SR 3.3.5.1.2 > 108 psig and Discharge SR 3.3.5.1.4 < 160 psig Pressure - High 2(0, 3(A SR 3.3.5.1.5 (continued)
| |
| (c) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (d) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| (f) With reactor steam dome pressure > 150 psig.
| |
| Cooper 3.3-41 Amendment No.
| |
| | |
| ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 6 of 6)
| |
| Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE
| |
| : 5. ADS Trip System B (continued)
| |
| : e. Low Pressure 1, 4 G SR 3.3.5.1.2 > 108 psig and Coolant Injection SR 3.3.5.1.4 < 160 psig Pump Discharge 2(f, 3(f SR 3.3.5.1.5 Pressure - High (f) With reactor steam dome pressure > 150 psig.
| |
| Cooper 3.3-42 Amendment No.
| |
| | |
| RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS
| |
| ------------------------------ NOTES ------------------------------
| |
| : 1. Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Function 2; and (b) for up to 6 hours for Functions 1 and 3 provided the associated Function maintains RCIC initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.5.2.3 Perform CHANNEL CALIBRATION. 92 days SR 3.3.5.2.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-45 Amendment No.
| |
| | |
| RCIC System Instrumentation 3.3.5.2 Table 3.3.5.2-1 (page 1 of 1)
| |
| Reactor Core Isolation Cooling System Instrumentation CONDITIONS REQUIRED REFERENCED CHANNELS FROM REQUIRED SURVEILLANCE ALLOWABLE FUNCTION PER FUNCTION ACTION A.1 REQUIREMENTS VALUE Reactor Vessel Water 4 B SR 3.3.5.2.1 > -42 inches Level - Low Low (Level 2) SR 3.3.5.2.2 SR 3.3.5.2.4(a)(b)
| |
| SR 3.3.5.2.5
| |
| : 2. Reactor Vessel Water 2 C SR 3.3.5.2.1 < 54 inches Level - High (Level 8) SR 3.3.5.2.2 SR 3.3.5.2.4 SR 3.3.5.2.5
| |
| : 3. Emergency Condensate 2 D SR 3.3.5.2.2 > 23 inches Storage Tank (ECST) SR 3.3.5.2.3 Level - Low SR 3.3.5.2.5 (a) If the as-found channel setpoint is outside its predefined as-found tolerance, then the channel shall be evaluated to verify that it is functioning as required before returning the channel to service.
| |
| (b) The instrument channel setpoint shall be reset to a value that is within the as-left tolerance around the Limiting Trip Setpoint (LTSP) at the completion of the surveillance; otherwise, the channel shall be declared inoperable. Setpoints more conservative than the LTSP are acceptable provided that the as-found and as-left tolerances apply to the actual setpoint implemented in the Surveillance procedures (Nominal Trip Setpoint) to confirm channel performance. The Limiting Trip Setpoint and the methodologies used to determine the as-found and the as-left tolerances are specified in the Technical Requirements Manual.
| |
| Cooper 3.3-46 Amendment No.
| |
| | |
| Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS
| |
| ----------------------------------------- 11 r-ýý ---------------------------------------------------------
| |
| : 1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains isolation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. 12 hours SR 3.3.6.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.1.3 Perform CHANNEL CALIBRATION. 92 days SR 3.3.6.1.4 -------------------- NOTE ----------------
| |
| For Function 2.d, radiation detectors are excluded.
| |
| Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.1.5 Calibrate each radiation detector. 24 months SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-50 Amendment No.
| |
| | |
| Secondary Containment Isolation Instrumentation 3.3.6.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.2.3 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-56 Amendment No.
| |
| | |
| LLS Instrumentation 3.3.6.3 SURVEILLANCE REQUIREMENTS
| |
| ------------------------------ NOTES -------------------------------
| |
| : 1. Refer to Table 3.3.6.3-1 to determine which SRs apply for each Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains LLS initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.6.3.1 Perform CHANNEL FUNCTIONAL TEST for 92 days portion of the channel outside primary containment.
| |
| SR 3.3.6.3.2 --------------------- NOTE---------------
| |
| Only required to be performed prior to entering MODE 2 during each scheduled outage > 72 hours when entry is made into primary containment.
| |
| Perform CHANNEL FUNCTIONAL TEST for 92 days portions of the channel inside primary containment.
| |
| SR 3.3.6.3.3 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.3.4 Perform CHANNEL CALIBRATION. 24 months SR 3.3.6.3.5 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-59 Amendment No.
| |
| | |
| LLS Instrumentation 3.3.6.3 Table 3.3.6.3-1 (page 1 of 1)
| |
| Low-Low Set Instrumentation REQUIRED CHANNELS PER SURVEILLANCE ALLOWABLE FUNCTION FUNCTION REQUIREMENTS VALUE
| |
| : 1. Reactor Pressure - High 1 per LLS valve SR 3.3.6.3.3 < 1050 psig SR 3.3.6.3.4 SR 3.3.6.3.5
| |
| : 2. Low-Low Set Pressure Setpoints 2 per LLS valve SR 3.3.6.3.3 Low:
| |
| SR 3.3.6.3.4 Open > 996.5 psig SR 3.3.6.3.5 and < 1010 psig Close > 835 psig and < 875.5 psig High:
| |
| Open > 996.5 psig and < 1040 psig Close > 835 psig and _<875.5 psig
| |
| : 3. Discharge Line Pressure Switch 1 per SRV SR 3.3.6.3.1 > 25 psig and < 55 psig SR 3.3.6.3.2 SR 3.3.6.3.4 SR 3.3.6.3.5 Cooper 3.3-60 Amendment No.
| |
| | |
| CREF System Instrumentation 3.3.7.1 SURVEILLANCE REQUIREMENTS
| |
| : 1. Refer to Table 3.3.7.1-1 to determine which SRs apply for each CREF Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains CREF initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.7.1.1 Perform CHANNEL CHECK. 12 hours SR 3.3.7.1.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.7.1.3 Perform CHANNEL CALIBRATION. 24 months SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-62 Amendment No.
| |
| | |
| LOP Instrumentation 3.3.8.1 SURVEILLANCE REQUIREMENTS
| |
| -NOT 'ES---------------------------------------------
| |
| : 1. Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function.
| |
| : 2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours provided the associated Function maintains DG initiation capability.
| |
| SURVEILLANCE FREQUENCY SR 3.3.8.1.1 Perform CHANNEL FUNCTIONAL TEST. 31 days SR 3.3.8.1.2 Perform CHANNEL CALIBRATION. 24 months SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Cooper 3.3-65 Amendment No.
| |
| | |
| RPS Electric Power Monitoring 3.3.8.2 CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Initiate action to fully insert Immediately associated Completion all insertable control rods Time of Condition A in core cells containing or B not met in MODE 5 one or more fuel with any control rod assemblies.
| |
| withdrawn from a core cell containing one or more fuel assemblies.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.1 Perform CHANNEL CALIBRATION. The Allowable 24 months Values shall be:
| |
| : a. Overvoltage < 131 V with time delay set to
| |
| < 3.8 seconds.
| |
| : b. Undervoltage > 109 V, with time delay set to
| |
| < 3.8 seconds.
| |
| : c. Underfrequency > 57.2 Hz, with time delay set to < 3.8 seconds.
| |
| SR 3.3.8.2.2 Perform a system functional test. 24 months Cooper 3.3-68 Amendment No.
| |
| | |
| SRVs and SVs 3.4.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift setpoints of the SRVs In accordance and SVs are as follows: with the Inservice Testing Program Number of Setpoint SRVs 2 1080 +/- 32.4 3 1090 +/- 32.7 3 1100 +/- 33.0 Number of Setpoint SVs 3 1240 +/- 37.2 Following testing, lift settings shall be within +/- 1%.
| |
| SR 3.4.3.2 ---------------------- NOTE ----------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify each SRV opens when manually actuated. 24 months Cooper 3.4-7 Amendment No.
| |
| | |
| ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY 1-SR 3.5.1.6 Verify the following ECCS pumps develop the specified In accordance flow rate against a system head corresponding to the with the specified reactor pressure. Inservice SYSTEM HEAD Testing NO. CORRESPONDING Program OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF Core Spray > 4720 gpm 1
| |
| * 113 psig LPCI > 15,000 gpm 2
| |
| * 20 psig SR 3.5.1.7 NOTE ----------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify, with reactor pressure < 1020 and > 920 psig, the 92 days HPCI pump can develop a flow rate > 4250 gpm against a system head corresponding to reactor pressure.
| |
| SR 3.5.1.8 NOTE -----------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify, with reactor pressure < 165 psig, the HPCI pump 24 months can develop a flow rate > 4250 gpm against a system head corresponding to reactor pressure.
| |
| (continued)
| |
| Cooper 3.5-5 Amendment No.
| |
| | |
| ECCS - Operating 3.5.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY
| |
| +
| |
| SR 3.5.1.9
| |
| --------------------- NOTES ----------------
| |
| : 1. For HPCI only, not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| : 2. Vessel injection/spray may be excluded.
| |
| Verify each ECCS injection/spray subsystem actuates 24 months on an actual or simulated automatic initiation signal.
| |
| SR 3.5.1.10 ---------------------- NOTE -----------------
| |
| Valve actuation may be excluded.
| |
| Verify the ADS actuates on an actual or simulated 24 months automatic initiation signal.
| |
| SR 3.5.1.11 ---------------------- NOTE -----------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify each ADS valve opens when manually actuated. 24 months Cooper 3.5-6 Amendment No.
| |
| | |
| ECCS - Shutdown 3.5.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.2.4 Verify each required ECCS pump develops the specified In accordance flow rate against a system head corresponding to the with the specified reactor pressure. Inservice SYSTEM HEAD Testing NO. CORRESPONDING Program OF TO A REACTOR SYSTEM FLOW RATE PUMPS PRESSURE OF CS > 4720 gpm 1 > 113 psig LPCI > 7700 gpm 1 > 20 psig SR 3.5.2.5 ----------------------- NOTE -----------------
| |
| Vessel injection/spray may be excluded.
| |
| Verify each required ECCS injection/spray subsystem 24 months actuates on an actual or simulated automatic initiation signal.
| |
| Cooper 3.5-10 Amendment No.
| |
| | |
| RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.3.1 Verify the RCIC System piping is filled with water 31 days from the pump discharge valve to the injection valve.
| |
| SR 3.5.3.2 Verify each RCIC System manual, power operated, 31 days and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| SR 3.5.3.3 -- ------------------- NOTE ----------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify, with reactor pressure < 1020 psig and 92 days
| |
| * 920 psig, the RCIC pump can develop a flow rate
| |
| > 400 gpm against a system head corresponding to reactor pressure.
| |
| SR 3.5.3.4 -- ------------------- NOTE ----------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify, with reactor pressure < 165 psig, the RCIC 24 months pump can develop a flow rate > 400 gpm against a system head corresponding to reactor pressure.
| |
| (continued)
| |
| Cooper 3.5-12 Amendment No.
| |
| | |
| RCIC System 3.5.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.5.3.5 NOTES --------------
| |
| : 1. Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| : 2. Vessel injection may be excluded.
| |
| Verify the RCIC System actuates on an actual or 24 months simulated automatic initiation signal.
| |
| Cooper 3.5-13 Amendment No.
| |
| | |
| Primary Containment 3.6.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.1.1 Perform required visual examinations and leakage In accordance rate testing except for primary containment air lock with the Primary testing, in accordance with the Primary Containment Containment Leakage Rate Testing Program. Leakage Rate Testing Program SR 3.6.1.1.2 Verify drywell to suppression chamber bypass 24 months leakage is equivalent to a hole < 1.0 inch in diameter. AND
| |
| - -------NOTE--------
| |
| Only required after two consecutive tests fail and continues until two consecutive tests pass 9 months Cooper 3.6-2 Amendment No.
| |
| | |
| PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.6.1.3.6 Verify the isolation time of each MSIV is In accordance
| |
| > 3 seconds and < 5 seconds. with the Inservice Testing Program SR 3.6.1.3.7 Verify each automatic PCIV actuates to the 24 months isolation position on an actual or simulated isolation signal.
| |
| SR 3.6.1.3.8 Verify a representative sample of reactor 24 months instrumentation line EFCVs actuate to the isolation position on an actual or simulated instrument line break.
| |
| SR 3.6.1.3.9 Remove and test the explosive squib from each 24 months on a shear isolation valve of the TIP System. STAGGERED TEST BASIS SR 3.6.1.3.10 Verify leakage rate through each Main Steam line In accordance is < 106 scfh when tested at > 29 psig. with the Primary Containment Leakage Rate Testing Program (continued)
| |
| Cooper 3.6-14 Amendment No.
| |
| | |
| PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.6.1.3.11 Verify each inboard 24 inch primary containment 24 months purge and vent valve is blocked to restrict the maximum valve opening angle to 600.
| |
| SR 3.6.1.3.12 Verify leakage rate through the Main Steam In accordance Pathway is < 212 scfh when tested at > 29 psig. with the Primary Containment Leakage Rate Testing Program Cooper 3.6-15 Amendment No.
| |
| | |
| LLS Valves 3.6.1.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.6.1 --------------------- NOTE---------------
| |
| Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test.
| |
| Verify each LLS valve opens when manually 24 months actuated.
| |
| SR 3.6.1.6.2 --------------------- NOTE---------------
| |
| Valve actuation may be excluded.
| |
| Verify the LLS System actuates on an actual or 24 months simulated automatic initiation signal.
| |
| Cooper 3.6-19 Amendment No.
| |
| | |
| Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.7 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.6.1.7.3 Verify the full open setpoint of each vacuum 24 months breaker is < 0.5 psid.
| |
| Cooper 3.6-22 Amendment No.
| |
| | |
| Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.8.1 ---------------------- NOTE ---------------
| |
| Not required to be met for vacuum breakers that are open during Surveillances.
| |
| Verify each vacuum breaker is closed. 14 days SR 3.6.1.8.2 Perform a functional test of each required vacuum 31 days breaker.
| |
| SR 3.6.1.8.3 Verify the opening setpoint of each required 24 months vacuum breaker is < 0.5 psid.
| |
| Cooper 3.6-24 Amendment No.
| |
| | |
| Secondary Containment 3.6.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2 Initiate action to suspend Immediately OPDRVs.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1.1 Verify secondary containment vacuum is 24 hours
| |
| > 0.25 inch of vacuum water gauge.
| |
| SR 3.6.4.1.2 Verify all secondary containment equipment 31 days hatches are closed and sealed.
| |
| SR 3.6.4.1.3 Verify one secondary containment access door in 31 days each access opening is closed.
| |
| SR 3.6.4.1.4 Verify each SGT subsystem can maintain 24 months on a
| |
| > 0.25 inch of vacuum water gauge in the STAGGERED secondary containment for 1 hour at a flow rate TEST BASIS
| |
| < 1780 cfm.
| |
| Cooper 3.6-33 Amendment No.
| |
| | |
| SCIVs 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1 --------------------- NOTES---------------
| |
| : 1. Valves and blind flanges in high radiation areas may be verified by use of administrative means.
| |
| : 2. Not required to be met for SCIVs that are open under administrative controls.
| |
| Verify each secondary containment isolation 31 days manual valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed.
| |
| SR 3.6.4.2.2 Verify the isolation time of each power operated In accordance automatic SCIV is within limits, with the Inservice Testing Program SR 3.6.4.2.3 Verify each automatic SCIV actuates to the 24 months isolation position on an actual or simulated actuation signal.
| |
| Cooper 3.6-37 Amendment No.
| |
| | |
| SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.2 Initiate action to Immediately suspend OPDRVs.
| |
| SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for> 10 continuous 31 days hours with heaters operating.
| |
| SR 3.6.4.3.2 Perform required SGT filter testing in accordance In accordance with the Ventilation Filter Testing Program (VFTP). with the VFTP SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual 24 months or simulated initiation signal.
| |
| SR 3.6.4.3.4 Verify the SGT units cross tie damper is in the 24 months correct position, and each SGT room air supply check valve and SGT dilution air shutoff valve can be opened.
| |
| Cooper 3.6-40 Amendment No.
| |
| | |
| SW System and UHS 3.7.2 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.7.2.3 --------------------- NOTE -----------------------------
| |
| Isolation of flow to individual components does not render SW System inoperable.
| |
| Verify each SW subsystem manual, power operated, 31 days and automatic valve in the flow paths servicing safety related systems or components, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| SR 3.7.2.4 Verify each SW subsystem actuates on an actual or 24 months simulated initiation signal.
| |
| Cooper 3.7-5 Amendment No.
| |
| | |
| REC System 3.7.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 ------------------- NOTES--------------
| |
| : 1. SR 3.0.1 is not applicable when both Service Water backup subsystems are OPERABLE.
| |
| : 2. REC system leakage beyond limits by itself is only a degradation of the REC system and does not result in the REC system being inoperable.
| |
| Verify the REC system leakage is within limits. 24 hours SR 3.7.3.2 Verify the temperature of the REC supply water is 24 hours
| |
| < 100°F.
| |
| SR 3.7.3.3 ------------------- NOTE ----------------
| |
| Isolation of flow to individual components does not render REC System inoperable.
| |
| Verify each REC subsystem manual, power 31 days operated, and automatic valve in the flow paths servicing safety related cooling loads, that is not locked, sealed, or otherwise secured in position, is in the correct position.
| |
| SR 3.7.3.4 Verify each REC subsystem actuates on an 24 months actual or simulated initiation signal.
| |
| Cooper 3.7-7 Amendment No.
| |
| | |
| CREF System 3.7.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.4.1 Operate the CREF System for > 15 minutes. 31 days SR 3.7.4.2 Perform required CREF filter testing in accordance In accordance with the Ventilation Filter Testing Program (VFTP). with the VFTP.
| |
| SR 3.7.4.3 Verify the CREF System actuates on an actual or 24 months simulated initiation signal.
| |
| SR 3.7.4.4 Perform required CRE unfiltered air inleakage testing In accordance in accordance with the Control Room Envelope with the Control Habitability Program. Room Envelope Habitability Program Cooper 3.7-10 Amendment No.
| |
| | |
| Main Turbine Bypass System 3.7.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify operation of each main turbine bypass valve. 31 days SR 3.7.7.2 Perform a system functional test. 24 months SR 3.7.7.3 Verify the TURBINE BYPASS SYSTEM RESPONSE 24 months TIME is within limits.
| |
| Cooper 3.7-15 Amendment No.
| |
| | |
| AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.7 NOTE ----------------
| |
| All DG starts may be preceded by an engine prelube period.
| |
| Verify each DG starts from standby condition and 184 days achieves, in < 14 seconds, voltage > 3950 V and frequency > 58.8 Hz, and after steady state conditions are reached, maintains voltage > 3950 V and < 4400 V and frequency > 58.8 Hz and < 61.2 Hz.
| |
| SR 3,8.1.8 NOTE ----------------
| |
| This Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify automatic and manual transfer of unit power 24 months supply from the normal offsite circuit to the alternate offsite circuit.
| |
| (continued)
| |
| Cooper 3.8-7 Amendment No.
| |
| | |
| AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY 4.
| |
| SR 3.8.1.9 --------------------- NOTES ---------------
| |
| : 1. Momentary transients outside the load and power factor ranges do not invalidate this test.
| |
| : 2. This Surveillance shall not be performed in MODE 1 or 2. However, credit may be taken for unplanned events that satisfy this SR.
| |
| : 3. If performed with DG synchronized with offsite power, the surveillance shall be performed at a power factor < 0.89. However, if grid conditions do not permit, the power factor limit is not required to be met. Under this condition the power factor shall be maintained as close to the limit as practicable.
| |
| Verify each DG operates for > 8 hours: 24 months
| |
| : a. For > 2 hours loaded > 4200 kW and < 4400 kW; and
| |
| : b. For the remaining hours of the test loaded >
| |
| 3600 kW and < 4000 kW.
| |
| SR 3.8.1.10 --------------------- NOTES ---------------
| |
| This Surveillance shall not be performed in MODE 1, 2 or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify interval between each sequenced load is within 24 months
| |
| + 10% of nominal timer setpoint.
| |
| (continued)
| |
| Cooper 3.8-8 Amendment No.
| |
| | |
| AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.1.11 NOTES ---------------
| |
| : 1. All DG starts may be preceded by an engine prelube period.
| |
| : 2. This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify, on an actual or simulated loss of offsite power 24 months signal in conjunction with an actual or simulated ECCS initiation signal:
| |
| : a. De-energization of emergency buses;
| |
| : b. Load shedding from emergency buses; and
| |
| : c. DG auto-starts from standby condition and:
| |
| : 1. energizes permanently connected loads in < 14 seconds,
| |
| : 2. energizes auto-connected emergency loads through the timed logic sequence,
| |
| : 3. maintains steady state voltage > 3950 V and < 4400 V,
| |
| : 4. maintains steady state frequency > 58.8 Hz and < 61.2 Hz, and
| |
| : 5. supplies permanently connected and auto-connected emergency loads for
| |
| > 5 minutes.
| |
| Cooper 3.8-9 Amendment No.
| |
| | |
| DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage on float charge is: 7 days
| |
| : a. > 125 V for the 125 V batteries; and
| |
| : b. > 250 V for the 250 V batteries.
| |
| SR 3.8.4.2 Verify no visible corrosion at battery terminals and 92 days connectors.
| |
| OR Verify battery connection resistance meets the limits specified in Table 3.8.4-1.
| |
| SR 3.8.4.3 Verify battery cells, cell plates, and racks show no 18 months visual indication of physical damage or abnormal deterioration that degrades battery performance.
| |
| SR 3.8.4.4 Remove visible corrosion and verify battery cell to 18 months cell and terminal connections are coated with anti-corrosion material.
| |
| SR 3,8.4.5 Verify battery connection resistance meets the limits 18 months specified in Table 3.8.4-1.
| |
| SR 3,8.4.6 Verify: 24 months
| |
| : a. Each required 125 V battery charger supplies >
| |
| 200 amps at > 125 V for > 4 hours; and
| |
| : b. Each required 250 V battery charger supplies >
| |
| 200 amps at > 250 V for > 4 hours.
| |
| (continued)
| |
| Cooper 3.8-17 Amendment No.
| |
| | |
| DC Sources - Operating 3.8.4 SURVEILLANCE REQUIREMENTS (continued)
| |
| SURVEILLANCE FREQUENCY SR 3.8.4.7 --------------------- NOTES---------------
| |
| : 1. The modified performance discharge test in SR 3.8.4.8 may be performed in lieu of the service test in SR 3.8.4.7 once per 60 months.
| |
| : 2. This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify battery capacity is adequate to supply, and 24 months maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.
| |
| SR 3.8.4.8 -------------------- NOTE ----------------
| |
| This Surveillance shall not be performed in MODE 1, 2, or 3. However, credit may be taken for unplanned events that satisfy this SR.
| |
| Verify battery capacity is > 90% of the manufacturer's 60 months rating when subjected to a performance discharge test or a modified performance discharge test. AND 18 months when.
| |
| battery shows degradation or has reached 85%
| |
| of expected life with capacity
| |
| < 100% of manufacturer's rating AND 24 months when battery has reached 85% of the expected life with capacity
| |
| > 100% of manufacturer's rating Cooper 3.8-18 Amendment No.
| |
| | |
| Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.1 Offsite Dose Assessment Manual (ODAM) (continued) markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicate the date (i.e., month and year) the change was implemented.
| |
| 5.5.2 Systems Integrity Monitoring Program This program provides controls to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to levels as low as practicable. The systems include the Core Spray, High Pressure Coolant Injection, Residual Heat Removal, and Reactor Core Isolation Cooling. The program shall include the following:
| |
| : a. Preventive maintenance and periodic visual inspection requirements; and
| |
| : b. Integrated leak test requirements for each system at 24 month intervals or less.
| |
| The provisions of SR 3.0.2 and SR 3.0.3 are applicable at the 24 month Frequency for performing system leak test activities.
| |
| 5.5.3 Post Accident Sampling This program provides controls that ensure the capability to obtain and analyze reactor coolant, radioactive gases, and particulates in plant gaseous effluents and containment atmosphere samples under accident conditions. The program shall include the following:
| |
| : a. Training of personnel;
| |
| : b. Procedures for sampling and analysis; and
| |
| : c. Provisions for maintenance of sampling and analysis equipment.
| |
| (continued)
| |
| Cooper 5.0-7 Amendment No.
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| | |
| Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.7 Ventilation Filter Testing Program (VFTP)
| |
| The VFTP shall establish the required testing of Engineered Safety Feature (ESF) filter ventilation systems. Tests described in Specifications 5.5.7.a, 5.5.7.b, and 5.5.7.c shall be performed once per 24 months for standby service or after 720 hours of system operation; and, following significant painting, fire, or chemical release concurrent with system operation in any ventilation zone communicating with the system.
| |
| Tests described in Specifications 5.5.7.a and 5.5.7.b shall be performed after each complete or partial replacement of the HEPA filter train or charcoal adsorber filter; and after any structural maintenance on the system housing.
| |
| Tests described in Specifications 5.5.7.d and 5.5.7.e shall be performed once per 24 months.
| |
| The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.
| |
| : a. Demonstrate for each of the ESF systems that an inplace test of the HEPA filters shows a penetration and system bypass < 1% when tested in accordance with Regulatory Guide 1.52, Revision 2, Section C.5.c, and ASME N510-1989 at the system conditions specified below.
| |
| ESF Ventilation System Flowrate (cfm)
| |
| SGT System 1602 to 1958 Control Room Emergency 810 to 990 Filter System
| |
| : b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass < 1% when tested in accordance with Regulatory Guide 1.52, Revision 2, Section C.5.d, and ASME N510-1989 at the system conditions specified below.
| |
| ESF Ventilation System Flowrate (cfm)
| |
| SGT System 1602 to 1958 Control Room Emergency 810 to 990 Filter System (continued)
| |
| Cooper 5.0-11 Amendment No.
| |
| | |
| Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Control Room Envelope Habitability ProQram (continued) personnel receiving radiation exposures in excess of either (a) 5 rem whole body or its equivalent to any part of the body for the duration of the loss-of-coolant accident, or (b) 5 rem total effective dose equivalent (TEDE) for the duration of the fuel handling accident. The program shall include the following elements:
| |
| : a. The definition of the CRE and CRE boundary.
| |
| : b. Requirements for maintaining the CRE boundary in its design condition including configuration control and preventive maintenance.
| |
| : c. Requirements for (i) determining the unfiltered air inleakage past the CRE boundary into the CRE in accordance with the testing methods and at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors,"
| |
| Revision 0, May 2003, and (ii) assessing CRE habitability at the Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0. No exceptions to Sections C.1 and C.2 of Regulatory Guide 1.197, Revision 0, are proposed.
| |
| : d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by the CREF System, operating at the flow rate required by the Ventilation Filter Testing Program, at a Frequency of 24 months. The results shall be trended and used as part of the periodic assessment of the CRE boundary.
| |
| : e. The quantitative limits on unfiltered air inleakage into the CRE. These limits shall be stated in a manner to allow direct comparison to the unfiltered air inleakage measured by the testing described in paragraph c. The unfiltered air inleakage limit for radiological challenges is the inleakage flow rate assumed in the licensing basis analyses of DBA consequences. Unfiltered air inleakage limits for hazardous chemicals must ensure that exposure of CRE occupants to these hazards will be within the assumptions in the licensing basis.
| |
| : f. The provisions of SR 3.0.2 are applicable to the Frequencies for assessing CRE habitability, determining CRE unfiltered air inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively.
| |
| Cooper 5.0-18 Amendment No.
| |
| | |
| NLS2011071 Page 1 of 128 Attachment 4 Proposed Technical Specification Bases Revisions (Information Only)
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| Cooper Nuclear Station, Docket No. 50-298, DPR-46 Revised Technical Specification Bases Pages B 3.1-44 B 3.3-32 B 3.3-93 B 3.3-124 B 3.5-15 B 3.1-50 B 3.3-40 B 3.3-96 B 3.3-125 B 3.5-16 B 3.3-1 B 3.3-41 B 3.3-97 B 3.3-126 B 3.5-29 B 3.3-2 B 3.3-42 B 3.3-98 B 3.3-127 B 3.6-5 B 3.3-3 B 3.3-44 B 3.3-99 B 3.3-128 B 3.6-27 B 3.3-4 B 3.3-45 B 3.3-100 B 3.3-132 B 3.6-28 B 3.3-5 B 3.3-46 B 3.3-102 B 3.3-133 B 3.6-37 B 3.3-6 B 3.3-47 B 3.3-103 B 3.3-134 B 3.6-38 B 3.3-10 B 3.3-50 B 3.3-104 B 3.3-135 B 3.6-44 B 3.3-11 B 3.3-51 B 3.3-105 B 3.3-136 B 3.6-50 B 3.3-13 B 3.3-52 B 3.3-108 B 3.3-164 B 3.6-71 B 3.3-14 B 3.3-53 B 3.3-109 B 3.3-165 B 3.6-78 B 3.3-15 B 3.3-54 B 3.3-110 B 3.3-176 B 3.6-84 B 3.3-17 B 3.3-60 B 3.3-111 B 3.3-183 B 3.7-10 B 3.3-18 B 3.3-61 B 3.3-114 B 3.3-192 B 3.7-16 B 3.3-21 B 3.3-72 B 3.3-115 B 3.3-193 B 3.7-23 B 3.3-24 B 3.3-73 B 3.3-116 B 3.3-203 B 3.7-33 B 3.3-25 B 3.3-78 B 3.3-117 B 3.3-204 B 3.7-34 B 3.3-26 B 3.3-88 B 3.3-118 B 3.3-209 B 3.8-21 B 3.3-27 B 3.3-89 B 3.3-120 B 3.3-210 B 3.8-22 B 3.3-29 B 3.3-90 B 3.3-121 B 3.4-17 B 3.8-23 B 3.3-30 B 3.3-91 B 3.3-122 B 3.5-13 B 3.8-24 B 3.3-31 B 3.3-92 B 3.3-123 B 3.5-14 B 3.8-48
| |
| | |
| BASES INSERTS
| |
| <INSERT 1>
| |
| The Limiting Trip Setpoint (LTSP) is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the Safety Limit (SL) would not be exceeded. As such, the LTSP accounts for uncertainties in setting the channel (e.g., calibration), uncertainties in how the channel might actually perform (e.g., repeatability), changes in the point of action of the channel over time (e.g., drift during surveillance intervals), and any other factors which may influence its actual performance (e.g., harsh accident environments). In this manner, the LTSP ensures that SLs are not exceeded. Therefore, the LTSP meets the definition of an LSSS (Ref. 1).
| |
| Technical Specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility. Operable is defined in Technical Specifications as "...being capable of performing its safety function(s)." Relying solely on the LTSP to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as-found" value of a protection channel setting during a Surveillance. This would result in Technical Specification compliance problems, as well as reports and corrective actions required by the rule which are not necessary to ensure safety.
| |
| For example, an automatic protective protection channel with a setting that has been found to be different from the LTSP due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the LTSP and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as-found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around the LTSP to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, in accordance with uncertainty assumptions stated in the referenced setpoint methodology (as-left criteria), and confirmed to be operating within the statistical allowances of the uncertainty terms assigned (as-found criteria). However, there is also some point beyond which the channel may not be able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
| |
| If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the LTSP (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
| |
| <INSERT 2>
| |
| Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses. These permissives and interlocks ensure that the starting
| |
| | |
| conditions are consistent with the safety analysis, before preventive or mitigating actions occur.
| |
| Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
| |
| <INSERT 3>
| |
| SR 3.3.1.1.9 for Function 3.3.1.1-1.2.d is modified by two Notes as identified in Table 3.3.1.1-1.
| |
| The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program.
| |
| Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the LTSP. Where a setpoint more conservative than the LTSP is used in the plant surveillance procedures (NTSP), 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 LTSP, then the channel shall be declared inoperable. The second Note also requires that LTSPs and the methodologies for calculating the as-left and the as-found tolerances be in the Technical Requirements Manual.
| |
| <INSERT 4>
| |
| Numerous SR 3.3.1.1.10 and 12 functions are modified by two Notes as identified in Table 3.3.1.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the LTSP. Where a setpoint more conservative than the LTSP is used in the plant surveillance procedures (NTSP), 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 LTSP, then the channel shall be declared inoperable. The second Note also requires that LTSPs and the methodologies for calculating the as-left and the as-found tolerances be in the Technical Requirements Manual.
| |
| | |
| <INSERT 5>
| |
| The protection and monitoring functions of the control rod block instrumentation have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters and equipment performance.
| |
| Technical Specifications are required by 10 CFR 50.36 to include LSSS for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated, as established by the safety analysis, to ensure that a Safety Limit (SL) is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
| |
| The Limiting Trip Setpoint (LTSP) is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the LTSP accounts for uncertainties in setting the channel (e.g., calibration), uncertainties in how the channel might actually perform (e.g., repeatability), changes in the point of action of the channel over time (e.g., drift during surveillance intervals), and any other factors which may influence its actual performance (e.g.,
| |
| harsh accident environments). In this manner, the LTSP ensures that SLs are not exceeded.
| |
| Therefore, the LTSP meets the definition of an LSSS (Ref. 1).
| |
| The Allowable Values specified in Table 3.3.2.1-1 serves as the LSSS such that a channel is OPERABLE if the trip setpoint is found not to exceed the Allowable Value. As such, the Allowable Value differs from the trip setpoint by an amount primarily equal to the expected instrument loop uncertainties, such as drift, during the surveillance interval. In this manner, the actual setting of the device will still meet the LSSS definition and ensure that a SL is not exceeded at any given point of time as long as the device has not drifted beyond that expected during the surveillance interval.
| |
| Technical Specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility. Operable is defined in Technical Specifications as "...being capable of performing its safety function(s)." Relying solely on the LTSP to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel setting during a Surveillance. This would result in Technical Specification compliance problems, as well as reports and corrective actions required by the rule which are not necessary to ensure safety.
| |
| For example, an automatic protection channel with a setting that has been found to be different from the LTSP due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the LTSP and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around LTSP to account for further drift during the next
| |
| | |
| surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, in accordance with uncertainty assumptions stated in the referenced setpoint methodology (as-left criteria), and confirmed to be operating within the statistical allowances of the uncertainty terms assigned (as-found criteria).
| |
| However, there is also some point beyond which the channel would have not been able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
| |
| If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the LTSP (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
| |
| <INSERT 6>
| |
| Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses. These permissives and interlocks ensure that the starting conditions are consistent with the safety analysis, before preventive or mitigating actions occur.
| |
| Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
| |
| <INSERT 7>
| |
| Allowable Values are specified for each Rod Block Function specified in SR 3.3.2.1.5. LTSPs and the methodologies for calculation of the as-left and as-found tolerances are described in the Technical Requirements Manual. The LTSPs are selected to ensure that the actual setpoints remain conservative with respect to the as-found tolerance band between successive CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the LTSP.
| |
| LTSPs are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytical limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors.
| |
| The LTSPs are then determined accounting for the remaining instrument errors (e.g., drift). The LTSPs derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
| |
| | |
| The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
| |
| <INSERT 8>
| |
| SR 3.3.2.1.5 for Functions 3.3.2.1-1.1.a, 3.3.2.1-1.1.b and 3.3.2.1-1.1.c is modified by two Notes as identified in Table 3.3.2.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology.
| |
| The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the LTSP. Where a setpoint more conservative than the LTSP is used in the plant surveillance procedures (NTSP), 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 LTSP, then the channel shall be declared inoperable. The second Note also requires that LTSPs and the methodologies for calculating the as-left and the as-found tolerances be in the Technical Requirements Manual.
| |
| <INSERT 9>
| |
| This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the ECCS, as well as LCOs on other reactor system parameters and equipment performance.
| |
| Technical Specifications are required by 10 CFR 50.36 to include LSSS for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated, as established by the safety analysis, to ensure that a Safety Limit (SL) is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
| |
| The Limiting Trip Setpoint (LTSP) is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the LTSP accounts for uncertainties in setting the channel (e.g., calibration), uncertainties in how the channel might actually perform (e.g., repeatability), changes in the point of action of the channel over time (e.g., drift during surveillance intervals), and any other factors which may influence its actual performance (e.g.,
| |
| harsh accident environments). In this manner, the LTSP ensures that SLs are not exceeded.
| |
| Therefore, the LTSP meets the definition of an LSSS (Ref. 1).
| |
| | |
| The Allowable Values specified in Table 3.3.5.1-1 serves as the LSSS such that a channel is OPERABLE if the trip setpoint is found not to exceed the Allowable Value. As such, the Allowable Value differs from the trip setpoint by an amount primarily equal to the expected instrument loop uncertainties, such as drift, during the surveillance interval. In this manner, the actual setting of the device will still meet the LSSS definition and ensure that a SL is not exceeded at any given point of time as long as the device has not drifted beyond that expected during the surveillance interval.
| |
| Technical Specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility. Operable is defined in Technical Specifications as "...being capable of performing its safety function(s)." Relying solely on the LTSP to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel setting during a Surveillance. This would result in Technical Specification compliance problems, as well as reports and corrective actions required by the rule which are not necessary to ensure safety.
| |
| For example, an automatic protection channel with a setting that has been found to be different from the LTSP due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the LTSP and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around LTSP to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, in accordance with uncertainty assumptions stated in the referenced setpoint methodology (as-left criteria), and confirmed to be operating within the statistical allowances of the uncertainty terms assigned (as-found criteria).
| |
| However, there is also some point beyond which the channel would have not been able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
| |
| If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the LTSP (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
| |
| <INSERT 10>
| |
| SR 3.3.5.1.4 for selected functions is modified by two Notes as identified in Table 3.3.5.1-1.
| |
| The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance
| |
| | |
| assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program.
| |
| Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the LTSP. Where a setpoint more conservative than the LTSP is used in the plant surveillance procedures (NTSP), 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 LTSP, then the channel shall be declared inoperable. The second Note also requires that LTSPs and the methodologies for calculating the as-left and the as-found tolerances be in the Technical Requirements Manual.
| |
| <INSERT 11>
| |
| This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RCIC, as well as LCOs on other reactor system parameters and equipment performance.
| |
| Technical Specifications are required by 10 CFR 50.36 to include LSSS for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated, as established by the safety analysis, to ensure that a Safety Limit (SL) is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
| |
| The Limiting Trip Setpoint (LTSP) is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the LTSP accounts for uncertainties in setting the channel (e.g., calibration), uncertainties in how the channel might actually perform (e.g., repeatability), changes in the point of action of the channel over time (e.g., drift during surveillance intervals), and any other factors which may influence its actual performance (e.g.,
| |
| harsh accident environments). In this manner, the LTSP ensures that SLs are not exceeded.
| |
| Therefore, the LTSP meets the definition of an LSSS (Ref. 1).
| |
| The Allowable Values specified in Table 3.3.5.2-1 serve as the LSSS such that a channel is OPERABLE if the trip setpoint is found not to exceed the Allowable Value. As such, the Allowable Value differs from the trip setpoint by an amount primarily equal to the expected instrument loop uncertainties, such as drift, during the surveillance interval. In this manner, the actual setting of the device will still meet the LSSS definition and ensure that a SL is not exceeded at any given point of time as long as the device has not drifted beyond that expected during the surveillance interval.
| |
| Technical Specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility. Operable is defined in Technical Specifications as "...being
| |
| | |
| capable of performing its safety function(s)." Relying solely on the LTSP to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel setting during a Surveillance. This would result in Technical Specification compliance problems, as well as reports and corrective actions required by the rule which are not necessary to ensure safety.
| |
| For example, an automatic protection channel with a setting that has been found to be different from the LTSP due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the LTSP and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around LTSP to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, in accordance with uncertainty assumptions stated in the referenced setpoint methodology (as-left criteria), and confirmed to be operating within the statistical allowances of the uncertainty terms assigned (as-found criteria).
| |
| However, there is also some point beyond which the channel would have not been able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
| |
| If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the LTSP (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
| |
| <INSERT 12>
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| SR 3.3.5.2.3 and SR 3.3.5.2.4 are modified by two Notes as identified in Table 3.3.5.2-1. 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.
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| 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 within the as-left tolerance of the LTSP. Where a setpoint more conservative than the LTSP is used in the plant surveillance procedures (NTSP), 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 LTSP, then the channel shall be declared
| |
| | |
| inoperable. The second Note also requires that LTSPs and the methodologies for calculating the as-left and the as-found tolerances be in the Technical Requirements Manual.
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| INFORMATION ONLY SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS (continued) positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, and detect incipient failures by indicating abnormal performance. The Frequency of this Surveillance is in accordance with the Inservice Testing Program.
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| SR 3.1.7.8 and SR 3.1.7.9 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired. The pump and explosive valve tested should be alternated such 48 that both complete flow paths are tested every 36"onths at alternating month intervals. The Surveillance may be performed in separate 2steps to prevent injecting boron into the RPV. An acceptable method for 2verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. The month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient ifthe Surveillance were performed with the reactor at power. Operating experience has shown thesp neats-ý4 usually pass the Surveillance when performed at the a o-nth Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| Demonstrating that all heat traced piping between the boron solution storage tank and the suction inlet to the injection pumps is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. An acceptable method for verifying that the suction piping is unblocked is to manually initiate the system, except the explosive valves, and pump from the storage tank to the test tank. Upon completion of this verification, the pump suction piping must be flushed 4 with demineralized water to ensure piping between the storage tank and pump suction is unblocked. Th-158 month Frequency is acceptable since there is a low probability that the subject piping will be blocked due to precipitation of the boron from solution in the heat traced piping. This is especially true in light of the temperature verification of this piping Cooper B 3.1-44 09/25/09 INFORMATION ONLY
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| INFORMATION ONLY SDV Vent and Drain Valves B 3.1.8 BASES SURVEILLANCE SR 3.1.8.2 REQUIREMENTS (continued) During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping. Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function properly during a scram. The 92 day Frequency is based on operating experience and takes into account the level of redundancy in the system design.
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| SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the automatic SDV vent and drain valves is verified.
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| The closure time of 30 seconds after receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis.
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| Similarly, after receipt of a simulated or actual scram reset signal, the opening of the SDV vent and drain valves is verified. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of control rods in LCO 3.1.3, "Control Rod Operability," overlap this 24 Surveillance to provide complete testing of the assumed safety function.
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| Th month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and 7the potential for an unplanned transient ifthe Surveillance were performed with the reactor at power. Operating experience has shown
| |
| ,these components usually pass the Surveillance when performed at the 1.8-month Frequency; therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| (continued)
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| Cooper B 3.1-50 June 10, 1999 1 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 B 3.3 INSTRUMENTATION B 3.3.1.1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limits to preserve the integrity of the fuel cladding and the reactor coolant pressure boundary (RCPB) and minimize the energy that must be absorbed following a loss of coolant accident (LOCA).
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| This can be accomplished either automatically or manually.
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| The protection and monitoring functions of the RPS have been designed to ensure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters and equipment performance. The LSSS are defined in th4s Specification a; thc Allowable Values, which-, incnjntion
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| [<INSE T 1 ý> lith
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| _o.-.. ÷ [COs,
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| . ...I. establish
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| ___ __h1
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| ÷....
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| --- -. the threshold
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| . . for *,pretective
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| ,, system L~L~JT~ction t prcvent cxceeeding acceeptable limit-s, inG.l-d-i-.
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| Safety Limits (SLs) during Design Basis Accidcnts (DBAs)j,,
| |
| The RPS, as described in the USAR, Section VII-2 (Ref.
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| includes sensors, relays, bypass circuits, and switches that are necessary to cause initiation of a reactor scram.
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| Functional diversity is provided by monitoring a wide range of dependent and independent parameters. The input parameters to the scram logic are from instrumentation that monitors reactor vessel water level, reactor vessel pressure, neutron flux, main steam line isolation valve position, turbine control valve (TCV) fast closure, trip oil pressure, turbine stop valve (TSV) position, drywell pressure, and scram discharge volume (SDV) water level, as well as reactor mode switch in shutdown position and manual scram signals. There are at least four redundant sensor input signals from each of these parameters (with the exception of the manual scram signal and the reactor mode switch in shutdown scram signal). Most channels include instrumentation that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel outputs an RPS trip signal to the trip logic.
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| (continued)
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| Cooper B 3.3-1 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES BACKGROUND The RPS is comprised of two independent trip systems (continued) (A and B) with three logic channels in each trip system (logic channels Al, A?, and A3, BI, B2, and B3) as shown in Referenck -]. Logic channels A], A2, BI and B2 contain E-l- automatii logic. The above mentioned parameters are represented by at least one input to each of these logic channels. The outputs of the logic channels in a trip system are combined in a one-out-of-two logic so that either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram. This logic arrangement is referred to as a one-out-of-two taken twice logic. In addition to the automatic logic channels, logic channels A3 and B3 (one logic channel per trip system) are provided for manual scram. Both channel push buttons must be depressed to initiate the manual trip function.
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| Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is received. This 10 second delay on reset ensures that the scram function will be completed.
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| Two scram pilot valves are located in the hydraulic control unit for each control rod drive (CRD). Each scram pilot valve is solenoid operated, with the solenoids normally energized. The scram pilot valves control the air supply to the scram inlet and outlet valves for the associated CRD.
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| When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to scram. The scram valves control the supply and discharge paths for the CRD water during a scram. One of the scram pilot valve solenoids for each CRD is controlled by trip system A, and the other solenoid is controlled by trip system B. Any trip of trip system A in conjunction with any trip in trip system B results in de-energizing both solenoids, air bleeding off, scram valves opening, and control rod scram.
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| The backup scram valves, which energize on a scram signal to depressurize the scram air header, are also controlled by the RPS. Additionally, the RPS System controls the SDV vent and drain valves such that when both trip systems trip, the SDV vent and drain valves close to isolate the SDV.
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| (continued)
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| Cooper B 3.3-2 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES (continued) 2,34,and 5 APPLICABLE The actionof the RPS are assumed in the safety analyses of SAFETY ANALYSES, References , 2, R3,and 4 . The RPS is required to initiate LCO, and a reactor scram when monitored parameter values emeeed the APPLICABILITY Allowable Valus, specified by the setpoint methodology and la exeeed 4 izted In4Table 3.3.1.1 1 to preserve the integrity of the lcareeeded fuel cladding, the reactor coolant pressure boundary (RCPB),
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| and the containment by minimizing the energy that must be absorbed following a LOCA.
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| RPS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (c)(2)(ii) (Ref. &). Functions not specifically credited in the accident analysis are retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
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| I
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| <INSERT 2>1]J >
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| The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions setting specified in Table 3.3.1.1-1. Each Function must have a toleranceofi se ruirtdnlmhPr nfAPERABLE channels per RPS trip system, tEdLTSPs with their setpoints within the specified Allowable Value--I Table 3.3.1.1-1. Limit where appropriate. The actual setpoint is calibrated Trip Setpoints and the consistent with applicable setpoint methodology assumptions.
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| methodologies for Each channel must also respond within its assumed response calculation of the as-l ?ft time, where appropriate. [umentation and as-found toleranc are described in the Allowable Values ae sper.444ek as appropriatc, torRPS Technical Requiremel ts unctions specified in the Table. Nominal trip setpe.i..
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| Manual. e_ 4 te iie etoit alulti 7The sepe remain conservative NEC 31336P-4, "Gneral El.ectric instrument S.tp..t . LTM.
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| with foundrespect toleranc to the as-band I Methed~e1egy-,-j'
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| ýý I.....
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| ea i dated
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| ... September
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| ....... 1996. The .........nominal setpaints~-*
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| 4 i
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| u e are e selected to ensure that the actual setpoints de-not ex.... th .lo. bl alue...... between successive CHANNEL Aftereach calibration CALIBRATIONS. Operation with a trip setp.int less the trip setpoint shall G.onseryati. e than the nominal trip stpo- t, but within its be left within the as- A! ,,owab e Value, ' ..... ' 4-e- A -hannc. is 4inperable if left band around the its actual trip .etp.intis not within its- required LT S P . Al l o wabl e V al ue ;
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| L s Tripse-tpie-R-si.f are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device changes state. The limits are derived from (continued)
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| Cooper B 3.3-3 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES APPLICABLE the limiting values of the process parameters obtained from SAFETY ANALYSES, the safety analysis or other appropriate documentsanalyticalI LCO, and The Allowable Values are derived from the an;lyi4-4imits,' -- '
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| APPLICABILITY corrected for calibration, process, and some of the (continued) instrument errors Th44p se-tpe4-t. are then determined dor the remaining instrument errors (e.g.,
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| r ift). eTtrip setpei4ts derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
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| The OPERABILITY of scram pilot valves and associated solenoids, backup scram valves, and SDV valves, described in the Background section, are not addressed by this LCO.
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| The individual Functions are required to be OPERABLE in the MODES or other Conditions specified in the table, which may require an RPS trip to mitigate the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Fu..t..... are required in each MODE to provide primary and diversi t Ifunctionsl ns The only MODES specified in Table 3.3.1.1-1 are MODES 1 and 2 and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4 since, all control rods are fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow any control rod to be withdrawn. In MODE 5, control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and, therefore, are not required to have the capability to scram. Provided all other control rods remain inserted, no RPS Function is required. In this condition, the required SDM (LCO 3.1.1) and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS will occur.
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| The trip that results from the removal of a circuit card is a basic design feature of selected circuits. This feature is excluded from periodic testing in order to minimize component wear and damage.
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| (continued)
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| Cooper B 3.3-4 Revision I INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES APPLICABLE The specific Applicable Safety Analyses, LCO, and SAFETY ANALYSES, Applicability discussions are listed below on a Function by LCO, and Function basis.
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| APPLICABILITY (continued) Intermediate Range Monitor (IRM) 1.a. Intermediate Range Monitor Neutron Flux-High The IRMs monitor neutron flux levels from the upper range of the source range monitor (SRM) to the lower range of the average power range monitors (APRMs). The IRMs are capable of generating trip signals that can be used to prevent fuel damage resulting from abnormal operating transients in the intermediate power range. In this power range, the most significant source of reactivity change is due to control rod withdrawal. The IRM provides diverse protection from the rod worth minimizer (RWM), which monitors and controls the movement of control rods at low power. The RWM prevents the withdrawal of an out of sequence control rod during startup that could result in an unacceptable neutron flux excursion Ref. ). The IRM provides mitigation of the I]- Heutron flux e -cursion. To demonstrate the capability of the IRM System to mitigate control rod withdrawal events, i generic analyses have been performed (Ref. 3-)416o evaluateLJ the consequences of control rod withdrawal events during startup that are mitigated only by the IRM. The contin rod withdrawal during reactor startup analysis (Refs. 27nd Ii--.-), which assumes that one IRM channel in each trip system is bypassed, demonstrates that the IRMs provide protection against local control rod withdrawal errors and results in peak fuel enthalpy below the 170 cal/gm fuel failure threshold criterion.
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| The IRMs are also capable of limiting other reactivity excursions during startup, such as cold water injection events, although no credit is specifically assumed.
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| The IRM System is divided into two groups of IRM channels, with four IRM channels inputting to each trip system. The analysis of Reference43 assumes that one channel in each trip system is bypassed. Therefore, six channels with three channels in each trip system are required for IRM OPERABILITY to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This (continued)
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| Cooper B 3.3-5 Revision 1 INFORMATION ONLY
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| INFORMATION ONLY .RPS Instrumentation B 3.3.1.1 BASES APPLICABLE L.a. Intermediate Range Monitor Neutron Flux-High SAFETY ANALYSES (continued)
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| LCO, and APPLICABILITY trip is active in each of the 9 ranges of the IRM, which must be selected by the operator to maintain the neutron flux within the monitored level of an IRM range.
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| The analysis of Reference Ahas adequate conservatism to permit an IRM Allowable Value of 121 divisions of a 125 division scale.
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| The Intermediate Range Monitor Neutron Flux-High Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential for criticality exists. In MODE 5, when a cell with fuel has its control rod withdrawn, the IRMs provide monitoring for and protection against unexpected reactivity excursions. In MODE 1, the APRM System and the RWM provide protection against control rod withdrawal error events and the IRMs are not required. An IRM is automatically bypassed when the mode switch is in the "Run" position and its companion APRM is above its downscale trip setpoint.
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| 1.b. Intermediate Range Monitor-Inop This trip signal provides assurance that a minimum number of IRMs are OPERABLE. Anytime an IRM mode switch is moved to any position other than "Operate," the detector voltage drops below a preset level, loss of the negative or positive DC voltages, or when a module is not plugged in, an inoperative trip signal will be received by the RPS unless the IRM is bypassed. Since only one IRM in each trip system may be bypassed, only one IRM in each RPS trip system may be inoperable without resulting in an RPS trip signal.
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| This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
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| Six channels of Intermediate Range Monitor-Inop with three channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.
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| (continued)
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| Cooper B 3.3-6 Revision 1 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY 2.b. Average Power Rangqe Monitor Neutron Flux-Hiqh (Flow Biased)
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| (continued)
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| The Average Power Range Monitor Neutron Flux-High (Flow Biased)
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| Function is required to be OPERABLE in MODE 1 when there is the possibility of generating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR SL). During MODES 2 and 5, other IRM and APRM Functions provide protection for fuel cladding integrity.
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| 2.c. Average Power Range Monitor Neutron Flux-High (Fixed)
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| The APRM channels provide the primary indication of neutron flux within the core and respond almost instantaneously to neutron flux increases.
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| The Average Power Range Monitor Neutron Flux-High (Fixed) Function is capable of generating a trip signal to prevent fuel damage or excessive Reactor Coolant System (RCS) pressure. For the overpressurization
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| [] protection analysis 0? H(eferenc*, the Average Power Range Monitor Neutron Flux-High (Fixed) Function is assumed to terminate the main steam isolation valve (MSIV) closure event and, along with the safety/relief valves (SRVs), limits the peak reactor pressure vessel (RPV)
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| [fl pressure to less than the ASME Code limits. The control rod drop accident (CR DA) analysis (R*eŽ7) takes credit for the Average Power Range Monitor Neutron Flux-High (Fixed) Function to terminate the CRDA.
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| The APRM System is divided into two groups of channels with three APRM channels inputting to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel in a trip system can cause the associated trip system to trip.
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| Four channels of Average Power Range Monitor Neutron Flux-High (Fixed) with two channels in each trip system arranged in a one-out-of-Cooper B 3.3-10 6/7/02 INFORMATION ONLY
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| INFORMATION ONLY RPS. Instrumentation 17 t B 3.3.1.1 BASES APPLICABLE 2.c. Average Power Range Monitor Neutron Flux-High (Fixed)
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| SAFETY ANALYSES, (continued)
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| LCO, and APPLICABILITY two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 11 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located.
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| The Allowable Value is based on the Analytical Limit assumed in the CRDA analyses.
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| The Average Power Range Monitor Neutron Flux-High (Fixed)
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| Function is required to be OPERABLE in MODE I where the potential consequences of the analyzed transients could result in the SLs (e.g., MCPR and RCS pressure) being exceeded. Although the Average Power Range Monitor Neutron igh (Fixed) Function is assumed in the CRDA analysis (Rel?'-), which is applicable in MODE 2, the Average Power Range Monitor Neutron Flux-High, (Startup) Function conservatively bounds the assumed trip and, together with the assumed IRM trips, provides adequate protection.
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| Therefore, the Average Power Range Monitor Neutron Flux-High (Fixed) Function is not required in MODE 2.
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| 2.d. Averaae Power Rance Monitor-Downscale This signal ensures that there is adequate Neutron Monitoring System protection if the reactor mode switch is placed in the run position prior to the APRMs coming on scale. With the reactor mode switch in run, an APRM downscale signal coincident with an associated Intermediate Range Monitor Neutron Flux-High or Inop signal generates a trip signal. This Function was not specifically credited in the accident analysis but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
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| The APRM System is divided into two groups of channels with three inputs into each trip system. The system is designed to allow one channel in each trip system to be bypassed.
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| Four channels of Average Power Range Monitor-Downscale with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no (continued)
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| Cooper B 3.3-11 Revision 1 1 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation
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| ; ~B3.3.1.1 BASES APPLICABLE 2.e. Average Power Range Monitor-Inop (continued)
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| SAFETY ANALYSES, LCO, and This Function is required to be OPERABLE in the MODES where APPLICABILITY the APRM Functions are required.
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| : 3. Reactor Vessel Pressure-High An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This causes the neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. No specific safety analysis takes direct credit for this Function. However, the Reactor Vessel Pressure-High Function initiates a scram for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core power. For,1-the overpressurization protection analysis of Reference 6,fz-'
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| reactor scram (the analyses conservatively assume scram on the Average Power Range Monitor Neutron Flux-High (Fixed) signal, not the Reactor Vessel Pressure-High signal), along with the SRVs, limits the peak RPV pressure to less than the ASME Section III Code limits.
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| High reactor pressure signals are initiated from four
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| -. -pressure switches that sense reactor pressure. The Reactor Vessel Pressure-High Allowable Value is chosen to provide a sufficient margin to the ASME Section III Code limits during the event.
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| Four channels of Reactor Vessel Pressure-High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is required to be OPERABLE in MODES 1 and 2 when the RCS is pressurized and the potential for pressure increase exists.
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| : 4. Reactor Vessel Water Level-Low (Level 3)
| |
| Low RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, a reactor scram is initiated at Level 3 to substantially reduce the heat (continued)
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| Cooper B 3.3-13 Revision 1 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 4. Reactor Vessel Water Level-Low, Level 3 (continued)
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| SAFETY ANALYSES, LCO, and generated in the fuel from fission. The Reactor Vessel APPLICABILITY Water Level-Low (Level 3) Function is assumed in the analysis of a loss of feedwater flow (Ref. &)S-- Tle reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| Reactor Vessel Water Level-Low (Level 3) signals are initiated from four level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
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| Four channels of Reactor Vessel Water Level-Low (Level 3)
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| Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.
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| The Reactor Vessel Water Level-Low (Level 3) Allowable Value is selected to ensure that during normal operation the separator skirts are not uncovered (this protects available recirculation pump net positive suction head (NPSH) from significant carryunder) and, for transients involving loss of all normal feedwater flow, initiation of the low pressure ECCS subsystems at Reactor Vessel Water-Low Low Low (Level 1) will not be required.
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| The Function is required in MODES 1 and 2 where considerable energy exists in the RCS resulting in the limiting transients and accidents. ECCS initiations at Reactor Vessel Water Level-Low Low (Level 2) and Low Low Low (Level 1) provide sufficient protection for level transients in all other MODES.
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| : 5. Main Steam Isolation Valve-Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the nuclear steam supply system and indicates a need to shut down the reactor to reduce heat generation. Therefore, a reactor scram is initiated on a Main Steam Isolation Valve-Closure signal before the MSIVs (continued)
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| Cooper B 3.3-14 Revision I INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 5. Main Steam Isolation Valve-Closure (continued)
| |
| SAFETY ANALYSES, LCO, and are completely closed in anticipation of the complete loss APPLICABILITY of the normal heat sink and subsequent overpressurization 71] transient. However, for the overpressurization protection analysis of Reference&, the Average Power Range Monitor Neutron Flux-High (Fixed) Function, along with the SRVs, limits the peak RPV pressure to less than the ASME Code limits. That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis.
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| The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
| |
| MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B. Each RPS trip system receives an input from four Main Steam Isolation Valve-Closure channels, each consisting of two position switches (one for the inboard MSIV and one for the outboard MSIV in the same steam line) in series with a sensor relay. The logic for the Main Steam Isolation Valve-Closure Function is arranged such that either the inboard or outboard valve on three or more of the main steam lines must close in order for a scram to occur. The design permits closure of any two lines without a full scram being initiated.
| |
| The Main Steam Isolation Valve-Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient.
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| Eight channels of the Main Steam Isolation Valve-Closure Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a valid signal. This Function is only required in MODE I since, with the MSIVs open and the heat generation rate high, a pressurization transient can occur if the MSIVs close. In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.
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| (continued)
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| Cooper B 3.3-15 Revision I I INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES APPLICABLE, SAFETY ANALYSES, LCO, and APPLICABILITY (continued) system from each SDV. The level measurement instrumentation satisfies the recommendations of Reference 8*---r The Allowable Value is chosen low enough to ensure that there is sufficient volume in each SDV to accommodate the water from a full scram.
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| For each Scram Discharge Volume Water Level-High Function (i.e., for each SDV), there is one channel of each type (type 7.a and 7.b) in each trip system. Since Table 3.3.1.1-1 provides the total number of required channels per trip system for both SDVs, a total of two required channels of each type per trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.
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| : 8. Turbine Stop Valve-Closure Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of the transients that would result from the closure of these valves. The Turbine Stop Valve-Closure Function is the primary scram
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| ,7 signal for the turbine trip and feedwater controller failure maximum demand events analyzed in Rfeterenc?2'-. For this event, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not exceeded.
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| Turbine Stop Valve-Closure signals are initiated from position switches located on each of the two TSVs. Two independent position switches are associated with each stop valve. Both of the switches from one TSV provide input to RPS trip system A; the two switches from the other TSV provide input to RPS trip system B. Thus, each RPS trip system receives two Turbine Stop Valve-Closure channel inputs from a TSV, each consisting of one position switch assembly with two contacts, each inputting to a relay. The relays provide a parallel logic input to an RPS trip logic channel. The logic for the Turbine Stop Valve-Closure Function is such that both TSVs must be closed to produce a scram. Single valve Cooper B 3.3-17 08/28/08 INFORMATION ONLY
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| IN FORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES APPLICABLE, SAFETY ANALYSES, LCO, and APPLICABILITY (continued) closure will produce a half scram. This Function must be enabled at THERMAL POWER > 29.5% RTP as measured by turbine first stage pressure. This is accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this Function.
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| The Turbine Stop Valve-Closure Allowable Value is selected to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.
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| Four channels of Turbine Stop Valve-Closure Function, with two channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if both TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is > 29.5% RTP. This Function is not required when THERMAL POWER is < 29.5% RTP since the Reactor Vessel Pressure-High and the Average Power Range Monitor Neutron Flux-High (Fixed) Functions are adequate to maintain the necessary safety margins.
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| : 9. Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-7-1 Low Function is the primary scram signal for the generator load rejection event analyzed in Referencr.. For this event, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not exceeded.
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| Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low signals are initiated by low digital-electrohydraulic control (DEHC) fluid pressure in the emergency trip header for the control valves. There are four pressure switches which sense off the common header, with one pressure switch assigned to each separate RPS logic channel. This Function must be enabled at THERMAL POWER > 29.5% RTP as measured by turbine first stage pressure. This is accomplished automatically by pressure switches sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this Function.
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| Cooper B 3.3-18 07/16/08 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES ACTIONS (continued)
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| A.1 and A.2 Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out 9f servie .. 11 12 hours has been shown to be acceptable (Ref. -0o permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternatively, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Condition D must be entered and its Required Action taken.
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| B.1 and B.2 Condition B exists when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE, the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system. For Items 7.a and 7.b (Scram Discharge Volume Water Level - High, Level Transmitter and Level Switch), entry into Condition B is required when at least one channel (either an Item 7.a or 7.b channel) is inoperable in each trip system associated with one SDV.
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| Required Actions B.1 and B.2 limit the time the RPS scram logic, for any Function, would not accommodate single failure in both trip systems (e.g.,
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| one-out-of-one and one-out-of-one arrangement for a typical four channel E11 Function). The reduce* reliability of this logic arrangement was not evaluated in Referenc=-, 0 for the 12 hour Completion Time. Within the 6 hour allowance, the associated Function will have all required channels OPERABLE or in trip (or any combination) in one trip system.
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| Completing one of these Required Actions restores RPS to a reliability level equivalent to that evaluated in Refer , which justified a Cooper B 3.3-21 June 28, 2001 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES ACTIONS (continued)
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| H.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.
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| SURVEILLANCE REQUIREMENTS As noted at the beginning of the SRs, the SRs for each RPS instrumentatien Function are located in the SRs column of Table 3.3.1.1-1.
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| The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref.
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| assumption of the average time required to perform channel Surveillances. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RPS will trip when necessary.
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| Cooper B 3.3-24 June 28, 2001 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.1.1.1 Performance of the CHANNEL CHECK once every 12 hours 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 re, the-approximately the same value. Significant deviations betweerýnstrument channels could be an indication of excessive instrument drift othe channels or something even more serious. A CHANNEL CHECK wlF"92.j_
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| 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 plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.
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| The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
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| SR 3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading between performances of SR 3.3.1.1.8.
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| A restriction to satisfying this SR when < 25% RTP is provided that requires the SR to be met only at > 25% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 25% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large, inherent margin to thermal limits (MCPR and APLHGR). At > 25% RTP, the Cooper B 3.3-25 June 28, 2001 I INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| Surveillance is required to have been satisfactorily performed within the last 7 days, in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after reaching or exceeding 25% RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.
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| SR 3.3.1.1.3 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
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| As noted, SR 3.3.1.1.3 is not required to be performed when entering MODE 2 from MODE 1, since testing of the MODE 2 required IRM and APRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the 7 day Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after entering MODE 2 from MODE 1.
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| Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.
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| A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 4.461[.
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| Cooper B 3.3-26 June 28, 2001 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.11 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.1.1.4 There are four RPS channel test switches, one associated with each of the four automatic scram logic channels (Al, A2, B1, and B2). These keylock switches allow the operator to test the OPERABILITY of each individual logic channel (i.e., test through the K14 relay) without the necessity of using a scram function trip. This is accomplished by placing the RPS channel test switch in test, which will input a trip signal into the associated RPS logic channel. The RPS channel test switches are not specifically credited in the accident analysis. However, because the
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| [1] Manual Scram Functions at CNS were not configured the same as the generic model in Referenc+"40, the RPS-channel test switches were 12 included in the analysis in Reference that the Survefliance Frequency extensions for RPS Functions, described in Reference-Z*-, were not affected by the difference in configuration, since each automatic RPS channel has a test switch which is functionally the same as the manual scram switches in the generic model. As such, a functional test of each RPS channel test switch is required to be performed once every 7 days. The Frequency of 7 days is based on the reliability analysis of Reference -4.1-, 2 SR 3.3.1.1.5 and SR 3.3.1.1.6 These Surveillances are established to ensure that no gaps in neutron flux indication exist from subcritical to power operation for monitoring core reactivity status, The overlap between SRMs and IRMs is required to be demonstrated to ensure that reactor power will not be increased into a neutron flux region without adequate indication. This is required prior to withdrawing SRMs from the fully inserted position since indication is being transitioned from the SRMs to the IRMs.
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| The overlap between IRMs and APRMs is of concern when reducing power into the IRM range. On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained. Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRM downscale rod block, or IRM upscale rod block. On controlled shutdowns, the IRM reading 121/125 of full scale will be set equal to or less than 45% of rated power. All range scales above that scale on Cooper B 3.3-27 June 28, 2001 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.1.1.9 and SR 3.3.1.1.11 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The 92 day Frequency of SR 3.3.1.1.9 is based on the reliability analysis of 24 Reference +-.9*-------_ "-
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| Th 14 month Frequency of SR 3.3.1.1.11 is based on the need to perform some of the surveillance procedures which satisfy this SR under I the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power. Testing of Function 10 requires placing the mode switch in "Shutdown". Operating experience has shown that these omponents usually pass the Surveillance when performed at the I<INSERT>33I1* month Frequency.
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| -<NE-8 SR 3.3.1.1.10 and SR 3.3.1.1.12 te eLTSP wtinc the A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accur c CHANNEL CALIBRATION leaves the channel adjusted to count for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. Physical inspection of the position switches is performed in conjunction with SR 3.3.1,1.12 for Functions 5, 7.b, and 8 to ensure that the switches are not corroded or otherwise degraded.
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| Note 1 of SR 3.3.1.1.10 and SR 3.3.1.1.12 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the 7 day calorimetric calibration (SR 3.3.1.1.2) and the 1000 MWD/T LPRM calibration against the TIPs Cooper 02/20/07 INFORIA-I N ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| (SR 3.3.1.1.8). Note 1 of SR 3.3.1.1.10 states that recirculation loop flow transmitters are excluded from CHANNEL CALIBRATION. This exclusion is based on calculation results and site-sp cific instrument a24 setpoint drift data, which alternately supports a4.8Gonth calibration interval for the recirculation loop flow transmitters. As such, the flow transmitters are calibrated on an,-I8-.month frequency as required by SR 3.3.1.1.12 for Function 2 a 42 A second Note to SR 3.3.1.1.12 is provided that requires the APRM and IRM SRs to be performed within 12 hours of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM and IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.
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| The Frequency of SR 3.3.1.1.10 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1.1.12 is based upon the assumption of month calibration interval in the determination of the magnitude o quipment drift in the setpoint analysis.
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| J<INSERT4ý> 2 S R 3.3.1.1.13 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods (LCO 3.1.3), and SDV vent and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed safety function.
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| [Z' Th -18month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| Operating experience has shown that these components usually pass the Surveillance when performed at the 4-- month Frequency.
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| C Cooper INFORMX'fi1-N ONLY 02/20/07
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.1.1.14 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is > 29.5% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the main turbine bypass valves must remain closed during an in-service calibration at THERMAL POWER > 29.5% RTP to ensure that the calibration is valid.
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| If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at > 29.5% RTP, then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Open main turbine bypass valve(s) can also affect these two functions. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass).
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| If placed in the nonbypass condition, this SR is met and the channel is csidered OPERABLE.
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| The Frequency l-8. months is based on engineering judgment and reliability of the components.
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| SR 3.3.1.1.15 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. This test may be performed in one measurement or in overlapping segments, with verification that all components are tested. The RPS RESPONSE TIME acceptance criteria are included in Reference I4--2 Fi]
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| As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an 2 instantaneous response time.
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| The month Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.
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| Cooper B 3.3-31 07/16/08 INFORMATION ONLY
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| INFORMATION ONLY RPS Instrumentation B 3.3.1.1 BASES
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| - l1. Regulatory Guide 1.105, "Setpoints for Safety-REFERENCES 2.m 1-. USAR, Section VII-2. Related Instrumentation," Revision 3.
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| 3.
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| USAR, Chapter XIV.
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| : 3. NEDO-23842, "Continuous Control Rod Withdrawal in the 4.
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| Startup Range," April 18, 1978.
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| : 5. 4. USAR, Section VI-5.
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| : 6. 10 CFR 50.36(c)(2)(ii).
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| 6..
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| : 7. USAR, Section IV-4.9.
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| : 8. 7-. USAR, Section XIV-6.2.
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| : 9. 8. USAR, Section XIV-5.4.3.
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| : 10. 9. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.
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| 11.
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| NEDO-30851-P-A, "Technical Specification Improvement Analyses 1-4. for BWR Reactor Protection System," March 1988.
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| : 12. MDE-94-0485, "Technical Specification Improvement Analysis for the Reactor Protection System for Cooper Nuclear Station," April 1985.
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| : 13. USAR, VII-2.3.9.10.
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| Cooper B 3.3-32 June 28, 2001 1 INFORMATION ONLY
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| INFORMATION ONLY SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| CHANNEL CHECK), that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.
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| SR 3.3.1.2.6 is required in MODE 2 with IRMs on Range 2 or below, and in MODES 3 and 4. Since core reactivity changes do not normally take place in MODES 3 and 4, and core reactivity changes are due only to control rod movement in MODE 2, the Frequency has been extended from 7 days to 31 days. The 31 day Frequency is based on operating experience and on other Surveillances (such as CHANNEL CHECK) that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.
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| Verification of the signal to noise ratio also ensures that the detectors are inserted to an acceptable operating level. In a fully withdrawn condition, the detectors are sufficiently removed from the fueled region of the core to essentially eliminate neutrons from reaching the detector. Any count rate obtained while the detectors are fully withdrawn is assumed-to be "noise" only. An alternative to fully withdrawing the detector is to configure the assembly cabling such that only the noise signal is observed.
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| The Note to SR 3.3.1.2.6 allows the Surveillance to be delayed until entry into the specified condition of the Applicability (THERMAL POWER decreased to IRM Range 2 or below). The SR must be performed within 12 hours after IRMs are on Range 2 or below. The allowance to enter the Applicability with the 31 day Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels.
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| Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e.,
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| satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.
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| SR 3.3.1.2.7 Performance of a CHANNEL CALIBRATION at a Frequency of
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| -1 months verifies the performance of the SRM detectors and associated circuitry. The Frequency considers the plant conditions required to perform the test, the ease of performing the test, and the likelihood of a change in the system or component status. The neutron detectors are excluded from the CHANNEL CALIBRATION (Note 1) because they cannot readily be adjusted. The detectors are fission chambers that are Cooper INFORMATJQN ONLY 11/04/06
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| INFORMATION ONLY SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued) designed to have a relatively constant sensitivity over the range and with an accuracy specified for a fixed useful life.
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| Note 2 to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be There is a plant specific performed in MODE 2 within 12 hours of entering MODE 2 with IRMs onjF'*
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| program which verifies Range 2 or below. The allowance to enter the Applicability with the 4 -
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| that the instrument month Frequency not met is reasonable, based on the limited time of 12 channel functions as hours allowed after entering the Applicability and the inability to perform required by verifying the the Surveillance while at higher power levels. Although the Surveillance as-left and as-found could be performed while on IRM Range 3, the plant would not be settings are consistent expected to maintain steady state operation at this power level. In this with those established by the setpoint methodology, event, the 12 hour Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.
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| REFERENCES None.
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| Cooper B 3.3-41 June 28, 2001 I INFORMATION ONLY
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| INFORMATIONo NoI. od Block Instrumentation B 3.3.2.1 B 3.3 INSTRUMENTATION B 3.3.2.1 Control Rod Block Instrumentation BASES BACKGROUND Control rods provide the primary means for control of reactivity changes. Control rod block instrumentation includes channel sensors, logic circuitry, switches, and relays that are designed to ensure that specified fuel design limits are not exceeded for pestulated transients and accidents. During high power operation, the rod block monitor (RBM) provides protection for control rod withdrawal error events. During low power operations, control rod blocks from the rod worth minimizer (RWM) enforce specific control rod sequences designed to mitigate the consequences of the control rod drop accident (CRDA). During shutdown conditions, control rod blocks from the Reactor Mode Switch-Shutdown Position Function ensure that all control rods remain inserted to prevent inadvertent criticalities.
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| [<INSERT 5>1- -
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| The purpose of the RBM is to limit control rod withdrawal if localized neutron flux exceeds a predeter ined setpoint during control rod manipulations (Ref. i-s assumed to function to block further control rod withdrawal to preclude a MCPR Safety Limit (SL) violation. One set of power referenced RBM upscale trip settings (Low Trip Set Point, LTSP; Intermediate Trip Set Point, ITSP; and High Trip Set Point, HTSP) is applied based on the Lowest Rated MCPR Limit given in the COLR. The RBM supplies a trip signal to the Reactor Manual Control System (RMCS) to appropriately inhibit control rod withdrawal during power operation above the low power range setpoint. The RBM has two channels, either of which can initiate a control rod block when the channel output exceeds the control rod block setpoint. One RBM channel inputs into one RMCS rod block circuit and the other RBM channel inputs into the second RMCS rod block circuit. The RBM channel signal is generated by averaging a set of local power range monitor (LPRM) signals at various core heights surrounding the control rod being withdrawn.
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| Upon selection of a certain rod for withdrawal or insertion, the conditioned LPRM signals around that rod are automatically fed into the two RBM channels. Each channel averages two B-position, two D-position and the same four C-position LPRM inputs. The RBM Channel A is powered by the RPS power bus "A" and the RMB Channel B is powered by the RPS power bus "B". A-position LPRMs are not included in the (continued)
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| Cooper B 3.3-42 Revision 0 INFORMATION ONLY
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| No Changes I FORMATION ON LXroi Rod Block Instrumentation Included for Comnleteness B 3.3.2.1 BASES BACKGROUND (continued)
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| RBM averaging but remain in the display and LPRM alarm logic.
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| Assignment of power range detector assemblies to be used in RBM averaging is controlled by the selection of control rods. The minimum number of LPRM inputs required to each RBM channel to prevent an instrument inoperative alarm is four when using eight LPRM assemblies, three when using six LPRM assemblies, and two when using four LPRM assemblies. The RBM is automatically bypassed and the output set to zero if a peripheral control rod is selected since the RBM function is not required for these rods. In addition, any one of the two RBM channels can be manually bypassed. If any LPRM detector assigned to a RBM is bypassed, the computed average signal is adjusted automatically to compensate for the number of LPRM input signals to average. When a control rod is selected, the signal conditioner gain is automatically adjusted so that the output level of the signal conditioner always corresponds to a constant level (relative to the initialization reference signal of 100/125 of full scale). The gain set will be held constant during the movement of that rod, thus providing an indication of the change in the relative local power level. Whenever the reactor power level is below the lowest RBM operating range, the RBM is zeroed and RBM outputs are bypassed. If the indicated power increases above the preset limit, a rod block will occur. In addition, to preclude rod movement with an inoperable RBM, a downscale trip and an inoperative trip are provided. A rod block signal is generated if an RBM downscale trip or an inoperable trip occurs, since this could indicate a problem with the RBM channel.
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| The downscale trip will occur if the RBM channel signal decreases below the downscale trip setpoint after the RBM channel signal has been normalized. The inoperable trip will occur during the nulling (normalization) sequence, ifthe RBM channel fails to null, too few LPRM inputs are available, a module is not plugged in, or the function switch is moved to any position other than "Operate."
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| The purpose of the RWM is to control rod patterns during startup and shutdown, such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to 9.85% RTP. The sequences effectively limit the potential amount and rate of reactivity increase during a CRDA. Prescribed control rod sequences are stored in the RWM, which will initiate control rod withdrawal and insert blocks when the Cooper B 3.3-43 07116/08 INFORMATION ONLY
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| INFORMATION' ! I)r od Block Instrumentation B 3.3.2.1 BASES BACKGROUND actual sequence deviates beyond allowances from the stored (continued) sequence. The RWM determines the actual sequence based position indication for each control rod. The RWM also uses feedwater flow and steam flow signals to determine when the reactor power is above the preset power level at which the RWM is automatically bypassed (Ref. -). The RWM is a single channel system that provides input)Into both RMCS rod block circuits. [-
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| With the reactor mode switch in the shutdown position, a control rod withdrawal block is applied to all control rods to ensure that the shutdown condition is maintained. This Function prevents inadvertent criticality as the result of a control rod withdrawal during MODE 3 or 4, or during MODE 5 when the reactor mode switch is required to be in the shutdown position. The reactor mode switch has two channels, each inputting into a separate RMCS rod block circuit. A rod block in either RMCS circuit will provide a control rod block to all control rods.
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| [<INSERT 6>D I<INSERT 7>j APPLICABLE 1. Rod Block Monitor SAFETY ANALYSES, LCO, and The RBM is designed to prevent violation of the MCPR APPLICABILITY SL and the cladding 1% plastic strain fuel design limit that may result from a single control rod withdrawal error (RWE) event. The analytical methods and assumptions used in 4 evaluating the RWE event are summarized in Reference X. A statistical analysis of RWE events was performed to determine the RBM response for both channels for each event.
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| From these responses, the fuel thermal performance as a function of RBM Allowable Value was determined. The Allowable Values are chosen as a function of power level.
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| Based on the specified Allowable Values, operating limits are established.
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| The RBM Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 4-)------[A Two channels of the RBM are required to be OPERABLE, with their setpoints within the appropriate Allowable Values, to ensure that no single instrument failure can preclude a rod block from this Function. The actual setpoints are calibrated consistent with applicable setpoint methodology.
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| (continued)
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| Cooper B 3.3-44 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| NomFinal trip setpoints are S198Gificd in the setpaint csalculations. The setpoint caIculations are perefrmed using methodology describeed in NEDC 31336P A, "General Eloctric InStr'-ment Setpicnt Methodology,"
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| dated Soptenmber 1006. The nominal setpeinte arc cceleetcd to @nsR6 that the otpoin~tG EIo not eXceed the Allowva-bl 6 ValuecN between Succeceive CHANNELk CAI=IBRAT!IONS. Oper~ation with a trip satpoin ccc
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| . .nservatiy- than the nominal trip 6tpoint, but within its Allowabo Value, is acoptablc. Trip G8,tP,1it* arc these predetormlned valu", of
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| +f-, +t ý, ,k;,L i., +;nfs 1li, 1A1f 1 nlr-1a T-ioc #nrqI nrn rnmor te the actual procccss parameter (eg.ractor power), anAd whMA the m.ea.ured output valuef the proccos parameter eXceeds the setpe...,
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| the associated device changes state. The analYtic limits are derived from the limiting valuer, of the process par@ameters obtafined froM the safety eatlaysis. The Allewalgte e4~s arc dcrived ferom the analytic, lim~ito, ecrroctedl f9r calibration, proccess, and some of the instrumenRt errors The !rip sctpeintc rat then d8t*rMiRnd accounting far the.. Mai;;i*n instrument crrcrc (e.g., drift), Th11 trip Getpeints deriVed in this mannr provide adequate protoctinm beAuc ismmnat ucrtitis F. ..6-. 081 .. . fn .. ..
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| eeaesjst--~;tditad6vr . .. --
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| en..ronment OrrorS (for .hanRnolthat mu.t func .tion in.. h onviranments ac defined by 0 CF.R 60.49) We accounted fo..
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| The RBM is assumed to mitigate the consequences of an RWE event when operating > 30% RTP (analytical limit) and a peripheral control rod is not selected. Below this power level or if a peripheral control rod is selected, the consequences of an RWE event will not exceed the MCPR... 4f EJ SL and, therefore, the RBM is not required to be OPERABLE (Ref. a.
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| When operating < 90% RTP, analyses (Re) have shown that with an initial MCPR > 1.70, no RWE event will result in exceeding the MCPR SL.
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| Also, the analyses demonstrate that when operating at > 90% RTP with MV.CPR> 1.40, no RWE event will result in exceeding the MCPR SL (R .- ). Therefore, under these conditions, the RBM is also not required to be OPERABLE.
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| : 2. Rod Worth Minimizer The RWM is a backup to operator control of the rod sequences. The RWM enforces the banked position withdrawal sequence (BPWS) by alerting the operator when the rod pattern is not in accordance with BPWS. Compliance with BPWS ensures that the initial conditions of the CRDA analysis are not violated.
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| Cooper B 3,3-45 08/17/11 INFORMATION ONLY
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| IN FORMATION ONyrol Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 6d7 The analytical methods and assumptions used in evaluating the CRDA are summarized in Reference5 F4and. The BPWS requires that control rods be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions. Requirements that the control rod sequence is in compliance with the BPWS are specified in LCO 3.1.6, "Rod Pattern Control."
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| 8 When perform.ng a shutdown of the plant, an optional BPWS control rod sequence (Re .7) may be used if the coupling of each withdrawn control rod has been confirmed. The rods may be inserted without tneed- 8 stop at intermediate positions. When using the Reference 'c ntrol rod insertion sequence for shutdown, the rod worth minimizer may be reprogrammed to enforce the requirements of the improved BPWS control rod insertion, or may be bypassed and the improved BPWS shutdown sequence implemented under the controls in Condition D.
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| The RWM Function satisfies Criterion 3 of Reference 4**.-E Since the RWM is a system designed to act as a backup to operator control of the rod sequences, only one channel of the RWM is available and required to be OPERABLE (ReŽ7-). Special circumstances provided for in the Required Action of LCO 3.1.3, "Control Rod OPERABILITY,"
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| and LCO 3.1.6 may necessitate bypassing the RWM to allow continued operation with inoperable control rods, or to allow correction of a control rod pattern not in compliance with the BPWS. The RWM may be bypassed as required by these conditions, but then it must be considered inoperable and the Required Actions of this LCO followed.
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| Compliance with the BPWS, and therefore OPERABILITY of the RWM, is required in MODES 1 and 2 when THERMAL POWER is < 9.85% RTP.
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| When THERMAL POWER is > 9.85% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the .6 280 cal/gm fuel damage limit during a CRDA (Ref. 5-._n MODES 3 and 4, all control rods are required to be inserted into the core; therefore, a CRDA cannot occur. In MODE 5, since only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will be subcritical.
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| Cooper B 3.3-46 07/16/08 INFORMATION ONLY
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| INFORMATION ONLY Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE 3. Reactor Mode Switch-Shutdown Position SAFETY ANALYSIS LCO, AND During MODES 3 and 4, and during MODE 5 when the reactor mode APPLICABILITY switch is required to be in the shutdown position, the core is assumed to be subcritical; therefore, no positive reactivity insertion events are analyzed. The Reactor Mode Switch - Shutdown Position control rod withdrawal block ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions of the safety analysis.
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| The Reactor Mode Switch - Shutdown Position Function satisfies Criterion 3 of Referencr4. Two channels are required to be OPERABLE to ensure that no single channel failure will preclude a rod block when required. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on reactor mode switch position.
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| During shutdown conditions (MODE 3, 4, or 5), no positive reactivity insertion events are analyzed because assumptions are that control rod withdrawal blocks are provided to prevent criticality. Therefore, when the reactor mode switch is in the shutdown position, the control rod withdrawal block is required to be OPERABLE. During MODE 5 with the reactor mode switch in the refueling position, the refuel position one-rod-out interlock (LCO 3.9.2, "Refuel Position One-Rod-Out Interlock") provides the required control rod withdrawal blocks.
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| ACTIONS A..1 With one RBM channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod block function; however, overall reliability is reduced because a single failure in the remaining OPERABLE channel can result in no control rod block capability for the RBM. For this reason, Required Action A.1 requires restoration of the inoperable channel to OPERABLE status. The Completion Time of 24 hours is based on the low probability of an event occurring coincident with a failure in the remaining OPERABLE channel.
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| B.I If Required Action A.1 is not met and the associated Completion Time has expired, the inoperable channel must be placed in trip within 1 hour.
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| If both RBM channels are inoperable, the RBM is not capable of performing its intended function; thus, one channel must also be placed Cooper B 3.3-47 1/14/05 INFORMATION ONLY
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| INFORMATION ONLY No Changes Control Rod Block Instrumentation Included for Completeness B 3.3.2.1 BASES ACTIONS D.1 (continued)
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| With the RWM inoperable during a reactor shutdown, the operator is still capable of enforcing the prescribed control rod sequence. Required Action D.1 allows for the RWM Function to be performed manually and requires a double check of compliance with the prescribed rod sequence by a second licensed operator (Reactor Operator or Senior Reactor Operator) or other qualified member of the technical staff. The RWM may be bypassed under these conditions to allow the reactor shutdown to continue.
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| E.1 and E.2 With one Reactor Mode Switch - Shutdown Position control rod withdrawal block channel inoperable, the remaining OPERABLE channel is adequate to perform the control rod withdrawal block function.
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| However, since the Required Actions are consistent with the normal action of an OPERABLE Reactor Mode Switch - Shutdown Position Function (i.e., maintaining all control rods inserted), there is no distinction between having one or two channels inoperable.
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| In both cases (one or both channels inoperable), suspending all control rod withdrawal and initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies will ensure that the core is subcritical with adequate SDM ensured by LCO 3.1.1. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are therefore not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.
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| SURVEILLANCE As noted at the beginning of the SRs, the SRs for each REQUIREMENTS Control Rod Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1.
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| The Surveillances are modified by a second Note to indicate that when an RBM channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains control rod block capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Cooper B 3.3-49 1/14/05 INFORMATION ONLY
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| INFORMATION ONXItrol Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| Req ired Actions taken. This Note is based on the reliability analysis Re?) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that a control rod block will be initiated when necessary.
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| SR 3.3.2.1.1 A CHANNEL FUNCTIONAL TEST is performed for each RBM channel to ensure that the channel will perform the intended function. It includes the Reactor Manual Control System input. It also includes the local alarm lights representing upscale and downscale trips, but no rod block will be produced at this time. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
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| Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The Frequency of 92 days is based on reliability analyses (Ref.
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| SR 3.3.2.1.2 and SR 3.3.2.1.3 A CHANNEL FUNCTIONAL TEST is performed for the RWM to ensure that the system will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay.
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| This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The CHANNEL FUNCTIONAL TEST for the RWM includes performing the RWM computer on line diagnostic test satisfactorily, attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying a control rod block occurs. For SR 3.3.2.1.2, the CHANNEL FUNCTIONAL TEST also includes attempting to select a control rod not in compliance with the prescribed sequence and verifying a selection error occurs. As noted in the SRs, SR 3.3.2.1.2 is not required to be performed until 1 hour after any control rod is withdrawn in MODE 2. As noted, SR 3.3.2.1.3 is not required to be performed until 1 hour after THERMAL POWER is < 9.85% RTP in MODE 1. This allows Cooper B 3.3-50 07/16/08 INFORMATION ONLY
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| IN-FORMATION "hq'nYrolRod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued) entry into MODE 2 for SR 3.3.2.1.2, and entry into MODE 1 when THERMAL POWER is < 9.85% RTP for SR 3.3.2.1.3, to perform the required Surveillance if the 92 day Frequency is not met per SR 3.0.2.
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| The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs. The Frequencies are based on reliability analysis (RefO).
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| SR 3.3.2.1.4 The RBM power range setpoints control the enforcement of the appropriate upscale trips over the proper core thermal power range of the Applicability Notes (a), (b), (c), (d), and (e) of ITS Table 3.3.2.1-1. The RBM Upscale Trip Function setpoints are automatically varied as a function of power. Three Allowable Values are specified in the COLR as denoted in Table 3.3.2.1-1, each within a specific power range. The power at which the control rod block Allowable Values automatically change are based on the reference APRM signal's input to each RBM channel. Below the minimum power setpoint of 27.5% RTP or when a peripheral control rod is selected, the RBM is automatically bypassed.
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| These power Allowable Values must be verified periodically by determining that the power level setpoints are less than or equal to the specified values. If any power range setpoint is nonconservative, then the affected RBM channel is considered inoperable. Alternatively, the power range channel can be placed in the conservative condition (i.e.,
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| enabling the proper RBM setpoint). If placed in this condition, the SR is met and the RBM channel is not considered inoperable. As noted, neutron detectors are excluded from the Surveillance because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8. The 184 day Frequency is based on the actual trip setpoint methodology utilized for these channels.
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| SR 3.3.2.1.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
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| Cooper B 3.3-51 07/16/08 INFORMATION ONLY
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| IN-FORMATION "''nY'rol Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| As noted, neutron detectors are excluded from the CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Neutron detectors are adequately tested in SR 3.3.1.1.2 and SR 3.3.1.1.8.
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| The Frequency is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| -INISERT 8>J SR 3.3.2.1.6 The RWM is automatically bypassed when power is above a specified value. The power level is determined from feedwater flow and steam flow signals. The setpoint where the automatic bypass feature is unbypassed must be verified periodically to be > 9.85% RTP. If the RWM low power setpoint is nonconservative, then the RWM is considered inoperable.
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| Alternately, the low power setpoint channel can be placed in the conservative condition (nonbypass). If placed in the nonbypassed condition, the SR is met and the RWM is not considered inoperable. The Frequency is based on the trip setpoint methodology utilized for the low power setpoint channel.
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| SR 3.3.2.1.7 A CHANNEL FUNCTIONAL TEST is performed for the Reactor Mode Switch - Shutdown Position Function to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch - Shutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown position and verifying a control rod block occurs.
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| As noted in the SR, the Surveillance is not required to be performed until 1 hour after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable links. This allows entry into MODES 3 and 4 if the 4month Frequency Cooper B 3.3-52 07/16/08 INFORMATION ONLY
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| INFORMATION ONLY Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued) is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which 24 ,,I L I jFIII,.tlI:I LIIU O b The 4- month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| Operating experience has shown these components usually pass the Surveillance when performed at the 4-& month Frequency.
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| SR 3.3.2.1.8 The RWM will only enforce the proper control rod sequence if the rod sequence is properly input into the RWM computer. This SR ensures that the proper sequence is loaded into the RWM so that it can perform its intended function. The Surveillance is performed once prior to declaring RWM OPERABLE following loading of sequence into RWM, since this is when rod sequence input errors are possible.
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| Cooper B 3.3-53 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY Control Rod Block Instrumentation B 3.3.2.1 BASES
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| .4 1. Regulatory Guide 1.105, "Setpoints for REFERENCE* 2. USAR, Section VII-7. 3afetv-Related Instrumentation," Revision 3.
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| : 3. USAR, Section VII-16.3.3.
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| : 4. NEDC-31892P, "Extended Load Line Limit and ARTS Improvement Program Analyses for Cooper Nuclear Station," Rev. 1, May 1991.
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| : 5. 10 CFR 50.36(c)(2)(ii).
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| 6.
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| USAR, Section XIV-6.2.
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| : 7. NEDO-21231, "Banked Position Withdrawal Sequence,"
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| January 1977.
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| 8.
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| NEDO 33091, Revision 2, "Improved BPWS Control Rod Insertion Process," April 2003.
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| : 9. NRC SER, "Acceptance of Referencing of Licensing Topical Report NEDE-24011-P-A," "General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 2987.
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| : 10. GENE-770-06-1, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
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| : 11. NEDC-30851-P-A, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation," October 1988.
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| Cooper B 3.3-54 1/14/05 INFORMATION ONLY
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| Feedwater &MTn'VWQNXel Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE SR 3.3.2.2.1 (continued)
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| REQUIREMENTS 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 instrument channels could be an indication of excessive instrument drift in one of the channels, or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
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| Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limits.
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| The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with the channels required by the LCO.
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| SR 3.3.2.2.2 There is a plant specific CHANNEL CALIBRATION is a complete check of the instrument program which verifies loop and the sensor. This test verifies the channel that the instrument responds to the measured parameter within the necessary channel functions as range and accuracy. CHANNEL CALIBRATION leaves the channel required by verifying the adjusted to account for instrument drifts between successive as-left and as-found calibrations consistent with the plant specific setpoint settings are consistent methodology. a 2_4 with those established by the setpoint methodology. The Frequency is based upon the assumption of an -18 mmonth calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| SR 3.3.2.2.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the feedwater and (continued)
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| Cooper B 3.3-60 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 BASES SURVEILLANCE REQUIREMENTS (continued) main turbine valves is included as part of this Surveillance and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if a valve is incapable of
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| [24 operating, the associated instrumentation would also be inoperable. The
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| - month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| Operating experience has shown that these components usually pass the Surveillance when performed at the 4-8 month Frequency.
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| REFERENCES 1. USAR, Section XIV-5.8.1.
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| : 2. 10 CFR 50.36(c)(2)(ii).
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| : 3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-Of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
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| Cooper B 3.3-61 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.1 (continued)
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| REQUIREMENTS CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar plant instruments located throughout the plant. The CHANNEL CHECK does not apply to the primary containment H2 and 02 analyzer that is in a normal standby configuration.
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| Agreement criteria are determined by the plant 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.
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| The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the channels required by the LCO.
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| SR 3.3.3.1.2 and SR 3.3.3.1.3 There is a plant specific program which verifies These SRs require a CHANNEL CALIBRATION to be performed.
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| that the instrument CHANNEL CALIBRATION is a complete check of the instrument channel functions as loop, including the sensor. The test verifies the channel required by verifying the responds to measured parameter with the necessary range and as-left and as-found accuracy.4 For the Primary Containment Gross Radiation settings are consistent Monitors, the CHANNEL CALIBRATION consists of an electronic with those established calibration of the channel, excluding the detector, for by the setpoint methodology.
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| range decades > 10 R/hour and a one point calibration check of the detector with an installed or portable gamma source (conti nued)
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| Cooper B 3.3-72 Revision I INFORMATION ONLY
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| INFORMATION ONLY PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2 and SR 3.3.3.1.3 (continued)
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| REQUIREMENTS for range decades < 10 R/hour. For the PCIV Position Function, the CHANNEL CALIBRATION consists of verifying the remote indication conforms to actual value position.
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| The 92 day Frequency for CHANNEL CALIBRATION of the Primary S Containment Hydrogen and Oxygen Analyzers is based on vendor recommendations. Ine, month Frequency for CHANNEL CALIBRATION of all other PAM instrumentation of Table 3.3.3.1-1 is based on operating experience and consistency with the CNS refueling cycles.
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| REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, Revision 3," May 1985.
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| : 2. Letter from G. A. Trevors (NPPD) to U.S. NRC dated April 12, 1990, "NUREG-0737, Supplement 1-Regulatory Guide 1.97 Response, Revision IX."
| |
| : 3. Letter from W. 0. Long (NRC) to J. M. Pilant (NPPD) dated October 27, 1986, "Emergency Response Capability-Conformance to Regulatory Guide 1.97, Revision 2."
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| : 4. 10 CFR 50.36(c)(2)(ii).
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| Cooper B 3.3-73 Revision 1 1 INFORMATION ONLY
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| INFORMATION ONLY Alternate Shutdown System B 3.3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The Frequency is based upon plant operating experience that demonstrates channel failure is rare.
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| SR 3.3.3.2.2 SR 3.3.3.2.2 verifies each required Alternate Shutdown System transfer switch and control circuit performs the intended function. This verification is performed from the alternate shutdown panel and locally, as appropriate. Operation of the equipment from the alternate shutdown panel is not necessary. The Surveillance can be satisfied by performance of a continuity check. This will ensure that if the control room becomes inaccessible, the plant can be placed and maintained in a safe shutdown condition from the alternate shutdown panel and the local control stations. However, this Surveillance is not required to be performed only during a plant outage. Operating experience demonstrates that Alternate Shutdown System control channels usually pass the Surveillance when performed at the 1-8 month Frequency.
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| There is a plant specific program which verifies that the instrument d channel functions as SR 3.3.3.2.3 required by verifying the as-left and as-found CHANNEL CALIBRATION is a complete check of the instrument loop settings are consistent with those established and the sensor. The test verifies the channel responds to measured by the setpoint parameter values with the necessary range and accuracy.z*
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| methodology.
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| - g month Frequency is based upon operating experience and
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| [2TBn'stency with the typical industry refueling cycle.
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| REFERENCES 1. USAR, Section VII-18.0.
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| : 2. USAR, Section XIV-5.9.
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| : 3. 10 CFR 50.36(c)(2)(ii),
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| Cooper B 3.3-78 06/07/06 INFORMATION ONLY
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| INFORMATION ONLY ATWS-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.4.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
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| Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
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| The Frequency of 92 days is based on the reliability analysis of Reference 3.
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| There is a plant specific SR 3.3.4.1.2 program which verifies that the instrument channel functions as A CHANNEL CALIBRATION is a complete check of the instrument loop required by verifying the and the sensor. This test verifies the channel responds to the measured as-left and as-found parameter within the necessary range and accuracy. CHANNEL settings are consistent CALIBRATION leaves the channel adjusted to account for instrument with those established drifts between successive calibrations consistent with the plant specific by the setpoint methodology.
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| setpoint methodology.4 a"24 The Frequency is based upon the assumption of ah 4- month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| SR 3.3.4.1.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. For the Reactor Vessel Water Level-Low Low (Level 2) logic, this shall include the nominal 9 second time delay of the RRMG field breaker trip. The system functional test of the RRMG field breakers is included as part of this Surveillance and overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if Cooper B 3.3-88 June 28, 2001 1 INFORMATION ONLY
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| INFORMATION ONLY ATWS-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued) an RRMG field breaker is incapable of operating, the associated E, instrument channel(s) would be inoperable.
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| The 48 month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| Operating experience has shown these components usually pass the Surveillance when performed at the-8 month Frequency.
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| REFERENCES 1. USAR, Section VII-9.4.4.2.
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| : 2. 10 CFR 50.36(c)(2)(ii).
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| : 3. GENE-770-06-1, "Bases for Changes To Surveillance Test Intervals and Allowed Out-of-Service Times For Selected Instrumentation Technical Specifications," February 1991.
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| Cooper B 3.3-89 02/20/07 INFORMATION ONLY
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| | |
| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 B 3.3 INSTRUMENTATION B 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation BASES BACKGROUND The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that the fuel is adequately cooled in the event of a design basis accident or transient.*
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| <INSERT 9>-
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| For most abnormal operational transients and Design Basis Accidents (DBAs), a wide range of dependent and independent parameters are monitored.
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| The ECCS instrumentation actuates core spray (CS), low pressure coolant injection (LPCI), high pressure coolant injection (HPCI), Automatic Depressurization System (ADS),
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| and the diesel generators (DGs). The equipment involved with each of these systems is described in the Bases for LCO 3.5.1, "ECCS-Operating."
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| Core Spray System The CS System may be initiated by either automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low (Level 1) or Drywell Pressure-High. Each of these diverse variables is monitored by four redundant switches, which are connected to relays which send signals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic.
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| Each trip system initiates one of the two CS pumps.
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| Upon receipt of an initiation signal, if normal AC power is available, both CS pumps start after an approximate 10 second time delay. If a core spray initiation signal is received when normal AC power is not available, the CS pumps start approximately 10 seconds after the bus is energized by the DGs.
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| The CS test line isolation valve, which is also a primary containment isolation valve (PCIV), is closed on a CS initiation signal to allow full system flow assumed in the (continued)
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| Cooper B 3.3-90 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Core Spray System (continued) accident analyses and maintain primary containment isolated in the event CS is not operating.
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| The CS pump discharge flow is monitored by a flow transmitter and trip unit. When the pump is running and discharge flow is low enough so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint. It is not necessary for the minimum flow valve to close to achieve adequate system flow assumed in the accident analysis (Ref. -)<----
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| The CS System also monitors the pressure in the reactor to ensure that, before the injection valves open, the reactor pressure has fallen to a value below the CS System's maximum design pressure. The variable is monitored by four redundant pressure switches. The outputs of the switches are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.
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| Low Pressure Coolant Injection System
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| - The LPCI is an operating mode of the Residual Heat Removal (RHR) System, with two LPCI subsystems. The LPCI subsystems may be initiated by automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level -Low Low Low (Level 1); Drywell Pressure-High; or both. Each of these diverse variables is monitored by four redundant switches, which are connected to relays which send signals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic. Each trip system initiates two of the four LPCI pumps. Once an initiation signal is received by the LPCI control circuitry, the signal is sealed in until manually reset.
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| Upon receipt of an initiation signal if normal AC power is available, the LPCI A and D pumps start in approximately 0.5 seconds when power is available. The LPCI B and C pumps are started after an approximate 5 second delay to limit the loading of the standby power sources. With a loss of off-site power LPCI pumps A and D start within approximately 0.5 seconds on restoration of power, and pumps B and C start approximately 5 seconds after the restoration of power.
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| (continued)
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| Cooper B 3.3-91 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND Low Pressure Coolant Injection System (continued)
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| Each LPCI subsystem's discharge flow is monitored by a differential pressure switch. When a pump is running and discharge flow is low enough so that pump overheating may occur, the respective minimum flow return line valve is opened. If flow is above the minimum flow setpoint, the valve is automatically closed. It is not necessary for the minimum flow valve to close to achieve adequate system flow assumed in the analyses (Ref. -)*
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| The containment cooling return valves, suppression pool spray isolation valves, and containment spray isolation valves (which are also PCIVs) are also closed on a LPCI initiation signal to allow the full system flow assumed in the accident analyses and maintain primary containment isolated in the event LPCI is not operating.
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| The LPCI System monitors the pressure in the reactor to ensure that, before an injection valve opens, the reactor pressure has fallen to a value below the LPCI System's maximum design pressure. The variable is monitored by four redundant pressure switches, which are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic. Additionally, instruments are provided to close the recirculation pump discharge valves to ensure that LPCI flow does not bypass the core when it injects into the recirculation lines. The variable is monitored by four redundant pressure switches, which are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.
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| Low reactor water level in the shroud is detected by two additional instruments. When level is greater than the low level setpoint, LPCI may no longer be required, therefore other modes of RHR (e.g., suppression pool cooling) are allowed. Manual overrides for the isolations below the low level setpoint are provided.
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| High Pressure Coolant Injection System The HPCI System may be initiated by either automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low (Level 2) or Drywell (continued)
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| Cooper B 3.3-92 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND High Pressure Coolant Injection System (continued)
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| Pressure-High. Each of these variables is monitored by four redundant switches, which are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic for each Function.
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| The HPCI pump discharge flow is monitored by a flow switch (only one trip system). When the pump is running and discharge flow is low enough so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint. It is not necessary for the minimum flow valve to close to achieve adequate system flow assumed in the accident analysis (Ref. -)1 The HPCI test line isolation valves are closed upon receipt of a HPCI initiation signal to allow the full system flow assumed in the accident analysis and maintain primary containment isolated in the event HPCI is not operating.
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| The HPCI System also monitors the water levels in the emergency condensate storage tanks (ECSTs) and the suppression pool because these are the two sources of water for HPCI operation. Reactor grade water in the ECSTs is the normal source. The ECST suction source consists of two ECSTs connected in parallel to the HPCI pump suction.
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| Upon receipt of a HPCI initiation signal, the ECST suction valve is automatically signaled to open (it is normally in the open position) unless the suppression pool suction valve is open. If the water level in the ECSTs falls below a preselected level, first the suppression pool suction valve automatically opens, and then the ECST suction valve automatically closes. Two level switches are used to detect low water level in the ECST. Either switch can cause the suppression pool suction valve to open and the ECST suction valve to close. The suppression pool suction valve also automatically opens and the ECST suction valve closes if high water level is detected in the suppression pool. Two level switches monitor the suppression pool water level. To prevent losing suction to the pump, the suction valves are interlocked so that one suction path must be full open before the other automatically closes.
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| The HPCI provides makeup water to the reactor until the reactor vessel water level reaches the Reactor Vessel Water (continued)
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| Cooper B 3.3-93 Revision 1 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued) in approximately 14 seconds, and will run in standby conditions (rated voltage and speed, with the DG output breaker open). The DGs will only energize their respective Engineered Safety Feature buses if a loss of offsite power occurs. (Refer to Bases for LCO 3.3.8.1.)
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| and 8 APPLICABLE The actions of the[ECCS are explicitly assumed in the safety analyses of SAFETY ANALYSES, References e, 6,99d 7. The ECCS is initiated to preserve the integrity of LCO, and the fuel cladding by limiting the post LOCA peak cladding temperature to APPLICABILITY less than the 10 CFR 50.46 limits.
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| [TL ECCS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii)
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| .. )ReCertain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
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| I<INSER 2>
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| The OPERABILITY of the ECCS instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.1-1. Each Function must have a required number set within the setting of OPERABLE channels, with their setpoints withiRn the Gpecified tolerance of the I b, where appropriate. The actual setpoint is calibrated specified LTSPs consistent with applicable setpoint methodology assumptions; Table 3.3.5.1-1 contains several footnotes, Footnote (a) clarifies that the associated functions are required to be OPERABLE in MODES 4 and 5 only when their supported ECCS are required to be OPERABLE per LCO LTSPs and the 3.5.2, ECCS - Shutdown. Footnote (b), is added to show that certain methodologies for ECCS instrumentation Functions also perform DG initiation. ITable 3.3.5. 1-1 calculation of the as-found and as-left Allowable Values are specified for each ECCS Function specified in ti*e tolerances are described tab4e. Neminal trip ,,tpoints . arc. p. ificd in the sctp.i.t calc..atiens.
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| in the Technical Requirements Manual. The cctpeint calculatieons are pfcrformd using methodology describcd in The LTSPs NEWO 3 D336P A, "Gen.r.l El .ectric In t Methaoelogy,"
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| ct Sc.poin*,,-,,
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| remain conservative with dated September 4996. The nominal setp:ints' are selected to ensure respect to the as-found that the set oints'e nel e-cced the ,able Value between CHANNEL tolerance band CALIBRATIONS. *Opeatien with a tFip cetpeint IeG .. E.R...atiVe than After each calibration the the nominl trp stpont, buta ,ithn ;it Allowable Value, uA i... ae tab**
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| trip setpoint shall be left "Vebhea*el- i iFnEperablc i' t act** U trip GetpOint i*" ,,t Within its Feguir-within the as-left band Allowable Value. Trip ,,tpe:RG are those predetermined values of output around the LTSP. LTSPs at which an action should take place. The setpoints are compared to the actual Cooper B 3.3-96 05/09/06 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE process parameter (e.g., reactor vessel water level), and analytical SAFETY ANALYSES, when the measured output value of the process parameter LCO, and exceeds the setpoint, the associated_1evice '(e APPLICABILITY switch) changes state. The analyti Imits are derived (continued) from the limiting values of the process parameters obtained from the safety analysis or other appropriate document. The Allowable Values are derived from the alA-y-4-4, corrected for calibration, process, and some of the instrument errors. The trip sctpok i-n1trthen determined, accounting for the remaining instrument errors (e.g., LT-PS drift .. derived in this manner provide ade uate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for. For some Functions, the Allowable Values and thtip setpeints are determined from historically accept practice relative to the intended functions of the channels. Such is the case for the Core Spray Pump Start-Time Delay Relay and for the LPCI Pump Start-Time Delay Relay.
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| In general, the individual Functions are required to be OPERABLE in the MODES or other specified conditions that may require ECCS (or DG) initiation to mitigate the consequences of a design basis transient or accident. To ensure reliable ECCS and DG function, a combination of Functions is required to provide primary and secondary initiation signals.
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| The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
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| Core Spray ana Low Pressure Coolant-Injection Systems
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| ..a. 2.a. Reactor Vessel Water Level-Low Low Low (Level 11 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result.
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| The low pressure ECCS and associated DGs are initiated at Reactor Vessel Water Level-Low Low Low (Level 1) to ensure that core spray and flooding functions are available to prevent or minimize fuel damage. The DGs are initiated from (continued)
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| Cooper B 3.3-97 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| Function 1 .a signals. The Reactor Vessel Water Level - Low Low Low (Level 1) is one of the Functions assumed to be OPERABLE and capable of initiating the ECCS during the transients analyzed in References &
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| 6 nd8 7-7.In addition, the Reactor Vessel Water Level - Low Low Low (Level 1) Function is directly assumed in the analysis of the recirculation line break (Re ). The core cooling function of the ECCS, along with the
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| -scram action of the Reactor Protection System (RPS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| Reactor Vessel Water Level - Low Low Low (Level 1) signals are initiated from four level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
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| The Reactor Vessel Water Level - Low Low Low (Level 1) Allowable Value is chosen to allow time for the low pressure core flooding systems to activate and provide adequate cooling.
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| Four channels of Reactor Vessel Water Level - Low Low Low.(Level 1)
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| Function are only required to be OPERABLE when the ECCS are required to be OPERABLE to ensure that no single instrument failure can preclude ECCS initiation. Per Footnote (a) to Table 3.3.5.1-1, this ECCS function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2, "ECCS - Shutdown," for Applicability Bases for the low pressure ECCS subsystems; LCO 3.8.1, "AC Sources - Operating"; and LCO 3.8.2, "AC Sources - Shutdown," for Applicability Bases for the DGs.
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| .b 2.b. Dywell Pressure-High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). The low pressure ECCS and associated DGs are initiated upon receipt of the Drywell Pressure - High Function in order to minimize the possibility of fuel damage. The DGs are initiated from Function 1.b signals. The Drywell Pressure - High Function, along with the Reactor Water Level - Low Low Low (Level 1) Function, is directly assumed in the analysis of the Cooper B 3.3-98 05/09/06 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 1.b, 2.b. Drywell Pressure-High (continued L-8*
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| SAFETY ANALYSES, LCO, and recirculation line break (Ref. & The core cooling APPLICABILITY function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| High drywell pressure signals are initiated from four pressure switches that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary .ontainment.
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| The Drywell Pressure-High Function is required to be OPERABLE when the ECCS or DG is required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. Thus, four channels of the CS and LPCI Drywell Pressure-High Function are required to be OPERABLE in MODES 1, 2, and 3 to ensure that no single instrument failure can preclude ECCS and DG initiation. In MODES 4 and 5, the Drywell Pressure-High Function is not required, since there is insufficient energy in the reactor to pressurize the primary containment to Drywell Pressure-High setpoint. Refer to LCO 3.5.1 for Applicability Bases for the low pressure ECCS subsystems and to LCO 3.8.1 for Applicability Bases for the DGs.
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| 1.c, 2.c. Reactor Pressure-Low (Injection Permissive)
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| Low reactor pressure signals are used as permissives for the low pressure ECCS subsystems. This ensures that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximum design pressure and a break in the RCPB has occurred, respectively. The Reactor Pressure-Low is one of the Functions assumed to be OPERABLE and capable 6an8 nf permitting initiation of the ECCS during the transients analyzed in Referenceý5 and 7. In addition, the Reactor Pressure-Low Function is directly assumed in the analysis of the recirculation line break (Ref*6-). The core cooling function or the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| The Reactor Pressure-Low signals are initiated from four pressure switches that sense the reactor dome pressure.
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| (continued)
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| Cooper B 3.3-99 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| The Allowable Value is low enough to prevent overpressuring the equipment in the low pressure ECCS, but high enough to ensure that the ECCS injection prevents the fuel peak cladding temperature from exceeding the limits of 10 CFR 50.46.
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| Four channels of Reactor Pressure - Low Function are only required to be OPERABLE when the ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude ECCS initiation. Per Footnote (a) to Table 3.3.5.1-1, this ECCS function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems.
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| 1.d, 2.g Core Spray and Low Pressure Coolant Iniection Pump Discharge Flow-Low (Bypass)
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| The minimum flow instruments are provided to protect the associated low pressure ECCS pump from overheating when the pump is operating and the associated injection valve is not fully open. The minimum flow line valve is opened when low flow is sensed, and the valve is automatically closed when the flow rate is adequate to protect the pump. The LPCI and CS Pump Discharge Flow - Low Functions are assumed to be OPERABLE. The minimum flow valves for CS and LPCI are not required to close to ensure that the low pressure ECCS flows assumed during the transients and accidents analyzed in References , are met.
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| The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| One flow transmitter per CS pump and one differential pressure switch per LPCI subsystem are used to detect the associated subsystems' flow rates. The logic is arranged such that each switch or transmitter causes its associated minimum flow valve to open. The logic will close the minimum flow valve once the closure setpoint is exceeded. The LPCI minimum flow valves are time delayed such that the valves will not open for approximately 3.5 seconds after the switches detect low flow. The time delay is provided to limit reactor vessel inventory loss during the startup of the RHR shutdown cooling mode. The Pump Discharge Flow - Low Allowable Values are high enough to ensure that the pump Cooper B 3.3-100 05/09/06 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 2.d. Reactor Pressure-Low (Recirculation Discharge Valve SAFETY ANALYSES, Permissive)
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| LCO, and APPLIC ABILITY Low reactor pressure signals are used as permissives for
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| .(con tinued) recirculation discharge valve closure. This ensures that the LPCI subsystems inject into the proper RPV location assumed in the safety analysis. The Reactor Pressure-Low is one of the Functions assumed to be OPERABLE and capable of closing the valve during the transients analyzed in Refere7. The core cooling function of the ECCS,
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| _ a on with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Pressure--Low Function is directly assumed in the analysis of the recirculation line break (Ref. 6-)*1---FT The Reactor Pressure-Low signals are initiated from four pressure switches that sense the reactor dome pressure.
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| The Allowable Value is chosen high enough that the valves close prior to when LPCI injection flow into the core is required (as assumed in the safety analysis) and low enough to avoid excessive differential pressures.
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| Four channels of the Reactor Pressure-Low Function are only required to be OPERABLE in MODES 1, 2, and 3 with the associated recirculation pump discharge valve open. With the valve(s) closed, the function of the instrumentation has been performed; thus, the Function is not required. In MODES 4 and 5, the loop injection location is not critical since LPCI injection through the recirculation loop in either direction will still ensure that LPCI flow reaches the core (i.e., there is no significant reactor steam dome back pressure).
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| 2.e. Reactor Vessel Shroud Level-Level 0 The Reactor Vessel Shroud Level-Level 0 Function is provided as a permissive to allow the RHR System to be manually aligned from the LPCI mode to the suppression pool cooling/spray or drywell spray modes. The reactor vessel shroud level permissive ensures that water in the vessel is approximately two thirds core height before the manual transfer is allowed. This ensures that LPCI is available to prevent or minimize fuel damage. This function may be (continued)
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| Cooper B 3.3-102 Revision I INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 2.e. Reactor Vessel Shroud Level-Level 0 (continued)
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| SAFETY ANALYSES, LCO, and overridden during accident conditions as allowed by plant procedures.
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| APPLICABILITY Reactor Vessel Shroud Level - Level 0 Function is implicitly assumed in the analysis of the recirculation line break (Ref. r5q:nce the analysis []
| |
| assumes that no LPCI flow diversion occurs when reactor water level is below Level 0.
| |
| Reactor Vessel Shroud Level - Level 0 signals are initiated from two level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Reactor Vessel Shroud Level - Level 0 Allowable Value of - 193.19 inches referenced to instrument zero (which is equivalent to 35 inches below FZZ) is chosen to allow the low pressure core flooding systems to activate and provide adequate cooling before allowing a manual transfer.
| |
| Two channels of the Reactor Vessel Shroud Level - Level 0 Function are only required to be OPERABLE in MODES 1, 2, and 3. In MODES 4 and 5, the specified initiation time of the LPCI subsystems is not assumed, and other administrative controls are adequate to control the valves associated with this Function (since the systems that the valves are opened for are not required to be OPERABLE in MODES 4 and 5 and are normally not used).
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| 2.f. Low Pressure Coolant Injection Pump Start-Time Delay Relay The purpose of this time delay is to stagger the start of the LPCI pumps that are in each of Divisions 1 and 2, thus limiting the starting transients on the 4.16 kV emergency buses. This Function is only necessary when power is being supplied from the standby power sources (DG). However, since the time delay does not degrade ECCS operation, it remains in the pump start logic at all times. The LPCI Pump Start - Time Delay Relays are assumed to be OPERABLE in the accident analyses requiring ECCS initiation. That is, the analyses assume that the pumps will initiate when required and excess loading will not cause failure of the power sources.
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| (continued)
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| Cooper B 3.3-103 June 10, 1999 I INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| There are four LPCI Pump Start - Time Delay Relays, one in each of the RHR pump start logic circuits. While each time delay relay is dedicated to a single pump start logic, a single failure of a LPCI Pump Start - Time Delay Relay could result in the failure of the two low pressure ECCS pumps, powered for the same ESF bus, to perform their intended function (e.g., as in the case where both ECCS pumps on one ESF bus start simultaneously due to an inoperable time delay relay). This still leaves four of the six low pressure ECCS pumps OPERABLE; thus, the single failure criterion is met (i.e., loss of one instrument does not preclude ECCS initiation). The Allowable Value for the LPCI Pump Start - Time Delay Relays is chosen to be long enough so that most of the starting transient of the first pump is complete before starting the second pump on the same 4.16 kV emergency bus and short enough so that ECCS operation is not degraded.
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| Each LPCI Pump Start - Time Delay Relay Function is required to be OPERABLE only when the associated LPCI subsystem is required to be OPERABLE. Per Footnote (a) to Table 3.3.5.1-1, this ECCS function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to I LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the LPCI subsystems.
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| High Pressure Coolant Iniection P(tHPIJ System 3.a. Reactor Vessel Water Level-Low Low (Level 2)
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| Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the HPCI System is initiated at Level 2 to maintain level above fuel zone zero. The Reactor Vessel Water Level - Low Low (Level 2) is one of the Functions assumed to be OPERABLE and capable of initiating HPCI during the transients analyzed in References Additionally, the Reactor Vessel Water Level - Low Low (Level 2) 0 Function associated with HPCI is directly assumed in the analysis of the recirculation line break (IReS). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| Cooper B 3.3-104 05/09/06 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 3.a. Reactor Vessel Water Level-Low Low (Level 2)
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| SAFETY ANALYSES, (continued)
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| LCO, and APPLICABILITY Reactor Vessel Water Level-Low Low (Level 2) signals are initiated from four level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
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| The Reactor Vessel Water Level-Low Low (Level 2) Allowable Value is high enough such that for complete loss of feedwater flow, the Reactor Core Isolation Cooling (RCIC)
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| System flow with HPCI assumed to fail will be sufficient to avoid initiation of low pressure ECCS at Reactor Vessel Water Level--Low Low Low (Level 1).
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| Four channels of Reactor Vessel Water Level--Low Low (Level 2) Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.1 for HPCI Applicability Bases.
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| 3.b. Drywell Pressure-Hiqh High pressure in the drywell could indicate a break in the RCPB. The HPCI System is initiated upon receipt of the Drywell Pressure-High Function in order to minimize the possibility of fuel damage. While HPCI is not assumed to be OPERABLE in any DBA or transient analysis, the Drywell Pressure-High Function, along with the Reactor Water Ipvel-Low Low (Level 2),Function, is capable of initiating HPCI during a LOCA (Ret/>7-). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| High drywell pressure signals are initiated from four pressure switches that sense drywell pressure. The Allowable Value was selected to be as low as possible to be indicative of a LOCA inside primary containment.
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| Four channels of the Drywell Pressure-High Function are required to be OPERABLE when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.1 for the Applicability Bases for the HPCI System.
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| (continued)
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| Cooper B 3.3-105 Revision I INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABLITY 3.e. Suppression Pool Water Level-High (continued)
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| OPERABLE to ensure that no single instrument failure can preclude HPCI swap to suppression pool source. Refer to LCO 3.5.1 for HPCI Applicability Bases.
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| 3.f. High Pressure Coolant Injection Pump Discharge Flow-Low (Bypass)
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| The minimum flow instrument is provided to protect the HPCI pump from overheating when the pump is operating at reduced flow. The minimum flow line valve is opened when low flow is sensed and either 1) the pump is on, or 2) the system has initiated; and the valve is automatically closed when the flow rate is adequate to protect the pump. The High Pressure Coolant Injection Pump Discharge Flow - Low Function is assumed to be OPERABLE. The minimum flow valve for HPCI is not required to 6, 7, and 8 close to ensure that the ECCS flow assumed during the transients analyzed in References ,G-, a*d 7 are met. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| One flow switch is used to detect the HPCI System's flow rate. The logic is arranged such that the switch causes the minimum flow valve to open.
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| The logic will close the minimum flow valve once the closure setpoint is exceeded.
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| The High Pressure Coolant Injection Pump Discharge Flow- Low Allowable Value is high enough to ensure that pump flow rate is sufficient to protect the pump.
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| One channel is required to be OPERABLE when the HPCI is required to be OPERABLE. Refer to LCO 3.5.1 for HPCI Applicability Bases.
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| Automatic Depressurization System 4.a, 5.a. Reactor Vessel Water Level-Low Low Low (Level 1)
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| Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, ADS receives one of the signals necessary for initiation from this Cooper B 3.3-108 August 29, 2002 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.a, 5.a. Reactor Vessel Water Level-Low Low Low, Level 1 SAFETY ANALY SES, (continued)
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| LCO, and APPLICABILIT Y Function. The Reactor Vessel Water Level-Low Low Low (Level 1) is one of the Functions assumed to be OPERABLE and 7 a able of *itiating the ADS during the accident analyzed in Referenc t6. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| Reactor Vessel Water Level-Low Low Low (Level 1) signals are initiated from four level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level--Low Low Low (Level 1) Function are required to be OPERABLE only when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two channels input to ADS trip system A, while the other two channels input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.
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| The Reactor Vessel Water Level--Low Low Low (Level 1)
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| Allowable Value is chosen to allow time for the low pressure core flooding systems to initiate and provide adequate cooling.
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| 4.b, 5.b. Automatic Depressurization System Initiation Timer The purpose of the Automatic Depressurization System Initiation Timer is to delay depressurization of the reactor vessel to allow the HPCI System time to maintain reactor vessel water level. Since the rapid depressurization caused by ADS operation is one of the most severe transients on the reactor vessel, its occurrence should be limited. By delaying initiation of the ADS Function, the operator is given the chance to monitor the success or failure of the HPCI System to maintain water level, and then to decide whether or not to allow ADS to initiate, to delay initiation further by recycling the timer, or to inhibit initiation permanently. The Automatic Depressurization System Initiation Timer Function is assumed to be OPERABLE for the (continued)
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| Cooper B 3.3-109 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.b, 5.b. Automatic Depressurization System Initiation SAFETY ANALYSES, Timer (continued)
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| LCO, and APPLICABILITY accident analysis of Reference at requires ECCS initiation and assumes failure of the HPCI System.
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| There are two Automatic Depressurization System Initiation Timer relays, one in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Initiation Timer is chosen so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.
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| Two channels of the Automatic Depressurization System Initiation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.
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| 4.c, 5.c. Reactor Vessel Water Level-Low (Level 3)
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| The Reactor Vessel Water Level--Low (Level 3) Function is used by the ADS only as a confirmatory low water level signal. ADS receives one of the signals necessary for initiation from Reactor Vessel Water Level--Low Low Low (Level 1) signals. In order to prevent spurious initiation of the ADS due to spurious Level 1 signals, a Level 3 signal must also be received before ADS initiation commences.
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| Reactor Vessel Water Level-Low (Level 3) signals are initiated from two level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Allowable Value for Reactor Vessel Water Level-Low (Level 3) is selected to be above the RPS Level 3 scram Allowable Value for convenience.
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| Refer to LCO 3.3.1.1, "Reactor Protection System (RPS)
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| Instrumentation," for the Bases discussion of this Function.
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| Two channels of Reactor Vessel Water Level-Low (Level 3)
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| Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. One channel inputs to ADS trip system A, while the other channel inputs to ADS (continued)
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| Cooper B 3.3-110 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE 4.c, 5.c. Reactor Vessel Water Level-Low (Level 3)
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| SAFETY ANALYSES (continued)
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| LCO, and APPLICABILITY trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.
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| ,4.d, 4.e. 5.d, 5.e. Core Spray and Low Pressure Coolant Injection Pump Discharqe Pressure-High The Pump Discharge Pressure-High signals from the CS and LPCI pumps are used as permissives for ADS initiation, indicating that there is a source of low pressure cooling water available once the ADS has depressurized the vessel.
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| Pump Discharge Pressure-High is one of the Functions 7 assumed to be OPERABLE and capable of permitting ADS initiation during the events analyzed in Reference 6-with an assumed HPCI failure. For these events the ADS depressurizes the reactor vessel so that the low pressure ECCS can perform the core cooling functions. This core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
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| Pump discharge pressure signals are initiated from twelve pressure switches, two on the discharge side of each of the six low pressure ECCS pumps. In order to generate an ADS permissive in one trip system, it is necessary that only one pump (both channels for the pump) indicate the high discharge pressure condition. The Pump Discharge Pressure-High Allowable Value is less than the pump discharge pressure when the pump is operating in a full flow mode and high enough to avoid any condition that results in a discharge pressure permissive when the CS and LPCI pumps are aligned for injection and the pumps are not running.
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| The actual operating point of this function is not assumed E in any transient or accident analysis. However, this pf function is indirectly assumed to operate (in Reference5ý to provide the ADS permissive to depressurize the RCS to allow the ECCS low pressure systems to operate.
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| Twelve channels of Core Spray and Low Pressure Coolant Injection Pump Discharge Pressure-High Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Two CS channels associated with CS (continued)
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| Cooper B 3.3-111 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation
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| - B 3.3.5.1 BASES ACTIONS B.I B.2, and B.3 (continued) into Condition B if an associated channel is inoperable.
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| This ensures that the proper loss of initiation capability check is performed. Required Action B.1 (the Required Action for certain inoperable channels in the low pressure ECCS subsystems) is not applicable to Function 2.e, since this Function provides backup to administrative controls ensuring that operators do not divert LPCI flow from injecting into the core when needed. Thus, a total loss of Function 2.e capability for 24 hours is allowed, since the LPCI subsystems remain capable of performing their intended function.
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| 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."
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| For Required Action B.1, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable, untripped channels within the same Function as described in the paragraph above. For Required Action B.2, the Completion Time only begins upon discovery that the HPCI System cannot be automatically initiated due to two inoperable, untripped channels for the associated Function in the same trip system. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
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| Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an 9 *lowable a out of service time of 24 hours has been shown to be acceptable (Ret .) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.3. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
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| Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.
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| (continued)
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| Cooper B 3.3-114 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECGS Instrumentation B 3.3.5.1 BASES ACTIONS (continued)
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| A.1and C.2 Required Action A.1is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function result in redundant automatic initiation capability being lost for the feature(s).
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| Required Action A.1features would be those that are initiated by Functions 1.c, 1.e, 2.c, 2.d, and 2.f (i.e., low pressure EGOS).
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| Redundant automatic initiation capability is lost if either (a) two Function 1 .c channels are inoperable such that both trip systems lose initiation capability, (b) two Function i.e channels are inoperable, (c) two Function 2.c channels are inoperable such that both trip systems lose initiation capability, (d) two Function 2.d channels are inoperable such that both trip systems lose initiation capability, or (e) two or more Function 2.f channels are inoperable. In this situation (loss of redundant automatic initiation capability), the 24 hour allowance of Required Action C.2 is not appropriate and the feature(s) associated with the inoperable channels must be declared inoperable within 1 hour. Since each inoperable channel would have Required Action C.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system to be declared inoperable. However, since channels for both low pressure ECCS subsystems are inoperable (e.g., both CS subsystems), and the Completion Times started concurrently for the channels in both subsystems, this results in the affected portions in both subsystems being concurrently declared inoperable. For Functions 1.c, 1.e, 2.d, and 2.f, the affected portions are the associated low pressure ECCS pumps. As noted (Note 1), Required Action C.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the ECCS is not assumed and the probability of a LOCA is lower. Thus, a total loss of automatic initiation capability for 24 hours (as allowed by Required Action C.2) is allowed during MODES 4 and 5.
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| Note 2 states that Required Action C.1 is only applicable for Functions 1.c, 1.e, 2.c, 2.d, and 2.f. Required Action C.1 is not applicable to Function 3.c (which also requires entry into this Condition if a channel in this Function is inoperable), since the loss of one channel results in a loss of the Function (two-out-of-two logic). This loss was considered during the development of Reference considered acceptable for the 24 hours allowed by Required Action-C.-' E Cooper B 3.3-115 02/22/11 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES ACTIONS C.1 and C.2 (continued)
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| 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."
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| For Required Action C.1, the Completion Time only begins upon discovery that the same feature in both subsystems (e.g., both CS subsystems) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The I hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
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| Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an E]-]_allowable out of service time of 24 hours has been shown to be acceptable (Ref. P) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition H must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action would either cause the initiation or it would not necessarily result in a safe state for the channel in all events.
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| D.1, D.2.1. and D.2.2 Required Action D.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic component initiation capability for the HPCI System. Automatic component initiation capability is lost if two Function 3.d channels or two Function 3.e channels are inoperable and untripped. In this situation (loss of automatic suction swap), the 24 hour allowance of Required Actions D.2.1 and D.2.2 is not appropriate and the HPCI System must be declared inoperable within 1 hour after discovery of loss of HPCI initiation capability. As noted, Required Action D.1 is only applicable if the HPCI pump suction is not aligned to the suppression pool, since, if aligned, the Function is already performed.
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| (continued)
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| Cooper B 3.3-116 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES ACTIONS D.1, D.2.1, and D.2.2 (continued)
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| 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."
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| For Required Action D.1, the Completion Time only begins upon discovery that the HPCI System cannot be automatically aligned to the suppression pool due to two inoperable, untripped channels in the same Function. The I hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
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| Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours has been shown to be acceptaDle (Rei-*>) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action D.2.1 or the suction source must be aligned to the suppression pool per Required Action D.2.2. Placing the inoperable channel in trip performs the intended function of the channel (shifting the suction source to the suppression pool). Performance of either of these two Required Actions will allow operation to continue. If Required Action D.2.1 or D.2.2 is performed, measures should be taken to ensure that the HPCI System piping remains filled with water. Alternately, if it is not desired to perform Required Actions D.2.1 and D.2.2 (e.g.,
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| as in the case where shifting the suction source could drain down the HPCI suction piping), Condition H must be entered and its Required Action taken.
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| E.1 and E.2 Required Action E.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the Core Spray and Low Pressure Coolant Injection Pump Discharge Flow-Low Bypass Functions result in redundant automatic initiation capability being lost for the feature(s). For Required Action E.1, the features would be those that are initiated by Functions 1.d and 2.g (e.g., low pressure ECCS). Redundant automatic initiation capability (continued)
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| Cooper B 3.3-117 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES ACTIONS E.1 and E.2 (continued) is lost if (a) two Function 1.d channels are inoperable or (b) two Function 2.g channels are inoperable. Since each inoperable channel would have Required Action E.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected low pressure ECCS pump to be declared inoperable. However, since channels for more than one low pressure ECCS pump are inoperable, and the Completion Times started concurrently for the channels of the low pressure ECCS pumps, this results in the affected low pressure ECCS pumps being concurrently declared inoperable.
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| In this situation (loss of redundant automatic initiation capability), the 7 day allowance of Required Action E.2 is not appropriate and the subsystem associated with each inoperable channel must be declared inoperable within 1 hour. As noted (Note I to Required Action E.1), Required Action E.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the ECCS is not assumed and the probability of a LOCA is lower. Thus, a total loss of initiation capability for 7 days (as allowed by Required Action E.2) is allowed during MODES 4 and 5. A Note is also provided (Note 2 to Required Action E.I) to delineate that Required Action E.1 is only applicable to low pressure ECCS Functions. Required Action E.1 is not applicable to HPCI Function 3.f since the loss of one channel results in a loss of the Function (one-out-of-one logic). This loss was considered during the development of E] Re erenc 18- and considered acceptable for the 7 days allowed by Required Action E.2.
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| 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."
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| For Required Action E.1, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
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| (continued)
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| Cooper B 3.3-118 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES ACTIONS F.1 and F.2 (continued)
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| 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."
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| For Required Action F.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable, untripped channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
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| Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref.J`) to permit restoration of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE. If either HPCI or RCIC is inoperable, the time is shortened to 96 hours. If the status of HPCI or RCIC changes such that the Completion Time changes from 8 days to 96 hours, the 96 hours begins upon discovery of HPCI or RCIC inoperability. However, the total time for an inoperable, untripped channel cannot exceed 8 days. If the status of HPCI or RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable, untripped channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action F.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.
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| G.1 and G.2 Required Action G.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within (continued)
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| Cooper 8 3.3-120 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES ACTIONS G.1 and G.2 (continued) similar ADS trip system Functions result in automatic initiation capability being lost for the ADS. Automatic initiation capability is lost if either (a) one Function 4.b channel and one Function 5.b channel are inoperable, (b) a combination of Function 4.d, 4.e, 5.d, and 5.e channels are inoperable such that channels associated with five or more low pressure ECCS pumps are inoperable. In this situation (loss of automatic initiation capability), the 96 hour or 8 day allowance, as applicable, of Required Action G.2 is not appropriate, and all ADS valves must be declared inoperable within I hour after discovery of loss of ADS initiation capability.
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| 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."
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| For Required Action G.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
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| Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an D allowable out of service time of 8 days has been shown to be acceptable (Ref.i) to permit restoration of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE (Required Action G.2). If either HPCI or RCIC is inoperable, the time shortens to 96 hours. If the status of HPCI or RCIC changes such that the Completion Time changes from 8 days to 96 hours, the 96 hours begins upon discovery of HPCI or RCIC inoperability. However, the total time for an inoperable channel cannot exceed 8 days. If the status of HPCI or RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition H must be entered and its Required Action taken. The Required Actions do not allow placing the (continued)
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| Cooper B 3.3-121 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES ACTIONS G.1 and G.2 (continued) channel in trip since this action would not necessarily result in a safe state for the channel in all events.
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| H.1 With any Required Action and associated Completion Time not met, the associated feature(s) may be incapable of performing the intended function, and the supported feature(s) associated with inoperable untripped channels must be declared inoperable immediately.
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| SURVEILLANCE As noted in the beginning of the SRs, the SRs for each ECCS REQUIREMENTS instrumenta-t-oi Function are found in the SRs column of Table 3.3.5.1-1.
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| The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours as follows: (a) for Functions 3.c and 3.f; and (b) for Functions other than 3.c and 3.f provided the associated Function or redundant Function maintains ECCS initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition 9 ntered and. Required Actions t;ken. This Note is based on the reliability analysis (Ref. 8) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the ECCS will initiate when necessary.
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| SR 3.3.5.1.1 Performance of the CHANNEL CHECK once every 12 hours 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 (continued)
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| Cooper B 3.3-122 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued) approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected outright channel failure is limited to 12 hours; 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 plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.
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| The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
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| SR 3.3.5.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
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| Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
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| The Frequency of 92 days is based on the reliability analyses of Reference Cooper B 3.3-123 June 28, 2001 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5,1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.5.1.3 and SR 3.3.5.1.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
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| The Frequency of SR 3.3.5.1.3 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| SThe Frequency of SR 3.3.5.1.4 is based upon the assumption of a.*
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| month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| I<INSERT 1>--.
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| SR 3.3.5.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic and simulated automatic actuation for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this
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| [Surveillance to complete testing of the assumed safety function.
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| Th --month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| Operating experience has shown that these components usually pass the Surveillance when performed at the 4-8, month Frequency.
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| Cooper B 3.3-124 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY ECCS Instrumentation B 3.3.5.1 BASES 11. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.
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| REFERENCES T2 4-. Amendment No. 7 to Facility License No DPR-46 for the Cooper Nuclear Station, February 6, 1975.
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| : 3. Cooper Nuclear Station Design Change 94-332, December 1994.
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| : 4. . NEDC 97-023, "HPCI Minimum Flow Line Analysis."
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| : 5. 4- 10 CFR 50.36(c)(2)(ii).
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| : 6. USAR, Section V-2.4.
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| : 7. 6- USAR, Section VI-5.0.
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| : 8. 7-- USAR, Chapter XIV.
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| : 9. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.
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| Cooper B 3.3-125 June 28, 2001 1 INFORMATION ONLY
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| INFORMATION ONlc)( System Instrumentation B 3.3.5.2 B 3.3 INSTRUMENTATION B 3,3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation BASES BACKGROUND The purpose of the RCIC System instrumentation is to initiate actions to ensure adequate core cooling when the reactor vessel is isolated from its primary heat sink (the main condenser) and normal coolant makeup flow from the Reactor Feedwater System is insufficient or unavailable, such that RCIC System initiation occurs and maintains sufficient reactor water level such that an initiation of the low pressure Emergency Core Cooling Systems (ECCS) pumps does not occur. A more complete discussion of RCIC System operation is provided in the Bases of LCO 3.5.3, "RCIC System."A 1<INSERT 11>
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| The RCIC System may be initiated by either automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low (Level 2). The variable is monitored by four level switches that are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic arrangement. Once initiated, the RCIC logic seals in and can be reset by the operator only when the reactor vessel water level signals have cleared.
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| The RCIC test line isolation valves are closed on a RCIC initiation signal to allow full system flow.
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| The RCIC System also monitors the water level in the emergency condensate storage tanks (ECST) since this is the initial source of water for RCIC operation. Reactor grade water in the ECSTs is the normal source. The ECST suction source consists of two ECSTs connected in parallel to the RCIC pump suction. Upon receipt of a RCIC initiation signal, the ECSTs suction valve is automatically signaled to open (it is normally in the open position) unless the pump suction from the suppression pool valve is open. If the water level in the ECSTs falls below a preselected level, first the suppression pool suction valve automatically opens, and then the ECSTs suction valve automatically closes. Two level switches are used to detect low water level in the ECSTs. Either switch can cause the suppression pool suction valve to open. The opening of the suppression pool suction valve causes the ECSTs suction valve to close.
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| (continued)
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| Cooper B 3.3-126 Revision 0 INFORMATION ONLY
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| INFORMATION ONIlYc System Instrumentation B 3.3.5.2 BASES BACKGROUND To prevent losing suction to the pump when automatically (continued) transferring suction from the ECSTs to the suppression pool on low ECST level, the suction valves are interlocked so that the suppression pool suction path must be open before the ECST suction path automatically closes.
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| The RCIC System provides makeup wacer to the reactor until the reactor vessel water level reaches the high water level (Level 8) setting (two-out-of-two logic), at which time the RCIC turbine trip-throttle valve rloses. The RCIC System restarts if vessel level again drops to the low level initiation point (Level 2).
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| APP 'LICABLE The function of the RCIC System is to respond to transient SAF ETY ANALYSES, events by providing makeup coolant to the reactor. The LCO , and RCIC System is not an Engineered Safety Feature System and APP 'LICABILITY no credit is taken in the safety analyses for RCIC System operation. Based on its contribution to the reduction of overall plant risk, however, the system, and therefore its instrumentation meets Criterion 4 of 10 CFR 50.36(c)(2)(ii)
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| (Ref. I). -
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| I<INSERT 2> -0 The OPERABILITY of the RCIC System instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.2-1. Each Function must have a required number set withinthesetting of OPERABLE channels with their setpoints w-ithin the tolera nce of the speeificd All.wabl. . Values, where appropriate. The actual LTSP S setpoint is calibrated consistent with applicable setpoint lEach channel must methodology assumptions. +
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| also respond within its assumed response Allowable Values are specified for each RCIC System time. instrumentation Function specified in he, T*b*e. No*,i,*al-'
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| trip o.tp.int. arc spccificd in the stp*oi*t ealeulatie's.
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| Table 3.3.5.2-1. The sctpont are
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| .al.ulatio...
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| performed using mcthedel.gy LTSPs and the -- *ecrihed in NGrC 31336P A, "General gle.tri- instrument methodologies for Sctpoint Methedelegy,"2 dated September 19967 Thie-ftemil calculation of the as- set.pe..t are selected to ensure that the setpoints do-not left and as-found tolerances are xceecd thc Alle;able Value between CHANNEL CALIBRATIONS.
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| described in the After each calibration the trip setpoint shall Technical Requirements Manual. remain conservative to be left within the as-left band around the The LTSPs the as-left tolerance band LTSP.
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| (continued)
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| Cooper B 3.3-127 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY RCIC System Instrumentation B 3.3.5.2 BASES APPLICABLE Operation With a tFiF *etpQint le,*9 n..se.ativ.e than the nominal4tri*
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| SAFETY ANALYSES, tp""n, b ithin its Allowable Valu,, iGaceptable. A chann, .. l LCO, and e - its "ctuai trip setpOi't is not within its r.quir.d Allwabl..
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| APPLICABILITY Va*lue. Trip setpoints are those predetermined values of output at which (continued) an action should take place. The setpoints are compared to the actual analytical the janayti LTSPs process parameter (e.g., reactor vessel water level), and when measured output value of the process parameter exceeds the setpo the associated device (e.g., switch) changes state. The imits are derived from the limiting values of the process parameters obtained fro tl~analysis. The Allowable Values are derived from the imits, Fsa--ety Trrected for calibration, process, and some of the instrument errors.
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| T toi etp.. .. are then determined, accounting for the remaining
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| =TSs provirument
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| ýins e a equate e. . drift.
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| errors protection derived in this manner because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
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| The individual Functions are required to be OPERABLE in MODE 1, and in MODES 2 and 3 with reactor steam dome pressure > 150 psig since this is when RCIC is required to be OPERABLE. (Refer to LCO 3.5.3 for Applicability Bases for the RCIC System.)
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| The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
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| : 1. Reactor Vessel Water Level - Low Low (Level 2)
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| Low reactor pressure vessel (RPV) water level indicates that normal feedwater flow is insufficient to maintain reactor vessel water level and that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the RCIC System is initiated at Level 2 to assist in maintaining water level above fuel zone zero.
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| Reactor Vessel Water Level - Low Low (Level 2) signals are initiated from four level switches that sense the difference (continued)
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| Cooper B 3.3-128 June 10, 1999 I INFORMATION ONLY
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| INFORMATION ONLY RCIC System Instrumentation B 3.3.5.2 BASES ACTIONS B.1 and B.2 (continued)
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| Because of the redundancy of sensors available to provide initiation signals and the fact that the RCIC System is not assumed in any accident or transient analysis, an allowable 3-ut of service time of 24 hours has been shown to be acceptablýe ef ) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
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| Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition E must be entered and its Required Action taken.
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| C.1 A risk based analysis was performed and determined that an mm allowable out of service time of 24 hours (Ref.
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| acceptable to permit restoration of any inoperable channel to OPERABLE status (Required Action C.i). A Required Action (similar to Required Action B.1) limiting the allowable out of service time, if a loss of automatic RCIC initiation capability exists, is not required. This Condition applies to the Reactor Vessel Water Level--High (Level 8) Function whose logic is arranged such that any inoperable channel will result in a loss of automatic RCIC initiation capability (closure of the turbine trip-throttle valve). As stated above, this loss of automatic RCIC initiation capability was analyzed and determined to be acceptable.
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| The Required Action does not allow placing a channel in trip since this action would not necessarily result in a safe state for the channel in all events.
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| D.1, D.2.1. and D.2.2 Required Action D.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in automatic component initiation capability being lost for the (continued)
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| Cooper B 3.3-132 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY RCIC System Instrumentation B 3.3.5.2 BASES ACTIONS D.1, 0.2.1. and D.2.2 (continued) feature(s). For Required Action D.1, the RCIC System is the only associated feature. In this case, automatic initiation capability is lost if two Function 3 channels are inoperable and untripped. In this situation (loss of automatic suction swap), the 24 hour allowance of Required Actions D.2.1 and D.2.2 is not appropriate, and the RCIC System must be declared inoperable within 1 hour from discovery of loss of RCIC initiation capability. As noted, Required Action D.1 is only applicable if the RCIC pump suction is not aligned to the suppression pool since, if aligned, the Function is already performed.
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| 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."
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| For Required Action D.1, the Completion Time only begins upon discovery that the RCIC System cannot be automatically aligned to the suppression pool due to two inoperable, untripped channels in the same Function. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
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| Because of the redundancy of sensors available to provide initiation signals and the fact that the RCIC System is not assumed in any accident or transient analysis, an allowable
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| _out of service time of 24 hours has been shown to be acceptable (Retr 22) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action D.2.1, which performs the intended function of the channel (shifting the suction source to the suppression pool). Alternatively, Required Action D.2.2 allows the manual alignment of the RCIC suction to the suppression pool, which also performs the intended function. If Required Action D.2.1 or D.2.2 is performed, measures should be taken to ensure that the RCIC System piping remains filled with water. If it is not desired to perform Required Actions D.2.1 and D.2.2 (e.g., as in the case where shifting the suction source could drain down the RCIC suction piping), Condition E must be entered and its Required Action taken.
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| (continued)
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| Cooper B 3.3-133 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY RCIC System Instrumentation B 3.3.5.2 BASES ACTIONS E.1 (continued)
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| With any Required Action and associated Completion Time not met, the RCIC System may be incapable of performing the intended function, and the RCIC System must be declared inoperable immediately.
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| SURVEILLANCE As noted in the beginning of the SRs, the SRs for each RCIC REQUIREMENTS System instrumentat4e Function are found in the SRs column of Table 3.3.5.2-1.
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| The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows:
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| (a) for up to 6 hours for Function 2; and (b) for up to 6 hours for Functions I and 3, provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
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| This Note is based on the reliability analysis (Ref.
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| * assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary.
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| SR 3.3.5.2.1 Performance of the CHANNEL CHECK once every 12 hours 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 parameter on other similar channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or (continued)
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| Cooper B 3.3-134 Revision 0 INFORMATION ONLY
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| INFORMATION ONLYRCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued) 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 plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.
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| The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
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| SR 3.3.5.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
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| Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
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| The Frequency of 92 days is based on the reliability analysis of Reference 2-.----
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| SR 3.3.5.2.3 and SR 3.3.5.2.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
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| Cooper B 3.3-135 June 28, 2001 INFORMATION ONLY
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| INFORMATION ONLY RCIC System Instrumentation B 3.3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The Frequency of SR 3.3.5.2.3 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| The Frequency of SR 3.3.5.2.4 is based upon the assumption of an I4-1 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| [<INSERT 12> .-
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| SR 3.3.5.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.3 overlaps this Surveillance to provide complete testing of the safety function. Simulated automatic actuation is performed each operating cycle.
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| [ "Th1- month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| Operating experience has shown that these components usually pass the Surveillance when performed at the 18- month Frequency.
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| : 1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.1 REFERENCErSjI,1.- 10 CFR 50.36(c)(2)(ii).
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| GENE-770-06-2, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
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| Cooper B 3.3-136 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.6.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
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| Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
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| The 92 day Frequency of SR 3.3.6.1.2 is based on the reliability analysis described in References 10 and 11.
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| SR 3.3.6.1.3, SR 3.3.6.1.4 and SR 3.3.6.1.5 There is a plant specific program which verifies that A CHANNEL CALIBRATION is a complete check of the instrument loop the instrument channel functions as required by and the sensor. This test verifies the channel responds to the measured verifying the as-left and as- parameter within the necessary range and accuracy'W CHANNEL found settings are consistent CALIBRATION leaves the channel adjusted to account for instrument with those established by the drifts between successive calibrations consistent with the plant specific setpoint methodology. setpoint methodology. SR 3.3.6.1.5, however, is only a calibration of the radiation detectors using a standard radiation source.
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| As noted for SR 3.3.6.1.4, the main steam line radiation detectors (Function 2.d) are excluded from CHANNEL CALIBRATION due to ALARA reasons (when the plant is operating, the radiation detectors are generally in a high radiation area; the steam tunnel). This exclusion is acceptable because the radiation detectors are passive devices, with 4 minimal drift. The radiation detectors are calibrated in accordance with a 24] month Frequency using a standard current source and radiation source. The CHANNEL CALIBRATION of the remaining portions of the channel (SR 3.3.6.1.4) are performed using a standard current source.
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| Cooper B 3.3-164 June 28, 2001 1 INFORMATION ONLY
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| INFORMATION ONLY Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The Frequency of SR 3.3.6.1.3 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.6.1.4 and SR 3.3.6.1.5 is based on the assumption of aA-1.8 month calibration interval in the determination of the magnitude o'quipment drift in the setpoint analysis.
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| SR 3.3.6.1.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety lated automatic actuation is performed each operating cycle.ThF-& month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the month Frequency.
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| F24-1ý Cooper B 3.3-165 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.6.2.3 There is a plant specific program which verifies that the instrument A CHANNEL CALIBRATION is a complete check of the instrument loop channel functions as and the sensor.- This test verifies the channel responds to the measured required by verifying parameter within the necessary range and accuracy.JCHANNEL the as-left and as-found settings are consistent CALIBRATION leaves the channel adjusted to account for instrument with those established drifts between successive calibrations consistent with the plant specific by the setpoint setpoint methodology.
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| methodology.
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| The Frequency of SR 3.3.6.2.3 is based on the assumption of a-month calibration interval, respectively, in the determination of the a 24 magnitude of equipment drift in the setpoint analysis.
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| SR 3.3.6.2.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on SCIVs and the SGT System in LCO 3.6.4.2 and LCO 3.6.4.3, respectively, overlaps this mSurveillance to provide complete testing of the assumed safety function.
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| L jýTh 1 4- month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| Operating experience has shown that these components usually pass the Surveillance when performed at the month Frequency.
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| Cooper B 3.3-176 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY LLS Instrumentation B 3.3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The 92 day Frequency is based on the reliability analysis of Reference 3.
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| A portion of the SRV discharge line pressure switch instrument channels are located inside the primary containment. The Note for SR 3.3.6.3.2, "Only required to be performed prior to entering MODE 2 during each scheduled outage > 72 hours when entry is made into primary containment," is based on the location of these instruments and ALARA There is a plant considerations.
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| specific program which verifies that the instrument channel SR 3.3.6.3.4 functions as required by verifying the as-left and as-found CHANNEL CALIBRATION is a complete check of the instrument loop settings are and sensor. This test verifies the channel responds to the measured consistent with those parameter within the necessary range and accuracy.HANNEL established by the setpoint CALIBRATION leaves the channel adjusted to account for instrument methodology. drifts between successive calibrations consistent with the plant specific setpoint methodology.
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| The Frequency of once every -- monnths for SR 3.3.6.3.4 is based on the assumption of *-18 month calibration interval in the determination of the magnitude of, quipment drift in the setpoint analysis.
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| a 24 SR 3.3.6.3.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specified channel.
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| The system functional testing performed in LCO 3.4.3, "Safety/Relief Valves (SRVs) and Safety Valves (SVs)" and LCO 3.6.1.6, "Low-Low Set (LLS) Safety/Relief Valves (SRVs)," for SRVs overlaps this test to provide complete testing of the assumed safety function.
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| The Frequency oFo eeve-rA4 months for SR 3.3.6.3.5 is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power. Operating experience has shown 15Z] these components usually pass the Surveillance when performed at the
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| 'month Frequency.
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| Cooper B 3.3-183 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY CREF System Instrumentation B 3.3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued) instrumentation continues to operate properly between each CHANNEL CALIBRATION.
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| Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.
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| The Frequency is based upon operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with channels required by the LCO.
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| SR 3,3.7.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.
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| Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
| |
| The Frequency of 92 days is based on the reliability analyses of References 5, 6, and 7.
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| There is a plant specific program which verifies that the instrument SR 3.3.7.1.3 channel functions as required by verifying the as-left and as-found A CHANNEL CALIBRATION is a complete check of the instrument loop settings are consistent and the sensor. This test verifies the channel responds to the measured with those established parameter within the necessary range and accuracy.CHANNEL by the setpoint CALIBRATION leaves the channel adjusted to account for instrument methodology.
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| drifts between successive calibrations consistent with the plant specific setpoint methodology.
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| Cooper B 3.3-192 10/05/06 INFORMATION ONLY
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| INFORMATION ONLY CREF System Instrumentation B 3.3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The Frequency is based upon the assumption of a- 4-1month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| SR 3.3.7.1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.7.4, "Control Room Emergency Filter (CREF) System," overlaps this Surveillance to provide F4 complete testing of the assumed safety function.
| |
| T month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
| |
| Operating experience has shown these components usually pass the Surveillance when performed at the month Frequency.
| |
| REFERENCES 1. USAR, Section X-10.4.
| |
| : 2. USAR, Section XIV-6.3.
| |
| : 3. USAR, Section XIV-6.4.
| |
| : 4. 10 CFR 50.36(c)(2)(ii).
| |
| : 5. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
| |
| : 6. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990.
| |
| : 7. NEDC-30851 P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
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| Cooper B 3.3-193 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE REQUIREMENTS SR 3.3.8.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
| |
| The Frequency of 31 days is based on operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is a rare event.
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| SR 3.3.8.1.2 There is a plant specific program A CHANNEL CALIBRATION is a complete check of the relay circuitry and which verifies that the associated time delay relays. This test verifies the channel responds to instrument channel the measured parameter within the necessary range and accuracy.
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| functions as required by verifying the as- CHANNEL CALIBRATION leaves the channel adjusted to account for left and as-found instrument drifts between successive calibrations consistent with the plant settings are specific setpoint methodology.
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| consistent with those established by the setpoint Any setpoint adjustment shall be consistent with the assumptions of the methodology. current plant specific setpoint methodology. a 24 The Frequency is based upon the assumption of aR.4 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
| |
| SR 3.3.8.1.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions.
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| Cooper B 3.3-203 11/04/01 INFORMATION ONLY
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| INFORMATION ONLY LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 'FTh-e- month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
| |
| Operating experience has shown these components usually pass the Surveillance when performed at th month Frequency.
| |
| REFERENCES 1. USAR, Section VIII-4.6.
| |
| : 2. USAR, Chapter XIV.
| |
| : 3. 10 CFR 50.36(c)(2)(ii)
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| Cooper B 3.3-204 02/20/07 INFORMATION ONLY
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| INFORMATION ONLYRPs Electric Power Monitoring B 3.3.8.2 BASES ACTIONS C.A (continued)
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| This places the plant in a condition where minimal equipment, powered through the inoperable RPS electric power monitoring assembly(s), is required and ensures that the safety function of the RPS (e.g., scram of control rods) is not required. The plant shutdown is accomplished by placing the plant in MODE 3 within 12 hours. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power condition in an orderly manner and without challenging plant systems.
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| D._I If any Required Action and associated Completion Time of Condition A or B are not met in MODE 5, with any control rod withdrawn from a core cell containing one or more fuel assemblies, the operator must immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Required Action D.1 results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not required.
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| Action must continue until the Required Action is completed.
| |
| SURVEILLANCE REQUIREMENTS There is a plant specific SR 3.3.8.2.1 program which verifies that the instrument CHANNEL CALIBRATION is a complete check of the instrument loop and channel functions as the sensor. This test verifies that the channel responds to the measured required by verifying the parameter within the necessary range and accuracy$,J/CHANNEL as-left and as-found settings are consistent CALIBRATION leaves the channel adjusted to account for instrument with those established drifts between successive calibrations consistent with the plant specific by the setpoint setpoint methodology. a ]L ,
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| methodology.
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| The Frequency is based on the assumption of " month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
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| Cooper B 3.3-209 11/04/01 1 INFORMATION ONLY
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| INFORMATION ONLY RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.8.2.2 Performance of a system functional test demonstrates that, with a required system actuation (simulated or actual) signal, the logic of the system will automatically trip open the associated power monitoring assembly. The system functional test shall include actuation of the protective relays, tripping logic, and output circuit breakers. Only one signal per power monitoring assembly is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class 1E circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be 2inoperable.
| |
| The month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
| |
| Operating experience has shown that these components usually pass the Surveillance when performed at the_-& month Frequency.
| |
| R.,,,f---
| |
| 2 REFERENCES 1. USAR, Section VII-2.3.
| |
| : 2. 10 CFR 50.36(c)(2)(ii).
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| Cooper B 3.3-210 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY SRVs and SVs B 3.4.3 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.4.3.2 A manual actuation of each SRV (until the main turbine bypass valves have closed to compensate for SRV opening) is performed to verify that, mechanically, the valve is functioning properly and no blockage exists in the valve discharge line. This can also be demonstrated by the response of the turbine control valves or bypass valves, by a change in the measured steam flow, or by any other method suitable to verify steam flow. Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure and steam flow when the SRVs divert steam flow upon opening. Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this test.
| |
| Adequate pressure at which this test is to be performed is t 500 psig, consistent with the recommendations of the vendor. Adequate steam flow is represented by turbine bypass valves at least 30% open, or total steam flow > 106 lb/hr. Plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME Code requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. The 12 hours allowed for manual actuation after the required pressure and steam flow are reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. If a valve fails to actuate due only to the failure of the solenoid but is capable of opening on overpressure, the safety function of the SRV is not considered 2inoperable.
| |
| The month Frequency was developed based on the SRV tests required by the ASME Code for Operation and Maintenance of Nuclear Power Plants (Ref. 6). Operating experience has shown that these components usually pass the Surveillance when performed at the I-.&
| |
| month Frequency. Therefore, the Frequency was concluded to beYN1'[J acceptable from a reliability standpoint.
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| Cooper B 3.4-17 04/28/10 INFORMATION ONLY
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| INFORMATION ONLY ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued) should overcome the RPV pressure and associated discharge line losses.
| |
| Adequate reactor pressure must be available to perform these tests.
| |
| Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPCI System diverts steam flow. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Adequate reactor steam pressure must be > 920 psig to perform SR 3.5.1.7 and > 145 psig to perform SR 3.5.1.8. Adequate steam flow is represented by turbine bypass valves at least 30% open, or total steam flow > 106 lb/hr. Reactor startup is allowed prior to performing the low pressure Surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the Surveillance test is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that HPCI is inoperable.
| |
| Therefore, SR 3.5.1.7 and SR 3.5.1.8 are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test. The 12 hours allowed for the flow tests after required pressure and flow are reached are sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SRs. For SR 3.5.1.8, while adequate pressure can be reached prior to the required Applicability for HPCI, the 12 hour allowance of the Note would not apply until entering the Applicability (>150 psig) with adequate steam flow.
| |
| The Frequency for SR 3,5,1.6 and SR 3.5.1.7 is inaccordance wit 2 Inservice Testing Program requirements. The ont Frequency for SR 3.5.1.8 is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage.
| |
| 241 perating experience has shown that these components usually pass the SR when performed at tWO-8 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| Cooper B 3.5-13 April 19, 2000 INFORMATION ONLY
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| | |
| INFORMATION ONLY ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.5.1.9 The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCI, CS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup and actuation of all automatic valves to their required positions. This SR also ensures that the HPCI System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from the ECSTs to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlaps this Surveillance to provide complete
| |
| [2-L testing of the assumed safety function.
| |
| The"month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
| |
| Operating experience has shown that these components usually pass the SR when performed at the l-8-*onth Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by Note 1 that says for HPCI only the Surveillance is not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test. The time allowed for this test after required pressure and flow are reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. Adequate reactor pressure must be available to perform this test. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPC! System diverts steam flow. Thus, sufficient time is allowed after adequate pressure and flow are achieved to perform this test. Adequate reactor steam pressure is > 145 psig.
| |
| Adequate steam flow is represented by turbine bypass valves at least Cooper B 3.5-14 02/20/07 INFORMATION ONLY
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| | |
| INFORMATION ONLY ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued) 30% open, or a total steam flow of 106 lb/hr. Reactor startup is allowed prior to performing this test because the reactor pressure is low and the time allowed to satisfactorily perform the test is short. For SR 3.5.1.9, while adequate pressure can be reached prior to the required Applicability for HPCI, the 12 hour allowance of the Note would not apply until entering the Applicability (>150 psig) with adequate steam flow.
| |
| This SR is modified by Note 2 that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.
| |
| SR 3.5.1.10 The ADS designated SRVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e.,
| |
| solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. SR 3.5.1.11 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete 24 testing of the assumed safety function.
| |
| Th month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
| |
| 24Operating experience has shown that these components usually pass the SR when performed at the '--month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by a Note that excludes valve actuation since the valves are individually tested in accordance with SR 3.5.1.11. This also prevents an RPV pressure blowdown.
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| Cooper B 3.5-15 02/20/07 INFORMATION ONLY
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| | |
| INFORMATION ONLY ECCS- Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.11 REQUIREMENTS (continued) A manual actuation of each ADS valve is performed to verify that the valve and solenoid are functioning properly and that no blockage exists in the SRV discharge lines. This is demonstrated by the response of the turbine control or bypass valve or by a change in the measured flow or by any other method suitable to verify steam flow. Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening. Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this SR. Adequate pressure at which this SR is to be performed is Ž 500 psig (consistent with the recommendations of the vendor). Adequate steam flow is represented by turbine bypass valves at least 30%
| |
| open, or total steam flow > 100 lb/hr. Reactor startup is allowed prior to performing this SR because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. The 12 hours allowed for manual actuation after the required pressure is reached is sufficient to achieve stable conditions and provides adequate time to complete the Surveillance. SR 3.5.1.10 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.
| |
| The Frequency is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage. Operating 2-4 experience has shown that these components usually pass the SR when performed at thie~t8 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| REFERENCES 1. USAR, Section VI-4.3.
| |
| : 2. USAR, Section VI-4.4.
| |
| (continued)
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| Cooper B 3.5-16 Revision 0 INFORMATION ONLY
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| | |
| INFORMATION ONLY RCIC System B 3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued) adequate to perform the test. The 12 hours allowed for the flow tests after the required pressure and flow are reached are sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SRs. For SR 3.5.3.4, while adequate pressure can be reached prior to the required Applicability for RCIC, the 12 hour allowance of the Note would not apply until entering the Applicability (>150 psig) with adequate steam flow.
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| A 92 day Frequency for SR 3.5.3.3 is consistent with the Inservice -[
| |
| Testing Program requirements. The lonth Frequency for SR 3.5.3.4 is based on the need to perform the Surveillance under conditions that apply just prior to or during a startup from a plant outage. Operating 24 erience has shown that these components usually pass the SR when performed at t month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| SR 3.5.3.5 The RCIC System is required to actuate automatically in order to verify its design function satisfactorily. This Surveillance verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of the RCIC System will cause the system to operate as designed, including actuation of the system throughout its emergency operating sequence; that is, automatic pump startup and actuation of all automatic valves to their required positions. This test also ensures the RCIC System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from the ECST to the suppression pool. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.2 overlaps this Surveillance to provide complete testing of 24 the assumed design function.
| |
| The ý- month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
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| 24 aerating experiencehas shown that these components usually pass the SIR when performed at the-8-month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| Cooper B 3.5-29 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY Primary Containment B 3.6.1.1 BASES SURVEILLANCE REQUIREMENTS (continued) does not change by more than the calculated amount per minute ove
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| _ 10 minute period. The leakage test is performed every 41-onths, The 2z4 h'i'* month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs. Two consecutive test failures, however, would indicate unexpected primary containment degradation; in this event, as the Note indicates, increasing the Frequency to once every 9 months is required until the situation is remedied as evidenced by passing two consecutive tests.
| |
| REFERENCES 1. USAR, Section V-2.4.
| |
| : 2. USAR, Section XIV-6.3.
| |
| : 3. 10 CFR 50, Appendix J, Option B.
| |
| : 4. 10 CFR 50.36(c)(2)(ii).
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| : 5. Safety Evaluation Report by U.S. Atomic Energy Commission dated February 14, 1973 (Section 6.2.1).
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| Cooper B 3.6-5 09/30/08 INFORMATION ONLY
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| INFORMATION ONLY PCIVs B 3.6.1.3 BASES SR 3.6.1.3.6 (continued) calculated radiological consequences of these events remain within 10 CFR 100 limits. The Frequency of this SR is in accordance with the requirements of the Inservice Testing Program.
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| SR 3.6.1.3.7 Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.1, "Primary Containment Isolation Instrumentation," overlaps this SR to provide 24 complete testing of the safety function. The 1 onth Frequency was developed considering it is prudent that this Surveillance be performed only during a unit outage since isolation of penetrations would disrupt the normal operation of many critical components. Operating experience has 24 hown that these components usually pass this Surveillance when performed at t 1-8-month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| SR 3.6.1.3.8 This SR requires a demonstration that a representative sample of reactor instrumentation line excess flow check valves (EFCVs) are OPERABLE by verifying that each valve actuates to the isolation position on an actual or simulated instrument line break. The representative sample consists of an approximately equal number of EFCVs, such that each EFCV is tested at least once every 10 years (nominal). This SR provides assurance that the instrumentation line EFCVs will perform so that predicted radiological 24 consequences will not be exceeded during the postulated instrument line break event. I n1month Frequency is based on the need to perform the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
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| The nominal 10 year interval is based on other performance-based testing programs, such as Inservice Testing (snubbers) and Option B to 10 CFR 50, Appendix J. Furthermore, any EFCV failures will be evaluated to determine if additional testing in that test interval is warranted to ensure overall reliability is maintained. Operating experience has demonstrated that these components are highly reliable and that failures to isolate are very infrequent. Therefore, testing of a representative sample was concluded to be acceptable from a reliability standpoint.
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| Cooper B 3.6-27 11/4/01 INFORMATION ONLY
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| INFORMATION ONLY PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.6.1.3.9 The TIP shear isolation valves are actuated by explosive charges. An in place functional test is not possible with this design. The explosive squib is removed and tested to provide assurance that the valves will actuate when required. The replacement charge for the explosive squib shall be from the same manufactured batch as the one fired or from another H h24th that has been certified by having one of the batch successfully fired. The Frequency o--8 months on a STAGGERED TEST BASIS is considered adequate given the administrative controls on replacement charges and the frequent checks of circuit continuity (SR 3.6.1.3.4).
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| SR 3.6.1.3.10 The analyses in References 8 and 9 are based on leakage that is less than the specified leakage rate. A leakage rate of 150 scfh per Main Steam line at > Pa (58 psig) was assumed in the LOCA analyses. The equivalent leakage rate at > Pt (29 psig) is 106 scfh. An "MSIV line" is each one of the four Main Steam lines with an inboard and an outboard Main Steam Isolation Valve (MSIV). The leakage rate to be measured is the Main Steam line "minimum path" leakage (the lesser actual pathway leakage of the two MSIVs in the Main Steam Line). The leakage limit is based on the analyses of References 11 and 12. The Frequency is in accordance with the Primary Containment Leakage Rate Testing Program.
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| SR 3.6.1.3.11 Verifying each inboard 24 inch primary containment purge and vent valve (PC-230 MV, PC-231 MV, PC-232 MV, and PC-233 MV) is blocked to restrict the maximum opening angle to 600 is required to ensure that the valves can close under DBA conditions within the times assumed in the analysis of References 7 and 8. If a LOCA occurs, the purge and vent valves must close to maintain containment leakage within the values assumed in the accident analysis. At other times, pressurization 24 concerns are not present, thus the purge valves can be fully open. The Smonth Frequency is appropriate because the blocking devices may be removed during a refueling outage.
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| SR 3.6.1.3.12 The Main Steam Pathway is the analyzed leakage path from the four Main Steam lines and the inboard Main Steam drain line to and including the condenser. The leakage limit imposed on the Main Steam Pathway with this surveillance requirement applies to the total (aggregate) leakage for the Main Steam Pathway. The Main Steam Pathway leakage includes the total leakage. of all four Main Steam line penetrations plus Cooper B 3.6-28 09/25/09 INFORMATION ONLY
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| INFORMATION ONLY LLS Valves B 3.6.1.6 BASES ACTIONS (continued)
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| 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 REQUIREMENTS SR 3.6.1.6.1 A manual actuation of each LLS valve is performed to verify that the valve and solenoids are functioning properly and no blockage exists in the valve discharge line. This can be demonstrated by the response of the turbine control or bypass valve, by a change in the measured steam flow, or by any other method that is suitable to verify steam flow.
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| Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Adequate pressure at which this test is to be performed is > 500 psig (consistent with the recommendations of the vendor). Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the LLS valves divert steam flow upon opening. Adequate 24f*.*m flow iS represented by turk ne bypass valves at least 30% open, or total steam flow > 106 lb/hr. Th--MI month Frequency was based on the SRV tests required by the ASME Code for Operation and Maintenance of Nuclear Power Plants (Ref. 3). Operating experience has shown that these components usually pass the Surveillance when performed at the
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| -- "4-- month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| Since steam pressure is required to perform the Surveillance, however, and steam may not be available during a unit outage, the Surveillance may be performed during the startup following a unit outage. Unit startup is allowed prior to performing the test because valve OPERABILITY and the setpoints for overpressure protection are verified by Reference 3 prior to valve installation. After adequate reactor steam dome pressure and flow are reached, 12 hours is allowed to prepare for and perform the test.
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| Cooper B 3.6-37 04/28/10 INFORMATION ONLY
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| INFORMATION ONLY LLS Valves B 3.6.1.6 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.6.1.6.2 The LLS designated SRVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to verify that the mechanical portions (i.e., solenoids) of the LLS function operate as designed when initiated either by an actual or simulated automatic initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.3, "Low-Low Set (LLS) Instrumentation," overlaps this SR to 24 provide complete testing of the safety function.
| |
| Th month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.
| |
| 2perating experience has shown t lj.se components usually pass the Surveillance when performed at th *98 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| This SR is modified by a Note that excludes valve actuation. This prevents a reactor pressure vessel pressure blowdown.
| |
| REFERENCES 1. 10 CFR 50.36(c)(2)(ii).
| |
| : 2. NEDE-22197, Safety Relief Valve Low Low Set System and Lower MSIV Water Level Trip for Cooper Nuclear Station, Unit 1, December 1982.
| |
| : 3. ASME Code for Operation and Maintenance of Nuclear Power Plants.
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| Cooper B 3.6-38 04/28/10 INFORMATION ONLY
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| INFORMATION ONLY Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.6.1.7.2 Each vacuum breaker must be cycled to ensure that it opens properly to perform its design function and returns to its fully closed position. This ensures that the safety analysis assumptions are valid. The 92 day Frequency of this SR was developed based upon Inservice Testing Program requirements to perform valve testing at least once every 92 days.
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| SR 3.6.1.7.3 Demonstration of vacuum breaker opening setpoint is necessary to ensure that the safety analysis assumption regarding va;uum breakerifll2 open differential pressure of < 0.5 psid is valid. The 1 -5ont Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular
| |
| [... procedures were performed with the reactor at power. For this unit, the 1-8-month Frequency has been shown to be acceptable, based on operating experience, and is further justified because of other Surveillances performed at shorter Frequencies that convey the proper functioning status of each vacuum breaker.
| |
| REFERENCES 1. Bodega Bay Preliminary Hazards Summary Report, Appendix I, Docket 50-205, December 28, 1962.
| |
| : 2. USAR, Section V-2.3.6.
| |
| : 3. 10 CFR 50.36(c)(2)(ii).
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| Cooper B 3.6-44 02/20/07 INFORMATION ONLY
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| INFORMATION ONLY Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.8 BASES SURVEILLANCE SR 3.6.1.8.2 (continued)
| |
| REQUIREMENTS requirements to perform valve testing at least once every 92 days. A 31 day Frequency was chosen to provide additional assurance that the vacuum breakers are OPERABLE, since they are located in a harsh environment (the suppression chamber airspace).
| |
| SR 3.6.1.8.3 Verification of the vacuum breaker setpoint for opening is necessary to ensure that the safety analysis assumption regarding vacuum breaker full open differential pressure of 0.5 psid is valid. The l-8-1*t Forequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if
| |
| [2m.k.he Surveillance were performed with the reactor at power. The Smonth Frequency has been shown to be acceptable, based on operating experience, and is further justified because of other surveillances performed at shorter Frequencies that convey the proper functioning status of each vacuum breaker.
| |
| REFERENCES 1. Bodega Bay Preliminary Hazards Summary Report, Appendix I, Docket 50-205, December 28, 1962.
| |
| : 2. USAR, Section XIV-6.3.
| |
| : 3. Deleted
| |
| : 4. USAR, Section V-2.3.6.
| |
| : 5. 10 CFR 50.36(c)(2)(ii).
| |
| : 6. FSAR Question No. 5.17.
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| Cooper B 3.6-50 June 10, 1999 I INFORMATION ONLY
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| INFORMATION ONLY Secondary Containment B 3.6.4.1 BASES SURVEILLA NCE SR 3.6.4.1.4 REQUIREME NTS (contin ued) The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment. SR 3.6.4.1.4 demonstrates that one SGT subsystem can maintain > 0.25 inches of vacuum water gauge for I hour at a flow rate < 1780 cfm. The 1 hour test period allows secondary containment to be in thermal equilibrium at steady state conditions. Therefore, this test is used to ensure secondary containment boundary integrity. Since this SR is a secondary containment test, it need not be performed with each SGT subsystem. The SGT subsystems are tested on a STAGGERED TEST BASIS, however, to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform this test. Operating experience has shown these nts usually pass the Surveillance when performed at
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| ~t 014-month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| REFERENCES 1. USAR, Section XIV-6.3.
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| : 2. USAR, Section XIV-6.4.
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| : 3. 10 CFR 50.36(c)(2)(ii).
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| Cooper B 3.6-71 Revision 0 INFORMATION ONLY
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| INFORMATION ONLY SCIVs B 3.6.4.2 BASES SURVEILLANCE REQUIREMENTS SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a secondary containment isolation signal is required to minimize leakage of radioactive material from secondary containment following a DBA or other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a secondary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation 24 Instrumentation," overlaps this SR to provide complete testing of the safety function. Th-8 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient ifthe Surveillance were performed with the reactor at power. Operating experience has n24 sop ý these components usually pass the Surveillance when performed at th 1-month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| REFERENCES 1. USAR, Section V-3.0.
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| : 2. USAR, Section XIV-6.0.
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| : 3. USAR, Section XIV-6.3.
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| : 4. USAR, Section XIV-6.4
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| : 5. 10 CFR 50.36(c)(2)(ii).
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| : 6. Technical Requirements Manual.
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| Cooper B 3.6-78 11/04/01 INFORMATION ONLY
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| INFORMATION ONLY SGT System B 3.6.4.3 BASES SURVEILLANCE REQUIREMENTS SR 3.6.4.3.1 (continued) fan motors and controls and the redundancy available in the system.
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| SR 3.6.4.3.2 This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations).
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| Specific test frequencies and additional information are discussed in detail in the VFTP.
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| SR 3.6.4.3,3 This SR verifies that each SGT subsystem starts on receipt of an actual or simulated initiation signal. While this Surveillance can be performed with the reactor at power, operating experience has shown that thýsý...74 components will pass the Surveillance when performed at the grhonth Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. Therefore, the Frequency was found to be acceptable from a reliability standpoint.
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| SR 3.6.4.3.4 This SR verifies that the SGT units cross tie damper is in the correct position, and that each SGT room air supply check valve and each air operated SGT dilution air shutoff valve open when required. This ensures that the decay heat removal function of SGT System operation is available. While this Surveillance can be performed with the reactor at 24 power. oerat ing experience has showQ that these components will pass the Surveillance when performed at th*-,'l8-month Frequency, which is based on the refueling cycle. Therefore, the Frequency was found to be acceptable from a reliability standpoint.
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| REFERENCES 1. (Deleted)
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| : 2. USAR, Section V-3.3.4.
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| : 3. 10 CFR 50,36(c)(2)(ii).
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| Cooper B 3.6-84 12/18/03 INFORMATION ONLY
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| INFORMATION ONLY SW System and UHS B 3.7.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.7.2.4 This SR verifies that the automatic isolation valves of the SW System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This is demonstrated by the use of an actual or simulated initiation signal. The initiation signal is caused by low SW header pressure (approximately 20 psig). This SR also verifies the automatic start capability of one of the two SW pumps in each subsystem.
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| 24 Operating experience hasshown that these components usually pass the SR when performed at tr"l-8-4month Frequency. Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.
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| REFERENCES 1. NEDC 94-255, "Hydraulic Evaluation of Opening in Intake Structure Guide Wall," June 14, 1995.
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| : 2. USAR, Chapter V.
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| : 3. USAR, Chapter XIV.
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| : 4. 10 CFR 50.36(c)(2)(ii).
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| : 5. NEDC 00-095E, "CNS Reactor Building Post-LOCA Heating Analysis," May 28, 2010.
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| 02/22/11 Cooper INFORMATION ONLY
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| INFORMATION ONLY REC System No changes B 3.7.3
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| [Page included for completeness BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.7.3.2 Verification of the REC System temperature ensures that the heat removal capability of the REC System is within the assumptions of the DBA analysis. The 24 hour Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
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| SR 3.7.3.3 Verifying the correct alignment for each manual, power operated, and automatic valve in each REC subsystem flow path provides assurance that the proper flow paths will exist for REC operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
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| This SR is modified by a Note indicating that isolation of the REC System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of the REC System.
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| As such, when all REC pumps, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the REC System is still OPERABLE.
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| The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
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| SR 3.7.3.4 This SR verifies that the automatic isolation valves of the REC System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This is demonstrated by the use of an actual or simulated initiation signal, The initiation signal is caused by low REC heat exchanger outlet pressure (which has an analytically determined limit of 55 psig decreasing). Also, a Group VI isolation signal will open Cooper INFORMATION ONLY 05/06/09 1
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| INFORMATION ONLY REC System B 3.7.3 BASES SURVEILLANCE REQUIREMENTS (continued) the REC heat exchanger service water outlet valves and the REC critical loop supply valves to provide cooling water to essential components.
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| 24 Oerating experience has shown that these components usually pass the 2ýý- sR when performed r-8 at tn month Frequency. Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.
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| REFERENCES 1. USAR, Section X-6.
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| : 2. 10 CFR 50.36(c)(2)(ii).
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| : 3. DC 93-057
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| : 4. NEDC 92-050X and NEDC 97-087 Cooper INFORI AIIbN ONLY 05/06/09 I
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| INFORMATION ONLY CREF System B 3.7.4 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.7.4.3 This SR verifies that on an actual or simulated initiation signal, the CREF System starts and operates. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.7.1, "Control Room Emergency Filter (CREF) System 24 Instrumentation," overlaps this SRto provide complete testing of the safety function. The Frequency offŽ8 months is based on industry operating experience and is consistent with the typical refueling cycle.
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| SR 3.7.4.4 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 this 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 whole body or its equivalent to any part of the body following a LOCA or 5 rem TEDE following a FHA and the CRE occupants are protected from hazardous chemicals and smoke.
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| 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.
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| Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref. 4) which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 6). 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. 7). 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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| Cooper INFORMAOqiON ONLY 10/29/08
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| INFORMATION ONLYMain Turbine Bypass System B 3.7.7 BASES ACTIONS (continued)
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| B.1 If the inoperable Main Turbine Bypass Valve cannot be restored to OPERABLE status and the MCPR operating limits for one inoperable Main Turbine Bypass Valve are not applied within 2 hours, or two or more Main Turbine Bypass Valves are inoperable, THERMAL POWER must be reduced to < 25% RTP. As discussed in the Applicability section, operation at < 25% RTP results in sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the Applicable Safety Analyses transients. The 4 hour Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
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| SURVEILLANCE SR 3.7.7.1 REQUIREMENTS Cycling each main turbine bypass valve through at least half of one cycle of full travel (50% open) demonstrates that the valves are mechanically OPERABLE and will function when required. The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
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| Operating experience has shown that these components usually pass the SR when performed at the 31 day Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.
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| SR 3.7.7.2 The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that, with the required 2 ssem initiation signals, the valves will actuate to their required position.
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| Th9:-lI month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance with the reactor at power. Operating experience has mwoeperformed shown 1 month Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.
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| Cooper B 3.7-33 10/29/08 INFORMATION ONLY
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| INFORMATION ONLYMain Turbine Bypass System B 3.7.7 BASES SURVEILLANCE REQUIREMENTS (continued)
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| Cycling open a bypass valve at slightly above 29.5 RTP may affect the RPS Turbine Stop and Control Valve functions.
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| SR 3.7.7.3 This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analyses. The response time limits are specified in the COLR. The 4-8 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performn,-9ý with the reactor at power. Operating experience has shown the 8-ionth Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.
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| REFERENCES 1. USAR, Section VII-1 1.3.
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| : 2. Amendment 25 to the FSAR.
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| : 3. NEDC 96-006, "Estimate of Steam Tunnel's HELB," March 3, 1996.
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| : 4. USAR, Section XIV-5.8.1.
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| : 5. 10 CFR 50.36(c)(2)(ii).
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| Cooper B 3.7-34 10/29/08 INFORMATION ONLY
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| INFORMATION ONLY AC Sources - Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.8.1.8 Transfer of each 4.16 kV critical bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the 24 OPERABILITY of the alternate circuit distribution network to power the shutdown loads. Th*-1-8 month Frequency of the Surveillance is based on engineering judgment taking into consideration the plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed on the
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| [~~J~ 1-8 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, plant safety systems.
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| Credit may be taken for unplanned events that satisfy this SR.
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| SR 3.8.1.9 24 Consistent with IEEE 387-1995 (Re . 15), Section 7.5.9 and Table 3, this SR requires demonstration once p1 -48months that the DGs can start and run continuously at full load capability for an interval of not less than 8 hours -6 hours of which is at a load equivalent to 90-100% of the continuous rating of the DG, and 2 hours of which is at a load equivalent to 105% to 110% of the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.
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| A load band of 90-100% accident load is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. Generator loadings less than 90%
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| occurring during the first 10 seconds of accident loading are bounded by the test conditions of 90 to 100% load and are well within the generator capability curves.
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| Cooper B 3.8-21 03/25/11 INFORMATION ONLY
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| INFORMATION ONLY AC Sources - Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) __cnitt[
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| [ Th month Frequency is eenseeative with Fespeet-te the
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| ...... mcndatien of IEEE. 387 19.. -f 4. IEEE 387-1995 (Ref.
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| 15), Section 7.5.9 and Table 3,teequire this SR to be performed duringwh 24 refueling 24 into consideration plant per outages once 24 months. Th>-1-8 month Frequency takes conditions required to perform the Surveillance; and is intended to be consistent with expected fuel cycle lengths.
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| This Surveillance has been modified by three Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. The reason for Note 2 is that during operation with the reactor critical, performance of this Surveillance could cause perturbations to the electrical distribution systems that would challenge continued steady state operation and, as a result, plant safety systems.
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| Note 3 ensures that the DG is tested under load conditions that are as close to worst case design basis conditions as possible. When synchronized with offsite power, testing should be performed at a power factor of < 0.89. This power factor is representative of the actual inductive loading a DG would see under design basis accident conditions. Under certain conditions, however, Note 3 allows the surveillance to be conducted at a power factor other than < 0.89. These conditions occur when grid voltage is high, and the additional field excitation needed to obtain a power factor of < 0.89 results in voltages on the emergency busses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.89 while still maintaining acceptable voltage limits on the emergency busses. In other circumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of 0.89 may not cause unacceptable voltages on the emergency busses, but the excitation levels are in excess of those recommended for the DG. In such cases, the power factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation limits. Credit may be taken for unplanned events that satisfy this SR.
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| SR 3.8.1.10 Under LOCA conditions and loss of offsite power, loads are sequentially connected to the bus by a timed logic sequence. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The 10%
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| load sequence time interval tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next Cooper INFORM7f N ONLY 03/25/11
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| INFORMATION ONLY AC Sources - Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 2 provides a summary of the automatic loading of ESF buses. 1*intenttof theI The Frequency of -18months is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(2); takes into consideration plant conditions required to perform the Surveillance; and is intended to be consistent with expected fuel cycle lengths.
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| This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy this SR.
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| SR 3.8.1.11 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.
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| This Surveillance demonstrates DG operation during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal.
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| This test verifies all actions encountered from the loss of offsite power and loss of coolant accident, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automatically maintain the required voltage and frequency.
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| The DG auto-start time of 14 seconds is derived from requirements of the accident analysis for responding to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.
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| The requirement to verify the connection and power supply of permanent and auto-connected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or systems are not capable of being operated at full flow. In lieu of actual demonstration of connection and Cooper 03/25/11 1 INFORM -( N ONLY
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| INFORMATION ONLY AC Sources - Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) 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.
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| -The Frequency48 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length t8 months.
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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 being periodically circulated and temperature maintained consistent with manufacturer recommendations. The reason for Note 2 Is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. Credit may be taken for unplanned events that satisfy this SR.
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| REFERENCES 1. USAR, Section VIII-1.0.
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| : 2. USAR, Section VIII-2.0 and VIII-3.0.
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| : 3. Safety Guide 9, Revision 0, March 1971.
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| : 4. USAR, Chapter VI.
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| : 5. USAR, Chapter XIV.
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| : 6. 10 CFR 50.36(c)(2)(ii).
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| : 7. Generic Letter 84-15.
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| : 8. Regulatory Guide 1.93.
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| : 9. Regulatory Guide 1.9, Revision 3, July 1993.
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| : 10. Regulatory Guide 1.108.
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| : 11. Regulatory Guide 1.137.
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| Cooper B 3.8-24 03/25/11 INFORMATION ONLY
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| INFORMATION ONLY DC Sources - Operating B 3.8.4 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The 18 month Frequency for the Surveillances is based on engineering judgment. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency.
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| Therefore, the Frequency has been concluded to be acceptable from a reliability standpoint.
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| SR 3.8.4.6 Battery charger capability requirements are basedon the design capacity of the chargers (Ref. 3). According to Regulatory Guide 1.32 (Ref. 8),
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| 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.
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| The Frequency is acceptable, given the unit conditions required to perform the test and the other administrative controls existing to ensure 24 adequate charger performance during these 448*nonth intervals. In addition, this Frequency is intended to be consistent with expected fuel cycle lengths.
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| SR 3.8.4.7 A battery service test is a special test of the battery's capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The discharge rate and test length corresponds to the 24 design duty cycle requirements as specified in design calculations.
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| lintent of the The Frequency o 4. months is consistent with the recommendations of Regulatory Guide 1.32 (Ref. 8) and Regulatory Guide 1.129 (Ref. 9),
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| which state that the battery service test should be performed during refueling operations or at some other outage, with interva!c between tctcs not to emcocd 18 menth .
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| This SR is modified by two Notes. Note 1 allows the performance of a modified performance discharge test in lieu of a service test once per 60 months. The substitution is acceptable because a modified performance discharge test represents a more severe test of battery capacity than SR 3.8.4.7.
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| Cooper INFORMATION ONLY 04/22/10 1
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| NLS2011071 Page 1 of 49 Attachment 5 GL 91-04 Review Cooper Nuclear Station, Docket No. 50-298, DPR-46
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| NLS2011071 Page 2 of 49
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| : 1. BACKGROUND Technical Specification (TS) Surveillance Requirement (SR) frequency changes are required to accommodate a 24-month fuel cycle for Cooper Nuclear Station (CNS). The Nebraska Public Power District (NPPD) is proposing changes in this submittal that were evaluated in accordance with the guidance provided in Nuclear Regulatory Commission (NRC) Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991. GL 91-04 provides NRC Staff guidance that identifies the types of information that must be addressed when proposing extensions of TS SR frequency intervals from 18 months to 24 months.
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| Historical surveillance test data and associated maintenance records were reviewed in evaluating the effect of these changes on safety. In addition, the licensing basis was reviewed to ensure it was not invalidated. Based on the results of these reviews, it is concluded that there is no adverse effect on plant safety due to increasing the surveillance test intervals from 18 to 24 months with the continued application of the 25% grace period allowed by SR 3.0.2.
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| GL 91-04 addressed steam generator inspections, which are not applicable to CNS, and are therefore not discussed in this submittal. Additionally, the GL addressed interval extensions to leak rate testing pursuant to 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors." This is also not discussed in this submittal because NPPD has adopted 10 CFR 50, Appendix J, Option B, as implemented by TS 5.5.12, "Primary Containment Leakage Rate Testing Program," which negates the need for 10 CFR 50 Appendix J exemptions.
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| : 2. EVALUATION In GL 91-04, the NRC provided generic guidance for evaluating a 24-month surveillance test interval for TS SRs. Attachment 1 of this submittal defines each step outlined by the NRC in GL 91-04, and provides a description of the methodology used by NPPD to complete the evaluation for each specific TS SR line item. The methodology utilized in the CNS drift analysis is similar to the methodology used for previous plant submittals such as the River Bend Station, Perry Nuclear Power Plant, and Edwin I. Hatch Nuclear Plant submittals. There have been minor revisions incorporated into the CNS drift design guide based on NRC comments or Requests for Additional Information from previous 24-month fuel cycle extension submittals; e.g., NPPD added the requirement that 30 samples were generally required to produce a statistically significant sample set.
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| For each of the identified surveillances, at least five operating cycles SR performances were retrieved. In most cases, this included SRs performed during the Fall 2009 refueling outage. In some cases, SRs performed in 2010 and 2011 were included in the evaluation if older records were not readily retrievable. This provided approximately three 30-month surveillance periods of data to identify any repetitive problems. It has been concluded, based on engineering judgment, that three 30-month periods provide adequate performance test history. In some instances, additional surveillance performances were included when insufficient data was
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| | |
| NLS2011071 Page 3 of 49 available for adequate statistical analysis of instrument drift. Further references to performance history reflect evaluations of the five most recent performances available through the Fall 2009 outage, unless otherwise specified.
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| In addition to evaluating the historical drift associated with current 18-month calibrations, the failure history of each 18-month surveillance was also evaluated. With the extension of the testing frequency to 24 months, there will be a longer period between each surveillance performance. If a failure that results in the loss of the associated safety function should occur during the operating cycle that would only be detected by the performance of the 18-month TS SR, then the increase in the surveillance testing interval might result in a decrease in the associated function's availability. Furthermore, potential common failures of similar components tested by different surveillances were also evaluated. This additional evaluation determined whether there is evidence of repetitive failures among similar plant components.
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| The surveillance failures detailed with each SR exclude failures that:
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| (a) Did not impact a TS safety function or TS operability; (b) Are detectable by required testing performed more frequently than the 18-month surveillance being extended; or (c) The cause can be attributed to an associated event such as a preventative maintenance task, human error, previous modification or previously existing design deficiency, or that were subsequently re-performed successfully with no intervening corrective maintenance (e.g., plant conditions or malfunctioning measurement and test equipment may have caused aborting the test performance).
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| These categories of failures are not related to potential unavailability due to testing interval extension, and are therefore not listed or further evaluated in this submittal.
| |
| The following sections summarize the results of the failure history evaluation. The evaluation confirmed that the impact on system availability, if any, would be small as a result of the change to a 24-month testing frequency.
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| The proposed TS changes related to GL 91-04 test interval extensions have been divided into two categories. The categories are: (A) changes to surveillances other than channel calibrations, identified as "Non-Calibration Changes," and (B) changes involving the channel calibration frequency, identified as "Calibration Changes."
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| A. Non-Calibration Changes For the non-calibration 18-month surveillances, GL 91-04 requires the following information to support conversion to a 24-month frequency:
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| : 1) Licensees should evaluate the effect on safety of an increase in 18-month surveillance intervals to accommodate a 24-month fuel cycle. This evaluation should support a conclusion that the effect on safety is small.
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| NLS2011071 Page 4 of 49
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| : 2) Licensees should confirm that historical plant maintenance and surveillance support this conclusion.
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| : 3) Licensees should confirm that the assumptions in the plant licensing basis would not be invalidated on the basis of performing any surveillance at the bounding surveillance interval limit provided to accommodate a 24-month fuel cycle.
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| In consideration of these confirmations, GL 91-04 provides that licensees need not quantify the effect of the change in surveillance intervals on the availability of individual systems or components.
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| The following non-calibration TS SRs are proposed for revision to a 24-month frequency. The associated qualitative evaluation is provided for each of these changes, which concludes that the effect on plant safety is small, that the change does not invalidate any assumption in the plant licensing basis, and that the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. These conclusions have been validated by a review of the surveillance test history at CNS as summarized below for each SR.
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| TS 3.1.7 Standby Liquid Control (SLC) System SR 3.1.7.8 Verify flow through one SLC subsystem from pump into reactor pressure vessel.
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| SR 3.1.7.9 Verify all heat traced piping between storage tank and pump suction is unblocked.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| The flow path through one SLC subsystem is verified per SR 3.1.7.8 during every refueling outage on a STAGGERED TEST BASIS and per SR 3.1.7.9 every refueling outage. These tests could inadvertently cause a reactor transient if performed with the unit operating. Therefore, to decrease the potential impact of the tests, they are performed during outage conditions.
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| The SLC pumps and valves are powered and controlled from separate buses and circuits so that a single electrical failure will not prevent system operation. The SLC pumps are tested quarterly in accordance with the Inservice Testing (IST) Program per SR 3.1.7.7 to verify operability. The available volume of the sodium pentaborate solution is verified every 24 hours per SR 3.1.7.1.
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| Similarly, the temperature of the sodium pentaborate solution in the storage tank and the temperature of the pump suction piping are verified to be within limits every 24 hours, per SR 3.1.7.2 and SR 3.1.7.3, to preclude precipitation of the boron solution. Additionally, an installed backup heater (automatically controlled) is used to maintain solution temperature above the saturation point (5 ITF to 63 0 F). In addition, SR 3.1.7.4 verifies the continuity of the charge in the explosive valves monthly. These more frequent tests ensure that the SLC system remains operable during the operating cycle.
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| NLS2011071 Page 5 of 49 A review of the surveillance history verified that this subsystem had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the inherent system and component reliability as shown by the failure history, and the more frequent testing performed during the operating cycle, the impact of this change on safety, if any, is small.
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| TS 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves SR 3.1.8.3 Verify each SDV vent and drain valve:
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| : a. Closes in < 30 seconds after receipt of an actual or simulated scram signal; and
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| : b. Opens when the actual or simulated scram signal is reset.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| This SR ensures that the SDV vent and drain valves close in < 30 seconds after receipt of an actual or simulated scram signal and open when the actual or simulated scram signal is reset.
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| SR 3.1.8.2 requires that the SDV vent and drain valves be cycled fully closed and fully open every 92 days during the operating cycle, which ensures that the mechanical components and a portion of the valve logic remain operable. It has been previously accepted that the failure rate of components is dominated by the mechanical components, not by the logic systems (refer to specific discussion in the Logic System Functional Test (LSFT) section below).
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| A review of the applicable CNS surveillance history demonstrated that the logic subsystem for the SDV vent and drain valves had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the manual cycling of the valves to ensure that the valves are operable, as required by SR 3.1.8.2, and the history of logic subsystem performance, the impact of this change on safety, if any, is small.
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| LOGIC SYSTEM FUNCTIONAL TESTS and SELECTED CHANNEL FUNCTIONAL TESTS TS 3.3.1.1 Reactor Protection System (RPS) Instrumentation SR 3.3.1.1.11 Perform CHANNEL FUNCTIONAL TEST.
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| (This test is essentially an LSFTfor the Reactor Mode Switch scram circuit. The justificationfor extending LSFTs is also validfor the extension of this SR).
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| SR 3.3.1.1.13 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.2.1 Control Rod Block Instrumentation SR 3.3.2.1.7 Perform CHANNEL FUNCTIONAL TEST.
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| (This test is essentially an LSFTfor the Reactor Mode Switch rod block circuit. The justificationfor extending LSFTs is also validfor the extension of this SR).
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| NLS2011071 Page 6 of 49 TS 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation SR 3.3.2.2.3 Perform LOGIC SYSTEM FUNCTIONAL TEST including valve actuation.
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| TS 3.3.3.2 Alternate Shutdown System SR 3.3.3.2.2 Verify each required control circuit and transfer switch is capable of performing the intended functions.
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| (This test is essentiallyan LSFTfor the transfer circuits associatedwith shifting indication and controlfrom the control room to the remote shutdown panel. The justificationfor extending LSFTs is also validfor the extension of this SR).
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| TS 3.3.4.1 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)
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| Instrumentation SR 3.3.4.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST including breaker actuation.
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| TS 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation SR 3.3.5.1.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation SR 3.3.5.2.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.6.1 Primary Containment Isolation Instrumentation SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.6.2 Secondary Containment Isolation Instrumentation SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.6.3 Low-Low Set (LLS) Instrumentation SR 3.3.6.3.5 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.7.1 Control Room Emergency Filter (CREF) System Instrumentation SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.8.1 Loss of Power (LOP) Instrumentation SR 3.3.8.1.3 Perform LOGIC SYSTEM FUNCTIONAL TEST.
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| TS 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring SR 3.3.8.2.2 Perform a system functional test.
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| (This test is essentially an LSFTfor the RPS Electric Power Monitor circuits. The justificationfor extending LSFTs is also validfor this SR).
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| NLS2011071 Page 7 of 49 Extending the surveillance test interval for the LSFTs and selected functional tests is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Checks, Channel Functional Tests, analog trip module calibration, and visual confirmation of satisfactory operation (as applicable). This more frequent testing ensures that a major portion of the circuitry is operating properly and will detect significant failures within the instrument loop. Additionally, the above actuation instrumentation and logic, controls, monitoring capabilities, and protection systems, are designed to meet applicable reliability, redundancy, single failure, and qualification standards and regulations as described in the CNS Updated Safety Analysis Report (USAR). As such, these functions are designed to be highly reliable. Furthermore, as stated in the August 2, 1993 NRC Safety Evaluation Report relating to extension of the Peach Bottom Atomic Power Station, Units 2 and 3, surveillance intervals from 18 to 24 months:
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| Industry reliability studies for boiling water reactors (BWRs), prepared by the BWR Owners Group (NEDC-30936P) show that the overall safety systems' reliabilities are not dominated by the reliabilities of the logic systems, but by that of the mechanical components, (e.g., pumps and valves), which are consequently tested on a more frequent basis. Since the probability of a relay or contact failure is small relative to the probability of mechanical component failure, increasing the logic system functional test interval represents no significant change in the overall safety system unavailability.
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| A review of the applicable CNS surveillance history demonstrated that the logic systems for these functions had 30 failures of the TS functions that would have been detected solely by the periodic performance of one of the above SRs.
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| a) On January 4, 2010, the Temperature Switch RCIC-TS-79B Trip Setpoint exceeded the TS limit. CR-CNS-2010-00064 was written to document the issue with RCIC-TS-79B.
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| The Trip Setpoints were adjusted to within proper limits. (SR 3.3.6.1.6) b) On November 19, 2009, the as-found Trip Setpoint for MS-DPIS- 119D exceeded instrument and TS limits. CR-CNS-2009-09839 was written to document the issue.
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| Work Order (WO) 4731278 replaced the switch. (SR 3.3.6.1.6) c) June 25, 2009, Intermediate Range Monitor (IRM) C as-found voltages were out-of-tolerance. The pre-regulator was found out-of-calibration and could not adjust per the surveillance procedure. CR-CNS-2009-02867 was written to document condition. All as-left values were adjusted in tolerance satisfactorily. (SR 3.3.1.1.13) d) On December 26, 2008, the as-found Trip Setpoint for NBI-PS-102A was out-of-tolerance exceeding instrument and TS limits. The CR-CNS-2008-09500 apparent cause evaluation concluded the failure was due to equipment excessive drift and equipment malfunction. Corrective actions replaced the pressure switch with new Static O-Ring Model 9N-AA45-P 1-F 1ATTX3 and adjusted the calibration frequency to quarterly for next two cycles. (SR 3.3.4.1.3)
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| NLS2011071 Page 8 of 49 e) On May 4, 2008, MS-LMS-A086A(A) RPS/Green Light was found out-of-tolerance and outside the TS limit. The switch was adjusted to within satisfactory limits. (SR 3.3.1.1.13) f) On August 15, 2007, the RPS logic failed to initiate and reset as expected. CR-CNS-2007-05545 stated that IRM D did not have an INOP or UPSCALE TRIP as expected.
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| WO 4583315 replaced relays KIB, K4B and K19B. (SR 3.3.1.1.13) g) On November 18, 2006, a contact on a time-delay relay (TDR) for Service Water Pump B did not properly close. This prevented Service Water Pump B restart. CR-CNS-2006-09360 stated that the pump breaker was realigned. (SR 3.3.5.1.5 and SR 3.3.8.1.3) h) On February 8, 2006, three of the Average Power Range Monitor (APRM) C Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument, Technical Requirements Manual (TRM), and TS limits. CR-CNS-2006-00994 documented the issue and the values were adjusted in tolerance. (SR 3.3.1.1.13) i) On December 29, 2005, the as-found Trip Setpoint for NBI-PS-102A was out-of-tolerance exceeding instrument and TS limits. CR-CNS-2005-09596 was written to document the issue. The pressure switch was replaced per WO 4478791. (SR 3.3.4.1.3) j) On March 31, 2005, Temperature Switch RWCU-TS-8 1 C Trip Setpoint exceeded TS limits. CR-CNS-2005-02202 was written to document the issue. The Trip Setpoint was adjusted to within proper limits. (SR 3.3.6.1.6) k) On March 31, 2005, Temperature Switch RWCU-TS-8 1G Trip Setpoint exceeded TS limits. CR-CNS-2005-02202 was written to document the issue. The Trip Setpoint was adjusted to within proper limits. (SR 3.3.6.1.6)
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| : 1) On February 15, 2005, Diesel Generator (DG)-I tripped during testing. Per CR-CNS-2005-01360, field troubleshooting determined that the failure occurred due to a short circuit in transient voltage suppression (TVS) network diodes installed in parallel with the coil of solenoid valve 20F01 "Non-Emergency Trips Bypass Valve." The short circuit allowed excessive current flow and caused two fuses in DG- 1 control power circuit 4 to blow (one in the positive lead and the other in the negative lead). WO 4426786 replaced a blown fuse, fused disconnect, diode assembly, and Relay 4EMX1.
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| (SR 3.3.5.1.5 and SR 3.3.8.1.3) m) On January 30, 2005, testing indicated that a resistance reading was out-of-specification at oo ohms. Notification 10366727, written to document this issue, stated that the contacts appeared to be open with relay 27X- 1GB actuated, and concluded that the relay contacts be inspected, and cleaned or repaired. WO 4424836 burnished the
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| NLS2011071 Page 9 of 49 contacts and retested relay contact resistance satisfactorily. (SR 3.3.5.1.5 and SR 3.3.8.1.3) n) On January 25, 2005, Square Root Converter Board 1 (Z8) (NMF-SQRT-152A) was found out-of-tolerance. The Square Root Converter Card was replaced by WO 4423227 with as-left values satisfactory. (SR 3.3.1.1.13) o) On June 18, 2004, the as-found Trip Setpoint for NBI-PS- 102A was out-of-tolerance exceeding instrument and TS limits. Notification 10322133 stated that the pressure switch was recalibrated to within tolerance. (SR 3.3.4.1.3) p) On April 6, 2004, three of the APRM E Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument limits. Notification 10306116 stated that the values were adjusted in tolerance. (SR 3.3.1.1.13) q) On June 28, 2003, Temperature Switch HPCI-TS-125A would not trip at required values. RCR 2003-1181 documented the Trip Setpoint being found in excess of TS limits. The Condition Report cited the apparent cause as a possible equipment end-of-life condition. The switch was replaced per WO 4315747. (SR 3.3.6.1.6) r) On June 28, 2003, the Temperature Switch HPCI-TS-126C as-found Trip Setpoint exceeded the TS limit. Notification 10248902 documented the Trip Setpoint being found in excess of TS limits, and cited the apparent cause as instrument drift. The switch was replaced per WO 4315747. (SR 3.3.6.1.6) s) On June 28, 2003, the Temperature Switch RHR-TS-151D Trip Setpoint exceeded TS limits. Notification 10248194 documented the Trip Setpoint being found in excess of TS limits and cited the apparent cause as instrument drift. The switch was adjusted to within proper limits. (SR 3.3.6.1.6) t) On June 28, 2003, the Temperature Switch HPCI-TS-103D Trip Setpoint exceeded TS limits. Notification 10249606 documented the Trip Setpoint being found in excess of TS limits and cited the apparent cause as instrument drift. The switches were adjusted to within proper limits. (SR 3.3.6.1.6) u) On April 4, 2003, transmitter RR-FT-10OC could not be adjusted, which caused numerous readings to be out-of-tolerance. Notification 10236953 was written to document the issue. The resolution to the Notification was that the amplifier module was sent off to be repaired. The procedure was completed with the repaired module, and all as-left values were satisfactory. (SR 3.3.1.1.13) v) On April 1, 2003, DG- 1 could not be unloaded to 1000 kW. When the governor control lowered to just below 2000 kW, load immediately dropped to 0 kW. Notification 10237864 stated that DG-1 was secured and declared inoperable. WO 4303040
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| NLS2011071 Page 10 of 49 performed troubleshooting and repair. The Digital Reference Unit (DRU) was replaced per vendor procedure under the WO. (SR 3.3.5.1.5 and SR 3.3.8.1.3) w) On March 3, 2003, testing found IRM H High Voltage Power Supply module had excessive ripple. Notification 10229873 was written to document the issue. The High Voltage Power Supply was replaced under WO 4297574. (SR 3.3.1.1.13) x) On February 21, 2003, the as-found Trip Setpoint for NBI-PS- 102A was out-of-tolerance exceeding instrument and TS limit. Notification 10228318 was written to document the issue. WO 4296657 replaced the pressure switch. (SR 3.3.4.1.3) y) On January 9, 2003, the as-found Trip Setpoint for MS-DPIS-1 17D exceeded instrument and TS limits. Notification 10219156 stated that the investigation of the calibration history determined the differential pressure switch was drifting excessively.
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| The switch was adjusted back within limits. (SR 3.3.6.1.6) z) On November 20, 2002, APRM C did not perform correctly. A half-scram occurred during performance of the surveillance when it was not supposed to occur. Notification 10209105 was written to document the issue. Troubleshooting per WO 4279450 resulted in the replacement of a faulty relay. (SR 3.3.1.1.13) aa) On December 23, 2001, MS-LMS-AO86A(A) RPS/Green Light was found out-of-tolerance and outside the TS Limit. The switch was adjusted to within limits. (SR 3.3.1.1.13) bb) On December 12, 2001, NMF-SQRT-152D was found out-of-tolerance and would not hold its adjustment. Notification 10129473 was written to document the issue. WO 4213392 replaced NMF-SQRT-152D. (SR 3.3.1.1.13) cc) On November 21, 2001, Under-Frequency Time Delay RPS-EPA- 1A2 was found out-of-tolerance. Notification 10125175 was written to document the issue. WO 4170624 replaced RPS-EPA- 1A2.
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| dd) On October 4, 2001, the as-found Trip Setpoint for NBI-PS-102A was out-of-tolerance exceeding the instrument and TS limits. RCR 2001-1005 was written to document the issue, stating that the switch was recalibrated in tolerance and declared operable. (SR 3.3.4.1.3)
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| For the above issues:
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| The January 4, 2010, March 31, 2005, and all four June 28, 2003 issues deal with Patel Engineering Model 01-170020-090 Temperature Switches. There are a total of seven failures identified relative to Patel Engineering Model 01-170020-090 Temperature Switches over the review period. In all seven of the instances, TS limits were exceeded. In two of the seven instances, the temperature switches were replaced, and in five cases the switches were re-
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| NLS2011071 Page 11 of 49 calibrated and returned to service. No time-based mechanisms are apparent. When considering that a total of 1216 temperature switch tests (152 times a total of 8 surveillance procedure performances) were conducted over the review period, a total of seven failures resulting in two switch replacements is a very small percentage of the total population tested. Therefore, an increase in the surveillance test interval will not result in a significant impact on system/component availability.
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| The November 19, 2009, and January 9, 2003 issues related to problems with ITT Barton Model 288A Differential Pressure Switches. There were a total of two failures identified relative to ITT Barton Model 288A Differential Pressure Switches over the review period. These switches were in the Reactor Protection and Primary Containment Isolation Systems. In one case, a microswitch was replaced, and in the other case the switch was recalibrated and returned to service. No time-based failure mechanisms are apparent. Therefore, these failures were unique, and so subsequent failures would not be expected to result in a significant impact on system/
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| component availability.
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| The December 26, 2008, December 29, 2005, June 18, 2004, February 21, 2003, and October 4, 2001 issues involve Static O-Ring Model 9N-AA45 pressure switches. There are a total of five failures identified relative to Static O-Ring Model 9N-AA45 pressure switches over the review period. In three cases, the switches were replaced and two were recalibrated and returned to service. There does not appear to be a time-based degradation or other condition which would affect the operation or accuracy of this device. The findings of apparent cause evaluation CR-CNS-2008-09500 rule out the possibility that the failures are related to environmental effects based on location. NBI-PS- 102A and NBI-PS- 102B are located next to each other at R-93 1-NW on Rack 25-5, and there have been no performance issues with NBI-PS-102B over the review period. Furthermore, there has been no evidence of performance issues with any of the redundant pressure switches (NBI-PS-102B, NBI-PS-102C, and NBI-PS-102D). CR-CNS-2011-8278 was initiated to continue monitoring the switch. Switch performance, since replacement in 2009, has been stable. Continued monitoring of NBI-PS-102A and the satisfactory performance of the other switches provides the basis for extension to 24 months for both the Channel Calibration and LSFT. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| In regards to the May 4, 2008, and December 23, 2001 issues, there are a total of two failures identified relative to Namco EA1 80-32302 over the review period. In each case, the as-found closure time exceeded the TS limit. However, no time-based mechanisms are apparent.
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| Therefore, these failures are unique, and so subsequent failures would not be expected to result in a significant impact on system/component availability.
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| In regards to the August 15, 2007, February 8, 2006, and April 6, 2004 events, there are a total of three failures identified relative to the APRM system over the review period. In each case, the as-found flow data value exceeded the instrument and/or TS limit. However, no time-based mechanisms are apparent. Therefore, these failures are unique and so subsequent failures would not be expected to result in a significant impact on system/component availability.
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| NLS2011071 Page 12 of 49 In regards to the June 25, 2009, November 18, 2006, February 15, 2005, January 30, 2005, January 25, 2005, April 4, 2003, April 1, 2003, March 3, 2003, November 20, 2002, December 12, 2001, and November 21, 2001 events, no similar failures are identified.
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| Therefore, the failures were not repetitive in nature. No time-based mechanisms are apparent.
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| Therefore, these failures are unique, and so subsequent failures would not be expected to result in a significant impact on system/component availability.
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| Based on the above discussions, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of portions of the circuits, and the history of logic system performance, and the corrective action for the failures, the impact of this change on safety, if any, is small.
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| RESPONSE TIME TESTS TS 3.3.1.1 Reactor Protection System (RPPS) Instrumentation SR 3.3.1.1.15 Verify the RPS RESPONSE TIME is within limits.
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| TS 3.7.7 The Main Turbine Bypass System SR 3.7.7.3 Verify the TURBINE BYPASS SYSTEM RESPONSE TIME is within limits.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| Extending the interval between response time tests is acceptable because the functions are verified to be operating properly throughout the operating cycle by the performance of Channel Checks and Channel Functional Tests (for SR 3.3.1.1.15) or by verifying proper operation of each bypass valve (for SR 3.7.7.3). This testing ensures that a significant portion of the circuitry is operating properly and will detect significant failures of this circuitry. Additional justification for extending the surveillance test interval is that these functions, including the actuating logic, are designed to be single failure proof and, therefore, are highly reliable. Moreover, the CNS TS Bases (as well as NUREG-1433, "Standard Technical Specifications BWR/4,") states that the frequency of response time testing is based in part "upon plant operating experience, which shows that random failures of instrumentation components causing serious time degradation, but not channel failure, are infrequent occurrences."
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| A review of the applicable CNS surveillance history demonstrated that the logic systems for these functions had nine failures of TS required system response times that would have been detected solely by the periodic performance of these SRs.
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| a) On May 4, 2008, MS-LMS-AO86A(A) RPS/Green Light was found out-of-tolerance and outside the TS limit. The switch was adjusted to within satisfactory limits. SR 3.3.1.1.15)
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| NLS2011071 Page 13 of 49 b) On August 15, 2007, the RPS logic failed to initiate and reset as expected. CR-CNS-2007-05545 stated that IRM D did not have an INOP or UPSCALE TRIP as expected.
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| WO 4583315 replaced relays KIB, K4B and K19B. (SR 3.3.1.1.15) c) On February 8, 2006, three of the APRM C Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument, TRM, and TS limits. CR-CNS-2006-00994 documented the issue and the values were adjusted in tolerance. (SR 3.3.1.1.15) d) On January 25, 2005, Square Root Converter Board 1 (Z8) (NMF-SQRT-152A) was found out-of-tolerance. The Square Root Converter Card was replaced by WO 4423227 with as-left values satisfactorily. (SR 3.3.1.1.15) e) On April 6, 2004, three of the APRM E Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument limits. Notification 10306116 stated that the values were adjusted in tolerance. (SR 3.3.1.1.15) f) On April 4, 2003, transmitter RR-FT-11 OC could not be adjusted, causing numerous readings to be out-of-tolerance. Notification 10236953 was written to document the issue. The resolution to the Notification documented that the module was repaired.
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| (SR 3.3.1.1.15) g) On November 20, 2002, APRM C did not perform correctly. A half-scram occurred during performance of the surveillance when it was not supposed to occur. Notification 10209105 was written to document the issue. Troubleshooting per WO 4279450 resulted in the replacement of a faulty relay. (SR 3.3.1.1.15) h) On December 23, 2001, MS-LMS-A086A(A) RPS/Green Light was found out-of-tolerance and outside the TS Limit. The switch was adjusted to within limits. (SR 3.3.1.1.15) i) On December 12, 2001, NMF-SQRT-152D was found out-of-tolerance and would not hold its adjustment. Notification 10129473 was written to document the issue. WO 4213392 replaced NMF-SQRT-152D. (SR 3.3.1.1.15)
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| For the above issues:
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| The May 4, 2008, and December 23, 2001 issues involved Namco EA180-32302 switches.
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| There were a total of two failures identified relative to Namco EA180-32302 over the review period. In each case, the as-found closure time exceeded the TS limit. No time-based mechanisms are apparent. Therefore, these failures are unique, and so subsequent failures would not be expected to result in a significant impact on system/component availability.
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| The August 15, 2007, February 8, 2006, and April 6, 2004 issues involved APRM system events.
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| There were a total of three failures identified relative to the APRM system over the review period. In each case, the as-found flow data values exceeded the instrument and/or TS limit. No
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| NLS2011071 Page 14 of 49 time-based mechanisms are apparent. Therefore, these failures are unique, and so subsequent failures would not be expected to result in a significant impact on system/component availability.
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| In regards to the January 25, 2005, April 4, 2003, November 20, 2002, and December 12, 2001 events, no similar failures are identified. Therefore, the failures were not repetitive in nature.
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| No time-based mechanisms are apparent. Therefore, these failures are unique, and so subsequent failures would not be expected to result in a significant impact on system/component availability.
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| In summary, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency, and the impact of this change on safety, if any, is small.
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| TS 3.3.2.1 Control Rod Block Instrumentation SR 3.3.2.1.6 Verify the RWM is not bypassed when THERMAL POWER is < 9.85%
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| RTP.
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| The surveillance test interval this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| The purpose of the Rod Worth Minimizer (RWM) is to control rod patterns during startup and shutdown, such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to 9.85% Rated Thermal Power (RTP).
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| For this function, no revisions to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical as-found minus as-left (AFAL) data will be completed as part of License Amendment implementation.
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| A review of the applicable CNS surveillance history for these Functions demonstrated that the as-found trip setpoint had no previous failure of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.4.3 Safety/Relief Valves (SRVs) and Safety Valves (SVs)
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| SR 3.4.3.2 Verify each SRV opens when manually actuated.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| SRVs are required to actuate automatically upon receipt of specific .initiation signals. A manual actuation of each required SRV per SR 3.4.3.2 is performed to verify that the valve is functioning properly, and no blockage exists in the valve discharge line.
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| NLS2011071 Page 15 of 49 A review of the applicable CNS surveillance history demonstrated that the SRVs had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.5.1 / 3.5.2 ECCS - Operating / ECCS - Shutdown SR 3.5.1.8 Verify, with reactor pressure < 165 psig, the HPCI pump can develop a flow rate > 4250 gpm against a system head corresponding to reactor pressure.
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| SR 3.5.1.9 Verify each ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.
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| SR 3.5.1.10 Verify the ADS actuates on an actual or simulated automatic initiation signal.
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| SR 3.5.1.11 Verify each ADS valve opens when manually actuated.
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| SR 3.5.2.5 Verify each required ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| The flow tests for the High Pressure Coolant Injection (HPCI) System are performed at two different pressure ranges such that system capability to provide rated flow against a system head corresponding to reactor pressure is tested at both the higher and lower operating ranges of the system. The required system head should overcome the Reactor Pressure Vessel (RPV) pressure and associated discharge line losses. Adequate reactor pressure must be available to perform these tests. Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the HPC1 System diverts steam flow. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these tests. Adequate reactor steam pressure must be >145 psig to perform SR 3.5.1.8. Adequate steam flow is represented by turbine bypass valves at least 30% open, or total steam flow > 106 lb/hr. Reactor startup is allowed prior to performing the low pressure surveillance test because the reactor pressure is low and the time allowed to satisfactorily perform the surveillance test is short.
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| The Emergency Core Cooling System (ECCS) and Automatic Depressurization System (ADS) functional tests ensure that a system initiation signal (actual or simulated) to the automatic initiation logic will cause the systems or subsystems to operate as designed. The ECCS network has built-in redundancy so that no single active failure prevents accomplishing the safety function of the ECCS. The pumps associated with ECCS are tested quarterly in accordance with the IST Program and SR 3.5.1.6 (some valves may have independent IST relief justifying less frequent testing). This testing ensures that the maj or components of the systems are capable of performing their design function. The tests proposed to be extended need to be performed during outage conditions since they have the potential to initiate an unplanned transient if performed during operating conditions.
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| NLS2011071 Page 16 of 49 A review of the applicable CNS surveillance history demonstrated that ECCS had five previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.
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| a) On November 18, 2006, a contact on a TDR for Service Water Pump B did not properly close. This prevented Service Water Pump B restart. CR-CNS-2006-09360 stated that the pump breaker was realigned. (SR 3.5.1.9) b) On February 15, 2005, DG-1 tripped during testing. Per CR-CNS-2005-01360, field troubleshooting determined that the failure occurred due to a short circuit in TVS network diodes installed in parallel with the coil of solenoid valve 20F0 1 "Non-Emergency Trips Bypass Valve." The short circuit allowed excessive current flow and caused two fuses in DG-1 control power circuit 4 to blow (one in the positive lead and the other in the negative lead). WO 4426786 replaced a blown fuse, fused disconnect, diode assembly, and Relay 4EMX1. (SR 3.5.1.9) c) On January 30, 2005, testing indicated that a resistance reading was out-of-specification at oo ohms. Notification 10366727, written to document this issue, stated that the contacts appeared to be open with relay 27X-1GB actuated, and concluded that the relay contacts be inspected, and cleaned or repaired. WO 4424836 burnished the contacts and retested relay contact resistance satisfactorily. (SR 3.5.1.9) d) On April 10, 2003, testing indicated that resistance readings were above acceptance criteria values for Terminal Block YW points 4 and 5. Notification 10240332 was written to document this issue. Resistance was re-mea~ured as satisfactorily. (SR 3.5.1.9) e) On April 1, 2003, DG- 1 could not be unloaded to 1000 kW. When the governor control lowered to just below 2000 kW, load immediately dropped to 0 kW. Notification 10237864 stated that DG-1 was secured and declared inoperable. WO 4303040 performed troubleshooting and repair. The DRU was replaced per vendor procedure under the WO. (SR 3.5.1.9)
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| For the above issues no similar failures are identified. Therefore, the failures were not repetitive in nature. No time-based mechanisms are apparent. Accordingly, these failures are unique, and subsequent failures would not be expected to result in a significant impact on system/component availability.
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| As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.
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| NLS2011071 Page 17 of 49 TS 3.5.3 RCIC System SR 3.5.3.4 Verify, with reactor pressure < 165 psig, the RCIC pump can develop a flow rate > 400 gpm against a system head corresponding to reactor pressure.
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| SR 3.5.3.5 Verify the RCIC System actuates on an actual or simulated automatic initiation signal.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| These Reactor Core Isolation Cooling (RCIC) functional tests ensure that the system will operate as designed. The pumps and valves associated with RCIC system are tested quarterly in accordance with the IST Program (some valves may have independent relief justifying less frequent testing). This testing ensures that the major components of the systems are capable of performing their design function.
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| A review of the applicable CNS surveillance history demonstrated that RCIC had no previous failures of these TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.6.1.1 Primary Containment SR 3.6.1.1.2 Verify drywell to suppression chamber bypass leakage is equivalent to a hole < 1.0 inch in diameter.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months including the 25% grace period afforded by TS SR 3.0.2.
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| This SR ensures that the drywell to suppression chamber bypass leakage is limited to an equivalent to a hole < 1.0 inch in diameter. The frequency was developed considering it is prudent that this surveillance be performed during a unit outage and also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.
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| A review of surveillance test history verified that the drywell-to-suppression chamber bypass leakage test had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency and the history of system performance. Therefore the impact of this change on safety, if any, is small.
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| NLS2011071 Page 18 of 49 TS 3.6.1.3 Primary Containment Isolation Valves (PCIVs)
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| SR 3.6.1.3.7 Verify each automatic PCIV actuates to the isolation position on an actual or simulated isolation signal.
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| SR 3.6.1.3.8 Verify a representative sample of reactor instrumentation line EFCVs actuate to the isolation position on an actual or simulated instrument line break.
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| SR 3.6.1.3.9 Remove and test the explosive squib from each shear isolation valve of the TIP System.
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| SR 3.6.1.3.11 Verify each inboard 24 inch primary containment purge and vent valve is blocked to restrict the maximum valve opening angle to 600.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months (on a STAGGERED TEST BASES for SR 3.6.1.3.9), for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| During the operating cycle, SR 3.6.1.3.5 requires automatic PCIV isolation times to be verified in accordance with the IST Program. Stroke testing of PCIVs tests a significant portion of the PCIV circuitry as well as the mechanical function, which will detect failures of this circuitry or failures with valve movement. The frequency of this testing is typically quarterly, unless approved relief has been granted justifying less frequent testing. For the excess flow check valves (EFCV) the frequency is based on the need to perform the surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the surveillance were performed with the reactor at power. The test consists of testing a representative sample such that the total population is tested every 10 years. Therefore, each valve is tested every 10 years. For the Traversing Incore Probe (TIP) System explosive squib, SR 3.6.1.3.4 verifies continuity of the TIP shear isolation valve explosive charge on a 31 -day frequency. For the 24-inch primary containment purge and vent valve, SR 3.6.1.3.11 is scheduled to be performed on a refueling outage frequency, because the valves may have been unblocked as part of the refueling outage, so the SR verifies that the blocks have been re-installed prior to operation.
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| A review of surveillance test history verified that no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.6.1.6 Low-Low Set (LLS) Valves SR 3.6.1.6.1 Verify each LLS valve opens when manually actuated.
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| SR 3.6.1.6.2 Verify the LLS System actuates on an actual or simulated automatic initiation signal.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| NLS2011071 Page 19 of 49 The frequency for SR 3.6.1.6.1 is based on the SRV tests required by the ASME Boiler and Pressure Vessel Code, Section XI. Operating experience has shown that these components usually pass the surveillance when performed at this frequency. Therefore, the frequency was concluded to be acceptable from a reliability standpoint. Extending the surveillance test interval for SR 3.6.1.6.2 is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Functional Tests per SR 3.3.6.3.3. This more frequent testing ensures that a major portion of the circuitry is operating properly and will detect significant failures within the instrument loop. Additionally, the LLS valves (i.e., SRVs assigned to the LLS logic) are designed to meet applicable reliability, redundancy, single failure, and qualification standards and regulations as described in the CNS USAR. As such, these functions are designed to be highly reliable.
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| A review of surveillance test history verified that the LLS valves had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.
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| Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers SR 3.6.1.7.3 Verify the full open setpoint of each vacuum breaker is < 0.5 psid.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| This SR ensures that the vacuum breaker opening setpoint safety analysis assumption regarding vacuum breaker full open differential pressure of < 0.5 psid is valid. SR 3.6.1.7.1 and SR 3.6.1.7.2 are performed at shorter intervals (14 days and 92 days, respectively) that convey the proper functioning status of each vacuum breaker.
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| A review of surveillance test history verified that the Reactor Building-to-Suppression Chamber Vacuum Breakers had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers SR 3.6.1.8.3 Verify the opening setpoint of each required vacuum breaker is < 0.5 psid.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| NLS2011071 Page 20 of 49 This SR ensures that the vacuum breaker opening setpoint safety analysis assumption regarding vacuum breaker full open differential pressure of < 0.5 psid is valid. SR 3.6.1.8.1 and SR 3.6.1.8.2 are performed at shorter intervals (14 days and 31 days, respectively) that convey the proper functioning status of each vacuum breaker.
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| A review of surveillance test history verified that the Suppression Chamber-to-Drywell Vacuum Breakers had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.6.4.1 Secondary Containment SR 3.6.4.1.4 Verify each SGT subsystem can maintain > 0.25 inch of vacuum water gauge in the secondary containment for 1 hour at a flow rate < 1780 cfm.
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| The surveillance test interval of these SRs is being increased from once every 18 months on a STAGGERED TEST BASIS to once every 24 months on a STAGGERED TEST BASIS, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| To ensure that all fission products are treated, the test required per SR 3.6.4.1.4 is performed utilizing one Standby Gas Treatment (SGT) subsystem (on a staggered test basis) to ensure secondary containment boundary integrity. SRs 3.6.4.1.1 (every 24 hours), 3.6.4.1.2 (every 31 days), and 3.6.4.1.3 (every 31 days) provide more frequent assurance that no significant boundary degradation has occurred.
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| A review of the applicable CNS surveillance history demonstrated that the secondary containment had one previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs.
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| a) On January 30, 2005, the differential pressure value for HV-DPR-835 was found out-of-tolerance and outside the operability limit with all motor-operated valves closed.
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| CR-CNS-2005-00996 was written to document the issue, and determined that the motor-operated valves were leaking. The test was reperformed satisfactorily.
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| The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24-month surveillance interval. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.
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| NLS2011071 Page 21 of 49 TS 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)
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| SR 3.6.4.2.3 Verify each automatic SCIV actuates to the isolation position on an actual or simulated actuation signal.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.'
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| During the operating cycle, SR 3.6.4.2.2 requires that each power-operated automatic SCIV isolation times to be tested (i.e., stroke timed to the closed position) in accordance with the IST Program. The stroke testing of these SCIVs tests a portion of the circuitry and the mechanical function, and provides more frequent testing to detect failures.
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| A review of surveillance test history verified that SCIVs had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.6.4.3 Standby Gas Treatment (SGT) System SR 3.6.4.3.3 Verify each SGT subsystem actuates on an actual or simulated initiation signal.
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| SR 3.6.4.3.4 Verify the SGT units cross tie damper is in the correct position, and each SGT room air supply check valve and SGT dilution air shutoff valve can be opened.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| These SGT functional tests ensure that subsystems operate as designed. The SGT subsystems are redundant so that following initial draw-down of post-Loss-of-Coolant Accident (LOCA)
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| Reactor Building pressure, no single-failure prevents accomplishing the safety functions of filtering the discharge from secondary containment and directing the discharge to the Elevated Release Point, and are therefore reliable. More frequent verification of portions of the SGT function are accomplished by operating each SGT subsystem and heaters every 31 days per SR 3.6.4.3.1.
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| A review of the applicable CNS surveillance history demonstrated that the SGT System had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| NLS2011071 Page 22 of 49 TS 3.7.2 Service Water (SW) System and Ultimate Heat Sink (UHS)
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| SR 3.7.2.4 Verify each SW subsystem actuates on an actual or simulated initiation signal.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| This SR verifies that the automatic isolation valves of the SW System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety-related equipment during an accident event. This SR also verifies the automatic start capability of one of the two SW pumps in each subsystem. The SW subsystems are redundant so that no single-failure prevents accomplishing the safety function of providing the required cooling. The SW system pumps and valves are tested quarterly in accordance with the IST Program (some valves may have independent relief justifying less frequent testing). This testing ensures that the major components of the systems are capable of performing their design function. Additionally, valves in the flow path are verified to be in the correct position every 31 days by SR 3.7.2.3. Since most of the components and associated circuits are tested on a more frequent basis, this testing would indicate any degradation to the SW System which would result in an inability to start based on a demand signal.
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| A review of the applicable CNS surveillance history demonstrated that the SW System had no previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.7.3 Reactor Equipment Cooling (REC) System SR 3.7.3.4 Verify each REC subsystem actuates on an actual or simulated initiation signal.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| This SR verifies that the automatic isolation valves of the REC System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety-related equipment during an accident event. The REC system is designed with sufficient redundancy so that no single-active system component failure prevents accomplishing the safety function of providing the required cooling. The REC system pumps and valves are tested quarterly in accordance with the IST Program (some valves may have independent relief justifying less frequent testing). This testing ensures that the maj or components of the systems are capable of performing their design function. Additionally, valves in the flow path are verified to be in the correct position every 31 days by SR 3.7.3.3. Since most of the components and associated
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| NLS2011071 Page 23 of 49 circuits are tested on a more frequent basis, this testing would indicate any degradation to the REC System which would result in an inability to start based on a demand signal.
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| A review of the applicable CNS surveillance history demonstrated that the REC System had no previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.7.4 Control Room Emergency Filter (CREF) System SR 3.7.4.3 Verify the CREF System actuates on an actual or simulated initiation signal.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| The CREF System maintains the habitability of the Control Room Envelope from which occupants can control the unit following an uncontrolled release of radioactivity during certain design basis accidents. More frequent verification of portions of the CREF System function is accomplished by operating the CREF System every 31 days per SR 3.7.4.1.
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| A review of the applicable CNS surveillance history demonstrated that the CREF System had no previous failures of the TS function that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, system design, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.7.7 The Main Turbine Bypass System SR 3.7.7.2 Perform a system functional test.
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| The surveillance test interval of this SR is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| This test ensures that on increasing main steam line pressure events, the main turbine bypass system will operate as designed. More frequent verification of portions of the main turbine bypass system is accomplished by SR 3.7.7.1, which requires that each main turbine bypass valve be cycled through at least half of one cycle of full travel once every 31 days. This test demonstrates that the valves are mechanically operable, and detects significant failures affecting system operation.
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| NLS2011071 Page 24 of 49 A review of the applicable CNS surveillance history demonstrated that the main turbine bypass system had one previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs.
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| a) On March 7, 2009, as-found voltage values for TG-XD/MW Loop Data - Rack 01K2, Slot R, TP-13 & TP-14, Rack 011K6, Slot R, TP-38, and A Panel Display were out-of-tolerance. The values were adjusted to within acceptable limits.
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| The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24-month surveillance interval. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.8.1 AC Sources - Onerating SR 3.8.1.8 Verify automatic and manual transfer of unit power supply from the normal offsite circuit to the alternate offsite circuit.
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| SR 3.8.1.9 Verify each DG operates for > 8 hours: a. For > 2 hours loaded > 4200 kW and < 4400 kW; and b. For the remaining hours of the test loaded > 3600 kW and < 4000 kW.
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| SR 3.8.1.10 Verify interval between each sequenced load is within +/- 10% of nominal timer setpoint.
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| SR 3.8.1.11 Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal: a. De-energization of emergency buses; b. Load shedding from emergency buses; and c. DG auto-starts from standby condition and: 1. energizes permanently connected loads in < 14 seconds, 2. energizes auto-connected emergency loads through the timed logic sequence, 3. maintains steady state voltage > 3950 V and < 4400 V, 4. maintains steady state frequency > 58.8 Hz and < 61.2 Hz, and
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| : 5. supplies permanently connected and auto-connected emergency loads for
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| > 5 minutes.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| The CNS Class 1E AC distribution system supplies electrical power to two divisional load groups, with each division powered by an independent Class 1E 4.16 kV Engineered Safety Feature (ESF) bus. Each ESF bus has connections to two qualified offsite power sources and a single dedicated onsite DG. The ESF systems of one of the two divisions provide for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition. This design provides substantial redundancy in AC power sources. The DGs are infrequently operated; therefore, the risk of wear-related degradation is minimal. Historical testing and surveillance testing during operation prove the ability of the diesel engines to start
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| NLS2011071 Page 25 of 49 and operate under various load conditions. DG loading is listed on USAR Table VIII-5-1.
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| Through the normal engineering design process, load additions and deletions are tracked and changes to loading are verified to be well within the capacity of their power sources. More frequent testing of the AC sources is also required as follows:
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| - Verifying correct breaker alignment and indicated power availability for each required offsite circuit every 7 days (SR 3.8.1.1);
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| - Verifying the DG starting and load carrying capability is demonstrated every 31 days (SRs 3.8.1.2 and 3.8.1.3), and ability to continuously supply makeup fuel oil is also demonstrated every 92 days per (SR 3.8.1.6);
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| - Verifying the ability of each DG to reach rated voltage and frequency within required time limits every 184 days (SR 3.8.1.7) will provide prompt identification of any substantial DG degradation or failure;
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| - Verifying the necessary support for DG start and operation (SRs 3.8.1.4, 3.8.1.5, 3.8.3.1, 3.8.3.2, 3.8.3.4 and 3.8.3.4.5) are required every 31 days.
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| - Verifying fuel oil properties of new and stored fuel oil are tested in accordance with, and maintained within the limits of, the Diesel Fuel Oil Testing Program.
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| A review of the applicable CNS surveillance history demonstrated that the AC power sources had five previous failures of the TS functions that would have been detected solely by the periodic performance of these SRs.
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| a) On November 18, 2006, a contact on a TDR for Service Water Pump B did not properly close. This prevented Service Water Pump B restart. CR-CNS-2006-09360 stated that the pump breaker was realigned. (SR 3.8.1.8, SR 3.8.1.9, SR 3.8.1.10, and SR 3.8.1.11) b) On February 15, 2005, DG-1 tripped during testing. Per CR-CNS-2005-01360, field troubleshooting determined that the failure occurred due to a short circuit in TVS network diodes installed in parallel with the coil of solenoid valve 20F0 1 "Non-Emergency Trips Bypass Valve." The short circuit allowed excessive current flow and caused two fuses in DG- 1 control power circuit 4 to blow (one in the positive lead and the other in the negative lead). WO 4426786 replaced a blown fuse, fused disconnect, diode assembly, and Relay 4EMX1. (SR 3.8.1.8, SR 3.8.1.9, SR 3.8.1.10, and SR 3.8.1.11) c) On January 30, 2005, testing indicated that a resistance reading was out-of-specification at oo ohms. Notification 10366727, written to document this issue, stated that the contacts appeared to be open with relay 27X- 1GB actuated, and concluded that the relay contacts be inspected, and cleaned or repaired. WO 4424836 burnished the contacts and retested relay contact resistance satisfactorily. (SR 3.8.1.8, SR 3.8.1.9, SR 3.8.1.10, and SR 3.8.1.11)
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| NLS2011071 Page 26 of 49 d) On April 10, 2003, testing indicated that resistance readings were above acceptance criteria values for Terminal Block YW points 4 and 5. Notification 10240332 was written to document this issue. Resistance was re-measured as satisfactory. (SR 3.8.1.8, SR 3.8.1.9, SR 3.8.1.10, and SR 3.8.1.11) e) On April 1, 2003, DG- 1 could not be unloaded to 1000 kW. When the governor control lowered to just below 2000 kW, load immediately dropped to 0 kW.
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| Notification 10237864 stated that DG-1 was secured and declared inoperable. WO 4303040 performed troubleshooting and repair. The DRU was replaced per vendor procedure under the WO. (SR 3.8.1.8, SR 3.8.1.9, SR 3.8.1.10, and SR 3.8.1.11)
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| For the above issues no similar failures are identified. Therefore, the failures were not repetitive in nature. No time-based mechanisms are apparent. Accordingly, these failures are unique, and subsequent failures would not be expected to result in a significant impact on system/component availability.
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| As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.8.4 DC Sources - Operating SR 3.8.4.6 Verify:
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| : a. Each required 125 V battery charger supplies > 200 amps at > 125 V for
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| > 4 hours; and
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| : b. Each required 250 V battery charger supplies > 200 amps at > 250 V for
| |
| > 4 hours.
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| SR 3.8.4.7 Verify battery capacity is adequate to supply, and maintain in OPERABLE status, the required emergency loads for the design duty cycle when subjected to a battery service test.
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| The surveillance test interval of these SRs is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| SR 3.8.4.1 and SR 3.8.6.1 are performed every 7 days to verify 125 V and 250 V battery terminal voltage, and battery pilot cell electrolyte level, float voltage, and specific gravity, respectively.
| |
| SR 3.8.6.2 and SR 3.8.6.3 are performed every 92 days to verify connected cell electrolyte level, float voltage, and specific gravity, and average electrolyte temperature for representative cells.
| |
| SR 3.8.4.2 is performed every 92 days to verify no visible battery terminal/connector corrosion or high resistance. These more frequent surveillances will provide prompt identification of substantial degradation or failure of the battery and/or battery chargers.
| |
| A review of the applicable CNS surveillance history demonstrated that the DC electric power subsystem had one previous failure of the TS functions that would have been detected solely by the periodic performance of these SRs.
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| | |
| NLS2011071 Page 27 of 49 a) On December 23, 2003, a test on battery charger EE-CHG-250 (1B) was aborted when the charger tripped when the automatic mode was starting the last ramp. This test was part of post-work testing following replacement of a current limiter card. RCR 2003-2033 was written to document this issue. Another current limiter card was installed and retested satisfactorily.
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| The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24-month surveillance interval. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on other more frequent testing of the system, and the history of system performance, the impact of this change on safety, if any, is small.
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| TS 5.5.2. Systems Integrity Monitoring Program The program shall include the following:
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| : b. Integrated leak test requirements for each system at 18 month intervals or less.
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| The test interval of this TS is being increased from once every 18 months to once every 24 months for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| This requirement establishes a program to reduce leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to as low as practical levels. Specifically, the program requires an "Integrated leak test requirement for each system at 18 month intervals or less." The surveillance history review did not find any cases where the required integrated leak tests were not performed within the 18-month interval (including the 25% grace period). The change to 24-month operating cycles will increase the testing interval. This change to the testing requirement has been evaluated and determined that the impact, if any, on safety is small. This conclusion is based on the fact that most portions of the subject systems included in this program are visually walked down, while the plant is operating, during plant testing and/or operator/system engineer walkdowns. In addition, housekeeping/safety walkdowns also serve to detect any gross leakage. If leakage is observed from these systems, corrective actions will be taken to repair the leakage. Finally, the plant radiological surveys will also identify any potential sources of leakage. Based on more frequent inspections previously described, and the ability to readily detect system leakage performance deficiencies, the impact of this change on safety, if any, is small.
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| TS 5.5.7 Ventilation Filter Testing Program (VFTP)
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| The VFTP shall establish the required testing of Engineered Safety Feature (ESF) filter ventilation systems. Tests described in Specifications 5.5.7.a, 5.5.7.b, and 5.5.7.c shall be performed once per 18 months for standby service or after 720 hours of system operation;
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| NLS2011071 Page 28 of 49 and, following significant painting, fire, or chemical release concurrent with system operation in any ventilation zone communicating with the system.
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| Tests described in Specifications 5.5.7.a and 5.5.7.b shall be performed after each complete or partial replacement of the HEPA filter train or charcoal adsorber filter; and after any structural maintenance on the system housing.
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| Tests described in Specifications 5.5.7.d and 5.5.7.e shall be performed once per 18 months.
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| With this change, the testing interval is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
| |
| This proposed change constitutes a change in conformance to RG 1.52, "Design, Testing and Maintenance Criteria for Post Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants," for the 18-month test requirements. In addition to the 24-month testing, ventilation filter (HEPA and charcoal) testing will continue to be performed in accordance with the other frequencies specified in TS 5.5.7 and RG 1.52. This proposed amendment request will not change the performance of these required tests.
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| A review of the applicable CNS surveillance history demonstrated that the ESF ventilation systems had one previous failure of the TS functions that would have been detected solely by the periodic performance of SRs that reference performance of the VFTP of TS 5.5.7.
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| a) A test report dated February 7, 2003, documented the results of filter testing on the CREF System for a test completed on January 30, 2003. The test indicated a radio-iodine penetration which exceeded the allowed limit. Notification 10223376 confirmed that the charcoal filter exceeded limits due to age-related degradation. The charcoal was replaced under WO 4292592 on January 31, 2003.
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| The identified failure is unique and did not occur on a repetitive basis, and is associated with a time-based failure mechanism due to the degradation of the charcoal over time. This is an isolated occurrence and the charcoal is typically replaced prior to reaching the point where the charcoal degradation exceeds the allowed limit. Therefore, this failure will have no impact on an extension to a 24-month surveillance interval. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| NLS2011071 Page 29 of 49 TS 5.5.13 Control Room Envelope Habitability Program The program shall include the following elements:
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| : d. Measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by the CREF System, operating at the flow rate required by the Ventilation Filter Testing Program, at a Frequency of 18 months. The results shall be trended and used as part of the periodic assessment of the CRE boundary.
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| With this change, the testing interval is being increased from once every 18 months to once every 24 months, for a maximum interval of 30 months, including the 25% grace period afforded by TS SR 3.0.2.
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| This program was placed in the TS as part of Amendment 230 dated May 12, 2008, which adopted Technical Specifications Task Force (TSTF)-448, Revision 3, "Control Room Habitability" using the consolidated line item improvement process. This TSTF contained proposed TS wording. For the frequency of the above portion of the program the TSTF proposed a frequency of [ 18] months in brackets. The brackets are provided to permit each plant to place the correct frequency in their proposed change. The TSTF stated:
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| Paragraph d requires measurement, at designated locations, of the CRE pressure relative to all external areas adjacent to the CRE boundary during the pressurization mode of operation by one train of the CREFS, operating at the flow rate required by the Ventilation Filter Test Program, at a Frequency of [ 18] months on a STAGGERED TEST BASIS. The test data is to be trended and used as part of the [18] month assessment of the CRE boundary required by Paragraph c. The measurement of the differential pressure between the CRE and adjacent areas provides a gross indication of barrier integrity and is useful in monitoring the health of the CRE barrier between performances of inleakage testing. NEI 99-03, Section 9.3, "Periodic Evaluations," recommends periodic evaluation of the CRE boundary integrity, including comparison to previous assessments, to examine the performance history.
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| However, as pointed out in Generic Letter 2003-01, the usefulness of differential pressure measurements is very limited and the importance of data from these measurements should not be overemphasized. Therefore, the Control Room Envelope Habitability Program requires measuring differential pressure every [ 18] months on a STAGGERED TEST BASIS in a manner similar to the current requirement in the Technical Specifications. The results will be trended and compared to positive pressure measurements taken, or to be taken, during CRE inleakage testing. These evaluations will be used as part of an assessment of CRE boundary integrity between CRE boundary inleakage tests. This approach balances the desire to assess CRE habitability between the performances of inleakage tests with the complexities inherent in the interpretation of differential pressure measurements."
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| For this facility, the testing is not done on a STAGGERED TEST BASIS due to the unique plant design of the CREF System. Reviewing other BWR/4 plants that have implemented both the 24-month cycle and the TSTF-448 line item improvement show that both have frequencies of 24
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| NLS2011071 Page 30 of 49 months for this program requirement. Based on the above, the impact of this change on safety, if any, is small.
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| B. Calibration Chanses NRC GL 91-04 requires that licensees address instrument drift when proposing an increase in the surveillance interval for calibrating instruments that perform safety functions including providing the capability for safe shutdown. The effect of the increased calibration interval on instrument errors must be addressed because instrument errors caused by drift were considered when determining safety system setpoints and when performing safety analyses. NRC GL 91-04 identifies seven steps for the evaluation of instrumentation calibration changes. These seven steps are discussed in Attachment 1 to this submittal. In that discussion, a description of the methodology used by NPPD for each step is summarized. The detailed methodology is provided in Enclosure 1.
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| The following are the calibration-related TS SRs being proposed for revision from 18 months to 24 months, for a maximum interval of 30 months (considering the 25% grace period allowed by TS SR 3.0.2). The methodology used to perform the drift analysis is consistent with the methodology utilized by other utilities requesting transition to a 24-month fuel cycle. The methodology is also based on Electric Power Research Institute (EPRI) TR-103335, "Statistical Analysis of Instrument Calibration Data" and is summarized in Enclosure 1.
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| The projected 30-month drift values for many of the instruments analyzed from the historical as-found/as-left evaluation shows sufficient margin between the current plant setpoint and the allowable value to compensate for the 30-month drift. For each instrument function that has a channel calibration proposed frequency change to 24 months, the associated setpoint calculation assumes a consistent or conservative drift value appropriate for a 24-month calibration interval.
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| As necessary, revisions to CNS setpoint calculations have been developed, and affected calibration and functional test procedures will be revised as part of implementation, to reflect the new 30-month drift values. The revised setpoint calculations were developed in accordance with NEDC-31336. These calculations determined the instrument loop uncertainty, setpoint, and allowable value for the affected function. The allowable values were determined in a manner suitable to establish limits for their application. The TS Allowable Values were compared against the allowable values developed in the setpoint calculations for the affected functions, and in all but two cases were determined to remain conservative (see Attachment 1, Sections 3.1.3 and 3.1.4). The TS Allowable Values have been determined in a manner suitable to establish limits for their application, and thus will continue to ensure that sufficient margins are maintained in the applicable safety analyses, and the affected instruments are capable of performing their intended design function. A review of the applicable safety analysis concluded that the setpoints, allowable values, and projected 30-month drift confirmed the safety limits and safety analysis assumptions remain bounding.
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| Below is a summary of the specific application of this methodology to the CNS 24-Month Fuel Cycle Project, as well as any required TS Allowable Value changes. Where optional methods are presented in Enclosure 1, and where other alternate engineering justifications are allowed, the
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| NLS2011071 Page 31 of 49 rationale for the selected method and alternate justification is summarized with the associated instrument calibration surveillance affected (e.g., for channel groupings having less than 30 calibrations, which is required to qualify for valid statistical evaluations).
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| TS 3.3.1.1 Reactor Protection System (RPS) Instrumentation The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limit, to preserve the integrity of the fuel cladding and the Reactor Coolant Pressure Boundary, and minimize the energy that must be absorbed following a LOCA.
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| SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.
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| - Function 3, Reactor Vessel Pressure - High
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| - Function 4, Reactor Vessel Water Level - Low (Level 3)
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| - Function 6, Drywell Pressure - High
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| - Function 7.a, Scram Discharge Volume Water Level - High, Level Transmitter
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| - Function 9, Turbine Control Valve Fast Closure, DEH Trip Oil Pressure - Low For these functions, no revisions to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
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| A review of the applicable CNS surveillance history for these Functions demonstrated that the as-found trip setpoint had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.
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| - Function 1.a, Intermediate Range Monitors, Neutron Flux - High
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| - Function 2.b, Average Power Range Monitors, Neutron Flux - High (Flow Biased)
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| No revisions to TS Allowable Values or safety analyses result from the required evaluations. Drift evaluations were not performed for TS Table 3.3.1.1-1 Function 1.a, Intermediate Range Monitors, Neutron Flux - High and Function 2.b, Average Power Range Monitors, Neutron Flux - High (Flow Biased). This is acceptable because of the design requirements for the instruments and more frequent functional testing (once per 7 days per SRs 3.3.1.1.3 and 3.3.1.1.4, as applicable). Before the IRM detectors are used for operation, an overlap check is performed to determine if the instruments are reading and tracking with the power range per SR 3.3.1.1.6, or the source range neutron detectors per SR 3.3.1.1.5, as applicable. Furthermore, when the IRM trip is required to be operable, a Channel Functional Test is performed on the IRM trip function every 7 days per SR 3.3.1.1.4. Before the APRM detectors are used for operation, an overlap check is
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| NLS2011071 Page 32 of 49 performed per SR 3.3.1.1.6 to determine if the instruments are reading and tracking with the intermediate range. Furthermore, when the APRM trip is required to be operable, a Channel Functional Test is performed on the APRM trip function every 7 days per SR 3.3.1.1.4.
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| A review of the applicable CNS surveillance history for the IRM and APRM channels demonstrated that the as-found trip setpoint for these functions had nine previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
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| a) On June 25, 2009, IRM C as-found voltages were out-of-tolerance. The pre-regulator was found out-of-calibration and could not adjust per the surveillance procedure. CR-CNS-2009-02867 was written to document condition. All as-left values were adjusted in tolerance satisfactorily.
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| b) On August 15, 2007, the RPS logic failed to initiate and reset as expected. CR-CNS-2007-05545 stated that IRM D did not have an INOP or UPSCALE TRIP as expected.
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| WO 4583315 replaced relays KIB, K4B and K19B.
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| c) On February 8, 2006, three of the APRM C Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument and TS limits. CR-CNS-2006-00994 documented the issue and the values were adjusted in tolerance.
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| d) On January 25, 2005, Square Root Converter Board 1 (Z8) (NMF-SQRT-152A) was found out-of-tolerance. The Square Root Converter Card was replaced by WO 4423227 with as-left values satisfactory.
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| e) On April 6, 2004, three of the APRM E Flow Trip Setpoint values were found to be out-of-tolerance high exceeding the instrument limits. Notification 10306116 stated that the values were adjusted in tolerance.
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| f) On April 4, 2003, transmitter RR-FT-I 10C could not be adjusted, which caused numerous reading to be out-of-tolerance. Notification 10236953 was written to document the issue. The resolution to the Notification was that the amplifier module was sent off to be repaired. The procedure was completed with the repaired module, and all as-left values were satisfactory.
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| g) On March 3, 2003, testing found IRM H High Voltage Power Supply module had excessive ripple. Notification 10229873 was written to document the issue. The High Voltage Power Supply was replaced under WO 4297574.
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| h) On November 20, 2002, APRM C did not perform correctly. A half-scram occurred during performance of the surveillance when it was not supposed to occur. Notification 10209105 was written to document the issue. Troubleshooting per WO 4279450 resulted in the replacement of a faulty relay.
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| NLS2011071 Page 33 of 49 i) On December 12, 2001, NMF-SQRT-152D was found out-of-tolerance and would not hold its adjustment. Notification 10129473 was written to document the issue. WO 4213392 replaced NMF-SQRT- 152D.
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| For the above issues:
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| The August 15, 2007, February 8, 2006 and April 6, 2004 issues involved APRM system events. There are a total of 3 failures identified relative to the APRM system over the review period. In each case, the as-found flow data value exceeded the instrument and/or TS limits. No time-based mechanisms are apparent. Therefore, these failures are unique, and subsequent failures would not be expected to result in a significant impact on system/component availability.
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| For the remaining issues identified above, the identified failures are unique and do not occur on a repetitive basis and are not associated with time-based failure mechanisms.
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| Therefore, these failures will have no impact on an extension to a 24-month surveillance interval.
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| Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| SR 3.3.1.1.12 Perform CHANNEL CALIBRATION.
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| - Function 5, Main Steam Isolation Valve - Closure
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| - Function 7.b, Scram Discharge Volume Water Level - High, Level Switch
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| - Function 8, Turbine Stop Valve - Closure No revisions to TS Allowable Values or safety analyses result from the required evaluations. Drift evaluations were not performed for TS Table 3.3.1.1-1 Functions 5 (Main Steam Isolation Valve limit switches), 7.b (Scram Discharge Volume float switches), and 8 (Turbine Stop Valve limit switches). The limit and float switches that perform these functions are mechanical devices that require mechanical adjustment only; drift is not applicable to these devices. The limit switches are functionally tested every 92 days by SR 3.3.1.1.9 to verify operation.
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| A review of the applicable CNS surveillance history for these limit switch channels demonstrated that the as-found trip setpoint for these functions had two previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR.
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| a) On May 4, 2008, MS-LMS-A086A(A) RPS/Green Light was found out-of-tolerance and outside the TS limit. The switch was adjusted to within satisfactory limits.
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| b) On December 23, 2001, MS-LMS-A086A(A) RPS/Green Light was found out-of-tolerance and outside the TS limit. The switch was adjusted to within limits.
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| NLS2011071 Page 34 of 49 These two events were the only failures identified relative to the Namco EA180-32302 Limit Switch over the review period. In each case, the as-found closure time exceeded the TS limit. No time-based mechanisms are apparent. Therefore, these failures are unique and any subsequent failure would not result in a significant impact on system/component availability. Therefore, these failures will have no impact on an extension to a 24-month surveillance interval. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| SR 3.3.1.1.14 Verify Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is > 29.5% RTP.
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| This SR ensures that scrams initiated from the Turbine Stop Valve Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is > 29.5% RTP. This involves calibration of the bypass channels.
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| No revisions to TS Allowable Values or safety analyses resulted from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations).
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| Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
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| A review of the applicable CNS surveillance history for this function demonstrated that the as-found trip setpoint had no previous failures of the TS Allowable Value that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.3.1.2 Source Range Monitor (SRM) Instrumentation The SRMs provide the operator with information relative to the neutron flux levels at very low neutron flux levels in the core. Specifically, the SRM indication is used by the operator to monitor the approach to criticality and to determine when criticality is achieved. During refueling, shutdown, and low power operations, the primary indication of neutron flux levels is provided by the SRMs to monitor reactivity changes during fuel or control rod movement and give the control room operator early indication of unexpected subcritical multiplication that could be indicative of an approach to criticality.
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| SR 3.3.1.2.7 Perform CHANNEL CALIBRATION.
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| There are no TS Allowable Values associated with this SR, and no changes to the safety analyses resulted from the required evaluations. Drift evaluations were not performed for
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| NLS2011071 Page 35 of 49 SRMs. This is acceptable because there are no trip setpoints or allowable values specified by the TS or credited in accident or safe shutdown analyses. There are also more frequent Channel Checks (SR 3.3.1.2.1 and SR 3.3.1.2.3) and Channel Functional Tests (SR 3.3.1.2.5 and SR 3.3.1.2.6).
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| Extending the SRM calibration interval from 18 months to 24 months is acceptable if the calibration is sufficient to ensure the neutron level is observable when the reactor is shutdown. This is verified at least every 24 hours when the reactor is shutdown per SR 3.3.1.2.4. SR 3.3.1.1.5 verifies sufficient SRM/IRM overlap exists during startup operations, which provides an indication of proper SRM operation and calibration.
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| Additionally, SRM response to reactivity changes is distinctive and well known to plant operators and SRM response is closely monitored during these reactivity changes.
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| Therefore, any substantial degradation of the SRMs will be evident prior to the scheduled performance of Channel Calibrations. Based on the above discussion, there will be no significant adverse impact from the surveillance test frequency increase on system reliability.
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| A review of the applicable CNS surveillance history for this function demonstrated that there were no previous failures of TS required channel calibrations that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.
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| Based on the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation The Feedwater and Main Turbine High Water Level Trip Instrumentation is designed to detect a potential failure of the Feedwater Level Control System that causes excessive feedwater flow.
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| SR 3.3.2.2.2 Perform CHANNEL CALIBRATION. The Allowable Value shall be <
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| 54.0 inches.
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| For this function, no revisions to TS Allowable Values or safety analyses resulted from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
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| A review of the applicable CNS surveillance history for these Functions demonstrated that the as-found trip setpoint had one previous failure of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
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| a) On April 11, 2003, Relay 6A-K1A contacts 11/12 and 13/14 indicated open when they should have been closed. Notification 10241011 was written to document the issue.
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| WO 4300253 indicated that the contacts were burnished, and the adder block was
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| NLS2011071 Page 36 of 49 replaced, as was the coil for GE Model CR120A relay. Post-maintenance testing was performed satisfactorily.
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| The identified failure is unique and did not occur on a repetitive basis, and is not associated with a time-based failure mechanism. Therefore, this failure will have no impact on an extension to a 24-month surveillance interval. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation The primary purpose of the PAM instrumentation is to display plant variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operators to take the manual actions for which no automatic control is provided.
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| SR 3.3.3.1.3 Perform CHANNEL CALIBRATION of each required PAM Instrumentation channel except for the Primary Containment H2 and 02 Analyzers.
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| No TS Allowable Value is applicable to these functions. A separate drift evaluation has not been performed for the PAM instruments based on the design of the PAM instruments and equipment history. The PAM function is supported by a combination of process transmitters, indicators, and recorders. These components differ from other TS instruments in that they are not associated with a function trip, but indication only to the control room operator. As such, these instruments are not expected to function with the same high degree of accuracy demanded of functions with assumed trip actuations for accident detection and mitigation. The PAM devices are expected to maintain sufficient accuracy to detect trends or the existence or non-existence of a condition. The PAM functions require at least two operable channels (except for Steam Nozzle Reactor Vessel Water Level and some PCIV indications) to ensure no single failure prevents the operators from being presented with the information. The functioning status of the PAM instruments is also required more frequently by a Channel Check every 31 days per SR 3.3.3.1.1.
| |
| A review of the applicable CNS surveillance history for these Functions demonstrated that there were two previous failures that would have been detected solely by the periodic performance of this SR.
| |
| a) On October 31, 2009, RR-AO-741 failed to indicate full closed. CR-CNS-2009-08330 was written to document the issue. The Condition Report described that local observation indicated that the valve had traveled to the full closed position, and that the open limit switch appeared to be dropped out. WO 4649130 replaced the lower limit switch.
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| | |
| NLS2011071 Page 37 of 49 b) On November 24, 2001, PC-AO-NRV29 did not fully close. Notification 10125777 was written to document the issues. WO 4210478 replaced the actuator.
| |
| For these events, the identified failures are unique and did not occur on a repetitive basis, and are not associated with a time-based failure mechanism. Therefore, these failures will have no impact on an extension to a 24-month surveillance interval. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.3.2 Alternate Shutdown System The Alternate Shutdown System provides the control room operator with sufficient instrumentation and controls to place and maintain the plant in a safe shutdown condition from a location other than the control room.
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| SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for each required instrumentation channel.
| |
| No TS Allowable Values are applicable to these functions. A separate drift evaluation has not been performed for the Alternate Shutdown System instrument channels based on the design function and equipment history.
| |
| The Alternate Shutdown System instrument channels differ from other TS instruments in that they are not associated with an automatic protective action or trip. As such, these instruments are not expected to function with the same high degree of accuracy demanded of functions with assumed trip actuations for accident detection and mitigation. The normally energized Alternate Shutdown System instrument channels also require more frequent verification of the functioning status, as required by SR 3.3.3.2.1 every 31 days.
| |
| A review of the applicable CNS surveillance history for these Functions demonstrated that there was one previous failure that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.4.1 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)
| |
| Instrumentation The ATWS-RPT System initiates a recirculation pump trip, adding negative reactivity, following events in which a scram does not (but should) occur, to lessen the effects of an ATWS event.
| |
| Tripping the recirculation pumps adds negative reactivity from the increase in steam voiding in the core area as core flow decreases. When Reactor Vessel Water Level-Low Low (Level 2) or Reactor Pressure-High setpoint is reached, the Reactor Recirculation Motor Generator field breakers trip.
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| NLS2011071 Page 38 of 49 SR 3.3.4.1.2 Perform CHANNEL CALIBRATION. The Allowable Values shall be:
| |
| - a. Reactor Vessel Water Level - Low Low (Level 2): > -42 inches; and
| |
| - b. Reactor Pressure - High: < 1072 psig.
| |
| For these functions, no revision to TS Allowable Values or safety analyses resulted from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these functions demonstrated that the as-found trip setpoints had five previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
| |
| a) On December 26, 2008, the as-found Trip Setpoint for NBI-PS-102A was out-of-tolerance exceeding instrument and TS limits. The CR-CNS-2008-09500 apparent cause evaluation concluded the failure was due to equipment excessive drift and equipment malfunction. Corrective actions replaced the pressure switch with new SOR Model 9N-AA45-P1-F1ATTX3 and adjusted the calibration frequency to quarterly for next two cycles.
| |
| b) On December 29, 2005, the as-found Trip Setpoint for NBI-PS-102A was out-of-tolerance exceeding instrument and TS limits. CR-CNS-2005-09596 was written to document the issue. The pressure switch was replaced per WO 4478791.
| |
| c) On June 18, 2004, the as-found Trip Setpoint for NBI-PS-102A was out-of-tolerance exceeding instrument and TS limits. Notification 10322133 stated that the pressure switch was recalibrated to within tolerance.
| |
| d) On February 21, 2003, the as-found Trip Setpoint for NBI-PS- 102A was out-of-tolerance exceeding instrument and TS limit. Notification 10228318 was written to document the issue. WO 4296657 replaced the pressure switch.
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| e) On October 4, 2001, the as-found Trip Setpoint for NBI-PS-102A was out-of-tolerance exceeding the instrument and TS limits. RCR 2001-1005 was written to document the issue, stating that the switch was recalibrated in tolerance and declared operable.
| |
| The December 26, 2008, December 29, 2005, June 18, 2004, February 21, 2003, and October 4, 2001 issues involve Static O-Ring Model 9N-AA45 pressure switches. There are a total of five failures identified relative to Static O-Ring Model 9N-AA45 pressure switches over the review period. In three cases, the switches were replaced and two were recalibrated and returned to service. There does not appear to be a time-based degradation or other condition which would affect the operation or accuracy of this device. The findings of apparent cause evaluation CR-CNS-2008-9500 rule out the possibility that the failures are related to environmental effects based on location. NBI-PS-102A and NBI-PS-
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| NLS2011071 Page 39 of 49 102B are located next to each other at R-93 1-NW on Rack 25-5, and there have been no performance issues with NBI-PS-102B over the review period. Furthermore, there has been no evidence of performance issues with any of the redundant pressure switches (NBI-PS-102B, NBI-PS-102C, and NBI-PS-102D). CR-CNS-2011-8278 was initiated to continue monitoring the switch. Switch performance, since replacement in 2009, has been stable. Continued monitoring of NBI-PS-102A and the satisfactory performance of the other switches provides the basis for extension to 24 months for both the Channel Calibration and LSFT. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.5.1 ECCS Instrumentation The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that fuel is adequately cooled in the event of a design basis accident or transient.
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| SR 3.3.5.1.4 Perform CHANNEL CALIBRATION.
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| - Function 1.a, 2.a, 4.a, 5.a, Reactor Vessel Water Level - Low Low Low (Level 1)
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| - Function 1.b, 2.b, 3.b, Drywell Pressure - High
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| - Function 1.c, 2.c, Reactor Pressure - Low (Injection Permissive)
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| - Function 1.d, Core Spray Pump Discharge Flow - Low (Bypass)
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| - Function 1.e, Core Spray Pump Start - Time Delay Relay
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| - Function 2.d, Reactor Pressure - Low (Recirculation Discharge Valve Permissive)
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| - Function 2.e, Reactor Vessel Shroud Level - Level 0
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| - Function 2.f, Low Pressure Coolant Injection Pump Start - Time Delay Relay
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| - Function 2.g, Low Pressure Coolant Injection Pump Discharge Flow - Low (Bypass)
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| - Function 3.a, Reactor Vessel Water Level - Low Low (Level 2)
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| - Function 3.c, Reactor Vessel Water Level - High (Level 8)
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| - Function 3.e, Suppression Pool Water Level - High
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| - Function 3.f, High Pressure Coolant Injection Pump Discharge Flow - Low (Bypass)
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| - Function 4.b, 5.b, Automatic Depressurization System Initiation Timer
| |
| - Function 4.c, 5.c, Reactor Vessel Water Level - Low (Level 3) (Confirmatory)
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| - Function 4.d, 5.d, Core Spray Pump Discharge Pressure - High
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| - Function 4.e, 5.e, Low Pressure Coolant Injection Pump Discharge Pressure - High With the exception of Function 2.d, no revisions to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). The Function 2.d TS Allowable Value change is described in Attachment 1, Section 3.1.3. Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As
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| NLS2011071 Page 40 of 49 such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation The purpose of the RCIC System instrumentation is to initiate actions to ensure adequate core cooling when the reactor vessel is isolated from its primary heat sink (the main condenser) and normal coolant makeup flow from the Reactor Feedwater System is insufficient or unavailable, such that the RCIC System initiation occurs and maintains sufficient reactor water level such that an initiation of the low pressure ECCS pumps does not occur.
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| SR 3.3.5.2.4 Perform CHANNEL CALIBRATION.
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| - Function 1, Reactor Vessel Water Level - Low Low (Level 2)
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| - Function 2, Reactor Vessel Water Level - High (Level 8)
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| For these functions, no revision to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these functions demonstrated that the as-found trip setpoint had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| TS 3.3.6.1 Primary Containment Isolation Instrumentation The primary containment isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs).
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| SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.
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| - Function 1 .a, 2.e, Reactor Vessel Water Level - Low Low Low (Level 1)
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| - Function 1 .c, Main Steam Line Flow - High
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| - Function 2.a, 6.b, Reactor Vessel Water Levelf- Low (Level 3)
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| - Function 2.b, Drywell Pressure - High
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| - Function 3.a, HPCI Steam Line Flow - High
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| - Function 3.b, HPCI Steam Line Flow - Time Delay Relays
| |
| - Function 3.c, HPCI Steam Supply Line Pressure - Low
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| - Function 4.a, RCIC Steam Line Flow - High
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| - Function 4.b, RCIC Steam Line Flow - Time Delay Relays
| |
| - Function 4.c, RCIC Steam Supply Line Pressure - Low
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| NLS2011071 Page 41 of 49
| |
| - Function 5.a, RWCU Flow - High
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| - Function 5.d, Reactor Vessel Water Level - Low Low (Level 2)
| |
| - Function 6.a, Reactor Pressure - High For these functions, no revision to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had two previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
| |
| a) On November 19, 2009, the as-found Trip Setpoint for MS-DPIS-1 19D exceeded instrument and TS limits. CR-CNS-2009-09839 was written to document the issue.
| |
| WO 4731278 replaced the switch.
| |
| b) On January 9, 2003, the as-found Trip Setpoint for MS-DPIS-1 17D exceeded instrument and TS limits. Notification 10219156 stated that the investigation of the calibration history determined the differential pressure switch was drifting excessively.
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| The switch was adjusted back within limits.
| |
| For these events there are a total of two failures identified relative to ITT Barton Model 288A Differential Pressure Switches over the review period. In one case a microswitch was replaced, and in the other case the switch was re-calibrated and returned to service. No time-based failure mechanisms are apparent. Therefore, these failures are unique, and accordingly, subsequent failures would not be expected to result in a significant impact on system/component availability. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on system design and the history of system performance, the impact of this change on safety, if any, is small.
| |
| SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.
| |
| - Function 1 .e, Main Steam Tunnel Temperature - High
| |
| - Function 3.d, HPCI Steam Line Space Temperature - High
| |
| - Function 4.d, RCIC Steam Line Space Temperature - High
| |
| - Function 5.b, RWCU System Space Temperature - High For this function, no revision to TS Allowable Values or safety analyses resulted from the required evaluations. The temperature elements are not required to be calibrated, therefore, no drift evaluation was performed. Extending the surveillance test interval for calibration of these functions is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Checks (SR 3.3.6.1.1 every 12 hours) and Channel Functional Tests (SR 3.3.6.1.2 every 92 days). Additionally, each of the above
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| NLS2011071 Page 42 of 49 functions is provided with sufficient channels to ensure that no single instrument failure can preclude the isolation function.
| |
| Because the other components in the instrument loop are calibrated together, it was only possible to perform a qualitative evaluation of these devices. This was performed by reviewing the as-found, as-left history.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had seven previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
| |
| a) On January 4, 2010,'the Temperature Switch RCIC-TS-79B Trip Setpoint exceeded the TS limit. CR-CNS-2010-00064 was written to document the issue with RCIC-TS-79B.
| |
| The Trip Setpoints were adjusted to within proper limits.
| |
| b) On March 31, 2005, Temperature Switch RWCU-TS-81C Trip Setpoint exceeded TS limits. CR-CNS-2005-02202 was written to document issue. The Trip Setpoint was adjusted to within proper limits.
| |
| c) On March 31, 2005, Temperature Switch RWCU-TS-8 1 G Trip Setpoint exceeded TS limits. CR-CNS-2005-02202 was written to document issue. The Trip Setpoint was adjusted to within proper limits.
| |
| d) On June 28, 2003, Temperature Switch HPCI-TS-125A would not trip at required values. RCR 2003-1181 documented the Trip Setpoint being found in excess of TS limits. The Condition Report cited the apparent cause as a possible equipment end-of-life condition. The switch was replaced per WO 4315747.
| |
| e) On June 28, 2003, the Temperature Switch HPCI-TS-126C as-found Trip Setpoint exceeded the TS limit. Notification 10248902 documented the Trip Setpoint being found in excess of TS limits, and cited the apparent cause as instrument drift. The switch was replaced per WO 4315747.
| |
| f) On June 28, 2003, the Temperature Switch RHR-TS-151D Trip Setpoint exceeded TS limits. Notification 10248194 documented the Trip Setpoint being found in excess of TS limits and cited the apparent cause as instrument drift. The switch was adjusted to within proper limits.
| |
| g) On June 28, 2003, the Temperature Switch HPCI-TS-103D Trip Setpoint exceeded TS limits. Notification 10249606 documented the Trip Setpoint being found in excess of TS limits and cited the apparent cause as instrument drift. The switches were adjusted to within proper limits.
| |
| For these events, there are a total of seven failures identified relative to Patel Engineering Model 01-170020-090 Temperature Switches over the review period. In seven of the seven
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| NLS2011071 Page 43 of 49 instances, a TS Setpoint was found to exceed its limit, and in two of the seven instances, the temperature switch was replaced. In five of seven cases, the switches were re-calibrated and returned to service. No time-based mechanisms are apparent. When considering that a total of 1216 (152 times a total of 8 surveillance procedure performances) different temperature switches were tested over the review period, a total of seven failures resulting in two switch replacements is a very small percentage of the total population tested. Therefore, an increase in the surveillance test interval will not result in a significant impact on system/component availability. As. such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency.
| |
| Based on system design and the history of system performance, the impact of this change on safety, if any, is small.
| |
| SR 3.3.6.1.4 Perform CHANNEL CALIBRATION.
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| - Function 2.c, Reactor Building Ventilation Exhaust Plenum Radiation - High
| |
| - Function 2.d, Main Steam Line Radiation - High For these functions, no revision to TS Allowable Values or safety analyses results from the required evaluations. Drift evaluations were not performed for radiation monitors. For the Reactor Building Ventilation Exhaust Plenum Radiation - High Function, the radiation detectors are calibrated using a calibrated source as an input signal to the detector. The source check is performed by exposing the sensor-converter to a known source in a constant geometry. Source checks of radiation monitors are subject to far more uncertainties than electronic calibration checks because of source decay, positioning of the sources, signal strength, and the sensor response curves of that particular monitoring system. The radiation detectors for the Main Steam Line Radiation - High Function are excluded from the channel calibration per a note to SR 3.3.6.1.4.
| |
| Extending the surveillance test interval for calibration of these functions is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Checks (SR 3.3.6.1.1 every 12 hours) and Channel Functional Tests (SR 3.3.6.1.2 every 92 days).
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on system design and the history of system performance, the impact of this change on safety, if any, is small.
| |
| SR 3.3.6.1.5 Calibrate each radiation detector.
| |
| - Function 2.d, Main Steam Line Radiation - High For these functions, no revision to TS Allowable Values or safety analyses results from the required evaluations. Drift evaluations were not performed for radiation monitors. The above radiation detectors are calibrated using a calibrated source as an input signal to the
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| | |
| NLS2011071 Page 44 of 49 detector. The source check is performed by exposing the sensor-converter to a known source in a constant geometry. Source checks of radiation monitors are subject to far more uncertainties than electronic calibration checks because of source decay, positioning of the sources, signal strength, and the sensor response curves of that particular monitoring system. Because of the uncertainties associated with the calibration methods for these devices, any AFAL evaluation would provide no true indication of the instrument performance over time.
| |
| Extending the surveillance test interval for calibration of these functions is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Checks (SR 3.3.6.1.1 every 12 hours) and Channel Functional Tests (SR 3.3.6.1.2 every 92 days).
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
| |
| As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on system design and the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.6.2 Secondary Containment Isolation Instrumentation The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System.
| |
| SR 3.3.6.2.3 Perform CHANNEL CALIBRATION.
| |
| - Function 1, Reactor Vessel Water Level - Low Low (Level 2)
| |
| - Function 2, Drywell Pressure - High For this function, no revision to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| | |
| NLS2011071 Page 45 of 49 SR 3.3.6.2.3 Perform CHANNEL CALIBRATION.
| |
| - Function 3, Reactor Building Ventilation Exhaust Plenum Radiation - High For this function, no revision to TS Allowable Values or safety analyses result from the required evaluations. Drift evaluations were not performed for radiation monitors. The above radiation detectors are calibrated using a calibrated source as an input signal to the detector. The source check is performed by exposing the sensor-converter to a known source in a constant geometry. Source checks of radiation monitors are subject to far more uncertainties than electronic calibration checks because of source decay, positioning of the sources, signal strength, and the sensor response curves of that particular monitoring system. Because of the uncertainties associated with the calibration methods for these devices, any AFAL evaluation would provide no true indication of the overall instrument performance over time.
| |
| Extending the surveillance test interval for calibration of these functions is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Checks (SR 3.3.6.2.1 every 12 hours) and Channel Functional Tests (SR 3.3.6.2.2 every 92 days). Furthermore, the ongoing drift trend program will monitor these channels for operation within the assumptions of the setpoint analysis.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on system design and the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.6.3 Low-Low Set (LLS) Instrumentation The LLS logic and instrumentation is designed to mitigate the effects of postulated thrust loads on the safety/relief valve (SRV) discharge lines by preventing subsequent actuations with an elevated water leg in the SRV discharge line. It also mitigates the effects of postulated pressure loads on suppression chamber structural components by preventing multiple actuations in rapid succession of the SRVs subsequent to their initial actuation.
| |
| SR 3.3.6.3.4 Perform CHANNEL CALIBRATION.
| |
| - Function 1, Reactor Pressure - High
| |
| - Function 2, Low-Low Set Pressure Setpoints
| |
| - Function 3, Discharge Line Pressure Switch With the exception of Function 2, no revision to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). The Function 2 TS Allowable Value change is described in Attachment 1, Section 3.1.4. Any necessary revisions to setpoint calculations have been
| |
| | |
| NLS2011071 Page 46 of 49 developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.7.1 Control Room Emergency Filter (CREF) System Instrumentation The CREF System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all plant conditions. The instrumentation and controls for the CREF System automatically isolates the normal ventilation intake and initiate action to pressurize the main control room and filter incoming air to minimize the infiltration of radioactive material in the control room environment.
| |
| SR 3.3.7.1.3 Perform CHANNEL CALIBRATION.
| |
| - Function 1, Reactor Vessel Water Level - Low Low (Level 2)
| |
| - Function 2, Drywell Pressure - High For these functions, no revision to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
| |
| Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| SR 3.3.7.1.3 Perform CHANNEL CALIBRATION.
| |
| - Function 3, Reactor Building Ventilation Exhaust Plenum Radiation - High For this function, no revision to TS Allowable Values or safety analyses result from the required evaluations. Drift evaluations were not performed for radiation monitors. The above radiation detectors are calibrated using a calibrated source as an input signal to the detector. The source check is performed by exposing the sensor-converter to a known source in a constant geometry. Source checks of radiation monitors are subject to far more uncertainties than electronic calibration checks because of source decay, positioning of the sources, signal strength, and the sensor response curves of that particular monitoring
| |
| | |
| NLS2011071 Page 47 of 49 system. Because of the uncertainties associated with the calibration methods for these devices, any AFAL evaluation would provide no true indication of the overall instrument performance over time.
| |
| Extending the surveillance test interval for calibration of these functions is acceptable because the functions are verified to be operating properly by the performance of more frequent Channel Checks (SR 3.3.7.1.1 every 12 hours) and Channel Functional Tests (SR 3.3.7.1.2 every 92 days). Furthermore, the ongoing drift trend program will monitor these channels for operation within the assumptions of the setpoint analysis.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR. As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on system design and the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.8.1 Loss of Power (LOP) Instrumentation Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4.16 kV emergency buses and the power to the buses. Offsite power is the preferred source of power for the 4.16 kV emergency buses. If the monitors determine that insufficient power is available, the buses are disconnected from the offsite power sources and connected to the onsite DG power sources.
| |
| SR 3.3.8.1.2 Perform CHANNEL CALIBRATION.
| |
| - Function 1.a, 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) - Bus Undervoltage
| |
| - Function 1.b, 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) - Time Delay
| |
| - Function 2.a, 4.16 kV Emergency Bus Normal Supply Undervoltage (Loss of Voltage)
| |
| Bus - Tie Undervoltage
| |
| - Function 2.b, 4.16 kV Emergency Bus Normal Supply Undervoltage (Loss of Voltage) -
| |
| Time Delay
| |
| - Function 3.a, 4.16 kV Emergency Bus ESST Supply Undervoltage (Loss of Voltage) Bus
| |
| - Tie Undervoltage
| |
| - Function 3.b, 4.16 kV Emergency Bus ESST Supply Undervoltage (Loss of Voltage) -
| |
| Time Delay
| |
| - Function 4.a, 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - Bus Undervoltage
| |
| - Function 4.b. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - Time Delay (LOCA)
| |
| - Function 4.c. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - Time Delay (Non-LOCA)
| |
| | |
| NLS2011071 Page 48 of 49
| |
| - Function 5.a, 4.16 kV Emergency Bus ESST Supply Undervoltage (Degraded Voltage) -
| |
| Bus Undervoltage
| |
| - Function 5.b. 4.16 kV Emergency Bus ESST Supply Undervoltage (Degraded Voltage) -
| |
| Time Delay For these functions, no revision to TS Allowable Values or safety analyses result from the GL 91-04 evaluations (e.g., statistical evaluation of historical drift factored into setpoint calculations). Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had no previous failures of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
| |
| Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
| |
| TS 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring The RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG) set or alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus against unacceptable voltage and frequency conditions.
| |
| SR 3.3.8.2.1 Perform CHANNEL CALIBRATION.
| |
| - Function a, Overvoltage
| |
| - Function b, Undervoltage
| |
| - Function c, Underfrequency For these functions, no revision to TS Allowable Values or safety analyses result from the required evaluations. Any necessary revisions to setpoint calculations have been developed, and calibration procedures to incorporate results of the statistical analysis of the historical AFAL data will be completed as part of implementation.
| |
| A review of the applicable CNS surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had one previous failure of TS Allowable Values that would have been detected solely by the periodic performance of this SR.
| |
| a) On November 21, 2001, Under-Frequency Time Delay RPS-EPA-1A2 was found out-of-tolerance. Notification 10125175 was written to document the issue. WO 4170624 replaced RPS-EPA- 1A2.
| |
| For this event, no time-based mechanisms are apparent. Therefore, this failure is unique, and subsequent failures would not be expected to result in a significant impact on
| |
| | |
| NLS2011071 Page 49 of 49 system/component availability. Accordingly, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.
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| | |
| NLS2011071 Page 1 of 22 Attachment 6 Applicable Instrumentation Cooper Nuclear Station, Docket No. 50-298, DPR-46
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| NLS2011071 Page 2 of 22 TS TS Function Functional Location (1) .. Functional Location,- Calculation, Manufacturer* Model No. Range Surveillance _. (2)__ _-... . ........
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| SR 3.3.1.1.12 3.3.1.1-1-1A CNS-1-NMI-NAM-41A NMI-NAM-41A NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-1A CNS-2-NMI-NAM-41B NMI-NAM-41B NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-1A CNS-1-NMI-NAM-41C NMI-NAM-41C NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-1A CNS-2-NMI-NAM-41D NMI-NAM-41D NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-1A CNS-1-NMI-NAM-41E NMI-NAM-41E NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-1A CNS-2-NMI-NAM-41F NMI-NAM-41F NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-1A CNS-1-NMI-NAM-41G NMI-NAM-41G NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-1A CNS-2-NMI-NAM-41H NMI-NAM-41H NPPD047-CALC- General Electric K601 (194X672G8) Range: 0 to 125 025 Divisions SR 3.3.1.1.12 3.3.1.1-1-2B CNS-1-RR-FT-110A RR-FT-110A NPPD047-CALC- General Electric 555 na 022 SR 3.3.1.1.12 3.3.1.1-1-2B CNS-1-RR-FT-110B RR-FT-110B NPPD047-CALC- General Electric 555 na 022 SR 3.3.1.1.12 3.3.1.1-1-2B CNS-1-RR-FT-11OC RR-FT-110C NPPD047-CALC- General Electric 555 na 022 SR 3.3.1.1.12 3.3.1.1-1-2B CNS-1-RR-FT-110D RR-FT-11OD NPPD047-CALC- General Electric 555 na 022 SR 3.3.1.1.12 3.3.1.1-1-3 CNS-1-NBI-PS-55A NBI-PS-55A NPPD047-CALC- Barksdale B2T-M12SS Adjustable Range: 0 026 to 1200 psi SR 3.3.1.1.12 3.3.1.1-1-3 CNS-2-NBI-PS-55B NBI-PS-55B NPPD047-CALC- Barksdale B2T-M12Ss Adjustable Range: 0 026 to 1200 psi SR 3.3.1.1.12 3.3.1.1-1-3 CNS-1-NBI-PS-55C NBI-PS-55C NPPD047-CALC- Barksdale B2T-M12SS Adjustable Range: 0 026 to 1200 psi SR 3.3.1.1.12 3.3.1.1-1-3 CNS-2-NBI-PS-55D NBI-PS-55D NPPD047-CALC- Barksdale B2T-M12SS Adjustable Range: 0 026 to 1200 psi SR 3.3.1.1.12 3.3.1.1-1-4 CNS-1-NBI-LIS-101A [L3] NBI-LIS-101A NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.1.1.12 3.3.1.1-1-4 CNS-2-NBI-LIS-101B [L3] NBI-LIS-101B NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.1.1.12 3.3.1.1-1-4 CNS-1-NBI-LIS-101C [L3] NBI-LIS-101C NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.1.1.12 3.3.1.1-1-4 CNS-2-NBI-LIS-101D [L3] NBI-LIS-101D NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.1.1.12 3.3.1.1-1-6 CNS-1-PC-PS-12A PC-PS-12A NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.1.1.12 3.3.1.1-1-6 CNS-2-PC-PS-12B PC-PS-12B NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 1 037 1 JJTTX6 0.75 to 12 psig
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| NLS2011071 Page 3 of 22 TS TS Function Functional Location (1)' Functional Location Calculation Manufacturer Model'No. Range Surveillance (2) _ _ _.
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| SR 3.3.1.1.12 3.3.1.1-1-6 CNS-1-PC-PS-12C PC-PS-12C NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.1.1.12 3.3.1.1-1-6 CNS-2-PC-PS-12D PC-PS-12D NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.1.1.12 3.3.1.1-1-7A CNS-1-CRD-LT-231C CRD-LT-231C NPPD047-CALC- ITT Barton 764 Input Range: 0 to 100 029 Inches SR 3.3.1.1.12 3.3.1.1-1-7A CNS-2-CRD-LT-231D CRD-LT-231D NPPD047-CALC- ITT Barton 764 Input Range: 0 to 100 029 Inches SR 3.3.1.1.12 3.3.1.1-1-7A CNS-1-CRD-LT-234C CRD-LT-234C NPPD047-CALC- ITT Barton 764 Input Range: 0 to 100 029 Inches SR 3.3.1.1.12 3.3.1.1-1-7A CNS-2-CRD-LT-234D CRD-LT-234D NPPD047-CALC- ITT Barton 764 Input Range: 0 to 100 029 Inches SR 3.3.1.1.12 3.3.1.1-1-7A CRD-IE-1A CRD-IE-1A NPPD047-CALC- Foxboro N-2AI-12V In: 4 to 20 mA and 029 Out: 0 to 10 Vdc SR 3.3.1.1.12 3.3.1.1-1-7A CRD-IE-1B CRD-IE-1B NPPD047-CALC- Foxboro N-2AI-12V In: 4 to 20 mA and 029 Out: 0 to 10 Vdc SR 3.3.1.1.12 3.3.1.1-1-7A CRD-AM-1A CRD-AM-1A NPPD047-CALC- Foxboro N-2AP+ALM-AR Input Range: 0 to 10 029 Vdc SR 3.3.1.1.12 3.3.1.1-1-7A CRD-AM-1B CRD-AM-1B NPPD047-CALC- Foxboro N-2AP+ALM-AR Input Range: 0 to 10 029 Vdc SR 3.3.1.1.12 3.3.1.1-1-7A CRD-AM-2A CRD-AM-2A NPPD047-CALC- Foxboro N-2AP+ALM-AR Input Range: 0 to 10 029 Vdc SR 3.3.1.1.12 3.3.1.1-1-7A CRD-AM-2B CRD-AM-2B NPPD047-CALC- Foxboro N-2AP+ALM-AR Input Range: 0 to 10 029 Vdc SR 3.3.1.1.12 3.3.1.1-1-9 CNS-1-TGF-PS-630PC1 TGF-PS-630PC1 NPPD047-CALC- Static O-Ring 9N6-BB45-NX-C1A- Calibrated Span: 200-032 JJTTX12 1750psig SR 3.3.1.1.12 3.3.1.1-1-9 CNS-1-TGF-PS-630PC3 TGF-PS-630PC3 NPPD047-CALC- Static O-Ring 9N6-BB45-NX-C1A- Calibrated Span: 200-032 JJTTX12 1750psig SR 3.3.1.1.12 3.3.1.1-1-9 CNS-2-TGF-PS-63OPC2 TGF-PS-630PC2 NPPD047-CALC- Static O-Ring 9N6-BB45-NX-C1A- Calibrated Span: 200-032 JJTTX12 1750psig SR 3.3.1.1.12 3.3.1.1-1-9 CNS-2-TGF-PS-63OPC4 TGF-PS-630PC4 NPPD047-CALC- Static O-Ring 9N6-BB45-NX-CIA- Calibrated Span: 200-032 JJTTX12 1750psig SR 3.3.3.2.3 N/A CNS-2-HPCI-FT-82 HPCI-FT-82 NPPD047-CALC- Rosemount 1153DB5PC URL: 750" H20 035 SR 3.3.3.2.3 N/A CNS-2-RHR-FT-109B RHR-FT-109B NPPD047-CALC- Rosemount 1153DB5PC URL: 750" H20 035 SR 3.3.4.1.2a N/A CNS-1-NBI-LIS-57A [L2] NBI-LIS-57A NPPDO47-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.4.1.2a N/A CNS-1-NBI-LIS-58A [L2] NBI-LIS-58A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.4.1.2a N/A CNS-2-NBI-LIS-57B [L2] NBI-LIS-57B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.4.1.2a N/A CNS-2-NBI-LIS-58B 1L21 NBI-LIS-58B NPPDO47-CALC- Yarway 4418C IR: -150 to +60 001 inches
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| NLS2011071 Page 4 of 22 TS TS Function Functional Location (1.) Functional Location Calculation Manufacturer Model[No. Range Surveillance (2)
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| SR 3.3.4.1.2b N/A CNS-1-NBI-PS-102A NBI-PS-102A NPPD047-CALC- Static O-Ring 9N-AA45-P1-FIA- Calibrated Span: 200-030 TTC1C4X 1750psig SR 3.3.4.1.2b N/A CNS-2-NBI-PS-102B NBI-PS-102B NPPD047-CALC- Static O-Ring 9N-AA45-X9TT Calibrated Span: 200-030 1500psig SR 3.3.4.1.2b N/A CNS-1-NBI-PS-102C NBI-PS-102C NPPD047-CALC- Static O-Ring 9N-AA45-P1-FIA-TTX3 Calibrated Span: 200-030 1750psig SR 3.3.4.1.2b N/A CNS-2-NBI-PS-102D NBI-PS-102D NPPD047-CALC- Static O-Ring 9N-AA45-X1OTT Calibrated Span: 200-030 1500psig SR 3.3.5.1.4 3.3.5.1-1-1A CNS-1-NBI-LIS-72A [Li] NBI-LIS-72A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-1A CNS-2-NBI-LIS-72B [L1] NBI-LIS-72B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-1A CNS-1-NBI-LIS-72C [L1] NBI-LIS-72C NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-1A CNS-2-NBI-LIS-72D [L1] NBI-LIS-72D NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-1B CNS-1-PC-PS-101A PC-PS-101A NPPD047-CALC- Static 0-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-1B CNS-2-PC-PS-101B PC-PS-101B NPPDO47-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-1B CNS-1-PC-PS-101C PC-PS-101C NPPD047-CALC- Static O-Ring 12TA-BB4-NX-CIA- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-1B CNS-2-PC-PS-101D PC-PS-101D NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-1C CNS-2-NBI-PIS-52B [S2] NBI-PIS-52B NPPD047-CALC- ITT Barton 288A IR: 0 to 500 psig 015 SR 3.3.5.1.4 3.3.5.1-1-1C CNS-2-NBI-PIS-52D [S2] NBI-PIS-52D NPPD047-CALC- ITT Barton 288A IR: 0 to 500 psig 015 SR 3.3.5.1.4 3.3.5.1-1-1C CNS-1-NBI-PS-52A2 NBI-PS-52A2 NPPD047-CALC- Static O-Ring 9TA-B4-U8-ClA- Adjustable Range:
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| 036 JJTTNQ 100 to 500 psi SR 3.3.5.1.4 3.3.5.1-1-1C CNS-1-NBI-PS-52C2 NBI-PS-52C2 NPPD047-CALC- Static O-Ring 9TA-B4-U8-ClA- Adjustable Range:
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| 036 JJTTNQ 100 to 500 psi SR 3.3.5.1.4 3.3.5.1-1-1D CNS-1-CS-AM-45A CS-AM-45A NPPD047-CALC- General Electric 560 Span: 4 to 20 mA 011 SR 3.3.5.1.4 3.3.5.1-1-1D CNS-2-CS-AM-45B CS-AM-45B NPPD047-CALC- General Electric 560 Span: 4 to 20 mA 011 SR 3.3.5.1.4 3.3.5.1-1-1D CNS-1-CS-FT-40A CS-FT-40A NPPD047-CALC- Rosemount 1153DB5PC URL: 750" H20 035 SR 3.3.5.1.4 3.3.5.1-1-1D CNS-2-CS-FT-40B CS-FT-40B NPPD047-CALC- Rosemount 1153DB5PC URL: 750" H20 035 SR 3.3.5.1.4 3.3.5.1-1-1E CNS-1-CS-REL-K16A CS-REL-K16A NPPD047-CALC- Agastsat ETR14D3BOO4 URL: 15 sec 009 SR 3.3.5.1.4 3.3.5.1-1-1E CNS-2-CS-REL-K16B CS-REL-K16B NPPD047-CALC- Agastsat ETR14D3BOO4 URL: 15 sec 1_ 009 0 1
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| NLS2011071 Page 5 of 22 TS TS Functionr FunctionalLocationr (1) Functional Location" Calculation Manufacturer Model No. Range Surveillance (2)
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| SR 3.3.5.1.4 3.3.5.1-1-2A CNS-1-NBI-LIS-72A [L1] NBI-LIS-72A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-2A CNS-2-NBI-LIS-72B [L1] NBI-LIS-72B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-2A CNS-1-NBI-LIS-72C [L1] NBI-LIS-72C NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-2A CNS-2-NBI-LIS-72D [L1] NBI-LIS-72D NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-2B CNS-1-PC-PS-101A PC-PS-101A NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-2B CNS-2-PC-PS-101B PC-PS-101B NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-2B CNS-1-PC-PS-101C PC-PS-101C NPPD047-CALC- Static O-Ring 12TA-BB4-NX-CIA- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-2B CNS-2-PC-PS-101D PC-PS-101D NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-2C CNS-2-NBI-PIS-52B [S2] NBI-PIS-52B NPPD047-CALC- ITT Barton 288A IR: 0 to 500 psig 015 SR 3.3.5.1.4 3.3.5.1-1-2C CNS-2-NBI-PIS-52D [S2] NBI-PIS-52D NPPD047-CALC- ITT Barton 288A IR: 0 to 500 psig 015 SR 3.3.5.1.4 3.3.5.1-1-2C CNS-1-NBI-PS-52A2 NBI-PS-52A2 NPPD047-CALC- Static O-Ring 9TA-B4-U8-ClA- Adjustable Range:
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| 036 JJTTNQ 100 to 500 psi SR 3.3.5.1.4 3.3.5.1-1-2C CNS-1-NBI-PS-52C2 NBI-PS-52C2 NPPD047-CALC- Static O-Ring 9TA-B4-U8-C1A- Adjustable Range:
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| 036 JJTTNQ 100 to 500 psi SR 3.3.5.1.4 3.3.5.1-1-2D CNS-2-NBI-PIS-52B [51] NBI-PIS-52B NPPD047-CALC- ITT Barton 288A IR: 0 to 500 psig 015 SR 3.3.5.1.4 3.3.5.1-1-2D CNS-2-NBI-PIS-52D [51] NBI-PIS-52D NPPD047-CALC- ITT Barton 288A IR: 0 to 500 psig 015 SR 3.3.5.1.4 3.3.5.1-1-2D CNS-1-NBI-PS-52A1 NBI-PS-52A1 NPPD047-CALC- Static O-Ring 9TA-B4-U8-ClA- Adjustable Range:
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| 036 JJTTNQ 100 to 500 psi SR 3.3.5.1.4 3.3.5.1-1-2D CNS-1-NBI-PS-52C1 NBI-PS-52C1 NPPD047-CALC- Static O-Ring 9TA-B4-U8-ClA- Adjustable Range:
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| 036 JJTTNQ 100 to 500 psi SR 3.3.5.1.4 3.3.5.1-1-2E CNS-1-NBI-LITS-73A NBI-LITS-73A NPPD047-CALC- Yarway 4418C IR: -260 to +40 003 inches SR 3.3.5.1.4 3.3.5.1-1-2E CNS-2-NBI-LITS-73B NBI-LITS-73B NPPD047-CALC- Yarway 4418C IR: -260 to +40 003 inches SR 3.3.5.1.4 3.3.5.1-1-2G CNS-1-RHR-DPIS-125A RHR-DPIS-125A NPPD047-CALC- ITT Barton 289A IR: 0 to 10 in WC 017 SR 3.3.5.1.4 3.3.5.1-1-2G CNS-2-RHR-DPIS-125B RHR-DPIS-125B NPPD047-CALC- ITT Barton 581A IR: 0 to 10 in WC 017 SR 3.3.5.1.4 3.3.5.1-1-3A CNS-1-NBI-LIS-72A [L2] NBI-LIS-72A NPPD047-CALC- Yarway 4418C IR: -150 to +60 1 001 inches SR 3.3.5.1.4 3.3.5.1-1-3A CNS-2-NBI-LIS-72B [L2] NBI-LIS-72B NPPD047-CALC- Yarway 4418C IR: -150 to +60 1 001 inches
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| NLS2011071 Page 6 of 22 TS TS Function Functional Location (1) Functional Location Calculation Manufacturer Model No. Range Surveillance (2)
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| SR 3.3.5.1.4 3.3.5.1-1-3A CNS-1-NBI-LIS-72C1L21 NBI-LUS-72C NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-3A CNS-2-NBI-LIS-72D [L2] NBI-LIS-72D NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-3B CNS-1-PC-PS-101A PC-PS-101A NPPD047-CALC- Static 0-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-3B CNS-2-PC-PS-101B PC-PS-101B NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-3B CNS-1-PC-PS-101C PC-PS-101C NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-3B CNS-2-PC-PS-101D PC-PS-101D NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.5.1.4 3.3.5.1-1-3C CNS-2-NBI-LIS-101B [L8] NBI-LIS-101B NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.5.1.4 3.3.5.1-1-3C CNS-2-NBI-LIS-101D [L8] NBI-LIS-101D NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.5.1.4 3.3.5.1-1-3F CNS-2-HPCI-FIS-78 HPCI-FIS-78 NPPD047-CALC- ITT Barton 289A IR: 0 to 14 in WC 018 SR 3.3.5.1.4 3.3.5.1-1-4A CNS-1-NBI-LIS-72A [L1] NBI-LIS-72A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-4A CNS-1-NBI-LIS-72C [L1] NBI-LIS-72C NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-4C CNS-1-NBI-LIS-83A NBI-LIS-83A NPPD047-CALC- Yarway 4418C IR: 0 to +60 inches 002 SR 3.3.5.1.4 3.3.5.1-1-4D CNS-1-CS-PS-37A CS-PS-37A NPPD047-CALC- Static O-Ring 5TA-BB3-U8-ClA- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-4D CNS-1-CS-PS-44A CS-PS-44A NPPD047-CALC- Static O-Ring 5TA-BB3-U8-C1A- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-4E CNS-1-RHR-PS-105A RHR-PS-105A NPPD047-CALC- Static O-Ring 5TA-BB3-U8-CIA- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-4E CNS-1-RHR-PS-105C RHR-PS-105C NPPD047-CALC- Static O-Ring 5TA-BB3-U8-C1A- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-4E CNS-1-RHR-PS-120A RHR-PS-120A NPPD047-CALC- Static O-Ring 5TA-BB3-U8-C1A- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-4E CNS-1-RHR-PS-120C RHR-PS-120C NPPD047-CALC- Static O-Ring 5TA-BB3-U8-C1A- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-5A CNS-2-NBI-LIS-72B [L1] NBI-LIS-72B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-5A CNS-2-NBI-LIS-72D [L1] NBI-LIS-72D NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.1.4 3.3.5.1-1-5C CNS-2-NBI-LIS-83B NBI-LIS-83B NPPD047-CALC- Yarway 4418C IR: 0 to +60 inches 002 SR 3.3.5.1.4 3.3.5.1-1-5D CNS-2-CS-PS-37B CS-PS-37B NPPD047-CALC- Static O-Ring 5TA-BB3-U8-C1A- Adjustable Range: 25 L 033 JJTTNQ to 240 psig
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| NLS2011071 Page 7 of 22 TS TS Function Functional Location (1), Functional Location Calculation Manufacturer Model No. Range Surveillance (2)
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| SR 3.3.5.1.4 3.3.5.1-1-5D CNS-2-CS-PS-44B CS-PS-44B NPPD047-CALC- Static O-Ring 5TA-BB3-U8-ClA- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-5E CNS-2-RHR-PS-105B RHR-PS-105B NPPD047-CALC- Static O-Ring 5TA-BB3-U8-ClA- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-5E CNS-2-RHR-PS-105D RHR-PS-105D NPPD047-CALC- Static O-Ring 5TA-BB3-U8-ClA- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-5E CNS-2-RHR-PS-120B RHR-PS-120B NPPD047-CALC- Static O-Ring 5TA-BB3-U8-ClA- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.1.4 3.3.5.1-1-5E CNS-2-RHR-PS-120D RHR-PS-120D NPPD047-CALC- Static O-Ring 5TA-BB3-U8-C1A- Adjustable Range: 25 033 JJTTNQ to 240 psig SR 3.3.5.2.4 3.3.5.2-1-1 CNS-1-NBI-LIS-72A [L2] NBI-LIS-72A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.2.4 3.3.5.2-1-1 CNS-2-NBI-LIS-72B [L2] NBI-LIS-72B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.2.4 3.3.5.2-1-1 CNS-1-NBI-LIS-72C [L2] NBI-LIS-72C NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.2.4 3.3.5.2-1-1 CNS-2-NBI-LIS-72D [L2] NBI-LIS-72D NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.5.2.4 3.3.5.2-1-2 CNS-1-NBI-LIS-101A [L8] NBI-LIS-101A NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.5.2.4 3.3.5.2-1-2 CNS-1-NBI-LIS-101C [L8] NBI-LIS-101C NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-1A CNS-1-NBI-LIS-57A [L1] NBI-LIS-57A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-1A CNS-2-NBI-LIS-57B [L1] NBI-LIS-57B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-1A CNS-1-NBI-LIS-58A [L1] NBI-LIS-58A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-1A CNS-2-NBI-LIS-58B [L1] NBI-LIS-58B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-116A MS-DPIS-116A NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-116B MS-DPIS-116B NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-116C MS-DPIS-116C NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-116D MS-DPIS-116D NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-117A MS-DPIS-117A NPPDO47-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-117B MS-DPIS-117B NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-117C MS-DPIS-117C NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 1 1 013
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| NLS2011071 Page 8 of 22 TS TS Functiohn Fufic-tionaI'Loc,-ation (1) Functional Locatfion Cakculation ManUf3Ctuir ~ Model No. Rag SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-117D MS-DPIS-117D NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-118A MS-DPIS-118A NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-118B MS-DPIS-118B NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-118C MS-DPIS-118C NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-118D MS-DPIS-118D NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-119A MS-DPIS-119A NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-119B MS-DPIS-119B NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-1-MS-DPIS-119C MS-DPIS-119C NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1C CNS-2-MS-DPIS-119D MS-DPIS-119D NPPD047-CALC- ITT Barton 288A IR: 0 to 150 psid 013 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-121A MS-TS-121A NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-121B MS-TS-121B NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-121C MS-TS-121C NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-121D MS-TS-121D NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-122A MS-TS-122A NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-122B MS-TS-122B NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-1 22C MS-TS-122C NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-122D MS-TS-122D NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-123A MS-TS-123A NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-123B MS-TS-123B NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-123C MS-TS-123C NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-123D MS-TS-123D NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-124A MS-TS-124A NPPD047-CALC- Patel 01-170020-090 URL: 600°F I 010 Engineering
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| NLS2011071 Page 9 of 22 TSuvac TS Function~ Funthionfal Lcb:atiori()
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| ý F6unctionalocation Calculation Ma~nufactu~rer< - de~lNo. Ranige SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-124B MS-TS-124B NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-124C MS-TS-124C NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-124D MS-TS-124D NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-143A MS-TS-143A NPPD047-CALC- Fenwal 17002-40 URL: 600°F 010 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-143B MS-TS-143B NPPD047-CALC- Fenwal 17002-40 URL: 600TF 010 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-143C MS-TS-143C NPPD047-CALC- Fenwal 17002-40 URL: 600°F 010 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-143D MS-TS-143D NPPD047-CALC- Fenwal 17002-40 URL: 600TF 010 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-144A MS-TS-144A NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-144B MS-TS-144B NPPD047-CALC- Patel 01-170020-090 URL: 6007F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-144C MS-TS-144C NPPD047-CALC- Patel 01-170020-090 URL: 6007F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-144D MS-TS-144D NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-145A MS-TS-145A NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-145B MS-TS-145B NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-145C MS-TS-145C NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-145D MS-TS-145D NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-146A MS-TS-146A NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-146B MS-TS-146B NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-146C MS-TS-146C NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-146D MS-TS-146D NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-147A MS-TS-147A NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-147B MS-TS-147B NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-147C MS-TS-147C NPPD047-CALC- Patel 01-170020-090 URL: 600°F 010 Engineering
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| NLS2011071 Page 10 of 22 TS TS Function Functional Location (1) Functional Location Calculation Manufacturer Model No. Range Surveillance (2) -_
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| SR 3.3.6.1.4 3.3.6.1-1-1 E CNS-0-MS-TS-1470 MS-TS-1470 NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-148A MS-TS-148A NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-148B MS-TS-148B NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-148C MS-TS-148C NPPD047-CALC- Patel 01-170020-090 URL: 600'F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-148D MS-TS-148D NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-149A MS-TS-149A NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-149B MS-TS-149B NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-149C MS-TS-149C NPPD047-CALC- Patel 01-170020-090 URL: 600'F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-149D MS-TS-149D NPPD047-CALC- Patel 01-170020-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-150A MS-TS-150A NPPD047-CALC- Fenwal 17002-40 URL: 600TF 010 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-150B MS-TS-150B NPPD047-CALC- Fenwal 17002-40 URL: 600°F 010 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-150C MS-TS-150C NPPD047-CALC- Fenwal 17002-40 URL: 600TF 010 SR 3.3.6.1.4 3.3.6.1-1-1E CNS-0-MS-TS-150D MS-TS-150D NPPD047-CALC- Fenwal 17002-40 URL: 600TF 010 SR 3.3.6.1.4 3.3.6.1-1-2A CNS-1-NBI-LIS-101A [L3] NBI-LIS-101A NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-2A CNS-2-NBI-LIS-1O1B [L3] NBI-LIS-101B NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-2A CNS-1-NBI-LIS-101C 1L3] NBI-LIS-101C NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-2A CNS-2-NBI-LIS-101D [L3] NBI-LIS-101D NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-2B CNS-1-PC-PS-12A PC-PS-12A NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.6.1.4 3.3.6.1-1-2B CNS-2-PC-PS-12B PC-PS-12B NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.6.1.4 3.3.6.1-1-2B CNS-1-PC-PS-12C PC-PS-12C NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.6.1.4 3.3.6.1-1-2B CNS-2-PC-PS-12D PC-PS-12D NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.6.1.4 3.3.6.1-1-2E CNS-1-NBI-LIS-57A [L1] NBI-LIS-57A NPPD047-CALC- Yarway 4418C IR: -150 to +60 i i I 1 001 1 inches
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| NLS2011071 Page 11 of 22 TS * 'TS niction Fuiiictional Locatioh(l)) Function~il*Location. Calculatidn 'Manufacturer<, . . Model Nol '>..., Range Surveillance . . ;. '(2) ~ )
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| SR 3.3.6.1.4 3.3.6.1-1-2E CNS-2-NBI-LIS-57B [L1] NBI-LIS-57B NPPDO47-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-2E CNS-1-NBI-LIS-58A [L1] NBI-LIS-58A NPPDO47-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-2E CNS-2-NBI-LIS-58B [L1] NBI-LIS-58B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-3A CNS-2-HPCI-DPIS-76 HPCI-DPIS-76 NPPD047-CALC- ITT Barton 580A IR: -300 to +300 in 012 WC SR 3.3.6.1.4 3.3.6.1-1-3A CNS-2-HPCI-DPIS-77 HPCI-DPIS-77 NPPD047-CALC- ITT Barton 580A IR: -300 to +300 in 012 WC SR 3.3.6.1.4 3.3.6.1-1-3B CNS-2-HPCI-REL-K33 HPCI-REL-K33 NPPD047-CALC- Allen Bradley 700-RTC-1111OU1 Adjustable Range:
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| 021 0.2 to 8 sec SR 3.3.6.1.4 3.3.6.1-1-3B CNS-2-HPCI-REL-K43 HPCI-REL-K43 NPPD047-CALC- Allen Bradley 700-RTC-1111OU1 Adjustable Range:
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| 021 0.2 to 8 sec SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-101A HPCI-TS-101A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-101B HPCI-TS-101B NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-101C HPCI-TS-101C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-101D HPCI-TS-101D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-102A HPCI-TS-102A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-102B HPCI-TS-102B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-102C HPCI-TS-102C NPPD047-CALC- Patel 01-170230-090 URL: 600'F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-102D HPCI-TS-102D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-103A HPCI-TS-103A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-103B HPCI-TS-103B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-103C HPCI-TS-103C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-103D HPCI-TS-103D NPPD047-CALC- Patel 01-170230-090 URL: 600*F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-104A HPCI-TS-104A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-104B HPCI-TS-104B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering I SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-104C HPCI-TS-104C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering
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| NLS2011071 Page 12 of 22 T1S TS.Functibn Functi6nal Location (1) F ,Finction6l Location.; Calculation .:+ -Manufacturer ModelNo.,: >* Range:
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| Suiveiilafice- : ~ 2( ) 5 . . . .
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| SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-104D HPCI-TS-104D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-125A HPCI-TS-125A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-125B HPCI-TS-125B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-125C HPCI-TS-125C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SIR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-125D HPCI-TS-125D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-126A HPCI-TS-126A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-126B HPCI-TS-126B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-126C HPCI-TS-126C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-126D HPCI-TS-126D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-127A HPCI-TS-127A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SIR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-127B HPCI-TS-127B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-127C HPCI-TS-127C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SIR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-127D HPCI-TS-127D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-128A HPCI-TS-128A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-128B HPCI-TS-128B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SIR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-128C HPCI-TS-128C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-3D CNS-2-HPCI-TS-128D HPCI-TS-128D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4A CNS-1-RCIC-DPIS-83 RCIC-DPIS-83 NPPD047-CALC- ITT Barton 288 IR: -500 to 500 in 016 WC SR 3.3.6.1.4 3.3.6.1-1-4A CNS-2-RCIC-DPIS-84 RCIC-DPIS-84 NPPD047-CALC- ITT Barton 288 IR: -500 to 500 in 016 WC SR 3.3.6.1.4 3.3.6.1-1-4B CNS-1-RCIC-REL-K12 RCIC-REL-K12 NPPD047-CALC- Allen Bradley 700-RTC-1111OU1 Adjustable Range:
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| _021 0.2 to 8 sec SIR 3.3.6.1.4 3.3.6.1-1-4B CNS-2-RCIC-REL-K32 RCIC-REL-K32 NPPD047-CALC- Allen Bradley 700-RTC-1111OU1 Adjustable Range:
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| 021 0.2 to 8 sec SIR 3.3.6.1.4 3.3.6.1-1-4D CNS-1-RCIC-TS-79A RCIC-TS-79A NPPD047-CALC- Patel 01-170230-090 URL: 600"F 010 Engineering
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| NLS2011071 Page 13 of 22 TS TS FunctionV Functional Loca~tion (1)V Functional Locatiorn Calculationh Manufac-turer MdfN.Range
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| ,Surveillance. (2) ~
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| SR 3.3.6.1.4 3.3.6.1-1-4D CNS-1-RCIC-TS-79C RCIC-TS-79C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4b CNS-1-RCIC-TS-80A RCIC-TS-80A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-1-RCIC-TS-80C RCIC-TS-80C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-1-RCIC-TS-81A RCIC-TS-81A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-1-RCIC-TS-81C RCIC-TS-81C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-1-RCIC-TS-82A RCIC-TS-82A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-1-RCIC-TS-82C RCIC-TS-82C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-79B RCIC-TS-79B NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-79D RCIC-TS-79D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-80B RCIC-TS-80B NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-80D RCIC-TS-80D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-81B RCIC-TS-81B NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-81D RCIC-TS-81D NPPD047-CALC- Patel 01-170230-090 URL: 6007F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-82B RCIC-TS-82B NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-4D CNS-2-RCIC-TS-82D RCIC-TS-82D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5A CNS-1-RWCU-DPIS-170A RWCU-DPIS-170A NPPD047-CALC- ITT Barton 289A Range: 0 to 24 in WC 019 SR 3.3.6.1.4 3.3.6.1-1-5A CNS-2-RWCU-DPIS-170B RWCU-DPIS-170B NPPD047-CALC- ITT Barton 289A Range: 0 to 24 in WC 019 SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-150A RWCU-TS-150A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-150C RWCU-TS-150C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-151A RWCU-TS-151A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-151C RWCU-TS-151C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 1 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-152A RWCU-TS-152A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 1 010 Engineering
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| NLS2011071 Page 14 of 22 TS Functional Locatio r Functi6nal Location:
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| "TSFunction
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| * Calculation ,Manufacturer'; Model, No.'
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| .... , :. Range SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-1520 RWCU-TS-1 52C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-153A RWCU-TS-153A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-153C RWCU-TS-153C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-154A RWCU-TS-154A NPPD047-CALC- Patel 01-170230-090 URL: 600NF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-154C RWCU-TS-154C NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-155A RWCU-TS-1 55A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-155C RWCU-TS-1 55C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-156A RWCU-TS-156A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-156C RWCU-TS-156C NPPD047-CALC- Patel 01-170230-090 URL: 600 0F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-157A RWCU-TS-157A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-157C RWCU-TS-157C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-158A RWCU-TS-158A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-158C RWCU-TS-158C NPPD047-CALC- Patel 01-170230-090 URL: 600 0 F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-159A RWCU-TS-159A NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-159C RWCU-TS-159C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-81A RWCU-TS-81A NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-81C RWCU-TS-81C NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-81E RWCU-TS-81E NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-1-RWCU-TS-81G RWCU-TS-81G NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-1 50B RWCU-TS-150B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-1 50D RWCU-TS-150D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-151B RWCU-TS-151B NPPD047-CALC- Patel 01-170230-090 URL: 600TF I I 010 Engineering
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| NLS2011071 Page 15 of 22 TSFunction Fuinictional Location (1) , Functi6naI-"cation. Caluliation, Manufacturer. Model N -o. Riihge, SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-151D RWCU-TS-151D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-152B RWCU-TS-152B NPPD047-CALC- Patel 01-170230-090 URL: 600NF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-152D RWCU-TS-152D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-153B RWCU-TS-153B NPPD047-CALC- Patel 01-170230-090 URL: 600'F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-153D RWCU-TS-153D NPPD047-CALC- Patel 01-170230-090 URL: 600'F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-154B RWCU-TS-154B NPPD047-CALC- Patel 01-170230-090 URL: 600NF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-154D RWCU-TS-154D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-155B RWCU-TS-155B NPPD047-CALC- Patel 01-170230-090 URL: 600'F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-155D RWCU-TS-155D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-156B RWCU-TS-156B NPPD047-CALC- Patel 01-170230-090 URL: 600'F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-156D RWCU-TS-156D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-157B RWCU-TS-157B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-1 57D RWCU-TS-157D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-1 58B RWCU-TS-158B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-158D RWCU-TS-158D NPPD047-CALC- Patel 01-170230-090 URL: 6007F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-159B RWCU-TS-1 59B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-159D RWCU-TS-159D NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-81B RWCU-TS-81B NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-81D RWCU-TS-81D NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5B CNS-2-RWCU-TS-81F RWCU-TS-81F NPPD047-CALC- Patel 01-170230-090 URL: 600TF 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-58 CNS-2-RWCU-TS-81H RWCU-TS-81H NPPD047-CALC- Patel 01-170230-090 URL: 600°F 010 Engineering SR 3.3.6.1.4 3.3.6.1-1-5D CNS-1-NBI-LIS-57A [L2] NBI-LIS-57A NPPD047-CALC- Yarway 4418C IR: -150 to +60 I 001 inches
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| NLS20I 1071 Page 16 of 22 TS TS Function Functional Location (1) Functional Location C~alculation Manufacturer Model No. Range Surveillance (2) -
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| SR 3.3.6.1.4 3.3.6.1-1-5D CNS-2-NBI-LIS-57B [L2] NBI-LIS-57B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-5D CNS-1-NBI-LIS-58A [L2] NBI-LIS-58A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-5D CNS-2-NBI-LIS-58B [L2] NBI-LIS-58B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.1.4 3.3.6.1-1-6A CNS-0-RR-PS-128A RR-PS-128A NPPD047-CALC- Static O-Ring 5TA-BB3-U8-ClA- Adjustable Range: 25 034 JJTTNQ to 240 psig SR 3.3.6.1.4 3.3.6.1-1-6A CNS-0-RR-PS-128B RR-PS-128B NPPDO47-CALC- Static O-Ring 5TA-BB3-U8-ClA- Adjustable Range: 25 034 JJT-TNQ to 240 psig SR 3.3.6.1.4 3.3.6.1-1-6B CNS-1-NBI-LIS-101A [L31 NBI-LIS-1O1A NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-6B CNS-2-NBI-LIS-101B [L3] NBI-LIS-101B NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-6B CNS-1-NBI-LIS-101C [L3] NBI-LIS-101C NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.1.4 3.3.6.1-1-6B CNS-2-NBI-LIS-101D [L3] NBI-LIS-101D NPPD047-CALC- ITT Barton 288A IR: 69.3 to 27 in WC 014 SR 3.3.6.2.3 3.3.6.2-1-1 CNS-1-NBI-LIS-57A [L2] NBI-LIS-57A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.2.3 3.3.6.2-1-1 CNS-2-NBI-LIS-57B [L2] NBI-LIS-57B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.2.3 3.3.6.2-1-1 CNS-1-NBI-LIS-58A [L2] NBI-LIS-58A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.2.3 3.3.6.2-1-1 CNS-2-NBI-LIS-58B [L2] NBI-LIS-58B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.6.2.3 3.3.6.2-1-2 CNS-1-PC-PS-12A PC-PS-12A NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.6.2.3 3.3.6.2-1-2 CNS-2-PC-PS-12B PC-PS-12B NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.6.2.3 3.3.6.2-1-2 CNS-1-PC-PS-12C PC-PS-12C NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.6.2.3 3.3.6.2-1-2 CNS-2-PC-PS-12D PC-PS-12D NPPD047-CALC- Static O-Ring 12TA-BB5-NX-CIA- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.6.3.4 3.3.6.3-1-1 CNS-1-NBI-PS-55A NBI-PS-55A NPPD047-CALC- Barksdale B2T-M12SS Adjustable Range: 0 026 to 1200 psi SR 3.3.6.3.4 3.3.6.3-1-1 CNS-2-NBI-PS-55B NBI-PS-55B NPPD047-CALC- Barksdale B2T-M12SS Adjustable Range: 0 026 to 1200 psi SR 3.3.6.3.4 3.3.6.3-1-1 CNS-1-NBI-PS-55C NBI-PS-55C NPPD047-CALC- Barksdale B2T-M12SS Adjustable Range: 0 026 to 1200 psi SR 3.3.6.3.4 3.3.6.3-1-1 CNS-2-NBI-PS-55D NBI-PS-55D NPPD047-CALC- Barksdale B2T-M12SS Adjustable Range: 0 026 to 1200 psi SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300A MS-PS-300A NPPD047-CALC- Pressure A171P URL: 200 psig 1 008 Controls I I
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| NLS2011071 Page 17 of 22 TS TS Function Functional Location (1) Functional Location- 'Calculation Manufacturer Model No. Range Surveillance '(2)
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| SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300B MS-PS-300B NPPD047-CALC- Pressure A171P URL: 200 psig 008 Controls SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300C MS-PS-300C NPPD047-CALC- Pressure A171P URL: 200 psig 008 Controls SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300D MS-PS-300D NPPD047-CALC- Pressure A171P URL: 200 psig 008 Controls SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300E MS-PS-300E NPPD047-CALC- Pressure A171P URL: 200 psig 008 Controls SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300F MS-PS-300F NPPD047-CALC- Pressure A171P URL: 200 psig 008 Controls SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300G MS-PS-300G NPPD047-CALC- Pressure A171P URL: 200 psig 008 Controls SR 3.3.6.3.4 3.3.6.3-1-3 CNS-0-MS-PS-300H MS-PS-300H NPPD047-CALC- Pressure A171P URL: 200 psig 008 Controls SR 3.3.7.1.3 3.3.7.1-1-1 CNS-1-NBI-LIS-57A [L2] NBI-LIS-57A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.7.1.3 3.3.7.1A1-1 CNS-2-NBI-LIS-57B [L2] NBI-LIS-57B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.7.1.3 3.3.7.1-1-1 CNS-1-NBI-LIS-58A [L2] NBI-LIS-58A NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.7.1.3 3.3.7.1-1-1 CNS-2-NBI-LIS-58B [L2] NBI-LIS-58B NPPD047-CALC- Yarway 4418C IR: -150 to +60 001 inches SR 3.3.7.1.3 3.3.7.1-1-2 CNS-1-PC-PS-12A PC-PS-12A NPPD047-CALC- Static O-Ring 12TA-BB4-NX-C1A- Adjustable Range:
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| 031 JJTTX6 0.5 to 6 psig SR 3.3.7.1.3 3.3.7.1-1-2 CNS-2-PC-PS-12B PC-PS-12B NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.7.1.3 3.3.7.1-1-2 CNS-1-PC-PS-12C PC-PS-12C NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.7.1.3 3.3.7.1-1-2 CNS-2-PC-PS-12D PC-PS-12D NPPD047-CALC- Static O-Ring 12TA-BB5-NX-C1A- Adjustable Range:
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| 037 JJTTX6 0.75 to 12 psig SR 3.3.8.1.2 3.3.8.1-1-1A CNS-1-EE-REL- 27-1 F1 EE-REL-27-1F1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to 140VAC SR 3.3.8.1.2 3.3.8.1-1-1A CNS-1-EE-REL- 27-1 FA1 EE-REL-27-1FAl NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to 140VAC SR 3.3.8.1.2 3.3.8.1-1-1 A CNS-3-EE-REL- 27-ET1 EE-REL-27-ET1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-1A CNS-2-EE-REL- 27-1G1 EE-REL-27-1G1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-1A CNS-2-EE-REL- 27-1GB1 EE-REL-27-1GB1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-1A CNS-3-EE-REL- 27-ET2 EE-REL-27-ET2 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to 140VAC SR 3.3.8.1.2 3.3.8.1-1-1B CNS-1 -EE-REL- 27-1 F1 EE-REL-27-1 F1 NPPD047-CALC- General Electric IAV-54E Adjustable Time
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| __ _028 Delay: .5 to 10
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| NLS2011071 Page 18 of 22
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| *TS-. . ' TS~Fnction ý F~unctidnaltLc-ation 1j) Functional Location. Calculi~tion . ahnufkcturer. d~N.a~ .~ Range SR 3.3.8.1.2 3.3.8.1-1-1B CNS-1-EE-REL- 27-1FA1 EE-REL-27-1FA1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 11 SR 3.3.8.1.2 3.3.8.1-1-1B CNS-3-EE-REL- 27-ET1 EE-REL-27-ET1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 12 SR 3.3.8.1.2 3.3.8.1-1-1B CNS-2-EE-REL- 27-1G1 EE-REL-27-1G1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 13 SR 3.3.8.1.2 3.3.8.1-1-1B CNS-2-EE-REL- 27-1GB1 EE-REL-27-1GB1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Dela : .5 to 14 SR 3.3.8.1.2 3.3.8.1-1 -1 B CNS-3-EE-REL- 27-ET2 EE-REL-27-ET2 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 15 SR 3.3.8.1.2 3.3.8.1-1-2A CNS-1-EE-REL- 27-1F1 EE-REL-27-1F1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-2A CNS-1-EE-REL- 27-1 FA1 EE-REL-27-1FA1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to 140VAC SR 3.3.8.1.2 3.3.8.1-1-2A CNS-3-EE-REL- 27-ET1 EE-REL-27-ET1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to 140VAC SR 3.3.8.1.2 3.3.8.1-1-2A CNS-2-EE-REL- 27-1G1 EE-REL-27-1G1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-2A CNS-2-EE-REL- 27-1GB1 EE-REL-27-1GB1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 tol40VAC SR 3.3.8.1.2 3.3.8.1-1-2A CNS-3-EE-REL- 27-ET2 EE-REL-27-ET2 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 tol 40VAC SR 3.3.8.1.2 3.3.8.1-1-2B CNS-1-EE-REL- 27-1 F1 EE-REL-27-1F1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 16 SR 3.3.8.1.2 3.3.8.1-1-2B CNS-1-EE-REL- 27-1FA1 EE-REL-27-1FA1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 17 SR 3.3.8.1.2 3.3.8.1-1-2B CNS-3-EE-REL- 27-ET1 EE-REL-27-ET1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 18 SR 3.3.8.1.2 3.3.8.1-1-2B CNS-2-EE-REL- 27-1G1 EE-REL-27-1G1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 19 SR 3.3.8.1.2 3.3.8.1-1-2B CNS-2-EE-REL- 27-1GB1 EE-REL-27-1GB1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 20 SR 3.3.8.1.2 3.3.8.1-1-2B CNS-3-EE-REL- 27-ET2 EE-REL-27-ET2 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 21 SR 3.3.8.1.2 3.3.8.1-1-3A CNS-1-EE-REL- 27-1F1 EE-REL-27-1 F1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to 140VAC SR 3.3.8.1.2 3.3.8.1-1-3A CNS-1-EE-REL- 27-1 FA1 EE-REL-27-1FA1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to 140VAC SR 3.3.8.1.2 3.3.8.1-1-3A CNS-3-EE-REL- 27-ET1 EE-REL-27-ET1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-3A CNS-2-EE-REL- 27-1G1 EE-REL-27-1G1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-3A CNS-2-EE-REL- 27-1GB1 EE-REL-27-1GB1 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 1 027 55 to140VAC
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| NLS2011071 Page 19 of 22 TS. ~~ TSFunction, Function~al Location (If) ~Functional Location Calculation , Manufactureri Model No, Range Surveillance-,.,.. K 7 2 SR 3.3.8.1.2 3.3.8.1-1-3A CNS-3-EE-REL- 27-ET2 EE-REL-27-ET2 NPPD047-CALC- General Electric IAV-54E Adjustable Range:
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| 027 55 to140VAC SR 3.3.8.1.2 3.3.8.1-1-3B CNS-1-EE-REL- 27-I F1 EE-REL-27-1F1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 22 SR 3.3.8.1.2 3.3.8.1-1-3B CNS-1-EE-REL- 27-I FAI EE-REL-27-1FA1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 23 SR 3.3.8.1.2 3.3.8.1-1-3B CNS-3-EE-REL- 27-ETI EE-REL-27-ET1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 24 SR 3.3.8.1.2 3.3.8.1-1-3B CNS-2-EE-REL- 27-1G1 EE-REL-27-1G1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 25 SR 3.3.8.1.2 3.3.8.1-1-3B CNS-2-EE-REL- 27-1GB1 EE-REL-27-1GB1 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 26 SR 3.3.8.1.2 3.3.8.1-1-3B CNS-3-EE-REL- 27-ET2 EE-REL-27-ET2 NPPD047-CALC- General Electric IAV-54E Adjustable Time 028 Delay: .5 to 27 SR 3.3.8.1.2 3.3.8.1-1-4A CNS-1-EE-REL- 27-1F2 EE-REL-27-1F2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1.2 3.3.8.1-1-4A CNS-1-EE-REL- 27-1FA2 EE-REL-27-1FA2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1.2 3.3.8.1-1-4A CNS-2-EE-REL- 27-1G2 EE-REL-27-1G2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1.2 3.3.8.1-1-4A CNS-2-EE-REL- 27-1GB2 EE-REL-27-1GB2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1.2 3.3.8.1-1-4B CNS-1-EE-REL- 27-1 F2 EE-REL-27-1 F2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-4B CNS-1-EE-REL- 27-1FA2 EE-REL-27-1FA2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-4B CNS-2-EE-REL- 27-1G2 EE-REL-27-1G2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-4B CNS-2-EE-REL- 27-1GB2 EE-REL-27-1GB2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-4C CNS-1-EE-REL- 27-1F2 EE-REL-27-1F2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-4C CNS-1-EE-REL- 27-1FA2 EE-REL-27-1FA2 NPPD047-CALC- ABB 27N Time Delay Range: 1 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-4C CNS-2-EE-REL- 27-1G2 EE-REL-27-1G2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec
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| NLS2011071 Page 20 of 22 is S.Function:
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| TS Functional Lo~cation (1) , Functional Location > Calculation Manufacturer~ Model No ~ Range.
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| SR 3.3.8.1.2 3.3.8.1-1-4C CNS-2-EE-REL- 27-1GB2 EE-REL-27-1GB2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-5A CNS-1-EE-REL- 27-1F2 EE-REL-27-1F2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1.2 3.3.8.1-1-5A CNS-1-EE-REL- 27-1FA2 EE-REL-27-1FA2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1.2 3.3.8.1-1-5A CNS-2-EE-REL- 27-1G2 EE-REL-27-1G2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1.2 3.3.8.1-1-5A CNS-2-EE-REL- 27-1GB2 EE-REL-27-1GB2 ABB 27N Pickup Range: 60 to NPPD047-CALC- 110 VAC 023 Dropout Range: 70 to 99%
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| SR 3.3.8.1,.2 3.3.8.1-1-5B CNS-1-EE-REL- 27-1F2 EE-REL-27-1F2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-5B CNS-1-EE-REL- 27-1FA2 EE-REL-27-1FA2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-5B CNS-2-EE-REL- 27-1G2 EE-REL-27-1G2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.1.2 3.3.8.1-1-5B CNS-2-EE-REL- 27-1GB2 EE-REL-27-1GB2 NPPD047-CALC- ABB 27N Time Delay Range: 1 024 to 10 sec SR 3.3.8.2.1A N/A CNS-1-RPS-EPA-1A1 RPS-EPA-1A1 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A N/A CNS-1-RPS-EPA-1A2 RPS-EPA-1A2 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A N/A CNS-1-RPS-EPA-1A3 RPS-EPA-1A3 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A N/A CNS-1-RPS-EPA-1A4 RPS-EPA-1A4 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B1 RPS-EPA-1B1 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B2 RPS-EPA-1B2 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B3 RPS-EPA-1B3 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B4 RPS-EPA-1B4 NPPD047-CALC- General Electric 914E175 na (OV) 006 SR 3.3.8.2.1A NIA CNS-1-RPS-EPA-IAI RPS-EPA-1AW NPPDO47-CALC- General Electric "914EI75 Timer Adj Range: .1 (TD) 1 007 1 to 4 sec
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| NLS2011071 Page 21 of 22
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| -T :S -Functio6n Functional Location~ (1)~ .'Fdfctidnal Lo'6atiarv Xoaculation , Manufacturer. Mo~del No. R'ange SR 3.3.8.2.1A N/A CNS-1-RPS-EPA-1A2 RPS-EPA-1A2 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1A N/A CNS-1-RPS-EPA-1A3 RPS-EPA-1A3 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1A N/A CNS-1-RPS-EPA-1A4 RPS-EPA-1A4 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B1 RPS-EPA-1B1 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B2 RPS-EPA-1B2 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B3 RPS-EPA-1B3 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1A N/A CNS-2-RPS-EPA-1B4 RPS-EPA-1B4 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A1 RPS-EPA-1A1 NPPD047-CALC- General Electric 914E175 na (UV) 005 SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A2 RPS-EPA-1A2 NPPD047-CALC- General Electric 914E175 na (UV) 005 SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A3 RPS-EPA-1A3 NPPD047-CALC- General Electric 914E175 na (UV) 005 SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A4 RPS-EPA-1A4 NPPD047-CALC- General Electric 914E175 na (UV) 005 SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1B1 RPS-EPA-1B1 NPPD047-CALC- General Electric 914E175 na (UV) 005 SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1B2 RPS-EPA-1B2 NPPD047-CALC- General Electric 914E175 na (UV) 005 SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1B3 RPS-EPA-1B3 NPPD047-CALC- General Electric 914E175 na (Uv) 005 SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1 B4 RPS-EPA-1B4 NPPD047-CALC- General Electric 914E175 na (UV) 005 SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A1 RPS-EPA-1A1 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A2 RPS-EPA-1A2 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A3 RPS-EPA-1A3 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TO) 007 to 4 sec SR 3.3.8.2.1B N/A CNS-1-RPS-EPA-1A4 RPS-EPA-1A4 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1B1 RPS-EPA-1B1 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1B2 RPS-EPA-1B2 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1B3 RPS-EPA-1B3 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec
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| NLS2011071 Page 22 of 22
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| *rS 3 TS Function~ Functionial Location (1). Functional[Location Calcul ,AtonY Manufacturer - ModelNo. > .RangeK j
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| >Su.rveiliahce:i. ~ (2).<
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| SR 3.3.8.2.1B N/A CNS-2-RPS-EPA-1B4 RPS-EPA-1B4 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A1 RPS-EPA-1A1 NPPD047-CALC- General Electric 914E175 na (UF) 004 SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A2 RPS-EPA-1A2 NPPD047-CALC- General Electric 914E175 na (UF) 004 SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A3 RPS-EPA-1A3 NPPD047-CALC- General Electric 914E175 na (UF) 004 SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A4 RPS-EPA-1A4 NPPD047-CALC- General Electric 914E175 na (UF) 004 SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B1 RPS-EPA-1B1 NPPD047-CALC- General Electric 914E175 na (UF) 004 SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B2 RPS-EPA-1B2 NPPD047-CALC- General Electric 914E175 na (UF) 004 SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B3 RPS-EPA-1B3 NPPD047-CALC- General Electric 914E175 na (UF) 004 SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B4 RPS-EPA-1B4 NPPD047-CALC- General Electric 914E175 na (UE) 004 SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A1 RPS-EPA-1A1 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A2 RPS-EPA-1A2 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A3 RPS-EPA-1A3 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-1-RPS-EPA-1A4 RPS-EPA-1A4 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B1 RPS-EPA-1B1 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B2 RPS-EPA-1B2 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B3 RPS-EPA-1B3 NPPD047-CALC- General Electric 914E175 Timer Adj Range: .1 (TD) 007 to 4 sec SR 3.3.8.2.1C N/A CNS-2-RPS-EPA-1B4 RPS-EPA-1B4 NPPD047-CALC- General Electric 914E175 TimerAdj Range: .1 (TD) 007 to 4 sec SR 3.6.1.7.3 N/A CNS-1-PC-DPIS-516A PC-DPIS-516A NPPD047-CALC- ITT Barton 289A Range: -2 to 2 psid 020
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| NLS2011071 Page 1 of 59 Enclosure 1 Instrument Drift Analysis Design Guide Cooper Nuclear Station, Docket No. 50-298, DPR-46
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| COOPER NUCLEAR STATION ENGINEERING EVALUATION No. 10-045 INSTRUMENT DRIFT ANALYSIS DESIGN GUIDE IN SUPPORT OF 24-MONTH FUEL CYCLE EXTENSION PROJECT Revision 1 Preparedby:
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| EXCEL Services Corporation 11921 Rockville Pike, Suite 100 Rockville, MD 20852 Prepared By: Kirk R. Melson - Date: 9-6-2011 Reviewed By: Jerry D. Voss ',! "7 -/ /. -' ~ate:
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| [D; 1/
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| Approved By: D-)ate:7
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 2 of 58 TABLE OF CONTENTS SECTION PAGE HISTO RY O F REVISIO NS ...................................................................................................................... 3
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| : 1. O BJECTIVE/PURPO SE ......................................................................................................................... 4
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| : 2. DRIFT A NA LYSIS SCO PE ..................................................................................................................... 4
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| : 3. DISCUSSIO N/M ETHO DO LO GY ..................................................................................................... 5 3.1. Methodology O ptions ............................................................................................................ 5 3.2. Data Analysis Discussion ......................................................................................................... 5 3.3. Tolerance Interval .......................................................................................................................... 7 3.4. Calibration Data Collection ............................................. 8 3.5. Categorizing Calibration Data ................................................................................................. 9 3.6. O utlier Analysis ........................................................................................................................... 13 3.7. Methods for Verifying Norm ality ............................................................................................. 15 3.8. Binomial Pass/Fail Analysis For Distributions Considered Not To Be Normal ....................... 20 3.9. Tim e-Dependent Drift Analysis ............................................................................................... 21 3.10. Calibration Point Drift ............................................................................................................. 24 3.11. Drift Bias Determ ination ........................................................................................................ 24 3.12. Tim e Dependent Drift Uncertainty ........................................................................................... 27 3.13. Methods of Drift Assessment for Very Low Sample Sizes. .... ....... ............. 28 3.14. Shelf Life of Analysis Results .................................................................................................. 30
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| : 4. PERFO RM ING A N A NA LYSIS ............................................................................................................ 30 4.1. Populating the Spreadsheet .................................................................................................... 31 4.2. Spreadsheet Perform ance of Basic Statistics ....................................................................... 32 4.3. O utlier Detection and Expulsion ............................................................................................. 34 4.4. Norm ality Tests ........................................................................................................................... 35 4.5. Tim e Dependency Testing ...................................................................................................... 35 4.6. Calculate the Analyzed Drift (DA) Value ................................................................................ 37
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| : 5. CA LCULATIO NS .................................................................................................................................. 39 5.1. Drift Calculations ......................................................................................................................... 39 5.2. Setpoint/Uncertainty Calculations .......................................................................................... 41
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| : 6. DEFINITIONS ........................................................................................................................................ 42
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| : 7. REFERENCES ...................................................................................................................................... 45 7.1. Industry Standards and Correspondence .............................................................................. 45 7.2. Calculations and Program s .................................................................................................... 45 7.3. Miscellaneous .............................................................................................................................. 45 Appendix A: Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-1 03335, "Guidelines for Instrument Calibration Extension/Reduction Programs" 13 pages
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 3 of 58 TABLES PAGE Table 1 - 95% /95% Tolerance Interval Factors ........................................................................................... 8 Table 2 - Critical Values for t-Test ................................................................................................................... 14 Table 3- Population Percentage for a Normal Distribution ........................................................................ 19 Table 4 - Percentiles of the t Distribution (to 025,df) .......................................................................................... 25 Record of Revision Rev. No. Description 0 Initial Issue 1 Removed second paragraph on page 58, regarding implementation of TSTF-493, to comply with current project direction.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision I Instrument Drift Analysis Design Guide Page 4 of 58
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| : 1. OBJECTIVE/PURPOSE The objective of this Design Guide is to provide the necessary detail and guidance to perform drift analyses using past calibration history data for the purposes of:
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| * Quantifying component/loop drift characteristics within defined probability limits to gain an understanding of the expected behavior for the component/loop by evaluating past performance
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| * Estimating component/loop drift for integration into setpoint calculations
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| * Analysis aid for reliability centered maintenance practices (e.g., optimizing calibration frequency) 0 Establishing a technical basis for extending calibration and surveillance intervals using historical calibration data
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| * Trending device performance based on extended surveillance intervals
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| : 2. DRIFT ANALYSIS SCOPE The scope of this design guide is limited to the calculation of the expected performance for a component, group of components or loop, utilizing past calibration data. Drift Calculations are the final product of the data analysis. The output from the Drift Calculations may be used directly as input to setpoint or loop accuracy calculations. However, ifdesired, the output may be compared to the design values used within setpoint and loop accuracy calculations to show that the existing design approach is conservative.
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| The approaches described within this design guide can be applied to all devices that are surveilled or calibrated where As-Found and As-Left data is recorded. The scope of this design guide includes, but is not limited to, the following list of devices:
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| * Transmitters (Differential Pressure, Flow, Level, Pressure, Temperature, etc.)
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| * Bistables (Master & Slave Trip Units, Alarm Units, etc.)
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| " Indicators (Analog, Digital)
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| " Switches (Differential Pressure, Flow, Level, Position, Pressure, Temperature, etc.)
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| " Signal Conditioners/Converters (Summers, E/P Converters, Square Root Converters, etc.)
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| " Recorders (Temperature, Pressure, Flow, Level, etc.)
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| " Monitors & Modules (Radiation, Neutron, H20 2 , Pre-Amplifiers, etc.)
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| " Relays (Time Delay, Undervoltage, Overvoltage, etc.)
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| Note that a given device or device type may be justified not to require drift analysis in accordance with this design guide, ifappropriate.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 5 of 58
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| : 3. DISCUSSION/METHODOLOGY 3.1. Methodology Options This design guide is written to provide the methodology necessary for the analysis of As-Found versus As-Left calibration data, as a means of characterizing the performance of a component or group of components via the following methods:
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| 3.1.1. Electric Power Research Institute (EPRI) has developed a guideline to provide nuclear plants with practical methods for analyzing historic component calibration data to predict component performance via a simple spreadsheet program (e.g., Excel, Lotus 1-2-3). This design guide is written in close adherence to this guideline, Reference 7.1.1. The Nuclear Regulatory Commission reviewed Revision 0 of Reference 7.1.1 and had a list of concerns documented in Reference 7.1.7. These concerns prompted the issuance of Revision 1 to Reference 7.1.1. In addition, Appendix A to this design guide addresses each concern individually and provides the Cooper Nuclear Station (CNS) resolution.
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| 3.1.2. Commercial Grade Software programs other than Microsoft Excel (e.g. Quattro Pro, Lotus 1-2-3, Mathcad, etc.), that perform the functions necessary to evaluate drift, may be utilized providing:
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| * the intent of this design guide is met as outlined in Reference 7.1.1, and
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| * software is used only as a tool to produce hard copy outputs which are to be independently verified.
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| 3.1.3. The final products of the data analyses are hard copy Drift Calculations. The electronic files of the Drift Calculations are an intermediate step from raw data to final product and are not controlled as QA files. The Drift Calculation is independently verified using different software than that used to create the Drift Calculation. The documentation of the review of the Drift Calculation will include a summary tabulation of results from each program used in the review process to provide visual evidence of the acceptability of the results of the review.
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| 3.2. Data Analysis Discussion The following data analysis methods were evaluated for use at CNS: 1) As-Found Versus Setpoint, 2) Worst Case As-Found Versus As-Left, 3) Combined Calibration Data Points Analysis, and 4) As-Found Versus As-Left. The evaluation concluded that the As-Found versus As-Left methodology provided results that were more representative of the data and has been chosen for use by this Design Guide. Statistical tests not covered by this design guide may be utilized, provided the Engineer performing the analysis adequately justifies the use of the tests.
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| 3.2.1. As-Found Versus As-Left Calibration Data Analysis The As-Found versus As-Left calibration data analysis is based on calculating drift by subtracting the previous As-Left component setting from the current As-Found setting.
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| Each calibration point is treated as an independent set of data for purposes of characterizing drift across the full, calibrated span of the component/loop. By evaluating As-Found versus As-Left data for a component/loop or a similar group of components/loops, the following information may be obtained:
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| * The typical component/loop drift between calibrations (Random in nature)
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| * Any tendency for the component/loop to drift in a particular direction (Bias)
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| * Any tendency for the component/loop drift to increase in magnitude over time (Time Dependency)
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 6 of 58
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| * Confirmation that the selected setting or calibration tolerance is appropriate or achievable for the component/loop 3.2.1.1. General Features of As-Found Versus As-Left Analysis
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| " The methodology evaluates historical calibration data only. The method does not monitor on-line component output; data is obtained from component calibration records.
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| " Present and future performance is predicted based on statistical analysis of past performance.
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| * Data is readily available from component calibration records. Data can be analyzed from plant startup to the present or only more recent data can be evaluated.
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| * Since only historical data is evaluated, the method is not intended as a tool to identify individual faulty components, although it can be used to demonstrate that a particular component model or application historically performs poorly.
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| " A similar class of components, i.e., same make, model, or application, is evaluated. For example, the method can determine the drift of all analog indicators of a certain type installed in the control room.
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| * The methodology is less suitable for evaluating the drift of a single component over time, due to statistical analysis penalties that occur with smaller sample sizes.
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| " The methodology obtains a value of drift for a particular model, loop, or function that can be used in component or loop uncertainty and setpoint calculations.
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| " The methodology is designed to support the analysis of longer calibration intervals and is consistent with the NRC expectations described in Reference 7.3.3. Values for instrument drift developed in accordance with this Design Guide are to be applied in accordance with References 7.2.2 and 7.2.3, as appropriate.
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| 3.2.1.2. Error and Uncertainty Content in As-Found Versus As-Left Calibration Data The As-Found versus the As-Left data includes several sources of uncertainty over and above component drift. The difference between As-Found and previous As-Left data encompasses a number of instrument uncertainty terms in addition to drift, as defined by References 7.2.2 and 7.2.3, the setpoint calculation methodologies for CNS. The drift is not assumed to encompass the errors associated with temperature effect, since the temperature difference between the two calibrations is not quantified, and is not anticipated to be significant. Additional instruction for the use of As-Found and As-Left data may be found in Reference 7.1.2. The following possible contributors could be included within the measured variation, but are not necessarily considered as such.
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| * Accuracy errors present between any two consecutive calibrations
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| " Measurement and test equipment error between any two consecutive calibrations
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| * Personnel-induced or human-related variation or error between any two consecutive calibrations
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1I Instrument Drift Analysis Design Guide Page 7 of 58
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| * Normal temperature effects due to a difference in ambient temperature between any two consecutive calibrations
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| * Power Supply variations between any two consecutive calibrations
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| * Environmental effects on component performance, e.g., radiation, humidity, vibration, etc., between any two consecutive calibrations that cause a shift in component output
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| * Misapplication, improper installation, or other operating effects that affect component calibration between any two consecutive calibrations
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| * True drift representing a change, time-dependent or otherwise, in component/loop output over the time period between any two consecutive calibrations 3.2.1.3. Potential Impacts of As-Found Versus As-Left Data Analysis Many of the bulleted items listed in step 3.2.1.2 are not expected to have a significant effect on the measured As-Found and As-Left settings. Because there are so many independent parameters contributing to the possible variance in calibration data, they are all considered together and termed the component's Analyzed Drift (DA) uncertainty. This approach has the following potential impacts on an analysis of the component's calibration data:
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| " The magnitude of the calculated variation may exceed any assumptions or manufacturer predictions regarding drift. Attempts to validate manufacturer's performance claims should consider the possible contributors listed in step 3.2.1.2 to the calculated drift.
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| " The magnitude of the calculated variation that includes all of the above sources of uncertainty may mask any "true" time-dependent drift. In other words, the analysis of As-Found versus As-Left data may not demonstrate any time dependency. This does not mean that time-dependent drift does not exist, only that it could be so small that it is negligible in the cumulative effects of component uncertainty, when all of the above sources of uncertainty are combined.
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| 3.3. Tolerance Interval This Design Guide recommends a single confidence interval level to be used for performing data analyses and the associated calculations.
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| NOTE: The default Tolerance Interval Factor (TIF) for all Drift Calculations, performed using this Design Guide, is chosen for a 95%/95% probability and confidence, although this is not specifically required in every situation. This term means that the results have a 95% confidence (y)that at least 95% of the population lies between the stated interval (P) for a sample size (n).
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| Extrapolating the drift value for the extended time between surveillance is based on the assumption that future drift values will also be within the calculated drift interval 95% of the time.
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| Components that perform functions that support a specific Technical Specification value, Technical Requirements Manual (TRM) value or are associated with the safety analysis assumptions or inputs are always analyzed at a 95%/95% tolerance interval.
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| Components/loops that fall into this level must:
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| " be included in the data group (or be justified to apply the results per the guidance of Reference 7.1.1) ifthe analyzed drift value is to be applied to the component/loop in a Setpoint/Uncertainty Calculation,
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| * use the 95/95% TIF for determination of the Analyzed Drift term, and (see step 3.4.2 and Table 1 - 95%/95%Tolerance Interval Factors)
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision I Instrument Drift Analysis Design Guide Page 8 of 58 be evaluated in the Setpoint/Uncertainty Calculation for application of the Analyzed Drift term. (For example, the DA term may include the normal temperature effects for a given device, but due to the impossibility of separating out that specific term, an additional temperature uncertainty may be included in the Setpoint/Uncertainty Calculation.)
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| 3.4. Calibration Data Collection 3.4.1. Sources of Data The sources of data to perform a drift analysis are Surveillance Tests, Calibration Procedures and other calibration processes (calibration files, calibration sheets for Balance of Plant devices, Preventative Maintenance, etc.).
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| 3.4.2. How Much Data to Collect 3.4.2.1. The goal is to collect enough data for the instrument or group of instruments to make a statistically valid pool. There is no hard fast number that must be attained for any given pool, but a minimum of 30 drift values must be attained before the drift analysis can be performed without additional justification. As a general rule, drift analyses should not be performed for sample sizes of less than 20 drift values. Table 1 provides the 95%/95% TIF for various sample pool sizes; it should be noted that the smaller the pool the larger the penalty. A tolerance interval is a statement of confidence that a certain proportion of the total population is contained within a defined set of bounds. For example, a 95%/95% TIF indicates a 95% level of confidence that 95% of the population is contained within the stated interval.
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| Table 1 - 95%/95%Tolerance Interval Factors (Per Table VII(a) of Ref 7.3.2)
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| Sample Size] 95%195% Sample Size [95%195% - Sample Size J95%/95%
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| >2 37.674 >_23 2.673 _ 120 2.205
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| Ž3 9.916 Ž24 2.651 Ž130 2.194
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| >4 6.370 Ž25 2.631 Ž>140 2.184
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| >_Ž5 5.079 Ž26 2.612 Ž150 2.175
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| >6 4.414 1 227 2.595 Ž160 2.167
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| >7 4.007 2!30 2.549 2!170 2.160
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| >8 3.732 _>35 2.490 Ž180 2.154
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| __9 3.532 >_40 2.445 Ž190 2.148
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| >10 3.379 > 45 2.408 >200 2.143
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| >11 3.259 > 50 2.379 Ž250 2.121
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| > 12 3.162 >_55 2.354 Ž300 2.106
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| Ž_13 3.081 Ž!60 2.333 Ž!400 2.084 2! 14 3.012 > 65 2.315 Ž 500 2.070 2! 15 2.954 Ž_70 2.299 2!600 2.060
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| _>16 2.903 2!75 2.285 Ž 700 2.052
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| _ 17 2.858 _80 2.272 Ž800 2.046
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| _>18 2.819 Ž85 2.261 Ž900 2.040
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| > 19 2.784 Ž>90 2.251 1000 2.036 2!20 2.752 > 95 2.241 0o 1.960
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| Ž21
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| > 2.723 Ž100 2.233
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| >22 2.697 Ž!110 2.218
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision i Instrument Drift Analysis Design Guide Page 9 of 58 3.4.2.2. Different information may be needed, depending on the analysis purpose, therefore, the total population of components - all makes, models, and applications that are to be analyzed must be known (e.g., all Rosemount transmitters).
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| 3.4.2.3. Once the total population of components is known, the components should be separated into functionally equivalent groups. Each grouping is treated as a separate population for analysis purposes. For example, start with all Rosemount Differential Pressure Transmitters as the initial group and break them down into various sub-groups - Different Range Codes, Large vs. Small Turn Down Factors (TDF), Level vs. Flow Applications, etc. Note that TDF is a significant quantity, since drift is specified as a percent of Upper Range Limit for Rosemount transmitters.
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| 3.4.2.4. Not all components or available calibration data points need to be analyzed within each group in order to establish statistical performance limits for the group. Acquisition of data should be considered from different perspectives.
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| For each grouping, a large enough sample of components should be randomly selected from the population, so there is assurance that the evaluated components are representative of the entire population. By randomly selecting the components and confirming that the behavior of the randomly selected components is similar, a basis for not evaluating the entire population can be established. For sensors, a random sample from the population should include representation of all desired component spans and functions.
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| * For each selected component in the sample, enough historic calibration data should be provided to ensure that the component's performance over time is understood.
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| * Due to the difficulty of determining the total sample set, developing specific sampling criteria is difficult. A sampling method must be used which ensures that various instruments calibrated at different frequencies are included. The sampling method must also ensure that the different component types, operating conditions and other influences on drift are included. Because of the difficulty in developing a valid sampling program, it is often simpler to evaluate all available data for the required instrumentation within the chosen time period. This eliminates changing sample methods, should groups be combined or split, based on plant conditions or performance. For the purposes of this guide, specific justification in the Drift Calculation is required to document any sampling plan.
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| 3.5. Categorizing Calibration Data 3.5.1. Grouping Calibration Data One analysis goal should be to combine functionally equivalent components (components with similar design and performance characteristics) into a single group.
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| In some cases, all components of a particular manufacturer make and model can be combined into a single sample. In other cases, virtually no grouping of data beyond a particular component make, model, and specific span or application may be possible.
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| Some examples of possible groupings include, but are not limited to, the following:
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| 3.5.1.1. Small Groupings All devices of same manufacturer, model and range, covered by the same Surveillance Test
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 10 of 58
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| * All trip units used to monitor a specific parameter (assuming that all trip units are the same manufacturer, model and range) 3.5.1.2. Larger Groupings
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| * All transmitters of a specific manufacturer, model that have similar spans and performance requirements
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| * All Foxboro Spec 200 isolators with functionally equivalent model numbers
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| * All control room analog indicators of a specific manufacturer and model 3.5.2. Rationale for Grouping Components into a Larger Sample
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| " A single component analysis may result in too few data points to make statistically meaningful performance predictions.
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| * Smaller sample sizes associated with a single component may unduly penalize performance predictions by applying a larger TIF to account for the smaller data set. Larger sample sizes reflect a greater understanding and assurance of representative data that in turn, reduces the uncertainty factor.
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| " Large groupings of components into a sample set for a single population ultimately allows the user to state the plant-specific performance for a particular make and model of component. For example, the user may state, "Main Steam Flow Transmitters have historically drifted by less than 1%", or "All control room indicators of a particular make and model have historically drifted by less than 1.5%".
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| * An analysis of smaller sample sizes is more likely to be influenced by non-representative variations of a single component (outliers).
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| * Grouping similar components together, rather than analyzing them separately, is more efficient and minimizes the number of separate calculations that must be maintained.
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| 3.5.3. Considerations When Combining Components into a Single Group Grouping components together into a sample set for a single population does not have to become a complicated effort. Most components can be categorized readily into the appropriate population. Consider the following guidelines when grouping functionally equivalent components together.
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| * Ifperformed on a type-of-component basis, component groupings should usually be established down to the manufacturer make and model, as a minimum. For example, data from Rosemount and Foxboro transmitters should not be combined in the same drift analysis. The principles of operation are different for the various manufacturers, and combining the data could mask some trend for one type of component. This said; it might be desirable to combine groups of components for certain calculations. If dissimilar component types are combined, a separate analysis of each component type should still be completed to ensure analysis results of the mixed population are not misinterpreted or misapplied.
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| " Sensors of the same manufacturer make and model, but with different calibrated spans or elevated zero points, can possibly still be combined into a single group.
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| For example, a single analysis that determines the drift for all Rosemount pressure transmitters installed onsite might simplify the application of the results.
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| Note that some manufacturers provide a predicted accuracy and drift value for a given component model, regardless of its span. However, the validity of combining components with a variation of span, ranging from tens of pounds to several thousand pounds, should be confirmed. As part of the analysis, the performance of components within each span should be compared to the
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 11 of 58 performance of the other devices to determine ifany differences are evident between components with different spans.
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| Components combined into a single group should be exposed to similar calibration or surveillance conditions, as applicable. Note that the term operating condition was not used in this case. Although it is desirable that the grouped components perform similar functions, the method by which the data is obtained for this analysis is also significant. Ifhalf the components are calibrated in the summer at 90°F and the other half in the winter at 40'F, a difference in observed drift between the data for the two sets of components might exist. In many cases, ambient temperature variations are not expected to have a large effect, since the components are located in environmentally controlled areas.
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| 3.5.4. Verification That Data Grouping Is Appropriate
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| " Combining functionally equivalent components into a single group for analysis purposes may simplify the scope of work; however, some level of verification should be performed to confirm that the selected component grouping is appropriate. As an example, the manufacturer may claim the same accuracy and drift specifications for two components of the same model, but with different ranges, e.g., 0-5 PSIG and 0-3000 PSIG. However, in actual application, components of one range may perform differently than components of another range.
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| " Standard statistics texts provide methods that can be used to determine ifdata from similar types of components can be pooled into a single group. Ifdifferent groups of components have essentially equal variances and means at the desired statistical level, the data for the groups can be pooled into a single group.
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| * When evaluating groupings, care must be taken not to split instrument groups only because they are calibrated on a different time frequency. Differences in variances may be indicative of a time dependent component to the device drift.
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| The separation of these groups may mask a time-dependency for the component drift.
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| * A t-Test (two samples assuming unequal variances) should also be performed on the proposed components to be grouped. The t-Test returns the probability associated with a Student's t-Test to determine whether two samples are likely to have come from the same two underlying populations that have unequal variances. Iffor example, the proposed group contains 5 sub-groups, the t-Tests should be performed on all possible combinations for the groupings. However, if there is no plausible engineering explanation for the two sets of data being incompatible, the groups should be combined, despite the results of the t-Test.
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| The following formula is used to determine the test statistic value t.
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| S= X - T2 - A0 (Ref. 7.3.1) 2 SI + S 2 F2 n, n2 Where ;
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| t - test statistic n - Total number of data points x - Mean of the samples s2 - Pooled variance Ao - Hypothesized mean difference
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 12 of 58 The following formula is used to estimate the degrees of freedom (df) for the test statistic.
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| 2
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| +
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| df = n n2 n2 2 S2 n,1 + n2 n,-1 n 2 -1 Where; Values are as previously defined.
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| The t-Test may be performed using the t-Test: Two-Sample Assuming Unequal Variances analysis tool within Microsoft Excel. The Microsoft Excel output will look similar to the following:
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| t-Test: Two-Sample Assuming Unequal Variances Variable I Variable 2 Mean -0.017045 0.08413462 Variance 0.1008523 0.31185697 Observations 11 26 Hypothesized Mean Difference 0 df 32 t Stat -0.695517 P(T<=t) one-tail 0.245876 t Critical one-tail 1.6938887 P(T<=t) two-tail 0.4917521 t Critical two-tail 2.0369333 A comparison is made to determine whether the proposed groups of data can be combined for analysis. The t distribution is two-sided in this case, and therefore the t Critical two-tail is used as the criterion. Ifthe absolute value of the t statistic (t Stat) is less than the t Critical two-tail value, then the data can be considered to have very similar means, and can be considered acceptable for combination on that basis.
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| 3.5.5. Examples of Proven Groupings:
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| * All control room indicators receiving a 4-2OmAdc (or 1-5Vdc) signal. Notice that a combined grouping may be possible even though the indicators have different indication spans. For example, a 12 mAdc signal should move the indicator pointer to the 50% of span position on each indicator scale, regardless of the span indicated on the face plate (exceptions are non-linear meter scales).
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| " All control room bistables of similar make or model tested quarterly for Technical Specification surveillance. Note that this assumes that all bistables are tested in a similar manner and have the same input range, e.g., a 1-5Vdc or 4-20mAdc spans.
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| * A specific type of pressure transmitter used for similar applications in the plant in which the operating and calibration environment does not vary significantly between applications or location.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 13 of 58 A group of transmitters of the same make and model, but with different spans, given that a review confirms that the transmitters of different spans have similar performance characteristics.
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| 3.5.6. Using Data from Other Nuclear Power Plants:
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| * It is acceptable, although not recommended, to pool CNS specific data with data obtained from other nuclear power plants, providing the data can be verified to be of high quality. In this case the data must also be verified to be acceptable for grouping. Acceptability may be defined by verification of grouping, and an evaluation of calibration procedure methods, Measurement and Test Equipment used, and defined setting tolerances. Where there is agreement in calibration method (for instance, starting at zero increasing to 100 percent and decreasing to zero, taking data every 25%), calibration equipment, and area environment (if performance is affected by the temperature), there is a good possibility that the groups may be combined. Previously collected industry data may not have sufficient information about the manner of collection to allow combination with plant specific data.
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| 3.6. Outlier Analysis An outlier is a data point significantly different in value from the rest of the sample. The presence of an outlier or multiple outliers in the sample of component or group data may result in the calculation of a larger than expected sample standard deviation and tolerance interval.
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| Calibration data can contain outliers for several reasons. Outlier analyses can be used in the initial analysis process to help to identify problems with data that require correction. Examples include:
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| * Data TranscriptionErrors- Calibration data can be recorded incorrectly either on the original calibration data sheet or in the spreadsheet program used to analyze the data.
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| " CalibrationErrors- Improper setting of a device at the time of calibration would indicate larger than normal drift during the subsequent calibration.
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| * Measuring & Test Equipment Errors- Improperly selected or mis-calibrated test equipment could indicate drift, when little or no drift was actually present.
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| * Scaling or Setpoint Changes - Changes in scaling or setpoints can appear in the data as larger than actual drift points unless the change is detected during the data entry or screening process.
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| Failed Instruments - Calibrations are occasionally performed to verify proper operation due to erratic indications, spurious alarms, etc. These calibrations may be indicative of component failure (not drift), which would introduce errors that are not representative of the device performance during routine conditions.
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| Design or Application Deficiencies - An analysis of calibration data may indicate a particular component that always tends to drift significantly more than all other similar components installed in the plant. Inthis case, the component may need an evaluation for the possibility of a design, application, or installation problem. Including this particular component in the same population as the other similar components may skew the drift analysis results.
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| 3.6.1. Detection of Outliers There are several methods for determining the presence of outliers. This design guide utilizes the Critical Values for t-Test (Extreme Studentized Deviate). The t-Test utilizes the values listed in Table 2 with an upper significance level of 5% to compare a given data point against. Note that the critical value of t increases as the sample size
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1I Instrument Drift Analysis Design Guide Page 14 of 58 increases. This signifies that as the sample size grows, it is more likely that the sample is truly representative of the population. The t-Test assumes that the data is normally distributed.
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| Table 2 - Critical Values for t-Test Sample Size Upper 5% Sample Size Upper 5%
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| Level Significance Level Significance
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| -<3 1.15 22 2.60 4 1.46 23 2.62 5 1.67 24 2.64 6 1.82 25 2.66 7 1.94 *30 2.75
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| : 8. 2.03 _ 35 2.82 9 2.11 <40 2.87 10 2.18 <45 2.92 11 2.23 *50 2.96 12 2.29 *60 3.03 13 2.33 < 70 3.09 14 2.37 < 75 3.10 15 2.41 < 80 3.14 16 2.44 *<90 3.18 17 2.47 *100 3.21 18 2.50 *125 3.28 19 2.53 *150 3.33 20 2.56 >150 4.00 21 2.58 3.6.2. t-Test Outlier Detection Equation t xi -x (Ref. 7.1.1)
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| S Where; Xi - An individual sample data point X - Mean of all sample data points s - Standard deviation of all sample data points t - Calculated value of extreme studentized deviate that is compared to the critical value of t for the sample size.
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| 3.6.3. Outlier Expulsion This design guide does not permit multiple outlier tests or passes. The removal of poor quality data as listed in Section 3.6 is not considered removal of outliers, since it is merely assisting in identifying data errors. However, after removal of poor quality data as listed in Section 3.6, certain data points can still appear as outliers when the outlier analysis is performed. These "unique outliers" are not consistent with the other data collected; and could be judged as erroneous points, which tend to skew the representation of the distribution of the data. However, for the general case, since these outliers may accurately represent instrument performance, only one (1) additional unique outlier (as indicated by the t-Test), may be removed from the drift data. After removal of poor quality data and the removal of the unique outlier (if necessary), the remaining drift data is known as the Final Data Set.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 15 of 58 For transmitters or other devices with multiple calibration points, the general process is to use the calibration point with the worst-case drift values. This is determined by comparing the different calibration points and using the one with the largest error, determined by adding the absolute value of the drift mean to 2 times the drift standard deviation. The data set with the largest of those terms is used throughout the rest of the analysis, after outlier removal, as the Final Data Set. (Note that it is possible to use a specific calibration point and neglect the others, nly if that is the single point of concern for application of the results of the Drift Calculation. If so, this fact should be stated boldly in the results / conclusions of the calculation.)
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| The data set basic statistics (i.e., the Mean, Median, Standard Deviation, Variance, Minimum, Maximum, Kurtosis, Skewness, Count and Average Time Interval between Calibrations) should be computed and displayed for the data set prior to removal of the unique outlier and for the Final Data Set, if different.
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| 3.7. Methods for Verifying Normality A test for normality can be important because many frequently used statistical methods are based upon an assumption that the data is normally distributed. This assumption applies to the analysis of component calibration data also. For example, the following analyses may rely on an assumption that the data is normally distributed:
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| * Determination of a tolerance interval that bounds a stated proportion of the population based on calculation of mean and standard deviation
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| * Identification of outliers
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| * Pooling of data from different samples into a single population The normal distribution occurs frequently and is an excellent approximation to describe many processes. Testing the assumption of normality is important to confirm that the data appears to fit the model of a normal distribution, but the tests do not prove that the normal distribution is a correct model for the data. At best, it can only be found that the data is reasonably consistent with the characteristics of a normal distribution, and that the treatment of a distribution as normal is conservative. For example, some tests for normality only allow the rejection of the hypothesis that the data is normally distributed. A group of data passing the test does not mean the data is normally distributed; it only means that there is no evidence to say that it is not normally distributed. However, because of the wealth of industry evidence that drift can be conservatively represented by a normal distribution, a group of data passing these tests is considered as normally distributed without adjustments to the standard deviation of the data set.
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| Distribution-free techniques are available when the data is not normally distributed; however, these techniques are not as well known and often result in penalizing the results by calculating tolerance intervals that are substantially larger than the normal distribution equivalent. Because of this fact, there is a good reason to demonstrate that the data is normally distributed or can be bounded by the assumption of normality.
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| Analytically verifying that a sample appears to be normally distributed usually invokes a form of statistics known as hypothesis testing. In general, a hypothesis test includes the following steps:
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| : 1) Statement of the hypothesis to be tested and any assumptions
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| : 2) Statement of a level of significance to use as the basis for acceptance or rejection of the hypothesis
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| : 3) Determination of a test statistic and a critical region
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| : 4) Calculation of the appropriate statistics to compare against the test statistic
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| : 5) Statement of conclusions
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 16 of 58 The following sections discuss various ways in which the assumption of normality can be verified to be consistent with the data or can be claimed to be a conservative representation of the actual data. Analytical hypothesis testing and subjective graphical analyses are discussed.
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| Ifthe analytical hypothesis test (either Chi-Squared or D Prime / W Test) are passed, the coverage analysis and additional graphical analyses are not required. Generally, only a single hypothesis test should be performed on a given data set. Because of the consistent approach given for the D Prime and W tests from Reference 7.1.4, these tests are recommended.
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| However, use of the Chi-Squared test is allowed in place of the D Prime or W Test, ifdesired.
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| The following are descriptions of the methods for assessing normality.
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| 3.7.1. Chi-Squared, x2, Goodness of Fit Test This well-known test is stated as a method for assessing normality in References 7.1.1 and 7.1.2. The x2 test compares the actual distribution of sample values to the expected distribution. The expected values are calculated by using the normal mean and standard deviation for the sample. If the distribution is normally or approximately normally distributed, the difference between the actual versus expected values should be very small. And, if the distribution is not normally distributed, the differences should be significant.
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| 3.7.1.1. Equations to Perform the x2 Test
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| : 1) First calculate the mean for the sample group
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| - Xi (Ref. 7.1.1) n Where; Xi - An individual sample data point X - Mean of all sample data points n - Total number of data points
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| : 2) Second calculate the standard deviation for the sample group s= X (I X) (Ref. 7.1.1)
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| Where; x - Sample data values (xl, x2, x3 ......
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| s - Standard deviation of all sample data points n - Total number of data points
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| : 3) Third the data must be divided into bins to aid in determination of a normal distribution. The number of bins selected is up to the individual performing the analysis. Refer to Reference 7.1.1 for further guidance. For most applications, a 12-bin analysis is performed on the drift data. See Section 4.4.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 17 of 58
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| : 4) Fourth calculate the x2 value for the sample group X2 *(O -Ei)2 Ei= NPi Ei =(Ref. 7.1.1)
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| Where; Ei - Expected values for the sample N - Total number of samples in the population Pi - Probability that a given sample is contained in a bin Oi - Observed sample values (O1, 02, 03 ......
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| x2 - Chi squared result
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| : 5) Fifth, calculate the degrees of freedom. The degrees of freedom term is computed as the number of bins used for the chi-square computation minus the constraints. In all cases for these Drift Calculations, since the count, mean and standard deviation are computed, the constraints term is equal to three.
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| : 6) Sixth, compute the Chi squared per degree of freedom term (X02). This term is merely the Chi squared term computed in step 4 above, divided by the degrees of freedom.
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| : 7) Finally, evaluate the results. The results are evaluated in the following manner, as prescribed in Reference 7.1.1. Ifthe Chi squared result computed in step 4 is less than or equal to the degrees of freedom, the assumption that the distribution is normal is not rejected. Ifthe value from step 4 is greater than the degrees of freedom, then one final check is made.
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| The degrees of freedom and X02 are used to look up the probability of obtaining a X02 term greater than the observed value, in percent. (See Table C-3 of Reference 7.1. 1.) Ifthe lookup value is greater than or equal to 5%,
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| then the assumption of normality is not rejected. However, ifthe lookup value is less than 5%, the assumption of normality is rejected.
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| 3.7.2. W Test Reference 7.1.4 recommends this test for sample sizes less than or equal to 50. The W Test calculates a test statistic value for the sample population and compares the calculated value to the critical values for W, which are tabulated in Reference 7.1.4.
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| The W Test is a lower-tailed test. Thus ifthe calculated value of W is less than the critical value of W, the assumption of normality would be rejected at the stated significance level. Ifthe calculated value of W is larger than the critical value of W, there is no evidence to reject the assumption of normality. Reference 7.1.4 establishes the methods and equations required for performing a W Test.
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| 3.7.3. D-Prime Test Reference 7.1.4 recommends this test for moderate to large sample sizes, greater than
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| : 50. The D' Test calculates a test statistic value for the sample population and compares the calculated value to the values for the D' percentage points of the distribution, which are tabulated in Reference 7.1.4. The D' Test is two-sided, which means that the two-sided percentage limits at the stated level of significance must envelop the calculated D' value. For the given sample size, the calculated value of D' must lie within the two values provided in the Reference 7.1.4 table in order to accept the hypothesis of normality.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 18 of 58 3.7.3.1. Equations to Perform the D' Test
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| : 1) First, calculate the linear combination of the sample group. (Note: Data must be placed in ascending order of magnitude, prior to the application of this formula.)
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| (Ref. 7.1.4)
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| Where; T - Linear combination xi - An individual sample data point i - The number of the sample point n - Total number of data points
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| : 2) Second, calculate the S2 for the sample group.
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| 2 s 2 =(n_1)S (Ref. 7.1.4)
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| Where; S2 - Sum of the Squares about the mean s2 - Unbiased estimate of the sample population variance n - Total number of data points
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| : 3) Third, calculate the D' value for the sample group.
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| T (Ref. 7.1.4)
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| S
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| : 4) Finally, evaluate the results. If the D' value lies within the acceptable range of results (for the given data count) per Table 5 of Reference 7.1.4, for columns showing Probability (P) = 0.025 and 0.975, then the assumption of normality is not rejected. (These values of P were chosen to obtain a 5%
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| significance, ct, for the test.) (If the exact data count is not contained within the tables, the critical value limits for the D' value should be linearly interpolated to the correct data count.) If however, the value lies outside that range, the assumption of normality is rejected.
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| 3.7.4. Probability Plots For most Drift Calculations performed per this methodology, probability plots will not be included, since numerical methods or coverage analyses are recommended. However, probability plots are discussed, since a graphical presentation of the data can sometimes reveal possible reasons for why the data is or is not normal. A probability plot is a graph of the sample data with the axes scaled for a normal distribution. If the data is normal, the data tends to follow a straight line. If the data is non-normal, a nonlinear shape should be evident from the graph. This method of normality determination is subjective, and is not required if the numerical method shows the data to be normal, or if a coverage analysis is used. The types of probability plots used by this design guide are as follows:
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 19 of 58
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| * Cumulative ProbabilityPlot - an XY scatter plot of the Final Data Set plotted against the percent probability (Pi) for a normal distribution. Pi is calculated using the following equation:
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| = 1Pi ( (Ref. 7.1.1) n where; i = sample number i.e. 1,2,....
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| n = sample size NOTE: Refer, as necessary, to Appendix C Section C.4 of Reference 7.1.1.
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| " Normalized ProbabilityPlot - an XY scatter plot of the Final Data Set plotted against the probability for a normal distribution, expressed in multiples of the standard deviation.
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| 3.7.5. Coverage Analysis A coverage analysis is recommended for cases in which the hypothesis tests reject the assumption of normality, but the assumption of normality is still a conservative representation of the data. The coverage analysis involves the use of a histogram of the Final Data Set, overlaid with the equivalent probability distribution curve for the normal distribution, based on the data sample's mean and standard deviation.
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| Visual examination of the plot is used to determine if the distribution of the data is near normal, or if a normal distribution model for the data would adequately cover the data within the 2 sigma limits. Another measure of the conservatism in the use of a normal distribution as a model is the kurtosis of the data. Reference 7.1.1 states that samples that have a large value of kurtosis are the most likely candidates for a coverage analysis. Kurtosis characterizes the relative peakedness or flatness of the distribution compared to the normal distribution, and is readily calculated within statistical and spreadsheet programs. As shown in Reference 7.1.1, a positive kurtosis indicates a relatively high peaked distribution, and a negative kurtosis indicates a relatively flat distribution, with respect to the normal distribution.
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| If the data is near normal or is more peaked than a normal distribution (positive kurtosis), then a normal distribution model is derived, which adequately covers the set of drift data, as observed. This normal distribution is used as the model for the drift of the device. Sample counting is used to determine an acceptable normal distribution model. The Standard Deviation of the group is computed. The number of samples that are within +/- two Standard Deviations of the mean is computed. The count is divided by the total number of samples in the group to determine a percentage. The following table provides the percentage that should fall within the two Standard Deviation values for a normal distribution.
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| Table 3 - Population Percentage for a Normal Distribution Percentage for a Normal Distribution 2 Standard Deviations 1 95.45%
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 20 of 58 If the percentage of data within the two standard deviations tolerance is greater than the value in Table 3 for a given data set, the existing standard deviation is acceptable to be used for the encompassing normal distribution model. However, if the percentage is less than required, the standard deviation of the model is enlarged, such that greater than or equal to the required percentage falls within the +/- two Standard Deviations bounds. The required multiplier for the standard deviation in order to provide this coverage is termed the Normality Adjustment Factor (NAF). If no adjustment is required, the NAF is equal to one (1).
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| 3.8. Binomial Pass/Fail Analysis For Distributions Considered Not To Be Normal A pass/fail criteria for component performance simply compares the As-Found versus As-Left surveillance drift data against a pre-defined acceptable value of drift. If the drift value is less than the pass/fail criteria, that data point passes; if it is larger than the pass/fail criteria, it fails.
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| By comparing the total number of passes to the number of failures, a probability can be computed for the expected number of component passes in the population. Note that the term failure in this instance does not mean that the component actually failed, only that it exceeded the selected pass/fail criteria for the analysis. Often the pass/fail criteria will be established at a point that clearly demonstrates acceptable component performance. The equations used to determine the Failure Proportion, Normal, Minimum and Maximum Probabilities are as follows:
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| Failure Proportion Pf = x/n where; x = Number of values exceeding the pass/fail criteria (Failures) (Ref. 7.1.1) n = Total number of drift values in the sample Normal Probability that a value will pass P = 1-Pf (Ref. 7.1.1)
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| Minimum Probability that a value will pass x
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| P1 =1---zx -)Xx1- (Ref. 7.1.1)
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| Maximum Probability that a value will pass x
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| = 1---+ZX l (Ref. 7.1.1) nn where; P, = the minimum probability that a value will pass Pu = the maximum probability that a value will pass Z = the standardized normal distribution value corresponding to the desired confidence level, e.g., z = 1.96 for a 95% confidence level.
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| The Binomial Pass/Fail Analysis is a good tool for verifying that drift values calculated for calibration extensions are appropriate for the interval. See Reference 7.1.1 for the necessary detail to perform a pass/fail analysis.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 21 of 58 3.9. Time-Dependent Drift Analysis The component/loop drift calculated in the previous sections represented a predicted performance limit, without any consideration of whether the drift may vary with time between calibrations or component age. This section discusses the importance of understanding the time-related performance and the impact of any time-dependency on an analysis.
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| Understanding the time dependency can be either important or unimportant, depending on the application. A time dependency analysis is important whenever the drift analysis results are intended to support an extension of calibration intervals.
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| 3.9.1. Limitations of Time Dependency Analyses Reference 7.1.1 performed drift analysis for numerous components at several nuclear plants as part of the project. The data evaluated did not demonstrate any significant time-dependent or age-dependent trends. Time dependency may have existed in all of the cases analyzed, but was insignificant in comparison to other uncertainty contributors. Because time dependency cannot be completely ruled out, there should be an ongoing evaluation to verify that component drift continues to meet expectations whenever calibration intervals are extended.
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| 3.9.2. Scatter (Drift Interval) Plot A drift interval plot is an XY scatter plot that shows the Final Data Set plotted against the time interval between tests for the data points. This plot method relies upon the human eye to discriminate the plot for any trend in the data to exhibit time dependency.
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| A prediction line can be added to this plot which shows a "least squares" fit of the data over time. This can provide visual evidence of an increasing or decreasing mean over time, considering all drift data. An increasing standard deviation is indicated by a trend towards increasing "scatter" over the increased calibration intervals.
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| 3.9.3. Standard Deviations and Means at Different Calibration Intervals (Binning Analysis)
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| This analysis technique is the most recommended method of determining time dependent tendencies in a given sample pool. (See Reference 7.1.1.) The test consists simply of segregating the drift data into different groups (Bins) corresponding to different ranges of calibration or surveillance intervals and comparing the standard deviations and means for the data in the various groups. The purpose of this type of analysis is to determine ifthe standard deviation or mean tends to become larger as the time interval between calibrations increases.
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| 3.9.3.1. The available data is placed in interval bins. The intervals normally used at CNS coincide with Technical Specification calibration intervals plus the allowed tolerance as follows:
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| : a. 0 to 45 days (covers most weekly and monthly calibrations)
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| : b. 46 to 135 days (covers most quarterly calibrations)
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| : c. 136 to 230 days (covers most semi-annual calibrations)
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| : d. 231 to 460 days (covers most annual calibrations)
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| : e. 461 to 690 days (covers most 18 month refuel cycle calibrations)
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| : f. 691 to 915 days (covers most extended refuel cycle calibrations)
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| : g. > 915 days covers missed and forced outage refueling cycle calibrations.
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| Data will naturally fall into these time interval bins based on the calibration requirements for the subject instrument loops. Only on occasion will a device be calibrated on a much longer or shorter interval than that of the rest of the
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 22 of 58 population within its calibration requirement group. Therefore, the data will naturally separate into groups for analysis.
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| 3.9.3.2. Although not generally recommended, different bin splits could be used, but must be evaluated for data coverage, significant diversity in calibration intervals, and acceptable data groupings.
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| 3.9.3.3. For each bin where there is data, the mean (average), standard deviation, average time interval and data count will be computed.
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| 3.9.3.4. To determine iftime dependency does or does not exist, the data must be distributed across multiple bins, with a sufficient population of data in each of two or more bins, to consider the statistical results for those bins to be valid.
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| Normally the minimum expected distribution that would allow evaluation is defined below.
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| : a. A bin is considered valid in the final analysis if it holds more than five data points and more than ten percent of the total data count.
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| : b. At least two bins, including the bin with the most data, must be left for evaluation to occur.
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| The distribution percentages listed in these criteria are somewhat arbitrary, and thus engineering evaluation can modify them for a given situation.
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| The mean and standard deviations of the valid bins are plotted versus average time interval on a diagram. This diagram can give a good visual indication of whether or not the mean or standard deviation of a data set is increasing significantly over time interval between calibrations.
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| Ifthe binning analysis plot shows an increase in standard deviation over time, the critical value of the F-distribution is compared to the ratio of the smallest and largest variances for the evaluated bins. Ifthe ratio of variances exceeds the critical value, this result is indicative of time dependency for the random portion of drift. Likewise, a ratio of variances not exceeding the critical value is not indicative of significant time dependency.
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| NOTE: If multiple valid bins do NOT exist for a given data set, then the plot is not to be shown, and the regression analyses are not to be performed. The reasoning is that there is not enough diversity in the calibration intervals analyzed to make meaningful conclusions about time dependency from the existing data. Unless overwhelming evidence to the contrary exists in the scatter plot, the single bin data set is treated as moderately time dependent for the purposes of extrapolation of the drift value.
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| 3.9.4. Regression Analyses and Plots Regression Analyses can often provide very valuable data for the determination of time dependency. A standard regression analysis within an EXCEL spreadsheet can plot the drift data versus time, with a prediction line showing the trend. Itcan also provide Analysis of Variance (ANOVA) table printouts, which contain information required for various numerical tests to determine level of dependency between two parameters (time and drift value). Note that regression analyses are only to be performed if multiple valid bins are determined from the binning analysis.
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| Regression Analyses are to be performed on the Final Data Set drift values and on the Absolute Value of the Final Data Set drift values. The Final Data Set drift values show trends for the mean of drift, and the Absolute Values show trends for the standard deviation over time.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 23 of 58 Regression Plots The following are descriptions of the two plots generated by these regressions.
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| " Drift Regression - an XY scatter plot that fits a line through the final drift data, plotted against the time interval between tests for the data points, using the "least squares" method to predict values for the given data set. The predicted line is plotted through the actual data for use in predicting drift over time. It is important to note that statistical outliers can have a dramatic effect upon the regression line.
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| * Absolute Value Drift Regression - an XY scatter plot that fits a line through the Absolute Value of the final drift data, plotted against the time interval between tests for the data points, using the "least squares" method to predict values for the given data set. The predicted line is plotted through the actual data for use in predicting drift, in either direction, over time. It is important to note that statistical outliers can have a dramatic effect upon the regression line.
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| Regression Time Dependency Analytical Tests Typical spreadsheet software includes capabilities to include ANOVA tables with regression analyses. ANOVA tables give various statistical data, which can allow certain numerical tests to be employed, to search for time dependency. For each of the two regressions (drift regression and absolute value drift regression), the following ANOVA parameters are used to determine if time dependency of the drift data is evident. All tests listed should be evaluated, and if time dependency is indicated by any of the tests, the data should be considered as time dependent.
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| * R Squared Test - The R Squared value, printed out in the ANOVA table, is a relatively good indicator of time dependency. If the value is greater than 0.09 (thereby indicating the R value greater than 0.3), then it appears that the data closely conforms to a linear function, and therefore, should be considered time dependent.
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| * P Value Test - A P Value for X Variable 1 (as indicated by the ANOVA table for an EXCEL spreadsheet) less than 0.05 is indicative of time dependency.
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| * Significance ofF Test - An ANOVA table F value greater than the critical F-table value would indicate a time dependency. In an EXCEL spreadsheet, the FINV function can be used to return critical values from the F distribution. To return the critical value of F, use the significance level (in this case 0.05 or 5.0%) as the probability argument to FINV, 2 as the numerator degrees of freedom, and the data count minus two as the denominator. If the F value in the ANOVA table exceeds the critical value of F, then the drift is considered time dependent.
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| NOTE: For each of these tests, if time dependency is indicated, the plots should be observed to determine the reasonableness of the result. The tests above generally assess the possibility that the function of drift is linear over time, not necessarily that the function is significantly increasing over time. Time dependency can be indicated even when the plot shows the drift to remain approximately the same or decrease over time.
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| Generally, a decreasing drift over time is not expected for instrumentation, nor is a case where the drift function crosses zero. Under these conditions, the extrapolation of the drift term would normally be established assuming no time dependency, if extrapolation of the results is required beyond the analyzed time intervals between calibrations.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 24 of 58 3.9.5. Additional Time Dependency Analyses Instrument Resetting Evaluation - For data sets that consist of a single calibration interval the time dependency determination may be accomplished simply by evaluating the frequency at which instruments require resetting. This type of analysis is particularly useful when applied to extend quarterly Technical Specification surveillances to semi-annual. However, this type of analysis is less useful for instruments such as sensors or relays that may be reset at each calibration interval, regardless of whether the instrument was already in calibration.
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| The Instrument Resetting Evaluation may be performed only if the devices in the sample pool are shown to be stable, not requiring adjustment (i.e. less than 5% of the data shows that adjustments were made). Care also must be taken when mechanical connections or flex points may be exercised by the act of checking calibration (actuation of a bellows or switch movement), where the act of checking the actuation point may have an effect on the next reading. Methodology for calculating the drift is as follows:
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| Quarterly As-Found/As-Left (As-Found Current Calibration - As-Left Previous Calibration) orAF 1- AL 2 (Ref. 7.1.1)
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| Semi-Annual As-Found/As-Left using Monthly Data (AF1 -AL 2 ) + (AF 2 - AL 3) (Ref. 7.1.1) 3.9.6. Age-Dependent Drift Considerations Age-dependency is the tendency for a component's drift to increase in magnitude as the component ages. This can be assessed by plotting the As-Found value for each calibration minus the previous calibration As-Left value of each component over the period of time for which data is available. Random fluctuations around zero may obscure any age-dependent drift trends. By plotting the absolute values of the As-Found versus As-Left calibration data, the tendency for the magnitude of drift to increase with time can be assessed. This analysis is generally not performed as a part of a standard Drift Calculation, but can be used, if desired, when establishing maintenance practices.
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| 3.10. Calibration Point Drift For devices with multiple calibration points (e.g., transmitters, indicators, etc.) the Drift-Calibration Point Plot is a useful tool for comparing the amount of drift exhibited by the group of devices at the different calibration points. The plot consists of a line graph of tolerance interval as a function of calibration point. This is useful to understand the operation of an instrument, but is not normally included as a part of a standard Drift Calculation.
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| 3.11. Drift Bias Determination If an instrument or group of instruments consistently drifts predominately in one direction, the drift is assumed to have a bias. The application of a significant bias must be considered separately, so that the overall treatment of the analyzed drift remains conservative. Based on Sections 3.5 and 3.5.2 of Reference 7.3.2, a method is used to assess whether or not a significant bias exists for the drift data, based on the relative magnitudes of the mean and standard deviation and the sample size. Specifically, when the absolute value of the calculated average for the sample pool exceeds a critical value (Xcrit), the average is treated as a bias to the drift term. Otherwise, the drift bias term is considered insignificant and is not considered further in the drift analysis.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 25 of 58 The critical value (Xcrit) for a given standard deviation (s) and sample size (n) is calculated using the following formula:
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| S Xcrit ----tO.025,df X - (Ref. 7.3.2)
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| Where; Xjt = Maximum value of non-biased mean for a given s & n t.o25,df = Normal Deviate for a single-sided t-distribution @ 0.025 for 95% Confidence (See Table 4) s = Standard Deviation of sample pool n = Sample pool size df = Degrees of Freedom = n - 1 The normal deviate (t) can be looked up for a given value of degrees of freedom, or it can be generated automatically, utilizing the TINV function within Microsoft Excel, as follows.
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| t.025,df = TINV (0.05, df)
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| Note that the probability listed within the parentheses is 0.05 instead of 0.025 because the function returns the normal deviate for a double-sided distribution. In order to attain the value for a single-sided distribution, the probability is doubled, per the description of the function within Microsoft Excel.
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| The following are excerpts from the Microsoft Excel "Help" function:
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| TINV(probability,degrees freedom)
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| Probability is the probability associated with the two-tailed Student's t-distribution.
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| Degrees-freedom is the number of degrees of freedom with which to characterize the distribution.
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| A one-tailed t-value can be returned by replacing probability with 2*probability. For a probability of 0.05 and degrees of freedom of 10, the two-tailed value is calculated with TINV(0.05,10), which returns 2.28139. The one-tailed value for the same probability and degrees of freedom can be calculated with TINV(2*0.05,10), which returns 1.812462.
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| The values within Table 4 were generated from the TINV function within Microsoft Excel and have been verified to be consistent with the values from Table V of Reference 7.3.2. Therefore, they are acceptable for use in drift analyses.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 26 of 58 Table 4 - Percentiles of the t Distribution (to.025.d)
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| Degrees of Normal Deviate (t) Degrees of Normal Deviate (t) Degrees of Normal Deviate (t)
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| Freedom @ 0.025 for Freedom @ 0.025 for Freedom @ 0.025 for (df) 95% Confidence (df 95% Confidence (df 95% Confidence 1 12.706 42 2.018 83 1.989 2 4.303 43 2.017 84 1.989 3 3.182 44 2.015 85 1.988 4 2.776 45 2.014 86 1.988 5 2.571 46 2.013 87 1.988 6 2.447 47 2.012 88 1.987 7 2.365 48 2.011 89 1.987 8 2.306 49 2.010 90 1.987 9 2.262 50 2.009 91 1.986 10 2.228 51 2.008 92 1.986 11 2.201 52 2.007 93 1.986 12 2.179 53 2.006 94 1.986 13 2.160 54 2.005 95 1.985 14 2.145 55 2.004 96 1.985 15 2.131 56 2.003 97 1.985 16 2.120 57 2.002 98 1.984 17 2.110 58 2.002 99 1.984 18 2.101 59 2.001 100 1.984 19 2.093 60 2.000 101 1.984 20 2.086 61 2.000 102 1.983 21 2.080 62 1.999 103 1.983 22 2.074 63 1.998 104 1.983 23 2.069 64 1.998 105 1.983 24 2.064 65 1.997 106 1.983 25 2.060 66 1.997 107 1.982 26 2.056 67 1.996 108 1.982 27 2.052 68 1.995 109 1.982 28 2.048 69 1.995 110 1.982 29 2.045 70 1.994 111 1.982 30 2.042 71 1.994 112 1.981 31 2.040 72 1.993 113 1.981 32 2.037 73 1.993 114 1.981 33 2.035 74 1.993 115 1.981 34 2,032 75 1.992 116 1.981 35 2.030 76 1.992 117 1.980 36 2.028 77 1.991 118 1.980 37 2.026 78 1.991 119 1.980 38 2.024 79 1.990 120 1.980 39 2.023 80 1.990 >120 1.960 40 2.021 81 1.990 41 2.020 82 1.989
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 27 of 58 Examples of determining and applying bias to the analyzed drift term:
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| : 1) Transmitter Group With a Biased Mean - A group of transmitters are calculated to have a standard deviation of 1.150%, mean of - 0.355% with a count of 47. The degrees of freedom are 46. From Table 4, the t value is 2.013. Therefore, Xcrit is computed as:
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| s 1.150%
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| Xcrit =tx- =-2.013"x 150 =0.338%
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| -ýFn 47 Therefore, the mean value is significant because the absolute value of it is larger than Xcrit, and the bias must be considered. The analyzed drift term for a 95%/95% tolerance interval level is shown as follows.
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| DA = - 0.355% +/- 1.150% x 2.408 (TIF from Table 1 for 47 samples)
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| DA = - 0.355% +/- 2.769%
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| For conservatism, the DA term for the positive direction is not reduced by the bias value where as the negative direction is summed with the bias value.
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| DA = + 2.769%, - 3.124%.
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| : 2) Transmitter Group With a Non-Biased Mean - A group of transmitters are calculated to have a standard deviation of 1.150%, mean of 0.100% with a count of 47. The degrees of freedom are 46. From Table 4, the t value is 2.013. Therefore, Xcrit is computed as:
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| s 1.150%
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| Xcrit =tx -- =2.013x 150 -0.338%
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| Therefore, the absolute value of the mean value is less than Xcrit. Therefore, the bias is insignificant, and can be neglected. The analyzed drift term for a 95%/95% tolerance interval level is shown as follows.
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| DA = +/- 1.150% x 2.408 (TIF from Table 1 for 47 samples)
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| DA = +/- 2.769%
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| 3.12. Time Dependent Drift Uncertainty When calibration intervals are extended beyond the range for which historical data is available, the statistical confidence in the ability to predict drift is reduced. The bias and the random portions of the drift are extrapolated separately, but in the same manner. Where the analysis shows slight to moderate time dependency or time dependency is indeterminate, drift is extrapolated using the Square Root of the Sum of the Squares (SRSS) method per Section 6.2.7 of Reference 7.1.2. This method assumes that the drift to time relationship is not linear.
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| The formula below is used.
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| DA~xendd DAExtended =
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| =DAA x~RqdCalibration Interval 71 VAvgBin _Time_-Interval Where: DAExtended = the newly determined, extrapolated Drift Bias or Random Term DA = the bias or random drift term from the Final Data Set or of the longest-interval, valid time bin from the binning analysis (see note)
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 28 of 58 Avg_ BinTimeInterval = the average observed time interval within the longest-interval, valid time bin from the binning analysis (see note)
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| RqdCalibrationInterval = the worst case calibration interval, once the calibration interval requirement is changed Note: For conservatism, the largest drift value (DA) of either the Final Data Set or the longest-interval, valid time bin from the binning analysis is used as a starting point for the drift extrapolation. For those cases where no time dependency is apparent from the drift analysis, it is also acceptable to use the maximum observed time interval from the longest-interval, valid time bin from the binning analysis, as a starting point in the extrapolation, as opposed to the average observed time interval. This can be used to reduce over-conservatisms in determining an extrapolated analyzed drift value.
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| Where there is indication of a strong relationship between drift and time, drift is extrapolated using the linear method per Section 6.2.7 of Reference 7.1.2. The following formula may be used.
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| DAExtendxd = DA X Rqd Calibration Interval]
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| I AvgBin-TimeInterval Where the terms are the same as defined above.
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| Where it can be shown that there is no relationship between surveillance interval and drift, the drift value determined may be used for other time intervals, without change. However, for conservatism, due to the uncertainty involved in extrapolation to time intervals outside of the analysis period, drift values that show minimal or no particular time dependency are generally treated as moderately time dependent, for the purposes of the extrapolation.
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| 3.13. Methods of Drift Assessment for Very Low Sample Sizes Per Section 3.4.2.1, "There is no hard fast number that must be attained for any given pool, but a minimum of 30 drift values must be attained before the drift analysis can be performed without additional justification." When it has been determined that the sample size is small for an instrument group, the first thing which should be considered is increasing the sample size. In order to increase the sample size, more historical data should be collected on the subject devices if possible. Also, other similar devices can be added to the analysis, if they can be shown to be maintained with similar QA control of the calibration processes, and if they meet the requirements to properly pool the drift data, per Section 3.5. It is possible that after obtaining all data possible on certain device types, less than 30 samples will be available for analysis. The following paragraphs provide guidance for assessment of the drift in those circumstances.
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| Rigorous drift analysis as described in the sections above may be performed for sample sizes as low as 20 data values, with additional justification. The justification is generally based on engineering judgment, which would conclude that the drift analysis would provide a reasonably accurate, but conservative estimate for future performance for the subject devices. The following types of arguments can be made for this engineering judgment; but not all of these are required, and other similar arguments could be made in support of this position.
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| " All data possible is analyzed from the device type with the level of Quality Assurance treatment.
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| * The small number of devices in the study limits the AF/AL data available.
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| " Preliminary analysis of the drift values shows the data to be relatively consistent.
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| * The data distribution is similar to a normal distribution, per a Histogram plot, as would be expected.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 29 of 58 The method of determining the Analyzed Drift for 20 data values uses a high Tolerance Interval Factor (TIF) for 95/95 confidence, providing the required conservatism for use in setpoint calculations.
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| The rigorous drift analysis would be comprised of the same components as the others with data counts > 30, but would have the additional justification stated in the assumptions / engineering judgments section of the calculation.
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| For cases where there is no drift data, manufacturer drift specifications may be extrapolated to a maximum calibration interval of 30 months for use in the setpoint calculations, in accordance with the requirements of References 7.2.2 and 7.2.3. This encompasses the cases where the devices will be replaced prior to, or concurrent with, project implementation; or where the devices have been recently replaced, such that two calibrations have not yet been performed for any of the subject devices.
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| For those cases where there is a very small sample size (i.e., < 20 drift data values or 20-29 where the data does not appear to be reasonably uniform), a drift assessment should be prepared, based on engineering judgment. The assessment would not include any normality or time dependency evaluations. Within the assessment, all possible drift values from the available AF/AL data are computed. The magnitude of the largest computed drift value is compared to the Square Root of the Sum of the Squares (SRSS) combination of the following terms:
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| : 1. Manufacturer Specification for drift,
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| : 2. Manufacturer Specification for Reference Accuracy, and
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| : 3. Calibration Term, comprised of Measurement &Test Equipment (M&TE), M&TE Standard, and Setting Tolerance If all of the computed drift values are encompassed by the combined total, the conclusion should be made that the manufacturer specifications are conservative with respect to the observed drift values. For this case, the manufacturer specification for drift should be extrapolated to a maximum calibration interval of 30 months for use in the setpoint calculations, in accordance with the requirements of References 7.2.2 and 7.2.3.
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| If the comparison within the assessment shows any of the computed drift values to exceed the combined total, an Analyzed Drift value should be derived for use in setpoint calculations, based on engineering judgment. If the device has multiple calibration points, such as a transmitter, the data from the worst case calibration point should be used in the assessment, unless that calibration point has significantly less data values than the other calibration points.
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| (See Section 4.3.4 for the determination of the worst case calibration point.)
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| Because of the low data count, unless significant evidence to the contrary exists; the drift should be considered random in nature. The drift value chosen for the current calibration interval should be equal to or larger than the following:
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| : 1. The magnitude of the worst case drift value observed, and
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| : 2. The magnitude of the mean + 2 standard deviations.
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| The random portion of the drift value chosen for the current calibration interval should be extrapolated to the maximum proposed interval via the equation below.
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| DAExtended.random DACurrent.random X - nterval Avg_ Observed_ Time _ Interval If the mean value is very large in comparison to the standard deviation, with a significant enough data count (per engineering judgment), then a bias should be used as a portion of the Analyzed Drift. The bias should be set equal to the mean for the current calibration interval.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision I Instrument Drift Analysis Design Guide Page 30 of 58 The bias portion of the drift value chosen for the current calibration interval should be extrapolated to the maximum proposed interval via the equation below.
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| = DACurrent.bias x Max Rqd _Time Interval DAExtended.bias Avg_ Observed Time _ Interval 3.14. Shelf Life of Analysis Results Any analysis result based on performance of existing components has a shelf life. In this case, the term "shelf life" is used to describe a period of time extending from the present into the future during which the analysis results are considered valid. Predictions for future component/loop performance are based upon our knowledge of past calibration performance.
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| This approach assumes that changes in component/loop performance occur slowly or not at all over time. For example, ifevaluation of the last ten years of data shows the component/loop drift is stable with no observable trend, there is little reason to expect a dramatic change in performance during the next year. However, it is also difficult to claim that an analysis completed today is still a valid indicator of component/loop performance ten years from now.
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| For this reason, the analysis results should be re-verified periodically through an instrument trending program in accordance with Reference 7.1.1. The Analyzed Drift values from the Drift Calculations are to be used by the trending program as thresholds, which will require further investigation ifexceeded.
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| Depending on the type of component/loop, the analysis results are also dependent on the method of calibration, the component/loop span, and the M&TE accuracy. Any of the following program or component/loop changes should be evaluated to determine ifthey affect the analysis results.
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| * Changes to M&TE accuracy
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| * Changes to the component or loop (e.g. span, environment, manufacturer, model, etc.)
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| * Calibration procedure changes that alter the calibration method
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| : 4. PERFORMING AN ANALYSIS As Found and As Left calibration data for the subject instrumentation is collected from historical calibration records. The collected data is entered into Microsoft Excel spreadsheets, grouped by manufacturer and model number. All data is also entered into an independent software program (such as Quattro Pro, Lotus 1-2-3, or Mathcad), for independent review of certain of the drift analysis functions. The drift analysis is generally performed using EXCEL spreadsheets, but can be performed using other software packages. The discussion provided in this section is to assist in setting up an EXCEL spreadsheet for producing a Drift Calculation.
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| Microsoft Excel spreadsheets generally compute values to an approximate 15 decimal resolution, which is well beyond any required rounding for engineering analyses. However, for printing and display purposes, most values are displayed to lesser resolution. Itis possible that hand computations would produce slightly different results, because of using rounded numbers in initial and intermediate steps, but the Excel computed values are considered highly accurate in comparison. Values with significant differences between the original computations and the computations of the independent verifier are to be investigated to ensure that the Excel spreadsheet is properly computing the required values.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 31 of 58 4.1. Populating the Spreadsheet 4.1.1. Fora New Analysis 4.1.1.1. The Responsible Engineer determines the component group to be analyzed (e.g., all Rosemount pressure transmitters). The Responsible Engineer should determine the possible sub-groups within the large groupings, which from an engineering perspective, might show different drift characteristics; and therefore, may warrant separation into smaller groups. This determination would involve the manufacturer, model, calibration span, setpoints, time intervals, specifications, locations, environment, etc., as necessary.
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| 4.1.1.2. The Responsible Engineer develops a list of component numbers, manufacturers, models, component types, brief descriptions, surveillance tests, calibration procedures and calibration information (spans, setpoints, etc.).
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| 4.1.1.3. The Responsible Engineer determines the data to be collected, following the guidance of Sections 3.4 through 3.6 of this Design Guide.
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| 4.1.1.4. The Data Entry Person identifies, locates and collects data for the component group to be analyzed (e.g., all Surveillance Tests for the Rosemount pressure transmitters completed to present).
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| 4.1.1.5. The Data Entry Person sorts the data by surveillance test or calibration procedure ifmore than one test/procedure is involved.
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| 4.1.1.6. The Data Entry Person sequentially sorts the surveillance or calibration sheets descending, by date, starting with the most recent date.
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| 4.1.1.7. The Data Entry Person enters the Surveillance or Calibration Procedure Number, Tag Numbers, Required Trips, Indications or Outputs, Date, As-Found values and As-Left values on the appropriate data entry sheet.
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| 4.1.1.8. The Responsible Engineer verifies the data entered.
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| 4.1.1.9. The Responsible Engineer reviews the notes on each calibration data sheet to determine possible contributors for excluding data. The notes should be condensed and entered onto the EXCEL spreadsheet for the applicable calibration points. Where appropriate and obvious, the Responsible Engineer should remove the data that is invalid for calculating drift for the device.
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| 4.1.1.1 O.The Responsible Engineer (via the spreadsheet) calculates the time interval for each drift point by subtracting the date from the previous calibration from the date of the subject calibration. (Ifthe measured value is not valid for the As-Left or As-Found calibration information, then the time interval is not required to be computed for this data point.)
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| 4.1.1.11 .The Responsible Engineer (via the spreadsheet) calculates the Drift value for each calibration by subtracting the As-Left value from the previous calibration from the As-Found value of the subject calibration. (Ifthe measured value is not valid for the As-Left or As-Found calibration information, then the Drift value is not computed for this data point.)
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 32 of 58 4.2. Spreadsheet Performance of Basic Statistics Separate data columns are created for each calibration point within the calibrated span of the device. The % Span of each calibration point should closely match from device to device within a given analysis. Basic statistics include, at a minimum, determining the number of data points in the sample, the average drift, the average time interval between calibrations, standard deviation of the drift, variance of the drift, minimum drift value, maximum drift value, kurtosis, and skewness contained in each data column. This section provides the specific details for using Microsoft Excel. Other spreadsheet, statistical or Math programs that are similar in function, are acceptable for use to perform the data analysis, provided all analysis requirements are met.
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| 4.2.1. Determine the number of data points contained in each column for each initial group by using the "COUNT" function. Example cell format = COUNT(C2:C133). The Count function returns the number of all populated cells within the range of cells C2 through C133.
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| 4.2.2. Determine the average for the data points contained in each column for each initial group by using the "AVERAGE" function. Example cell format = AVERAGE(C2:C133).
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| The Average function returns the average of the data contained within the range of cells C2 through C133. This average is also known as the mean of the data. This same method should be used to determine the average time interval between calibrations.
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| 4.2.3. Determine the standard deviation for the data points contained in each column for each initial group by using the "STDEV" function. Example cell format =STDEV(C2:C133).
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| The Standard Deviation function returns the measure of how widely values are dispersed from the mean of the data contained within the range of cells C2 through C133. Formula used by Microsoft Excel to determine the standard deviation:
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| STD (Standard Deviation of the sample population): (Ref. 7.3.1)
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| Where; x - Sample data values (xj, x2, x3......
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| s - Standard deviation of all sample data points n - Total number of data points 4.2.4. Determine the variance for the data points contained in each column for each initial group by using the "VAR" function. Example cell format =VAR(C2:C133). The Variance function returns the measure of how widely values are dispersed from the mean of the data contained within the range of cells C2 through C133. Formula used by Microsoft Excel to determine the variance:
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| VAR (Variance of the sample population): (Ref. 7.3.1) 2 2 s2_ n~x - (yx) n(n -
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| Where; x - Sample data values (xj, x2, x3......
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| s2 - Variance of the sample population n - Total number of data points
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 33 of 58 4.2.5. Determine the kurtosis for the data points contained in each column for each initial group by using the "KURT" function. Example cell format =KURT(C2:C133). The Kurtosis function returns the relative peakedness or flatness of the distribution within the range of cells C2 through C133. Formula used by Microsoft Excel to determine the kurtosis:
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| 4 KURT j ( ~) (Re 7.3.1)~4x-~
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| (R- IXn -
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| * 2X,- 3)( (n- 2Xn-3)
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| Where ;
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| x - Sample data values (xj, x2, x3......
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| n - Total number of data points s - Sample Standard Deviation 4.2.6. Determine the skewness for the data points contained in each column for each initial group by using the "SKEW' function. Example cell format =SKEW(C2:C133). The Skewness function returns the degree of symmetry around the mean of the cells contained within the range of cells C2 through C133. Formula used by Microsoft Excel to determine the skewness:
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| SKEW = (n-+1-) -- 2 ) ,( (Ref. 7.3.1)
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| Where; x - Sample data values (x1, x2, x3,... )
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| n - Total number of data points s - Sample Standard Deviation 4.2.7. Determine the maximum value for the data points contained in each column for each initial group by using the "MAX" function. Example cell format =MAX(C2:C133). The Maximum function returns the largest value of the cells contained within the range of cells C2 through C133.
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| 4.2.8. Determine the minimum value for the data points contained in each column for each initial group by using the "MIN" function. Example cell format =MIN(C2:C133). The Minimum function returns the smallest value of the cells contained within the range of cells C2 through C133.
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| 4.2.9. Determine the median value for the data points contained in each column for each initial group by using the "MEDIAN" function. Example cell format =MEDIAN(C2:C133).
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| The median is the number in the middle of a set of numbers; that is, half the numbers have values that are greater than the median, and half have values that are less. If there is an even number of data points in the set, then MEDIAN calculates the average of the two numbers in the middle.
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| 4.2.10. Where sub-groups have been combined in a data set, and where engineering reasons exist for the possibility that the data should be separated, analyze the statistics and component data of the sub-groups to determine the acceptability for combination.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 34 of 58 4.2.11. Perform a t-Test in accordance with step 3.5.4 on each possible sub-group combination to test for the acceptability of combining the data.
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| Acceptability for combining the data is indicated when the absolute value of the Test Statistic It Stat] is greater than the It Critical two-tail]. Example: t Stat for combining sub-group A & B may be 0.703, which is larger than the t Critical two-tail of 0.485.
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| However, as a part of this process, the Responsible Engineer should ensure that the apparent unacceptability for combination does not mask time dependency. In other words, if the only difference in the groupings is that of the calibration interval, the differences in the data characteristics could exist because of time dependent drift. If this is the only difference, the data should be combined, even though the tests show that it may not be appropriate.
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| 4.3. Outlier Detection and Expulsion Refer to Section 3.6 for a detailed explanation of Outliers.
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| 4.3.1. Obtain the Critical Values for the t-Test from Table 2, which is based on the sample size of the data contained within the specified range of cells. Use the COUNT value to determine the sample size.
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| 4.3.2. Perform the outlier test for all the samples. For any values that show up as outliers, analyze the initial input data to determine if the data is erroneous. If so, remove the data in the earlier pages of the spreadsheet, and re-run all of the analysis up to this point. Continue this process until all erroneous data has been removed.
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| 4.3.3. If appropriate, if any outliers are still displayed, remove the worst-case outlier as a statistical outlier, per step 3.6.3. Once this outlier has been removed (if applicable), the remaining data set is the Final Data Set.
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| 4.3.4. For transmitters, or other devices with multiple calibration points, the general process is to use the calibration point with the worst case drift values. This is determined by comparing the different calibration points and using the one with the largest error, determined by adding the absolute value of the mean to 2 times the standard deviation.
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| The data set with the largest of those terms is used throughout the rest of the analysis, after outlier removal, as the Final Data Set. (Note that it is possible to use a specific calibration point and neglect the others, only if that is the single point of concern for application of the results of the Drift Calculation. If so, this fact should be stated boldly in the results / conclusions of the calculation.)
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| 4.3.5. Recalculate the Average, Median, Standard Deviation, Variance, Minimum, Maximum, Kurtosis, Skewness, Count and Average Time Interval Between Calibrations for the Final Data Set.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 35 of 58 4.4. Normality Tests To test for normality of the Final Data Set, the first step is to perform the required hypothesis testing. For Final Data Sets with more than 50 data points, the hypothesis testing can be performed with either the Chi-Square (Section 3.7.1) or the D-Prime Test (Section 3.7.3). The D-Prime Test is recommended. If the Final Data Set has less than or equal to 50 data points, the W Test (Section 3.7.2) or Chi-Square Test may be used. The W Test is recommended.
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| If used, the Chi Square test should generally be performed with 12 bins of data, starting from [-
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| c to (mean-2.57)], and bin increments of 0.5cy, ending at [(mean+2.5a) to +oo]. (Since the same bins are to be used for the histogram in the coverage analysis, the work for these two tasks may be combined.)
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| If the assumption of normality is rejected by the numerical test, then a coverage analysis should generally be performed as described in Section 3.7.5. As explained above the for Chi Square test, the coverage analysis and histogram are established with a 12 bin approach unless inappropriate for the application.
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| If an adjustment is required to the standard deviation to provide a normal distribution that adequately covers the data set, then the required multiplier to the standard deviation (Normality Adjustment Factor (NAF)) is determined iteratively in the coverage analysis. This multiplier produces a normal distribution model for the drift, which shows adequate data population from the Final Data Set within the +/- 2a bounds of the model.
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| 4.5. Time Dependency Testing Time dependency testing is only required for instruments for which the calibration intervals are being extended; however, the scatter plot is recommended for information in all Drift Calculations. Time dependency is evaluated through the use of a scatter (drift interval) plot, binning analysis, and regression analyses. The methods for each of these are detailed below.
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| 4.5.1. Scatter Plot The scatter plot is performed under a new page to the spreadsheet entitled "Scatter Plot" or "Drift Interval Plot". The chart function of EXCEL is used to merely chart the data with the x axis being the calibration interval and the y axis being the drift value for the Final Data Set. The prediction line should be added to the chart, along with the equation of the prediction line. This plot provides visual indication of the trend of the mean, and somewhat obscurely, of any increases in the scatter of the data over time.
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| Note: The trend line should NOT be forced to have a y-intercept value of 0, but should be plotted for the actual drift data only.
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| 4.5.2. Binning Analysis The binning analysis is performed under a separate page of the EXCEL spreadsheet.
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| The Final Data Set is split by bins I through 8 into the time intervals as defined in Section 3.9.3.1. A table is set up to compute the standard deviation, mean, average time interval, and count of the data in each time bin. Similar equation methods are used here as described in Section 4.2, when characterizing the drift data set. Another table is used to evaluate the validity of the bins, based on population per the criteria of Section 3.9.3.4. If multiple valid bins are not established, the time dependency analysis stops here, and no regression analyses are performed.
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| If multiple valid bins are established, the standard deviations, means and average time intervals are tabulated, and a plot is generated to show the variation of the bin averages and standard deviations versus average time interval. This plot can be used to determine whether standard deviations and means are significantly increasing over time between calibrations.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 36 of 58 If the plot shows an increase in standard deviation over time, compare the critical value of the F-distribution of the ratio of the smallest and largest variances for the required bins.
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| S1 2 Fcalc =
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| S2 where:
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| S1 = largest drift standard deviation value S2 = smallest drift standard deviation value The critical value of F-distribution can be found, using the FINV function in Microsoft Excel:
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| Fcrit = FINV (0.05, V 1, V2 )
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| V1 = number of samples minus 1 in bin with largest standard deviation V2 = number of samples minus 1 in bin with smallest standard deviation If the ratio of variances exceeds the critical value, this result is indicative of time dependency for the random portion of drift. Likewise, a ratio of variances not exceeding the critical value is not indicative of significant time dependency.
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| 4.5.3. Regression Analyses The regression analyses are performed in accordance with the requirements of Section 3.9.4, given that multiple valid time bins were established in the binning analysis. New pages should be created for the Drift Regression and the Absolute Value Drift Regression.
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| For each of the two Regression Analyses, use the following steps to produce the regression analysis output. Using the "Data Analysis" package under "Tools" in Microsoft EXCEL, the Regression option should be chosen. The Y range is established as the Drift (or Absolute Value of Drift) data range, and the X range should be the calibration time intervals. The output range should be established on the Regression Analysis page of the spreadsheet. The option for the residuals should be established as "Line Fit Plots". The regression computation should then be performed. The output of the regression routine is a list of residuals, an ANOVA table listing, and a plot of the Drift (or Absolute Value of Drift) versus the Time Interval between Calibrations. A prediction line is included on the plot.
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| Add a cell close to the ANOVA table listing which establishes the Critical Value of F, using the guidance of Section 3.9.4 for the Significance of F Test. This utilizes the FINV function of Microsoft EXCEL.
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| Analyze the results in the Drift Regression ANOVA table for R Square, P Value, and F Value, using the guidance of Section 3.9.4. If any of these analytical methods shows time dependency in the Drift Regression, the mean of the data set should be established as strongly time dependent if the slope of the prediction line significantly increases over time from an initially positive value (or decreases over time from an initially negative value), without crossing zero within the time interval of the regression analysis. This increase can also be validated by observing the results of the binning analysis plot for the mean of the bins and by observing the scatter plot and regression analysis prediction lines.
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| Analyze the results in the Absolute Value of Drift Regression ANOVA table for R Square, P Value, and F Value, using the guidance of Section 3.9.4. If any of these analytical means shows time dependency, the standard deviation of the data set should
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| | |
| Cooper Nuclear'Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 37 of 58 be established as strongly time dependent ifthe slope of the prediction line significantly increases over time. This increase can also be validated by observing the results of the binning analysis plot for the standard deviation of the bins, by observation of the results from the F distribution comparison within the binning plot, and by observing any discernible increases in data scatter, as time increases, on the scatter plot.
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| Regardless of the results of the analytical regression tests, ifthe plots tend to indicate significant increases in either the mean or standard deviation over time, those parameters should be judged to be strongly time dependent. Otherwise, for conservatism, the data is always considered to be moderately time dependent if extrapolation of the data is necessary, to accommodate the uncertainty involved in the extrapolation process, since no data has generally been observed at time intervals as large as those proposed.
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| 4.6. Calculate the Analyzed Drift (DA) Value The first step in determining the Analyzed Drift Value is to determine the required time interval for which the value must be computed. For the majority of the cases for instruments calibrated on a refueling basis, the required nominal calibration time interval is 24 months, or a maximum of 30 months. Since the average time intervals are generally computed in days, the most conservative value for a 30-Month calibration interval is established as 915 days.
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| The Analyzed Drift Value generally consists of two separate components - a random term and a bias term. Ifthe mean of the Final Data Set is significant per the criteria in Section 3.11, a bias term is considered. If no extrapolation is necessary, the bias term is set equal to the mean of the Final Data Set. If extrapolation is necessary, it is performed in one of two methods, as determined by the degree of time dependency established in the time dependency analysis. If the mean is determined to be strongly time dependent, the following equation is used, which extrapolates the value in a linear fashion.
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| DAExtended.bias =-x x Max Rqd _Time Interval Avg _ Bin - Time_ Interval Ifthe mean is determined to be moderately time dependent, the following equation is used to extrapolate the mean. (Note that this equation is also generally used for cases where no time dependency is evident, because of the uncertainty in defining a drift value beyond analysis limits.)
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| DAExtendedbias = Avg_ Bin _ Time Interval Where: 5 = Mean of the Final Data Set or of the longest-interval, valid time bin from the binning analysis (see note)
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| Avg Bin TimeInterval = the average observed time interval within the longest-interval, valid time bin from the binning analysis (see note)
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| MaxRqdTimeInterval = the maximum time interval for desired calibration interval.
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| For instance, 915 days for a desired 24 month nominal calibration interval.
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| Note: For conservatism, the largest drift value (DA) of either the Final Data Set or the longest-interval, valid time bin from the binning analysis is used as a starting point for the drift extrapolation. For those cases where no time dependency is apparent from the drift analysis, it is also acceptable to use the maximum observed time interval from the longest-interval, valid time bin from the binning analysis, as a starting point in the
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 38 of 58 extrapolation, as opposed to the average observed time interval. This can be used to reduce over-conservatisms in determining an extrapolated analyzed drift value.
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| The random portion of the Analyzed Drift is calculated by multiplying the standard deviation of the Final Data Set by the Tolerance Interval Factor for the sample size and by the Normality Adjustment Factor (if required from the Coverage Analysis). If extrapolation is necessary, it is performed in one of two methods, similar to the methods shown above for the bias term, depending on the degree of time dependency observed. Use the following procedure to perform the operation.
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| 4.6.1. Use the COUNT value of the Final Data Set to determine the sample size.
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| 4.6.2. Obtain the appropriate Tolerance Interval Factor (TIF) for the size of the sample set.
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| Table 1 lists the 95%/95% TIFs; refer to Standard statistical texts for other TIF multipliers. Note: TIFs other than 95%/95% must be specifically justified.
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| 4.6.3. For a generic data analysis, multiple Tolerance Interval Factors may be used, providing a clear tabulation of results is included in the analysis, showing each value for the multiple levels of TIF.
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| 4.6.4. Multiply the Tolerance Interval Factor by the standard deviation for the data points contained in the Final Data Set and by the Normality Adjustment Factor determined in the Coverage Analysis (if applicable).
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| 4.6.5. If the analyzed drift term calculated above is applied to the existing calibration interval, application of additional drift uncertainty is not necessary.
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| 4.6.6. When calculating drift for calibration intervals that exceed the historical calibration intervals, use the following equations, depending on whether the data is shown to be strongly time dependent or moderately time dependent.
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| For a Strongly Time Dependent random term, use the following equation.
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| Interval DAExtended.random = (Yx TIF x NAF x Max-RqdTime Avg_ Bin _Time_ Interval For a Moderately Time Dependent random term, use the following equation. (Note that this equation is also generally used for cases where no time dependency is evident, because of the uncertainty in defining a drift value beyond analysis limits.)
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| DAExtended.random = agx TIF x NAF x Mx_1 TimeI VAvg _Bin _Time _Interval Where: a = Standard Deviation of the Final Data Set or of the longest-interval, valid time bin from the binning analysis (see note)
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| TIF = Tolerance Interval Factor from Table 1 NAF = Normality Adjustment Factor from the Coverage Analysis (IfApplicable)
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| Avg_BinTimeInterval = the average observed time interval within the longest-interval, valid time bin from the binning analysis (see note)
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| MaxRqdTimeInterval = the maximum time interval for desired calibration interval.
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| For instance, 915 days for a desired 24 month nominal calibration interval.
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| Note: For conservatism, the largest drift value (DA) of either the Final Data Set or the longest-interval, valid time bin from the binning analysis is used as a starting point for the drift extrapolation. For those cases where no time dependency is apparent from the drift
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 39 of 58 analysis, it is also acceptable to use the maximum observed time interval from the longest-interval, valid time bin from the binning analysis, as a starting point in the extrapolation, as opposed to the average observed time interval. This can be used to reduce over-conservatisms in determining an extrapolated analyzed drift value.
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| 4.6.7. Since random errors are always expressed as +/- errors, specific consideration of directionality is not generally a concern. However, for bistables and switches, the directionality of any bias error must be carefully considered. Because of the fact that the As-Found and As-Left setpoints are recorded during calibration, the drift values determined up to this point in the Drift Calculation are representative of a drift in the setpoint, not in the indicated value.
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| Per Reference 7.1.2, error is defined as the algebraic difference between the indication and the ideal value of the measured signal. In other words, Error = indicated value - ideal value (actual value)
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| For devices with analog outputs, a positive error means that the indicated value exceeds the actual value, which would mean that ifa bistable or switching mechanism used that signal to produce an actuation on an increasing trend, the actuation would take place prior to the actual variable reaching the value of the intended setpoint. As analyzed so far in the Drift Calculation for bistables and switches, the drift causes the opposite effect. A positive Analyzed Drift would mean that the setpoint is higher than intended; thereby causing actuation to occur after the actual variable has exceeded the intended setpoint.
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| A bistable or switch can be considered to be a black box, which contains a sensing element or circuit and an ideal switching mechanism. At the time of actuation, the switch or bistable can be considered an indication of the process variable. Therefore, a positive shift of the setpoint can be considered to be a negative error. In other words, if the switch setting was intended to be 500 psig, but actually switched at 510 psig, at the time of the actuation, the switch "indicated" that the process value was 500 psig when the process value was actually 510 psig. Thus, error = indicated value (500 psig) - actual value (510 psig) = -10 psig Therefore, a positive shift of the setpoint on a switch or bistable is equivalent to a negative error, as defined by Reference 7.1.2. Therefore, for clarity and consistency with the treatment of other bias error terms, the sign of the bias errors of a bistable or switch should be reversed, in order to comply with the convention established by Reference 7.1.2. In either case, the conclusions of the Drift Calculation should be clear enough for proper application to setpoint computations.
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| : 5. CALCULATIONS 5.1. Drift Calculations The Drift Calculations should be performed in accordance with the methodology described above, with the following documentation requirements.
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| 5.1.1. The title includes the Manufacturer/Model number of the component group analyzed.
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| 5.1.2. The calculation objective must:
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| 5.1.2.1. describe, at a minimum, that the objective of the calculation is to document the drift analysis results for the component group, and extrapolate the drift value to the required calibration period (if applicable),
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 40 of 58 5.1.2.2. provide a list for the group of all pertinent information in tabular form (e.g. Tag Numbers, Manufacturer, Model Numbers, ranges and calibration spans), and 5.1.2.3. describe any limitations on the application of the results. For instance, ifthe analysis only applies to a certain range code, the objective should state this fact.
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| 5.1.3. The method of solution should describe, at a minimum, a summary of the methodology used to perform the drift analysis outlined by this Design Guide. Exceptions taken to this Design Guide are to be included in this section including basis and references for any exceptions.
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| 5.1.4. The actual calculation/analysis should provide:
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| 5.1.4.1. A listing of data which was removed and the justification for removal 5.1.4.2. List of references 5.1.4.3. A narrative discussion of the specific activities performed for this calculation 5.1.4.4. Results and conclusions, including
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| - Manufacturer and model number analyzed
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| - Bias and random Analyzed Drift values, as applicable
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| - The applicable Tolerance Interval Factors (provide detailed discussion and justification ifother than 95%/95%)
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| - Applicable drift time interval for application
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| - Normality conclusion
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| - Statement of time dependency observed, as applicable
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| - Limitations on the use of this value in application to uncertainty calculations, as applicable
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| - Limitations on the application ifthe results to similar instruments, as applicable 5.1.5. Attachment(s) should be provided, including the following information:
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| 5.1.5.1. Input data with notes on removal and validity 5.1.5.2. Computation of drift data and calibration time intervals 5.1.5.3. Outlier summary, including Final Data Set and basic statistical summaries 5.1.5.4. Chi Square Test Results (As Applicable) 5.1.5.5. W Test or D' Test Results (As Applicable) 5.1.5.6. Coverage Analysis, Including Histogram, Percentages in the Required Sigma Band, and Normality Adjustment Factor (As Applicable) 5.1.5.7. Scatter Plot with Prediction Line and Equation 5.1.5.8. Binning Analysis Summaries for Bins and Plots (As Applicable) 5.1.5.9. Regression Plots, ANOVA Tables, and Critical F Values (As Applicable) 5.1.5.1 O.Derivation of the Analyzed Drift Values, With Summary of Conclusions
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 41 of 58 5.2. Setpoint/Uncertainty Calculations To apply the results of the drift analyses to a specific device or loop, a setpoint or loop accuracy calculation must be performed, revised or evaluated in accordance with References 7.2.2 and 7.2.3, as appropriate. Per Section 3.2.1.2, the Analyzed Drift term characterizes various instrument uncertainty terms for the analyzed device, loop, or function. In order to save time, a comparison between these terms in an existing setpoint calculation to the Analyzed Drift can be made. Ifthe terms within the existing calculation bound the Analyzed Drift term, then the existing calculation is conservative as is, and does not specifically require revision. Ifrevision to the calculation is necessary, the Analyzed Drift term may be incorporated into the calculation, by replacing the appropriate terms for the analyzed devices with the Analyzed Drift term.
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| When comparing the results to setpoint calculations that have more than one device in the instrument loop that was analyzed for drift, comparisons can be made between the DA terms and the original terms on a device-by-device basis, or on a total loop basis. Care should be taken to properly combine terms for comparison in accordance with References 7.2.2 and 7.2.3, as appropriate.
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| When applying the Drift Calculation results of bistables or switches to a setpoint calculation, the preparer should fully understand the directionality of any bias terms within DA and apply the bias terms accordingly. (See Section 4.6.7.)
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 42 of 58
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| : 6. DEFINITIONS Standard statistics term meaning that the results have a 95% confidence (y) that 95%/95% at least 95% of the population will lie between the stated interval (P) for a sample Ref. 7.1.1 size (n).
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| A term representing the errors determined by a completed drift analysis for a Analyzed Drift group. Uncertainties that may be represented by the analyzed drift term are (DA) component reference accuracy, input and output M&TE errors, personnel- Section 4.6 induced or human related errors, ambient temperature and other environmental effects, power supply effects, misapplication errors and true component drift.
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| As-Found (AF) The conditionand of operation in which beforearecalibration.
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| channel, or portion of a channel, is found after a period Ref. 7.1.3 The condition in which a channel, or portion of a channel, is left after calibration Ref. 7.1.3 As-Left (AL) or final setpoint device verification.
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| Bias (B) A shift in the signal zero point by some amount. Ref. 7.1.1 Calibrated Span The maximum calibrated upper range value less the minimum calibrated lower Ref. 7.1.1 (CS) range value.
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| The elapsed time between the initiation or successful completion of calibrations Calibration Interval or calibration checks on the same instrument, channel, instrument loop, or other Ref. 7.1.1 specified system or device.
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| A test to determine if a sample appears to follow a given probability distribution.
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| Chi-Square Test This test is used as one method for assessing whether a sample follows a Ref. 7.1.1 normal distribution.
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| Confidence Interval An interval that contains the population mean to a given probability. Ref. 7.1.1 An analysis to determine whether the assumption of a normal distribution Coverage Analysis effectively bounds the data. A histogram is used to graphically portray the Ref. 7.1.1 coverage analysis.
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| Cumulative An expression of the total probability contained within an interval from -oo to some Ref. 7.1.1 Distribution value, x.
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| A test to verify the assumption of normality for moderate to large sample sizes Ref. 7.1.1, D-Prime Test (greater than 50 samples). 7.1.4 In statistics, dependent events are those for which the probability of all occurring at once is different than the product of the probabilities of each occurring Dependent separately. In setpoint determination, dependent uncertainties are those Ref. 7.1.1 uncertainties for which the sign or magnitude of one uncertainty affects the sign or magnitude of another uncertainty.
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| Drift An undesired to the change in output input, environment, over a period of time where change is unrelated or load. Ref. 7.1.2 Error The algebraic difference between the indication and the ideal value of the Ref. 7.1.2 measured signal.
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| The set of data that is analyzed for normality, time dependence, and used to Final Data Set (FDS) determine the drift value. This data has all outliers and erroneous data removed, Section 3.6.3 as allowed.
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| Functionally Components with similar design and performance characteristics that can be Ref. 7.1.1 Equivalent combined to form a single population for analysis purposes.
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| Histogram A graph of a frequency distribution. Ref. 7.1.1
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 43 of 58 In statistics, independent events are those in which the probability of all occurring at once is the same as the product of the probabilities of each occurring Independent separately. In setpoint determination, independent uncertainties are those for Ref. 7.1.1 which the sign or magnitude of one uncertainty does not affect the sign or magnitude of any other uncertainty.
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| An arrangement of components and modules as required to generate a single Instrument Channel protective action signal when required by a plant condition. A channel loses its Ref. 7.1.2 identity where single protective action signals are combined.
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| Instrument Range The region between transmitted, expressed the by limits within stating thewhich lower aand quantity upperisrange measured, values.received or Ref. 7.1.2 A characterization of the relative peakedness or flatness of a distribution Kurtosis compared to a normal distribution. A large kurtosis indicates a relatively peaked Ref. 7.1.1 distribution and a small kurtosis indicates a relatively flat distribution.
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| M&TE Measurement and Test Equipment. Ref. 7.1.1 Maximum Span The limit. component's maximum upper range limit less the maximum lower range Ref. 7.1.1 Mean The average value of a random sample or population. Ref. 7.1.1 The value of the middle number in an ordered set of numbers. Half the numbers Median have thevalues that are greater data than thean median even and halfofhave values Ref. 7.1.1 than median. Ifthe set has number values, thethat are less median is the average of the two middle values.
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| Any assembly of interconnected components that constitutes an identifiable Module device, instrument and replaced with aorspare.
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| piece of equipment.
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| It has definableAperformance module can be removed as that characteristics a unit Ref. 7.1.2 permit it to be tested as a unit.
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| A multiplier to be used for the standard deviation of the Final Data Set to provide Normality a drift model that adequately covers the population of drift points in the Final Section 3.7.5 Adjustment Factor Data Set.
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| Normality Test A statistics test to determine if a sample is normally distributed. Ref. 7.1.1 Outlier A data point significantly different in value from the rest of the sample. Ref. 7.1.1 The totality of the observations with which we are concerned. A true population Ref. 7.1.1 Population consists of all values, past, present and future.
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| The branch of mathematics which deals with the assignment of relative Probability frequencies of occurrence (confidence) of the possible outcomes of a process or Ref. 7.3.2 experiment according to some mathematical function.
| |
| Prob. Density An expression of the distribution of probability for a continuous function. Ref. 7.1.1 Function A type of graph scaled for a particular distribution in which the sample data plots as approximately a straight line if the data follows that distribution. For example, Probability Plot normally distributed data plots as a straight line on a probability plot scaled for a Ref. 7.1.1 normal distribution; the data may not appear as a straight line on a graph scaled for a different type of distribution.
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| A segment of a population that is contained by an upper and lower limit.
| |
| Tolerance intervals determine the bounds or limits of a proportion of the Ref. 7.3.2 Proportion population, not just the sampled data. The proportion (P) is the second term in the tolerance interval value (e.g. 95%/99%).
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| Random Random __
| |
| Describing a variable predicted exactly, but whose can only value at a particular be estimated by a future instant probability cannot befunction.
| |
| distribution Ref. 7.1.1
| |
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 44 of 58 As found minus As-Left calibration data used to characterize the performance of Ref. 7.1.1 Raw Data a functionally equivalent group of components.
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| Ref.
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| : 7. 7.1.2, 7.1.2, Reference Accuracy A number or quantity that defines a limit that errors will not exceed when a (AC) device is used under specified operating conditions. 7.2.3 Sample A subset of a population. Ref. 7.1.1 The portion of an instrument channel that responds to changes in a plant Sensor variable or condition and converts the measured process variable into a signal; Ref. 7.1.2 e.g., electric or pneumatic.
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| One or more modules that perform signal conversion, buffering, isolation or Ref. 7.1.2 Signal Conditioning mathematical operations on the signal as needed.
| |
| Skewness A measure of the degree of symmetry around the mean. Ref. 7.1.1 The algebraic difference between the upper and lower values of a calibrated Ref. 7.1.2 Span range.
| |
| Standard Deviation A measure of how widely values are dispersed from the population mean. Ref. 7.1.1 Surveillance The elapsed time between the initiation or successful completion of a surveillance or surveillance check on the same component, channel, instrument Ref. 7.1.1 Interval loop, or other specified system or device.
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| Time-Dependent The tendency for the magnitude of component drift to vary with time. Ref. 7.1.1 Drift Time-Dependent The uncertainty associated with extending calibration intervals beyond the range Ref. 7.1.1 Drift Uncertainty of available historical data for a given instrument or group of instruments.
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| Time-Independent The tendency for the magnitude of component drift to show no specific trend with Ref. 7.1.1 Drift time.
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| Tolerance The allowable variation from a specified or true value. Ref. 7.1.2 An interval that contains a defined proportion of the population to a given Ref. 7.1.1 Tolerance Interval probability.
| |
| Trip Setpoint A predetermined value for actuation of the final actuation device to initiate Ref. 7.1.2 TripSetpintprotective action.
| |
| Turndown Factor The upper range limit divided by the calibrated span of the device. Ref. 7.1.2 (TDF)
| |
| For this Design Guide the t-Test is used to determine: 1) if a sample is an outlier Ref. 7.1.1 t-Test of a sample pool, and 2) if two groups of data originate from the same pool.
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| The amount to which an instrument channel's output is in doubt (or the allowance made therefore) due to possible errors either random or systematic which have Ref. 7.1.1 Uncertainty not been corrected for. The uncertainty is generally identified within a probability and confidence level.
| |
| Variance A measure of how widely values are dispersed from the population mean. Ref. 7.1.1 A test to verify the assumption of normality for sample sizes less than or equal to Ref. 7.1.1, W Test 50. 7.1.4
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 45 of 58
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| : 7. REFERENCES 7.1. Industry Standards and Correspondence 7.1.1. EPRI TR-103335R1, "Statistical Analysis of Instrument Calibration Data - Guidelines for Instrument Calibration Extension/Reduction Programs," October, 1998 7.1.2. ISA-RP67.04.02-2000, "Recommended Practice, Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation" 7.1.3. ANSI/ISA-S67.04.01-2000, "American National Standard, Setpoints for Nuclear Safety-Related Instrumentation" 7.1.4. ANSI N15.15-1974, "Assessment of the Assumption of Normality (Employing Individual Observed Values)"
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| 7.1.5. NRC to EPRI Letter, "Status Report on the Staff Review of EPRI Technical Report TR-103335, "Guidelines for Instrument Calibration Extension/Reduction Program"," Dated March 1994 7.1.6. REGULATORY GUIDE 1.105, Rev. 2, "Instrument Setpoints" 7.1.7. US Nuclear Regulatory Commission Letter from Mr. Thomas H. Essig to Mr. R. W.
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| James of Electric Power Research Institute, Dated December 1, 1997, "Status Report on the Staff Review of EPRI Technical Report TR-1 03335, 'Guidelines for Instrument Calibration Extension / Reduction Programs,' Dated March 1994" 7.2. Calculations and Programs 7.2.1. GE NEDC 31336P-A "General Electric Instrument Setpoint Methodology" (Included within Reference 7.2.2) 7.2.2. CNS Procedure 3.26.3, Instrument Setpoint and Channel Error Calculation Methodology 7.2.3. CNS Procedure 3.26.4, Instrument Indication Uncertainty Program and Calculation Methodology 7.3. Miscellaneous 7.3.1. Microsoft Excel for Microsoft Office 2003 (or Later Versions), Spreadsheet Program 7.3.2. Statistics for Nuclear Engineers and Scientists Part 1: Basic Statistical Inference, William J. Beggs; February, 1981 7.3.3. NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle"
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 46 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" The following are excerpts or paraphrases from the NRC Status Report on the Staff review of EPRI Technical Report (TR)-1 03335, "Guidelines for Instrument Calibration Extension /Reduction Programs",
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| dated March, 1994 (Reference 7.1.7). These excerpts are followed by the Cooper Nuclear Station (CNS) evaluation of how the Instrument Drift Analysis Design Guide for CNS addresses the concern, as a part of the 24 Month Cycle Extension projects.
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| STATUS REPORT Item 4.1, Section 1, "Introduction", Second Paragraph:
| |
| "The staff has issued guidance on the second objective (evaluating extended surveillance intervals in support of longer fuel cycles) only for 18-month to 24-month refueling cycle extensions (GL 91-04).
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| Significant unresolved issues remain concerning the applicability of 18 month (or less) historical calibration data to extended intervals longer than 24 months (maximum 30 months), and instrument failure modes or conditions that may be present in instruments that are unattended for periods longer than 24 months."
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| CNS EVALUATION Extensions for longer than 24 months (maximum of 30 months, including 25% grace period) are not to be requested via drift analysis in accordance with the Instrument Drift Analysis Design Guide.
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| STATUS REPORT Item 4.2, Section 2, "Principles of Calibration Data Analysis", First Paragraph:
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| "This section describes the general relation between the as-found and as-left calibration values, and instrument drift. The term 'time dependent drift' is used. This should be clarified to mean time dependence of drift uncertainty, or in other words, time dependence of the standard deviation of drift of a sample or a population of instruments."
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| CNS EVALUATION Both the EPRI TR, Revisions 0 and 1 failed to adequately determine if there existed a relationship between the magnitude of drift and the time interval between calibrations. The drift analysis performed for CNS looked at the time to magnitude relationship using several different statistical and non-statistical methods. First, during the evaluation of data for grouping, data was grouped for the same or similar manufacturer, model number, and application combinations even though the t' statistical test may have shown that the groups were not necessarily from the same population ifthe groups were performed on significantly different frequencies. This test grouping was made to ensure that the analysis did not cover-up a significant time dependent bias or random element magnitude shift.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 47 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" After the standard deviation and other simple statistics are calculated, the data is evaluated for the time to magnitude relationship. If adequately time-diverse data is available, a time-binning analysis is performed on the data. Data is divided into time bins, based on the time between calibrations. Statistics are computed for those bins, such as mean and standard deviation. These values are then plotted to expose any significant increases in the magnitude of the mean or standard deviation over time.
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| Regression analysis is performed, based on the scatter of the raw "drift" values and a second regression analysis is performed on the absolute values of the "drift." For each of these regression analyses, statistical tests are performed to determine iftime dependency is evident. These statistical tests are the R2 , F, and P value tests.
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| Finally, visual examination of the plots generated as a result of the scatter plot, binning analysis, regression analysis of drift, and the regression analysis of the absolute value of drift are used to make a final judgment on whether or not the random or mean values of drift are time dependent. Therefore, the mean and random aspects of drift are evaluated for time dependency.
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| STATUS REPORT Item 4.2, Section 2, "Principles of Calibration Data Analysis", Second Paragraph:
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| "Drift is defined as as-found - as-left. As mentioned in the TR this quantity unavoidably contains uncertainty contributions from sources other than drift. These uncertainties account for variability in calibration equipment and personnel, instrument accuracy, and environmental effects. It may be difficult to separate these influences from drift uncertainty when attempting to estimate drift uncertainty but this is not sufficient reason to group these allowances with a drift allowance. Their purpose is to provide sufficient margin to account for differences between the instrument calibration environment and its operating environment see Section 4.7 of this report for a discussion of combining other uncertainties into a 'drift' term."
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| CNS EVALUATION The drift determined by analysis is compared to the equivalent set of variables in the setpoint calculation.
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| Per Section 3.2.1.2 of the CNS Instrument Drift Analysis Design Guide, "The As-Found versus the As-Left data includes several sources of uncertainty over and above component drift. The difference between As-Found and previous As-Left data encompasses a number of instrument uncertainty terms in addition to drift, as defined by Reference 7.2.2, the-setpoint calculation methodology for CNS. The drift is not assumed to encompass the errors associated with temperature effect, since the temperature difference between the two calibrations is not quantified, and is not anticipated to be significant.
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| Additional instruction for the use of As-Found and As-Left data may be found in Reference 7.1.2."
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| Therefore, the errors associated with the environment are not considered in the comparison of the Analyzed Drift values to the setpoint calculation values. The environmental effects are considered separately from the Analyzed Drift term, within the setpoint calculations.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 48 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" STATUS REPORT Item 4.2, Section 2, "Principles of Calibration Data Analysis", Third Paragraph:
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| "The guidance of Section 2 is acceptable provided that time dependency of drift for a sample or population is understood to be time dependent [sic] of the uncertainty statistic describing the sample or population; e.g., the standard deviation of drift. A combination of other uncertainties with drift uncertainty may obscure any existing time dependency of drift uncertainty, and should not be done before time-dependency analysis is done."
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| CNS EVALUATION Time dependency evaluations are performed on the basic as-left/as-found data. Obviously other error contributors are contained in this data, but it is impossible to separate the contribution due to drift from the contribution due to Measurement and Test Equipment and Reference Accuracy. All of these terms fully contribute to the observed errors. Using the raw values appears to give the most reliable interpretation of the time dependency for the calibration process, which is the true value of interest. No other uncertainties are combined with the basic as-left/as-found data for time dependency determination.
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| STATUS REPORT Item 4.3, Section 3, "Calibration Data Collection", Second Paragraph:
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| "When grouping instruments, as well as manufacturer make and model, care should be taken to group only instruments that experience similar environments and process effects. Also, changes in manufacturing method, sensor element design, or the quality assurance program under which the instrument was manufactured should be considered as reasons for separating instruments into different groups. Instrument groups may be divided into subgroups on the basis of instrument age, for the purpose of investigating whether instrument age is a factor in drift uncertainty."
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| CNS EVALUATION Instruments are originally grouped based on manufacturer make, model number, and specific range of setpoint or operation. The groups are then evaluated and combined based on Sections 3.5.1 through 3.5.4 of the design guide. The appropriateness of the grouping is then tested based on a t-Test (two samples assuming unequal variances). The t-Test defines the probability, associated with a Student's t-Test; that two samples are likely to have come from the same underlying population. Instrument groups are not divided into subgroups based on age.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 49 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" STATUS REPORT Item 4.3, Section 3, "Calibration Data Collection", Second Paragraph (continued):
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| "Instrument groups should also be evaluated for historical instrument anomalies or failure modes that may not be evident in a simple compilation of calibration data. This evaluation should confirm that almost all instruments in a group performed reliably and almost all required only calibration attendance."
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| CNS EVALUATION A separate surveillance test failure evaluation is performed for the procedures implementing the surveillance requirements. This evaluation identifies calibration-related and non-calibration-related failures for single instruments, and groups of instruments supporting a specific function. After all relevant device and multiple device failures are identified, a cross-check of failures across manufacturer make and model number is also performed to determine if common mode failures could present a problem for the cycle extension. This evaluation confirms that almost all instruments in a group (associated with extended Technical Specification line items) performed reliably and most failures are detected by more frequent testing.
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| STATUS REPORT Item 4.3, Section 3, "Calibration Data Collection", Third Paragraph:
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| "Instruments within a group should be investigated for factors that may cause correlation between calibrations. Common factors may cause data to be correlated, including common calibration equipment, same personnel performing calibrations, and calibrations occurring in the same conditions.
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| The group, not individual instruments within the group, should be tested for trends."
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| CNS EVALUATION Instruments are only investigated for correlation factors where multiple instruments appeared to have been driven out of tolerance by a single factor. Correlation may exist between the specific type of test equipment (e.g., Fluke 863 on the 0-200 mV range) and the personnel performing calibrations for each plant. This correlation would only affect the measurement ifit caused the instrument performance to be outside expected boundaries, e.g., where additional errors should be considered in the setpoint analysis or where it showed a defined bias. Because Measurement and Test Equipment (M&TE) is calibrated more frequently than most process components being monitored, the effect of test equipment between calibrations is considered to be negligible and random. The setting tolerance, readability, and other factors which are more personnel-based, would only affect the performance ifthere was a predisposition to leave or read settings in a particular direction (e.g., always in the more conservative direction). Plant training and evaluation programs are designed to eliminate this type of predisposition. Therefore, the correlation between M&TE and instrument performance; or between personnel and instrument performance is not evaluated. Observed as-found values outside the Allowable Value are treated as unique failures and are evaluated to determine if a common cause exists as a part of the failure analysis.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 50 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" STATUS REPORT Item 4.3, Section 3, "Calibration Data Collection", Fourth Paragraph:
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| "TR-1 03335, Section 3.3, advises that older data may be excluded from analysis. Itshould be emphasized that when selecting data for drift uncertainty time dependency analysis it is unacceptable to exclude data simply because it is old data. When selecting data for drift uncertainty time dependency analysis, the objective should be to include data for time spans at least as long as the proposed extended calibration interval, and preferably, several times as long, including calibration intervals as long as the proposed interval. For limited extensions (e.g., a GL 91-04 extension), acceptable ways to obtain this longer interval data include obtaining data from other nuclear-plants or from other industries for identical or close-to-identical instruments, or combining intervals between which the instrument was not reset or adjusted. Ifdata from other sources is used, the source should be analyzed for similarity to the target plant in procedures, process, environment methodology, test equipment, maintenance schedules and personnel training. An appropriate conclusion of the data collection process may be that there is insufficient data of appropriate time span for a sufficient number of instruments to support statistical analysis of drift uncertainty time dependency."
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| CNS EVALUATION Data is selected for the last 90 months (5 cycles). This allows for the evaluation of data with various different calibration spans over several calibration intervals to provide representative information for each type of instrument. Data from outside the CNS data set is not used to provide longer interval data.
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| In most cases the time dependency determination is based on calibrations performed at or near 18 months and data performed at shorter intervals (monthly, quarterly, or semiannually). There did not appear to be any time based factors that would be present from 18 to 24 months that would not have been present between 1, 3, 6, or 12 and 18 months. It could be determined that there is insufficient data to support statistical analysis of drift time dependency. For these cases, a correlation between drift magnitude and time is assumed and the calculation reflects time dependent drift values.
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| STATUS REPORT Item 4.3, Section 3, "Calibration Data Collection", Fifth Paragraph:
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| "TR-1 03335, Section 3.3 provides guidance on the amount of data to collect. As a general rule, it is unacceptable to reject applicable data, because biases in the data selection process may introduce biases in the calculated statistics. There are only two acceptable reasons for reducing the amount of data selected: enormity, and statistical dependence. When the number of data points is so enormous that the data acquisition task would be prohibitively expensive, a randomized selection process, not dependent upon engineering judgment, should be used. This selection process should have three steps. In the first step, all data is screened for applicability, meaning that all data for the chosen instrument grouping is selected, regardless of the age of the data. In the second step, a proportion of the applicable data is chosen by automated random selection, ensuring that the data records for single instruments are complete, and enough individual instruments are included to constitute a statistically diverse sample. In the third step, the first two steps are documented. Data points should be combined when there is indication that they are statistically dependent on each other, although alternate
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 51 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" approaches may be acceptable. See Section 4.5, below, on 'combined point' data selection and Section 4.4.1 on '0%, 25%, 50%, 75%, and 100% calibration span points'."
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| CNS EVALUATION A time interval of 90 months is selected as representative, based on CNS operating history. No data points are rejected from this time interval, and no sampling techniques are used.
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| STATUS REPORT Item 4.4, Section 4, "Analysis of Calibration Data":
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| Sub-item, 4.4.1, Sections 4.3 and 4.4, Data Setup and Spreadsheet Statistics, First Paragraph:
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| "The use of spreadsheets, databases, or other commercial software is acceptable for data analysis provided that the software, and the operating system used on the analysis computer, is under effective configuration control. Care should be exercised in the use of Windows or similar operating systems because of the dependence on shared libraries. Installation of other application software on the analysis machine can overwrite shared libraries with older versions or versions that are inconsistent with the software being used for analysis."
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| CNS EVALUATION The project uses Microsoft EXCEL spreadsheets to perform the drift analysis. This software is not treated as QA software. Therefore, computations are verified using hand verification and alternate software on different computers, such as Lotus 1-2-3 or Quattro Pro spreadsheets.
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| STATUS REPORT Item 4.4, Section 4, "Analysis of Calibration Data":
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| Sub-item, 4.4.1, Sections 4.3 and 4.4, Data Setup and Spreadsheet Statistics, Second Paragraph:
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| "Using either engineering units or per-unit (percent of span) quantities is acceptable. The simple statistic calculations (mean, sample standard deviation, sample size) are acceptable. Data should be examined for correlation or dependence to eliminate over-optimistic tolerance interval estimates. For example, if the standard deviation of drift can be fitted with a regression line through the 0%, 25%, 50%, 75%, and 100% calibration span points, there is reason to believe that drift uncertainty is correlated over the five (or nine, ifthe data includes a repeatability sweep) calibration data points. An example is shown in TR-103335, Figure 5.4, and a related discussion is given in TR-103335 Section 5.1.3. Confidence/tolerance estimates are based on (a) an assumption of normality (b) the number of points in the data set, and (c) the standard deviation of the sample. Increasing the number of points (utilizing each calibration span point) when data is statistically dependent decreases the tolerance factor k, which may falsely enhance the confidence in the predicted tolerance interval. To retain the information, but achieve a reasonable point count for confidence/tolerance estimates, the statistically dependent data points should be combined into a composite data point. This retains the information but cuts the point count. For drift
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 52 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" uncertainty estimates with data similar to that in the TR example, an acceptable method requires that the number of independent data points should be one-fifth (or one ninth) of the total number of data points in the example and a combined data point for each set of five span points should be selected that is representative of instrument performance at or near the span point most important to the purpose of the analysis (i.e., trip or normal operation point)."
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| CNS EVALUATION The analysis for CNS uses either engineering units or percent of calibrated span, as appropriate to the calibration process. As an example, for switches that do not have a realistic span value, the engineering units are used in the analyses; for analog devices, normally percent of span is used. Typically, dependence is found between calibration points (0%, 25%, 50%, 75%, and 100%) for a single calibration. However, due to the changes in M&TE and personnel performing the calibrations, independence is generally found between calibrations of the same component on different dates. To ensure conservatism, the most conservative simple statistic values for the points closest to the point of interest are selected, or the most conservative values for any data point are selected. The multiplier is determined based on the number of actual calibrations associated with the worst-case value selected.
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| Selection of the actual number of calibrations is equivalent to the determination of independent points (e.g., one fifth or one ninth of the total data point count). Selection of the worst-case point is also more conservative than the development of a combined data point.
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| STATUS REPORT Item 4.4, Section 4, "Analysis of Calibration Data":
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| Sub-item 4.4.2, Section 4.5, Outlier Analysis:
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| "Rejection of outliers is acceptable only if a specific, direct reason can be documented for each outlier rejected. For example, a documented tester failure would be cause for rejecting a calibration point taken with the tester when it had failed. Itis not acceptable to reject outliers on the basis of statistical tests alone. Multiple passes of outlier statistical criterion are not acceptable. An outlier test should only be used to direct attention to data points, which are then investigated for cause. Five acceptable reasons for outlier rejection provided that they can be demonstrated, are given in the TR: data transcription errors, calibration errors, calibration equipment errors, failed instruments, and design deficiencies.
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| Scaling or setpoint changes that are not annotated in the data record indicate unreliable data, and detection of unreliable data is not cause for outlier rejection, but may be cause for rejection of the entire data set and the filing of a licensee event report. The usual engineering technique of annotating the raw data record with the reason for rejecting it, but not obliterating the value, should be followed. The rejection of outliers typically has cosmetic effects: ifsufficient data exists, it makes the results look slightly better; if insufficient data exists, it may mask a real trend. Consequently, rejection of outliers should be done with extreme caution and should be viewed with considerable suspicion by a reviewer."
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 53 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" CNS EVALUATION Itis acceptable to remove one outlier from an analysis based on statistical means, other than those using the engineering judgments mentioned in the EPRI document. The Design Guide is written with this as a general rule. This does not reduce the amount of scrutiny that the preparer and reviewer use in the entry and evaluation of the calibration data. The intent is to properly model device performance after completion of this project. No more than one outlier is removed from the drift population on the basis of statistics alone. Given very large sample sizes or complicated calibration processes, specific diagnosis of problems when reviewing procedure data is sometimes not possible. However, the data can contain errors which are very likely to be unrelated to drift or device performance, which should be removed, given an appropriate consideration from both the preparer and reviewer. For this project, rejection of outliers is performed with extreme caution and is viewed with considerable suspicion by the reviewer.
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| Significant conservatisms exist in the assumptions for extrapolation of drift values as computed per this Design Guide, which provide additional margin for the devices to drift. Additionally, ifthe removal of the data reduces the computed extrapolated drift to a value that is not consistent with the capability of the device (which is not to be expected), the improved drift-monitoring program would detect the problem and implement design activity, maintenance activity, or both to correct the problem.
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| STATUS REPORT Item 4.4, Section 4, "Analysis of Calibration Data":
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| Sub-item 4.4.3, Section 4.6, "Verifying the Assumption of Normality":
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| "The methods described are acceptable in that they are used to demonstrate that calibration data or results are calculated as ifthe calibration data were a sample of a normally distributed random variable.
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| For example, a tolerance interval which states that there is a 95% probability that 95% of a sample drawn from a population will fall within tolerance bounds is based on an assumption of normality, or that the population distribution is a normal distribution. Because the unwarranted removal of outliers can have a significant effect on the normality test, removal of significant numbers of, or sometimes any (in small populations), outliers may invalidate this test."
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| CNS EVALUATION The methods that were found acceptable are used for the CNS analysis. All drift studies involve the removal of one or less outliers. Therefore, the normality tests are valid. Coverage analysis is used where the normality tests reject the assumption of normality. This produces a conservative model of the drift data by expanding the standard deviation to provide adequate coverage.
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 54 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" STATUS REPORT Item 4.4, Section 4, "Analysis of Calibration Data":
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| Sub-item 4.4.4, Section 4.7, "Time-Dependent Drift Considerations", First through Ninth Paragraphs:
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| "This section of the TR discusses a number of methods for detecting a time dependency in drift data, and one method of evaluating drift uncertainty time dependency. None of the methods uses a formal statistical model for instrument drift uncertainty, and all but one of them focus on drift rather than drift uncertainty. Two conclusions are inescapable: regression analysis cannot distinguish drift uncertainty time dependency, and the slope and intercept of regression lines may be artifacts of sample size, rather than being statistically significant. Using the results of a regression analysis to rule out time dependency of drift uncertainty is circular reasoning: i.e., regression analysis eliminates time dependency of uncertainty; no time dependency is found; therefore, there is no time dependency."
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| CNS EVALUATION Several different methods of evaluation for time dependency of the data are used for the analysis. One method, the binning analysis, is to evaluate the standard deviations at different calibration intervals. This analysis technique is the most recommended method of determining time-dependent tendencies in a given sample pool. The test consists simply of segregating the drift data into different groups (bins) corresponding to different ranges of calibration or surveillance intervals, and comparing the standard deviations for the data in the various groups. The purpose of this type of analysis is to determine ifthe standard deviation or mean tends to become larger as the time between calibration increases. Simple regression lines, regression of the absolute value of drift, as well as R2, F, and P tests are also generated and reviewed. Finally visual examinations of the scatter plot, binning plot, and both regression plots are used to assess or corroborate results. Where there is not sufficient data to perform the detailed evaluation, the data is assumed moderately time dependent. Whenever extrapolation of the drift value is required, in ALL cases, drift is conservatively assumed to be at least moderately time dependent for the purpose of extrapolation, even though many of the test results may show that the drift is time independent.
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| STATUS REPORT Item 4.4, Section 4, "Analysis of Calibration Data":
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| Sub-item 4.4.4, Section 4.7, "Time-Dependent Drift Considerations", Thirteenth and Fourteenth Paragraphs:
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| "Amodel can be used either to bound or project future values for the quantity in question (drift uncertainty) for extended intervals. An acceptable method would use standard statistical methods to show that a hypothesis (that the instruments under study have drift uncertainties bounded by the drift uncertainty predicted by a chosen model) is true with high probability. Ideally, the method should use data that include instruments that were un-reset for at least as long as the intended extended interval, or similar data from other sources for instruments of like construction and environmental usage. The use of data of appropriate time span is preferable; however, ifthis data is unavailable, model projection may be
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 55 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" used provided the total projected interval is no greater than 30 months and the use of the model is justified. A follow-up program of drift monitoring should confirm that model projections of uncertainty bounded the actual estimated uncertainty. If it is necessary to use generic instrument data or constructed intervals, the chosen data should be grouped with similar grouping criteria as are applied to instruments of the plant in question, and Student's "t"test should be used to verify that the generic or constructed data mean appears to come from the same population. The "F"test should be used on the estimate of sample variance. For a target surveillance interval constructed of shorter intervals where instrument reset did not occur, the longer intervals are statistically dependent upon the shorter intervals; hence, either the constructed longer-interval data or the shorter-interval data should be used, but not both. In a constructed interval, drift = as-left(o) - as found(LAST), the intermediate values are not used.
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| When using samples acquired from generic instrument drift analyses or constructed intervals, the variances are not simply summed, but are combined weighted by the degrees of freedom in each sample."
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| CNS EVALUATION The General Electric interval extension process is used because CNS is committed to the General Electric Setpoint Methodology. Where the drift can be proven to be time independent for the analysis period, or shown to be only slightly or moderately time dependent, the calculated drift value is extended based on the formula:
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| Drift 30 = Drift calculated * (30/calculated drift time interval)112.
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| Where there is a strong indication of time dependent drift, the following formula is used:
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| Drift30 = Drift calculated * (30/calculated drift time interval).
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| STATUS REPORT Item 4.4, Section 4, "Analysis of Calibration Data":
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| Sub-item 4.4.5, Section 4.8, "Shelf Life of Analysis Results":
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| "The TR gives guidance on how long analysis results remain valid. The guidance given is acceptable with the addition that once adequate analysis and documentation is presented and the calibration interval extended, a strong feedback loop must be put into place to ensure drift, tolerance and operability of affected components are not negatively impacted. An analysis should be re-performed if its predictions turn out to exceed predetermined limits set during the calibration interval extension study. A goal during the re-performance should be to discover why the analysis results were incorrect The establishment of a review and monitoring program, as indicated in GL 91-04, Enclosure 2, Item 7 is crucial to determining that the assumptions made during the calibration interval extension study were true. The methodology for obtaining reasonable and timely feedback must be documented."
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 56 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" CNS EVALUATION CNS is committed to establish a trending program to provide feedback on the acceptability of the drift error extension. This program will perform a detailed analysis of as-found values outside the calculated As Found Tolerance (AFT). The drift analysis will be re-performed when the root cause analysis indicates drift is a probable cause for the performance problems. The trending program will be combined with the program used to meet the calibration requirements for Technical Specification Task Force (TSTF)-493.
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| STATUS REPORT Item 4.5, Section 5, "Alternative Methods of Data Collection and Analysis":
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| "Section 5 discusses two alternatives to as-found/as-left (AFAL) analysis, combining the 0%, 25%, 50%,
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| 75% and 100% span calibration points, and the EPRI Instrument Calibration Reduction Program (ICRP).
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| Two alternatives to AFAL are mentioned: as-found/setpoint (AFSP) analysis and worst case as-found/as-left (WCAFAL). Both AFSP and WCAFAL are more conservative than the AFAL method because they produce higher estimates of drift. Therefore, they are acceptable alternatives to AFAL drift estimation.
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| The combined-point method is acceptable, and in some cases preferable, if the combined value of interest is taken at the point important to the purpose of the analysis. That is, if the instrument being evaluated is used to control the plant in an operating range, the instrument should be evaluated near its operating point. If the instrument being evaluated is employed to trip the reactor, the instrument should be evaluated near the trip point. The combined-point method should be used if the statistic of interest shows a correlation between calibration span points, thus inflating the apparent number of data points and causing an overstatement of confidence in the results. The method by which the points are combined (e.g., nearest point interpolation, averaging) should be justified and documented."
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| CNS EVALUATION Per Section 4.3.4 of the CNS Instrument Drift Analysis Design Guide, "For transmitters, or other devices with multiple calibration points, the general process is to use the calibration point with the worst case drift values." Therefore, the method at CNS is conservative, no matter which point on the calibration curve is most important for a given application.
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| STATUS REPORT Item 4.6, Section 6, "Guidelines for Calibration and Surveillance Interval Extension Programs":
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| "This section presents an example analysis in support of extending the surveillance interval of reactor trip bistables from monthly to quarterly. Because these bistables exhibit little or no bias, and very small drift, the analysis example does not challenge the methodology presented in TR-1 03335 Section 4, and thus raises no acceptability issues related to drift analysis that have not already been covered. The bistables are also rack instruments, and thus not representative of process instruments, for which drift is
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision I Instrument Drift Analysis Design Guide Page 57 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" a greater concern. Bistables do not produce a variable output signal that can be compared to redundant device readings by operations personnel, or during trending programs, and cannot be compared during channel checks, as redundant process instruments are. For these reasons the data presented in Section 6 have very little relationship to use in the TR methodology for calibration interval extensions for process instruments. The binomial pass/fail methodology of Section 6.3 is acceptable as a method of complying with GL 91-04, Enclosure 2, item 1 for bistables, "Confirm that acceptable limiting values of drift have not been exceeded except in rare instances." This method provides guidance for the definition of "rare" instances by describing how to compute expected numbers of exceedances for an assumed instrument confidence / tolerance criterion (e.g., 95/95, for a large set of bistable data. There are other methods that would be acceptable, in particular, the X test for significance.
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| This test can be used to determine ifthe exceedance-of-allowable-limits frequency in the sample is probably due to chance or probably not due to chance, for a given nominal frequency (e.g., 95% of drifts do not exceed allowable limits). This provides an acceptable method of complying with GL 91-04, Enclosure 2, item 1 in the general case."
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| CNS EVALUATION CNS does not plan to extend any bistables from monthly to quarterly. Therefore, this section is not evaluated for the 24-Month cycle extension project.
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| STATUS REPORT Item 4.7, Section 7, "Application to Instrument Setpoint Programs":
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| "Section 7 is a short tutorial on combining uncertainties in instrument Setpoint calculations. Figure 7-1 of this section is inconsistent with ANSI/ISA-S67.04-1994, Part 1, Figure 1. Rack uncertainty is not combined with sensor uncertainty in the computation of the allowable value in the standard. The purpose of the allowable value is to set a limit beyond which there is reasonable probability that the assumptions used in the setpoint calculation were in error. For channel functional tests, these assumptions normally do not include an allowance for sensor uncertainty (quarterly interval, sensor normally excluded). Ifa few instruments exceed the allowable value, this is probably due to instrument malfunction. Ifit happens frequently, the assumptions in the setpoint analysis may be wrong. Since the terminology used in Figure 7-1 is inconsistent with ANSI/ISA-S67.04-1994, Part I, Figure 1, the following correspondences are suggested: the 'Nominal Trip Setpoint' is the ANSI/ISA trip setpoint; ANSI/ISA value 'A' is the difference between TR 'Analytical Limit' and 'Nominal Trip Setpoint' [sic]; 'Sensor Uncertainty' is generally not included in the 'Allowable Value Uncertainty' and would require justification, the difference between 'Allowable Value' and 'Nominal Trip Setpoint' is ANSI/ISA value 'B'; the 'Leave-Alone-Zone' is equivalent to the ANSI/ISA value 'E' and the difference between 'System Shutdown' and
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| 'Nominal Trip Setpoint' is the ANSI/ISA value 'D'. Equation 7-5 (page 7-7 of the TR) combines a number of uncertainties into a drift term, D. Ifthis is done, the reasons and the method of combination should be justified and documented. The justification should include an analysis of the differences between operational and calibration environments, including accident environments in which the instrument is expected to perform."
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| Cooper Nuclear Station Engineering Evaluation 10-045, Revision 1 Instrument Drift Analysis Design Guide Page 58 of 58 Appendix A Evaluation of the NRC Status Report on the Staff Review of EPRI Technical Report-103335, "Guidelines for Instrument Calibration Extension/Reduction Programs" CNS EVALUATION Application of the drift values to plant setpoints is performed in accordance with CNS Procedure 3.26.3, the CNS setpoint methodology document, which includes the GE Setpoint Methodology, NEDC 31336P-A. The Allowable Value defined for the GE Setpoint Methodology is defined as the operability limit when performing the channel calibration. Therefore, the Allowable Value includes the sensor drift for the refueling cycle and the trip unit drift (for transmitter/trip unit combinations) for the quarter (or other surveillance interval at which the trip unit is calibrated). No environmental terms are considered to be included in the drift term.
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| STATUS REPORT Item 4.8, Section 8, "Guidelines for Fuel Cycle Extensions":
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| "The TR repeats the provisions of Enclosure 2, GL 91-04, and provides direct guidance, by reference to preceding sections of the TR, on some of them."
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| CNS EVALUATION A specific discussion of how the CNS evaluations meet the guidance of GL 91-04 will be provided in the licensing submittal for the 24 Month Cycle Extension project.}}
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