ML12269A254
| ML12269A254 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 01/29/2013 |
| From: | Gibson L K Plant Licensing Branch IV |
| To: | Reddeman M E Energy Northwest |
| Gibson L K | |
| References | |
| TAC ME7904 | |
| Download: ML12269A254 (353) | |
Text
{{#Wiki_filter:UNITED NUCLEAR REGULATORY WASHINGTON, D.C. 20555-0001 January 29, 2013 Mr. Mark E. Reddemann Chief Executive Officer Energy Northwest P.O. Box 968 (Mail Drop 1023) Richland, WA 99352-0968 COLUMBIA GENERATING STATION -ISSUANCE OF AMENDMENT RE: LICENSE AMENDMENT REQUEST TO MAKE ADMINISTRATIVE AND EDITORIAL CHANGES TO TECHNICAL SPECIFICATIONS AND OPERATING LICENSE (TAC NO. ME7904) Dear Mr. Reddemann: The U.S. Nuclear Regulatory Commission (NRC) has issued the enclosed Amendment No. 225 to Renewed Facility Operating License No. NPF-21 for the Columbia Generating Station. The amendment consists of changes to the Technical Specifications (TSs) and Operating License in response to your application dated January 9, 2012, as supplemented by letters dated July 30 and November 14,2012. The amendment implements formatting changes to the Operating License and TSs resulting from a change in the word processing programs and the adoption of TSTF-GG-05-01, "Writers Guide for Plant-Specific Improved Technical Specifications," Revision 1. In addition to these administrative changes, the amendment implements editorial changes which do not result in any changes to the technical or operating requirements. M. Reddemann -A copy of the related Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice. Sincerely, Lauren K. Gibson, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-397 Enclosures: 1. Amendment No. 225 to NPF-21 2. Safety Evaluation cc w/encls: Distribution via Listserv UNITED NUCLEAR REGULATORY WASHINGTON, D.C. 20555-0001 ENERGY NORTHWEST DOCKET NO. 50-397 COLUMBIA GENERATING STATION AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 225 License No. NPF-21 The Nuclear Regulatory Commission (the Commission) has found that: The application for amendment by Energy Northwest (licensee), dated January 9, 2012, as supplemented by letters dated July 30 and November 14, 2012, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act) and the Commission's regulations set forth in 10 CFR Chapter I; The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied. Enclosure 1 -2 Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-21 is hereby amended to read as follows: (2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 225 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. The license amendment is effective as of its date of issuance and shall be implemented within 30 days from the date of issuance. FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Attachment: Changes to the Facility Operating License No. NPF-21 and Technical Specifications Date of Issuance: January 29, 2013 ATTACHMENT TO LICENSE AMENDMENT NO. 225 RENEWED FACILITY OPERATING LICENSE NO. NPF-21 DOCKET NO. 50-397 Replace the following pages of the Renewed Facility Operating License No. NPF-21 and Appendix A, Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain vertical lines indicating the areas of change. Facility Operating License REMOVE INSERT 1 -10 1 -10 Attachments 1-3 Attachments 1-3 Appendix A -Technical Specifications REMOVE i -1 . 1-1 -1.1.2-1 -1.3-1 -1.4-1 -2.0-1 -3.1.1-1 -3.1.2-1 -3. 1.4-1 -3.1 3.1.5-1 -3.1.6-1 -3.3.1.1-1 -3.3.1.2-1 -3.3.1.3-1 -3.3.2.1-1 -3.3.2.2-1 -3.3.3.1-1 -3.3.3.2-1 -3.3.4.1-1 -3.3.4.2-1 -3.3.5.1-1-3.3.5.1-11 3.3.5.2-1 -3.3.5.2-4 3.3.6.1-1 -3.3.6.1-8 3.3.6.2-1 -3.3.6.2-4 3.3.7.1-1 -3.3.7.1-4 3.3.8.1-1 -3.3.8.1-4 INSERT i -1.1-1 1.2-1 -1.3-1 1.4-1 -1 .4-2.0-1 -3.1.1-1 -3.1.2-1 -3.1.4-1 -3.1.5-1 -3.1.6-1 -3.3.1.3-1 -3.3.2.1-1 -3.3.2.2-1 -3.3.3.1-1 -3.3.3.2-1 -3.3.4.1-1 -3.3.4.2-1 -3.3.5.1-1 -3.3.5.2-1 -3.3.6.1-1 -3.3.6.2-1 -3.3.7.1-1 -3.3.8.1-1 -3.3.8.2-1 -3.4.1-1 -3.4.9-1 -3.4.10-1 -3.4.11-1 -3.5.1-1 -3.5.2-1 -3.5.3-1 -3.6.1.1-1 -3.6.1.3-1 -3.6.1.5-1 -3.6.1.6-1 -3.6.1.7-1 -3.6.2.1-1 -3.6.3.1-1 -3.6.3.2-1 -3.6.3.3-1 -3.6.4.2-1 -3.6.4.3-1 -3.7.1-1 -3.7.3-1 -3.7.4-1 -3.7.6-1 -3.3.8.2-1 -3.4.1-1 -3.4.9-1 -3.4.10-1 -3.5.1-1 -3.5.2-1 -3.5.3-1 -3.6.1.1-1 -3.6.1.3-1 - 3.6.1.6-1 -3.6.1.7-1 -3.6.2.1-1 -3.6.3.3-1 -3.6.4.2-1 -3.6.4.3-1 -3.7.1-1 -3.7.3-1 -3.7.4-1 - 3.8.1-1 -3.8.2-1 -3.8.4-1 -3.8.5-1 -3.8.6-1 -3.8.7-1 -3.8.8-1 -3.9.1-1 -3.9.2-1 -3.9.4-1 -3.9.8-1 --2 Appendix A -Technical Specifications (Continued) INSERT REMOVE 3.7.7-1 3.9.9-1 -3.9.9-3 3.8.1-1 -3.8.1-16 3.9.10-1 3.8.2-1 -3.8.3-3 3.10.1-1 -3.10.1-3 3.8.4-1 -3.8.4-4 3.10.2-1 -3.10.3-3 3.8.5-1 -3.8.5-2 3.10.4-1 -3.10.4-4 3.8.6-1 -3.8.6-4 3.10.5-1 -3.10.5-3 3.8.7-1 -3.8.7-2 3.10.6-1 -3.10.7-2 3.8.8-1 -3.8.8-2 3.10.8-1 -3.10.8-4 3.9.1-1 4.0-1 -5.4-1 3.9.2-1 5.5-1 -5.5-14 3.9.3-1 5.6-1 -5.6-4 3.9.4-1 -3.9.7-1 5.7-1 -5.7-5 3.9.8-1 -3.9.8-2 Appendix B -Environmental Protection Plan REMOVE INSERT Table of Contents Table of Contents 1-1 1-1 2-1 -2-2 2-1 3-1 -3-3 3-1 -3-2 4-1 4-1 5-1 -5-4 5-1 -5-3 Appendix C REMOVE INSERT 1 1 3.9.9-1 -3.10.1-1 -3.10.2-1 -3.10.4-1 -3.10.5-1 -3.10.6-1 -3.10.8-1 -4.0-1 -5.5-1 -5.6-1 -5.7-1 - ENERGY NORTHWEST DOCKET NO. 50-397 COLUMBIA GENERATING STATION RENEWED FACILITY OPERATING LICENSE Renewed License No. NPF-21 The Nuclear Regulatory Commission (the Commission or the NRC) has found that: The application for renewed license filed by Energy Northwest (also the licensee), complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's regulations set forth in 10 CFR Chapter I, and all required notifications to other agencies or bodies have been duly made; Construction of Energy Northwest, Columbia Generating Station (the facility) has been substantially completed in conformity with Construction Permit No. CPPR-93 and the application, as amended, the provisions of the Act, and the regulations of the Commission; The facility will operate in conformity with the application, as amended, the provisions of the Act, and the regulations of the Commission (except as exempted from compliance in Section 2.0. below); There is reasonable assurance: (i) that the activities authorized by this renewed operating license can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations set forth in 10 CFR Chapter I (except as exempted from compliance in Section 2.0. below); Energy Northwest is technically qualified to engage in the activities authorized by this renewed license in accordance with the Commission's regulations set forth in 10 CFR Chapter I; Energy Northwest has satisfied the applicable provisions of 10 CFR Part 140, "Financial Protection Requirements and Indemnity Agreements", of the Commission's regUlations; Renewed License No. NPF-21 Amendment No. 225 -The issuance of this renewed license will not be inimical to the common defense and security or to the health and safety of the public; After weighing the environmental, economic, technical, and other benefits of the facility against environmental and other costs and considering available alternatives, the issuance of this Renewed Facility Operating License No. NPF-21, subject to the conditions for protection of the environment set forth in the Environmental Protection Plan attached as Appendix B, is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied; and The receipt, possession, and use of source, byproduct and special nuclear material as authorized by this renewed license will be in accordance with the Commission's regulations in 10 CFR Parts 30, 40 and 70. Actions have been identified and have been or will be taken with respect to (1) managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21 (a)(1), and (2) time-limited aging analyses that have been identified to require review under 10 CFR 54.21 (c), such that there is reasonable assurance that the activities authorized by the renewed operating license will continue to be conducted in accordance with the current licensing basis, as defined in 10 CFR 54.3, for the facility, and that any changes made to the facility's current licensing basis in order to comply with 10 CFR 54.29(a) are in accordance with the Act and the Commission's regulations. Based on the foregoing findings regarding this facility, Renewed Facility Operating License NPF-21 is hereby issued to Energy Northwest (the licensee) to read as follows: This renewed operating license applies to Columbia Generating Station, a boiling water nuclear reactor and associated equipment, owned by Energy Northwest. The facility is located on Hanford Reservation in Benton County near Richland, Washington, and is described in the licensee's "Final Safety Analysis Report", as supplemented and amended, and in the licensee's Environmental Report, as supplemented and amended. Subject to the conditions and requirements incorporated herein, the Commission hereby licenses Energy Northwest: Pursuant to Section 103 of the Act and 10 CFR Part 50, to possess, use, and operate the facility at the deSignated location on Hanford Reservation, Benton County, Washington, in accordance with the procedures and limitations set forth in this renewed license; Renewed License No. NPF-21 Amendment No. 225 -Pursuant to the Act and 10 CFR Part 70, to receive, possess and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source of special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility. Pursuant to the Act and 10 CFR Parts 30, 40 and 70, to store byproduct, source and special nuclear materials not intended for use at Columbia Generating Station. The materials shall be no more than 9 sealed neutron radiation sources designed for insertion into pressurized water reactors and no more than 40 sealed beta radiation sources designed for use in area radiation monitors. The total inventory shall not exceed 24 microcuries of strontium-90, 20 microcuries of uranium-235, 30 curies of plutonium-238, and 3 curies of americium-241. This renewed license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below: Maximum Power Level The licensee is authorized to operate the facility at reactor core power levels not in excess of full power (3486 megawatts thermal). Renewed License No. NPF-21 Amendment No. 225 (2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained.in Appendix A. as revised through Amendment No. 225 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the renewed license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan. a. For Surveillance Requirements (SRs) not previously performed by existing SRs or other plant tests, the requirement will be considered met on the implementation date and the next required test will be at the interval specified in the Technical Specifications as revised in Amendment No. 149. (3) Deleted. (4) Deleted. (5) Deleted. (6) Deleted. (7) Deleted. (8) Deleted. (9) Deleted. (10) Deleted. (11) Shield Wall Deferral (Section 12.3.2, SSER #4, License Amendment #7) The licensee shall complete construction of the deferred shield walls and window as identified in Attachment 3, as amended by this license amendment. (12) Deleted. (13) Deleted. *The parenthetical notation following the title of many license conditions denotes the section of the Safety Evaluation Report and/or its supplements wherein the license condition is discussed. Renewed License No. NPF-21 Amendment No. 225 -5 (14) Fire Protection Program (Generic Letter 86-10) The licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in Section 9.5.1 and Appendix F of the Final Safety Analysis Report (FSAR) for the facility thru Amendment #39 and as described in subsequent letters to the staff through November 30, 1988, referenced in the May 22, 1989 safety evaluation and in other pertinent sections of the FSAR referenced in either Section 9.5.1 or Appendix F and as approved in the Safety Evaluation Report issued in March 1982 (NUREG 0892) and in Supplements 3, issued in May 1983, and 4, issued in December 1983, and in safety evaluations issued with letters dated November 11, 1987 and May 22, 1989 subject to the following provision: The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. (15) Deleted. (16) Deleted. (17) Deleted. (18) Deleted. (19) Deleted. (20) Deleted. (21 ) Deleted. (22) Deleted. (23) Deleted. (24) Deleted. (25) Deleted. (26) Deleted. (27) Deleted. (28) Deleted. Renewed License No. NPF-21 Amendment No. 225 -6 Protection of the Environment (FES) Before engaging in additional construction or operational activities which may result in a significant adverse environmental impact that was not evaluated or that is significantly greater than the evaluation in the Final Environmental Statement the licensee shall provide a written notification to the Director of the Office of Nuclear Reactor Regulation and receive written approval from that office before proceeding with such activities. Deleted. Mitigation Strategy License Condition Develop and maintain strategies for addressing large fires and explosions and that include the following key areas: Fire fighting response strategy with the following elements: 1. Pre-defined coordinated fire response strategy and guidance 2. Assessment of mutual aid fire fighting assets 3. Designated staging areas for equipment and materials 4. Command and control 5. Training of response personnel Operations to mitigate fuel damage considering the following: 1. Protection and use of personnel assets 2. Communications 3. Minimizing fire spread 4. Procedures for implementing integrated fire response strategy 5. Identification of readily-available pre-staged equipment 6. Training on integrated fire response strategy 7. Spent fuel pool mitigation measures Actions to minimize release to include consideration of: 1. Water spray scrubbing 2. Dose to onsite responders The licensee shall implement and maintain all Actions required by Attachment 2 to NRC Order EA-06-137, issued June 20,2006, except the last action that requires incorporation of the strategies into the site security plan, contingency plan, emergency plan and/or guard training and qualification plan, as appropriate. Renewed License No. NPF-21 Amendment No. 225 -7 Control Room Envelope Habitability Program (CRE) Upon implementation of Amendment No. 207 adopting TSTF-448, Revision 3, the determination of eRE unfiltered air inleakage as required by SR 3.7.3.4, in accordance with TS S.S.14.c.(O, the assessment of eRE habitability as required by Specification S.S.14.c.{ii), and the measurement of eRE pressure as required by Specification S.S.14.d, shall be considered met. Following implementation: The first performance of SR 3.7.3.4, in accordance with Specification S.S.14.c.(i), shall be within the specified Frequency of 6 years, plus the 18-month allowance of SR 3.0.2, as measured from November 6,2003, the date of the most recent successful tracer gas test, or within the next 18 months if the time period since the most recent successful tracer gas test is greater than 6 years. The first performance of the periodic assessment of CRE habitability, Specification S.S.14.c.(ii), shall be within 3 years, plus the 9-month allowance of SR 3.0.2, as measured from November 6, 2003, the date of the most recent successful tracer gas test, or within the next 9 months if the time period since the most recent successful tracer gas test is greater than 3 years. The first performance of the periodic measurement of eRE pressure, Specification S.S.14.d, shall be within 24 months, plus the 184 days allowed by SR 3.0.2, as measured from March 23, 2006, the date of the most recent successful pressure measurement test, or within 184 days if not performed previously. Renewed License No. NPF-21 Amendment No. 22S -The information in the FSAR supplement, submitted pursuant to 10 CFR 54.21 (d), as supplemented by Commitment Nos. 1,5, 13, 14, 17, 18,23,24,26, 27,28,32,36,38,40,41,42,43,48,49,50,53,55,58, 59,60, 61,63,64,65, 66,67,68,69, and 70 of Appendix A of NUREG-2123, "Safety Evaluation Report Related to the License Renewal of Columbia Generating Station" dated May 2012, is henceforth part of the FSAR which will be updated in accordance with 10 CFR 50.71 (e). As such, the licensee may make changes to the programs and activities described in the UFSAR supplement and Commitment Nos. 1, 5, 13, 14,17,18,23,24,26,27,28,32,36, 38,40,41,42,43,48,49, 50, 53,55,58, 59,60,61,63,64,65,66,67,68,69, and 70 of Appendix A of NUREG-2123 provided the licensee evaluates such changes pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section. The licensee's FSAR supplement submitted pursuant to 10 CFR 54.21(d), as revised during the license renewal application review process, and as supplemented by Commitment Nos. 1,5,13,14,17, 18,23,24,26,27,28,32, 36,38,40,41,42,43,48,49,50,53, 55,58, 59,60,61,63,64,65,66,67,68, 69, and 70 of Appendix A of NUREG-2123, describes certain future programs and activities to be completed before the period of extended operation. Energy Northwest shall complete these activities no later than June 20, 2023, and shall notify the NRC in writing when implementation of these activities is complete. To prevent lateral motion of the core plate, the licensee shall install core plate wedges around the periphery of the core plate within the shroud on or before December 20,2021. Upon completion of the core plate wedge installation, the licensee shall submit a written report to the NRC staff summarizing the results of the installation. The licensee shall also submit a written report regarding any corrective action taken related to core plate rim hold-down bolts or core plate wedges and the results of extent of condition reviews on or before December 20, 2021. Renewed License No. NPF-21 Amendment No. 225 Exemptions from certain requirements of Appendices G, Hand J to 10 CFR Part 50, are described in the Safety Evaluation Report. These exemptions are authorized by law and will not endanger life or property or the common defense and security and are otherwise in the public interest. Therefore, these exemptions are hereby granted pursuant to 10 CFR 50.12. With the granting of this exemption the facility will operate, to the extent authorized herein, in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission. The licensee shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification, and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The plan, which contains Safeguards Information protected under 10 CFR 73.21, is entitled: "Columbia Generating Station Physical Security Plan, Training and Qualification Plan, Safeguards Contingency Plan, and Independent Spent Fuel Storage Installation Plan." Energy Northwest shall fully implement and maintain in effect all provisions of the Commission-approved cyber security plan (CSP), including changes made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The Energy Northwest CSP was approved by License Amendment No. 222. Deleted. The licensee shall notify the Commission, as soon as possible but not later than one hour, of any accident at this facility which could result in an unplanned release of quantities of fission products in excess of allowable limits for normal operation established by the Commission. The licensee shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims. Renewed License No. NPF-21 Amendment No. 225 -This renewed license is effective as of the date of issuance and shall expire at midnight on December 20,2043. FOR THE NUCLEAR REGULATORY COMMISSION (Original Signed By) Eric J. Leeds, Director Office of Nuclear Reactor Regulation Enclosures: 1. Appendix A Technical Specifications 2. Appendix B Environmental Protection Plan 3. Appendix C Additional Conditions Date of Issuance: May 22, 2012 Renewed License No. NPF-21 Amendment No. 225 ATTACHMENT 1 TO OPERATING LICENSE Amendment No. 157,223 AITACHMENT Amendment No. 162,223 ATTACHMENT LIST OF SHIELD 1. Deleted. 2. Deleted. 3. Deleted. 4. **5. FSAR Figure 12.3-12, Zone G-9 -The access blockout to duplicate centrifuge **6. FSAR Figure 12.3-12, Zone F-9 -Same as above for the duplicate **7. FSAR Figure 12.3-13, Zone J-5 -The blockout for one of the two decon **8. FSAR Figure 12.3-11, Zone D-8 -The two block walls at the north end of the loading bay. **9. FSAR Figure 12.3-11, Zone E-8 -The leaded glass viewing window in the radwaste area. Shield walls and window identified in items 5, 6, 7, 8, and 9 will be installed if the associated radiation levels at these locations exceed 2.5mR/hr as dictated by the ongoing ALARA reviews. Amendment No. 225 TABLE OF 1.0 USE AND APPLICATION 1.1 Definitions .............................................................................................................. 1.2 Logical Connectors ................................................................................................ 1.3 Completion Times .................................................................................................1.4 Frequency ............................................................................................................. 2.0 SAFETY LIMITS (SLs) 2.1 SLs ........................................................................................................................ 2.2 SL Violations ......................................................................................................... 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ..................... 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY .................................... 3.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM) ............................................................................ 3.1.2 Reactivity Anomalies .......................................................................................... 3.1.3 Control Rod OPERABILITY ................................................................................ 3 3.1.4 Control Rod Scram Times .................................................................................. 3.1.5 Control Rod Scram Accumulators ...................................................................... 3.1.6 Rod Pattern Control. ........................................................................................... 3.1.7 Standby Liquid Control (SLC) System ................................................................ 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves ................................... 3.2 POWER DISTRIBUTION LIMITS 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) ............. 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR) ................................................. 3.2.3 LINEAR HEAT GENERATION RATE (LHGR) ................................................... 3.2.4 Average Power Range Monitor (APRM) Gain and Setpoint ............................... 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation ......................................... 3.3.1.2 Source Range Monitor (SRM) Instrumentation ............................................... 3.3.1.3 Oscillation Power Range Monitor (OPRM) Instrumentation ............................ 3.3.2.1 Control Rod Block Instrumentation .................................................................. 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation ............. 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ............................................ 3.3.3. 3.3.3.2 Remote Shutdown System .............................................................................. 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation ............... Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation .................................................................... 3.3.4.2-1 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation ............................ 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation ..................... Columbia Generating Amendment -+69,-+74 225 TABLE OF INSTRUMENTATION (continued) 3.3.6.1 Primary Containment Isolation Instrumentation .............................................. 3.3.6.2 Secondary Containment Isolation Instrumentation ......................................... 3.3.7.1 Control Room Emergency Filtration (CREF) System Instrumentation ............ 3.3.8.1 Loss of Power (LOP) Instrumentation ............................................................. 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring ......................... REACTOR COOLANT SYSTEM (RCS) 3.4.1 Recirculation Loops Operating ........................................................................... 3.4.2 Jet Pumps .......................................................................................................... 3.4.3 Safety/Relief Valves (SRVs) -C!: 25% RTP ........................................................ 3.4.4 Safety/Relief Valves (SRVs) -< 25% RTP ........................................................ 3.4.5 RCS Operational LEAKAGE .............................................................................. 3.4.6 RCS Pressure Isolation Valve (PIV) Leakage .................................................... 3.4.7 RCS Leakage Detection Instrumentation ........................................................... 3.4.8 RCS Specific Activity .......................................................................................... 3.4.9 Residual Heat Removal (RHR) Shutdown Cooling System -Hot Shutdown ..... 3.4.9-1 3.4.10 Residual Heat Removal (RHR) Shutdown Cooling System -Cold Shutdown .. 3.4.1 0-1 3.4.11 RCS Pressure and Temperature (PIT) Limits .................................................. 3.4.12 Reactor Steam Dome Pressure ....................................................................... EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS -Operating .............................................................................................. 3.5.2 ECCS -Shutdown .............................................................................................. 3.5.3 RCIC System ..................................................................................................... CONTAINMENT SYSTEMS 3.6.1.1 Primary Containment ...................................................................................... 3.6.1.2 Primary Containment Air Lock ........................................................................ 3.6.1.3 Primary Containment Isolation Valves (PCIVs) ............................................... 3.6.1.4 Drywell Air Temperature ................................................................................. 3.6.1.5 Residual Heat Removal (RHR) Drywell Spray ................................................ 3.6.1.6 Reactor Building-to-Suppression Chamber Vacuum Breakers ....................... 3.6.1.7 Suppression Chamber-to-Drywell Vacuum Breakers ...................................... 3.6.2.1 Suppression Pool Average Temperature ........................................................ 3.6.2.2 Suppression Pool Water Level. ....................................................................... 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling ............................. 3.6.3.1 Deleted 3.6.3.2 Primary Containment Atmosphere Mixing System .......................................... 3.6.3.3 Primary Containment Oxygen Concentration .................................................. 3.6.4.1 Secondary Containment.. ................................................................................ 3.6.4.2 Secondary Containment Isolation Valves (SCIVs) .......................................... 3.6.4.3 Standby Gas Treatment (SGT) System .......................................................... Columbia Generating ii Amendment 169,1 QQ 225 TABLE OF 3.7 PLANT SYSTEMS 3.7.1 Standby Service Water (SW) System and Ultimate Heat Sink (UHS) ................ 3.7.2 High Pressure Core Spray (HPCS) Service Water (SW) System ...................... 3.7.3 Control Room Emergency Filtration (CREF) System ......................................... 3.7.4 Control Room Air Conditioning (AC) System ...................................................... 3.7.5 Main Condenser Offgas ..................................................................................... 3.7.6 Main Turbine Bypass System ............................................................................. 3.7.7 Spent Fuel Storage Pool Water Level ................................................................ 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources -Operating ..................................................................................... 3.8.2 AC Sources -Shutdown ..................................................................................... 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air .......................................................... 3.8.4 DC Sources -Operating .................................................................................... 3.8.5 DC Sources -Shutdown ..................................................................................... 3.8.6 Battery Parameters ............................................................................................ 3.8.7 Distribution Systems -Operating ........................................................................ 3.8.8 Distribution Systems -Shutdown ........................................................................ 3.9 REFUELING OPERATIONS 3.9.1 Refueling Equipment Interlocks .......................................................................... 3.9.2 Refuel Position One-Rod-Out Interlock .............................................................. 3.9.3 Control Rod Position .......................................................................................... 3.9.4 Control Rod Position Indication .......................................................................... 3.9.5 Control Rod OPERABILITY -Refueling ............................................................. 3.9.6 Reactor Pressure Vessel (RPV) Water Level -Irradiated Fuel .......................... 3.9.7 Reactor Pressure Vessel (RPV) Water Level-New Fuel or Control Rods ........ 3.9.8 Residual Heat Removal (RHR) -High Water Level. ........................................... 3.9.9 Residual Heat Removal (RHR) -Low Water Level ............................................. 3.9.10 Decay Time ...................................................................................................... 3.10 SPECIAL OPERATIONS 3.10.1 Inservice Leak and Hydrostatic Testing Operation ........................................... 3.10.2 Reactor Mode Switch Interlock Testing ............................................................ 3.10.3 Single Control Rod Withdrawal -Hot Shutdown ............................................... 3.10.4 Single Control Rod Withdrawal -Cold Shutdown ............................................. 3.10.5 Single Control Rod Drive (CRD) Removal-Refueling ..................................... 3.10.6 Multiple Control Rod Withdrawal -Refueling .................................................... 3.10.7 Control Rod Testing -Operating ....................................................................... 3.10.8 SHUTDOWN MARGIN (SDM) Test -Refueling .............................................. 4.0 DESIGN FEATURES 4.1 Site Location ......................................................................................................... 4.2 Reactor Core ......................................................................................................... 4.3 Fuel Storage .......................................................................................................... Columbia Generating Station iii Amendment 199,204 225 TABLE OF 5.0 ADMINISTRATIVE CONTROLS 5.1 Responsibility ........................................................................................................ 5.2 Organization .......................................................................................................... 5.3 Unit Staff Qualifications ......................................................................................... 5.4 Procedures ............................................................................................................ 5.5 Programs and Manuals ......................................................................................... 5.6 Reporting Requirements ....................................................................................... 5.7 High Radiation Area .............................................................................................. Columbia Generating Station iv Amendment 149,169225 1.1 Definitions 1.0 USE AND APPLICATION 1.1 Definitions The defined terms of this section appear in capitalized type and are applicable throughout these Technical Specifications and Bases. ACTIONS AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) CHANNEL CALIBRATION CHANNEL CHECK CHANNEL FUNCTIONAL TEST Definition ACTIONS shall be that part of a Specification that prescribes Required Actions to be taken under designated Conditions within specified Completion Times. The APLHGR shall be applicable to a specific planar height and is equal to the sum of the LHGRs for all the fuel rods in the specified bundle at the specified height divided by the number of fuel rods in the fuel bundle at the height. A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass the entire channel, including the required sensor, alarm, display, and trip functions, and shall include the CHANNEL FUNCTIONAL TEST. Calibration of instrument channels with resistance temperature detector (RTD) or thermocouple sensors may consist of an inplace qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is calibrated. A CHANNEL CHECK shall be the qualitative assessment, by observation, of channel behavior during operation. This determination shall include, where possible, comparison of the channel indication and status to other indications or status derived from independent instrument channels measuring the same parameter. A CHANNEL FUNCTIONAL TEST shall be the injection of a simulated or actual signal into the channel as close to the sensor as practicable to verify OPERABILITY, including required alarm, interlock, display, and trip functions, and channel failure trips. The CHANNEL FUNCTIONAL TEST may be performed by means of any series of sequential, overlapping, or total channel steps so that the entire channel is tested. Columbia Generating Station 1.1-1 Amendment No . .:1-49,.:tS9 225 Definitions 1.1 1.1 Definitions CORE ALTERATION CORE OPERATING LIMITS REPORT (COLR) DOSE EQUIVALENT 1-131 EMERGENCY CORE COOLING SYSTEM (ECCS) RESPONSE TIME CORE ALTERATION shall be the movement of any fuel, sources, or reactivity control components within the reactor vessel with the vessel head removed and fuel in the vessel. The following exceptions are not considered to be CORE ALTERATIONS: a. Movement of source range monitors, local power range monitors, intermediate range monitors, traversing incore probes, or special movable detectors (including undervessel replacement); and b. Control rod movement, provided there are no fuel assemblies in the associated core cell. Suspension of CORE ALTERATIONS shall not preclude completion of movement of a component to a safe position. The COLR is the unit specific document that provides cycle specific parameter limits for the current reload cycle. These cycle specific limits shall be determined for each reload cycle in accordance with Specification 5.6.3. Plant operation within these limits is addressed in individual Specifications. DOSE EQUIVALENT 1-131 shall be that concentration of 1-131 (microcuries/gram) that alone would produce the same Total Effective Dose Equivalent (TEDE) dose as the quantity and isotopic mixture of 1-131,1-132,1-133,1-134, and 1-135 actually present. The dose conversion factors used for this calculation shall be those listed in Federal Guidance Report (FGR) 11, "Limiting Values of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion," 1988. The ECCS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ECCS initiation setpoint at the channel sensor until the ECCS equipment is capable of performing its safety function {i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.}. Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. Columbia Generating Station 1.1-2 Amendment No. 49Q,4Q9 225 Definitions 1.1 1.1 Definitions END OF CYCLE RECIRCULATION PUMP TRIP (EOC-RPT) SYSTEM RESPONSE TIME ISOLATION SYSTEM RESPONSE TIME LEAKAGE The EOC-RPT SYSTEM RESPONSE TIME shall be that time interval from initial signal generation by the associated turbine throttle valve limit switch or from when the turbine governor* valve hydraulic control oil pressure drops below the pressure switch setpoint to complete suppression of the electric arc between the fully open contacts of the recirculation pump circuit breaker. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. The ISOLATION SYSTEM RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its isolation initiation setpoint at the channel sensor until the isolation valves travel to their required positions. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. LEAKAGE shall be: Identified LEAKAGE LEAKAGE into the drywell such as that from pump seals or valve packing. that is captured and conducted to a sump or collecting tank; or LEAKAGE into the drywell atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; Unidentified LEAKAGE All LEAKAGE into the drywell that is not identified LEAKAGE; Total LEAKAGE Sum of the identified and unidentified LEAKAGE; and Pressure Boundary LEAKAGE LEAKAGE through a nonisolable fault in a Reactor Coolant System (RCS) component body, pipe wall, or vessel wall. Columbia Generating 1.1-3 Amendment No. 449,+99 225 Definitions 1.1 1.1 Definitions LINEAR HEAT GENERATION RATE (LHGR) LOGIC SYSTEM FUNCTIONAL TEST MAXIMUM FRACTION OF LIMITING POWER DENSITY (MFLPD) MINIMUM CRITICAL POWER RATIO (MCPR) MODE OPERABLE -OPERABILITY PHYSICS TESTS The LHGR shall be the heat generation rate per unit length of fuel rod. It is the integral of the heat flux over the heat transfer area associated with the unit length. A LOGIC SYSTEM FUNCTIONAL TEST shall be a test of all required logic components (Le .. all required relays and contacts. trip units. solid state logic elements. etc.) of a logic circuit. from as close to the sensor as practicable up to. but not including. the actuated device, to verify OPERABILITY. The LOGIC SYSTEM FUNCTIONAL TEST may be performed by means of any series of sequential. overlapping, or total system steps so that the entire logic system is tested. The MFLPD shall be the largest value of the fraction of limiting power density (FLPD) in the core. The FLPD shall be the LHGR existing at a given location divided by the specified LHGR limit for that bundle type. The MCPR shall be the smallest critical power ratio (CPR) that exists in the core for each class of fuel. The CPR is that power in the assembly that is calculated by application of the appropriate correlation(s) to cause some point in the assembly to experience boiling transition. divided by the actual assembly operating power. A MODE shall correspond to anyone inclusive combination of mode switch position. average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1 with fuel in the reactor vessel. A system, subsystem. division. component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication. and other auxiliary equipment that are required for the system, subsystem, division, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s). PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation. These tests are: Described in Chapter 14. Initial Test Program of the FSAR; Authorized under the provisions of 10 CFR 50.59; or Columbia Generating 1.1-4 Amendment No . .:t49,4S9 225 Definitions 1.1 1.1 Definitions PHYSICS TESTS (continued) RATED THERMAL POWER (RTP) REACTOR PROTECTION SYSTEM (RPS) RESPONSE TIME SHUTDOWN MARGIN (SDM) STAGGERED TEST BASIS THERMAL POWER Otherwise approved by the Nuclear Regulatory Commission. RTP shall be a total reactor core heat transfer rate to the reactor coolant of 3486 MWt. The RPS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its RPS trip setpoint at the channel sensor until de-energization of the scram pilot valve solenoids. The response time may be measured by means of any series of sequential. overlapping, or total steps so that the entire response time is measured. SDM shall be the amount of reactivity by which the reactor is subcritical or would be subcritical assuming that: The reactor is xenon free; The moderator temperature is 68°F; and All control rods are fully inserted except for the single control rod of highest reactivity worth, which is assumed to be fully withdrawn. With control rods not capable of being fully inserted, the reactivity worth of these control rods must be accounted for in the determination of SDM. A STAGGERED TEST BASIS shall consist of the testing of one of the systems, subsystems, channels, or other designated components during the interval specified by the Surveillance Frequency, so that all systems, subsystems, channels, or other designated components are tested during n Surveillance Frequency intervals, where n is the total number of systems, subsystems, channels, or other designated components in the associated function. THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant. Columbia Generating 1.1-5 Amendment No. -149,469 225 Definitions 1.1 1.1 Definitions TURBINE BYPASS SYSTEM RESPONSE TIME The TURBINE BYPASS SYSTEM RESPONSE TIME shall be the time from when the turbine bypass control unit generates a turbine bypass valve flow signal until 80% of the turbine bypass capacity is established. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. Columbia Generating Station 1.1-6 Amendment No. 149,169225 Definitions 1.1 Table 1.1-1 (page 1 of 1) MODES MODE TITLE REACTOR MODE SWITCH POSITION AVERAGE REACTOR COOLANT TEMPERATURE (OF) 1 2 3 4 5 Power Operation Startup Hot Shutdown(a) Cold Shutdown(a) Refueling(b) Run Refuel(a) or Startup/Hot Standby Shutdown Shutdown Shutdown or Refuel NA NA > 200 :.:; 200 NA (a) All reactor vessel head closure bolts fully tensioned. (b) One or more reactor vessel head closure bolts less than fully tensioned. Columbia Generating Station 1.1-7 Amendment No. 449,169 225 Logical Connectors 1.2 1.0 USE AND APPLICATION 1.2 Logical Connectors The purpose of this section is to explain the meaning of logical connectors. Logical connectors are used in Technical Specifications (TS) to discriminate between, and yet connect, discrete Conditions, Required Actions, Completion Times, Surveillances, and Frequencies. The only logical connectors that appear in TS are AND and OR. The physical arrangement of these connectors constitutes logical conventions with specific meanings. Several levels of logic may be used to state Required Actions. These levels are identified by the placement (or nesting) of the logical connectors and by the number assigned to each Required Action. The first level of logic is identified by the first digit of the number assigned to a Required Action and the placement of the logical connector in the first level of nesting (Le., left justified with the number of the Required Action). The successive levels of logic are identified by additional digits of the Required Action number and by successive indentions of the logical connectors. . When logical connectors are used to state a Condition, Completion Time, Surveillance, or Frequency, only the first level of logic is used, and the logical connector is left justified with the statement of the Condition, Completion Time, Surveillance. or Frequency. The following examples illustrate the use of logical connectors. Logical Connectors EXAM PLE 1.2-1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. LCO not met. A.1 Verify . .. A2 Restore ... In this example, the logical connector AND is used to indicate that, when in Condition A, both Required Actions A 1 and A.2 must be completed. Columbia Generating 1.2-1 Amendment No. +49,.te9 225 Logical Connectors 1.2 1.2 Logical Connectors EXAMPLES (continued) EXAMPLE 1.2-2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. LCO not met. A.1 Trip ... A.2.1 Verify ... A.2.2.1 Reduce ... A.2.2.2 Perform ... A.3 Align ... This example represents a more complicated use of logical connectors. Required Actions A.1, A.2, and A.3 are alternative choices, only one of which must be performed as indicated by the use of the logical connector OR and the left justified placement. Anyone of these three Actions may be chosen. If A.2 is chosen, then both A.2.1 and A.2.2 must be performed as indicated by the logical connector AND. Required Action A.2.2 is met by performing A.2.2.1 or A.2.2.2. The indented position of the logical connector OR indicates that A.2.2.1 and A.2.2.2 are alternative choices, only one of which must be performed. Columbia Generating Station 1.2-2 Amendment No. 449,4-69 225 Completion Times 1.3 USE AND APPLICATION Completion Times PURPOSE The purpose of this section is to establish the Completion Time convention and to provide guidance for its use. Limiting Conditions for Operation (LCOs) specify minimum requirements for ensuring safe operation of the unit. The ACTIONS associated with an LCO state Conditions that typically describe the ways in which the requirements of the LCO can fail to be met. Specified with each stated Condition are Required Action(s) and Completion Time(s). The Completion Time is the amount of time allowed for completing a Required Action. It is referenced to the time of discovery of a situation (e.g., inoperable equipment or variable not within limits) that requires entering an ACTIONS Condition unless otherwise specified, providing the unit is in a MODE or specified condition stated in the Applicability of the LCO. Required Actions must be completed prior to the expiration of the specified Completion Time. An ACTIONS Condition remains in effect and the Required Actions apply until the Condition no longer exists or the unit is not within the LCO Applicability. If situations are discovered that require entry into more than one Condition at a time within a single LCO (multiple Conditions), the Required Actions for each Condition must be performed within the associated Completion Time. When in multiple Conditions, separate Completion Times are tracked for each Condition starting from the time of discovery of the situation that required entry into the Condition. Once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition unless specifically stated. The Required Actions of the Condition continue to apply to each additional failure, with Completion Times based on initial entry into the Condition. However, when a subsequent division, subsystem, component, or variable expressed in the Condition is discovered to be inoperable or not within limits, the Completion Time(s) may be extended. To apply this Completion Time extension, two criteria must first be met. The subsequent inoperability: Must exist concurrent with the first inoperability; and Must remain inoperable or not within limits after the first inoperability is resolved. Columbia Generating 1.3-1 Amendment No. 449,4$ 225 Completion Times 1.3 Completion Times DESCRIPTION (continued) The total Completion Time allowed for completing a Required Action to address the subsequent inoperability shall be limited to the more restrictive of either: The stated Completion Time, as measured from the initial entry into the Condition, plus an additional 24 hours; or The stated Completion Time as measured from discovery of the subsequent inoperability. The above Completion Time extension does not apply to those Specifications that have exceptions that allow completely separate entry into the Condition (for each division, subsystem, component, or variable expressed in the Condition) and separate tracking of Completion Times based on this re-entry. These exceptions are stated in individual Specifications. The above Completion Time extension does not apply to a Completion Time with a modified "time zero." This modified "time zero" may be expressed as a repetitive time (Le., "once per 8 hours," where the Completion Time is referenced from a previous completion of the Required Action versus the time of Condition entry) or as a time modified by the phrase "from discovery ... " Example 1.3-3 illustrates one use of this type of Completion Time. The 10 day Completion Time specified for Conditions A and B in Example 1.3-3 may not be extended. EXAMPLES The following examples illustrate the use of Completion Times with different types of Conditions and changing Conditions. EXAMPLE 1.3-1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and associated Completion Time not met. B.1 Be in MODE 3. B.2 Be in MODE 4. 12 hours 36 hours Condition B has two Required Actions. Each Required Action has its own separate Completion Time. Each Completion Time is referenced to the time that Condition B is entered. Columbia Generating 1.3-2 Amendment No. 449,469 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) The Required Actions of Condition B are to be in MODE 3 within 12 hours AND in MODE 4 within 36 hours. A total of 12 hours is allowed for reaching MODE 3 and a total of 36 hours (not 48 hours) is allowed for reaching MODE 4 from the time that Condition B was entered. If MODE 3 is reached within 6 hours, the time allowed for reaching MODE 4 is the next 30 hours because the total time allowed for reaching MODE 4 is 36 hours. If Condition B is entered while in MODE 3, the time allowed for reaching MODE 4 is the next 36 hours. EXAMPLE 1.3-2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One pump A.1 Restore pump to 7 days inoperable. OPERABLE status. B. Required Action and B.1 Be in MODE 3. 12 hours associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours When a pump is declared inoperable, Condition A is entered. If the pump is not restored to OPERABLE status within 7 days, Condition B is also entered and the Completion Time clocks for Required Actions B.1 and B.2 start. If the inoperable pump is restored to OPERABLE status after Condition B is entered, Conditions A and B are exited, and therefore, the Required Actions of Condition B may be terminated. When a second pump is declared inoperable while the first pump is still inoperable, Condition A is not re-entered for the second pump. LCO 3.0.3 is entered, since the ACTIONS do not include a Condition for more than one inoperable pump. The Completion Time clock for Condition A does not stop after LCO 3.0.3 is entered, but continues to be tracked from the time Condition A was initially entered. Columbia Generating Station 1.3-3 Amendment No. .:t49,+e9 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) While in LCO 3.0.3, if one of the inoperable pumps is restored to OPERABLE status and the Completion Time for Condition A has not expired, LCO 3.0.3 may be exited and operation continued in accordance with Condition A. While in LCO 3.0.3, if one of the inoperable pumps is restored to OPERABLE status and the Completion Time for Condition A has expired, LCO 3.0.3 may be exited and operation continued in accordance with Condition B. The Completion Time for Condition B is tracked from the time the Condition A Completion Time expired. On restoring one of the pumps to OPERABLE status, the Condition A Completion Time is not reset, but continues from the time the first pump was declared inoperable. This Completion Time may be extended if the pump restored to OPERABLE status was the first inoperable pump. A 24 hour extension to the stated 7 days is allowed, provided this does not result in the second pump being inoperable for> 7 days. Columbia Generating Station 1.3-4 Amendment No. 44B,4W 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) EXAMPLE 1.3-3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One Function X subsystem inoperable. A.1 Restore Function X subsystem to OPERABLE status. 7 days AND 10 days from discovery of failure to meet the LCO B. One Function Y subsystem inoperable. B.1 Restore Function Y subsystem to OPERABLE status. 72 hours AND 10 days from discovery of failure to meet the LCO C. One Function X subsystem inoperable. AND C.1 Restore Function X subsystem to OPERABLE status. OR 72 hours One Function Y subsystem inoperable. C.2 Restore Function Y subsystem to OPERABLE status. 72 hours When one Function X subsystem and one Function Y subsystem are inoperable, Condition A and Condition B are concurrently applicable. The Completion Times for Condition A and Condition B are tracked separately for each subsystem, starting from the time each subsystem was declared inoperable and the Condition was entered. A separate Completion Time is established for Condition C and tracked from the time the second subsystem was declared inoperable (I.e., the time the situation described in Condition C was discovered). Columbia Generating Station 1.3-5 Amendment No. 449,499 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) If Required Action C.2 is completed within the specified Completion Time, Conditions Band C are exited. If the Completion Time for Required Action A.1 has not expired, operation may continue in accordance with Condition A. The remaining Completion Time in Condition A is measured from the time the affected subsystem was declared inoperable (i.e., initial entry into Condition A). The Completion Times of Conditions A and B are modified by a logical connector, with a separate 10 day Completion Time measured from the time it was discovered the LCO was not met. In this example. without the separate Completion Time, it would be possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. The separate Completion Time modified by the phrase "from discovery of failure to meet the LCO" is designed to prevent indefinite continued operation while not meeting the LCO. This Completion Time allows for an exception to the normal "time zero" for beginning the Completion Time "clock". In this instance, the Completion Time "time zero" is specified as commencing at the time the LCO was initially not met, instead of at the time the associated Condition was entered. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Restore valve(s) to 4 hours valves OPERABLE status. inoperable. B. Required Action and B.1 Be in MODE 3. 12 hours associated Completion Time not met. AND B.2 Be in MODE 4. 36 hours A single Completion Time is used for any number of valves inoperable at the same time. The Completion Time associated with Condition A is based on the initial entry into Condition A and is not tracked on a per valve basis. Declaring subsequent valves inoperable, while Condition A is still in effect, does not trigger the tracking of separate Completion Times. Columbia Generating Station Amendment No. +49,469 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) Once one of the valves has been restored to OPERABLE status, the Condition A Completion Time is not reset, but continues from the time the first valve was declared inoperable. The Completion Time may be extended if the valve restored to OPERABLE status was the first inoperable valve. The Condition A Completion Time may be extended for up to 4 hours provided this does not result in any subsequent valve being inoperable for> 4 hours. If the Completion Time of 4 hours (pi us the extension) expires while one or more valves are still inoperable, Condition B is entered. EXAMPLE 1.3-5 ACTIONS Separate Condition entry is allowed for each inoperable valve. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Restore valve to 4 hours valves OPERABLE status. inoperable. B. Required Action and B.1 Be in MODE 3. 12 hours associated AND Completion Time not met. B.2 Be in MODE 4. 36 hours The Note above the ACTIONS Table is a method of modifying how the Completion Time is tracked. If this method of modifying how the Completion Time is tracked was applicable only to a specific Condition, the Note would appear in that Condition rather than at the top of the ACTIONS Table. Columbia Generating Station 1.3-7 Amendment No. -149,+SB 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) The Note allows Condition A to be entered separately for each inoperable valve, and Completion Times tracked on a per valve basis. When a valve is declared inoperable, Condition A is entered and its Completion Time starts. If subsequent valves are declared inoperable, Condition A is entered for each valve and separate Completion Times start and are tracked for each valve. If the Completion Time associated with a valve in Condition A expires, Condition B is entered for that valve. If the Completion Times associated with subsequent valves in Condition A expire, Condition B is entered separately for each valve and separate Completion Times start and are tracked for each valve. If a valve that caused entry into Condition B is restored to OPERABLE status, Condition B is exited for that valve. Since the Note in this example allows multiple Condition entry and tracking of separate Completion Times, Completion Time extensions do not apply. EXAMPLE 1.3-6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One channel inoperable. A.1 Perform SR 3.x.x.x. OR Once per 8 hours A.2 Reduce THERMAL POWER to ::; 50% RTP. 8 hours B. Required Action and associated Completion Time not met. B.1 Be in MODE 3. 12 hours Columbia Generating Station 1.3-8 Amendment No. 449-,-lS9 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) Entry into Condition A offers a choice between Required Action A.1 or A.2. Required Action A.1 has a "once per" Completion Time, which qualifies for the 25% extension, per SR 3.0.2, to each performance after the initial performance. The initial 8 hour interval of Required Action A.1 begins when Condition A is entered and the initial performance of Required Action A.1 must be completed within the first 8 hour interval. If Required Action A.1 is followed and the Required Action is not met within the Completion Time (plus the extension allowed by SR 3.0.2), Condition B is entered. If Required Action A.2 is followed and the Completion Time of 8 hours is not met, Condition B is entered. If after entry into Condition B, Required Action A.1 or A.2 is met, Condition B is exited and operation may then continue in Condition A. EXAMPLE 1.3-7 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One subsystem inoperable. A.1 Verify affected subsystem isolated. AND A.2 Restore subsystem to OPERABLE status. 1 hour AND Once per 8 hours thereafter 72 hours B. Required Action and associated Completion B.1 Be in MODE 3. AND 12 hours Time not met. B.2 Be in MODE 4. 36 hours Columbia Generating Station 1.3-9 Amendment No. 449,4(3.9 225 Completion Times 1.3 1.3 Completion Times EXAMPLES (continued) Required Action A.1 has two Completion Times. The 1 hour Completion Time begins at the time the Condition is entered and each "Once per 8 hours thereafter" interval begins upon performance of Required Action A.1. If after Condition A is entered, Required Action A.1 is not met within either the initial 1 hour or any subsequent 8 hour interval from the previous performance (plus the extension allowed by SR 3.0.2), Condition B is entered. The Completion Time clock for Condition A does not stop after Condition B is entered, but continues from the time Condition A was initially entered. If Required Action A.1 is met after Condition B is entered, Condition B is exited and operation may continue in accordance with Condition A, provided the Completion Time for Required Action A.2 has not expired. IMMEDIATE When "Immediately" is used as a Completion Time, the Required Action COMPLETION TIME should be pursued without delay and in a controlled manner. Columbia Generating Station 1.3-10 Amendment No. 449,469 225 Frequency 1.4 1.0 USE AND APPLICATION 1.4 Frequency PURPOSE The purpose of this section is to define the proper use and application of Frequency requirements. Each Surveillance Requirement (SR) has a specified Frequency in which the Surveillance must be met in order to meet the associated Limiting Conditions for Operation (LCO). An understanding of the correct application of the specified Frequency is necessary for compliance with the SR. The "specified Frequency" is referred to throughout this section and each of the Specifications of Section 3.0, "Surveillance Requirement (SR) Applicability." The "specified Frequency" consists of the requirements of the Frequency column of each SR, as well as certain Notes in the Surveillance column that modify performance requirements. Sometimes special situations dictate when the requirements of a Surveillance are to be met. They are "otherwise stated" conditions allowed by SR They may be stated as clarifying Notes in the Surveillance, as part of the Surveillance, or both. Situations where a Surveillance could be required (Le., its Frequency could expire), but where it is not possible or not desired that it be performed until sometime after the associated LCO is within its Applicability, represent potential SR 3.0.4 conflicts. To avoid these conflicts, the SR (Le., the Surveillance or the Frequency) is stated such that it is only "required" when it can be and should be performed. With an SR satisfied, SR 3.0.4 imposes no restriction. The use of "met" or "performed" in these instances conveys specified meanings. A Surveillance is "met" only when the acceptance criteria are satisfied. Known failure of the requirements of a Surveillance, even without a Surveillance specifically being "performed," constitutes a Surveillance not "met." "Performance" refers only to the requirement to specifically determine the ability to meet the acceptance criteria. Some Surveillances contain notes that modify the Frequency of performance or the conditions during which the acceptance criteria must be satisfied. For these Surveillances, the MODE-entry restrictions of SR 3.0.4 may not apply. Such a Surveillance is not required to be performed prior to entering a MODE or other specified condition in the Applicability of the associated LCO if any of the following three conditions are satisfied: The Surveillance is not required to be met in the MODE or other specified condition to be entered; or Columbia Generating 1.4-1 Amendment No. 4$,:wa 225 Frequency 1.4 Frequency DESCRIPTION (continued) The Surveillance is required to be met in the MODE or other specified condition to be entered, but has been performed within the speci'fied Frequency (Le., it is current) and is known not to be failed; or The Surveillance is required to be met, but not performed, in the MODE or other specified condition to be entered, and is known not to be failed. Examples 1.4-3, 1.4-4, 1.4-5, and 1.4-6 discusses these special situations. The following examples illustrate the various ways that Frequencies are specified. In these examples, the Applicability of the LCO (LCO not shown) is MODES 1, 2, and 3. EXAMPLE 1.4-1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Perform CHANNEL CHECK. 12 hours Example 1.4-1 contains the type of SR most often encountered in the Technical Specifications (TS). The Frequency specifies an interval (12 hours) during which the associated Surveillance must be performed at least one time. Performance of the Surveillance initiates the subsequent interval. Although the Frequency is stated as 12 hours, an extension of the time interval to 1.25 times the interval specified in the Frequency is allowed by SR 3.0.2 for operational flexibility. The measurement of this interval continues at all times, even when the SR is not required to be met per SR 3.0.1 (such as when the equipment is inoperable, a variable is outside specified limits, or the unit is outside the Applicability of the LCO). If the interval specified by SR 3.0.2 is exceeded while the unit is in a MODE or other specified condition in the Applicability of the LCO, and the performance of the Surveillance is not otherwise modified (refer to Examples 1.4-3 and 1.4-4), then SR 3.0.3 becomes applicable. Columbia Generating 1.4-2 Amendment No. 4S9,2Q& 225 Frequency 1.4 1.4 Frequency EXAMPLES (continued) If the interval as specified by SR 3.0.2 is exceeded while the unit is not in a MODE or other specified condition in the Applicability of the LCO for which performance of the SR is required, then SR 3.0.4 becomes applicable. The Surveillance must be performed within the Frequency requirements of SR 3.0.2, as modified by SR 3.0.3, prior to entry into the MODE or other specified condition or the LCO is considered not met (in accordance with SR 3.0.1) and LCO 3.0.4 becomes applicable. EXAMPLE 1.4-2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Verify flow is within limits. Once within 12 hours after ;::::25% RTP 24 hours thereafter Example 1.4-2 has two Frequencies. The first is a one time Frequency, and the second is of the type shown in Example 1.4-1. logical connector "AND" indicates that both Frequency requirements be met. Each time reactor power is increased from a power < 25% RTP to 25% RTP, the Surveillance must be performed 12 The use of "once" indicates a single performance will satisfy the Frequency (assuming no other Frequencies are connected by This type of Frequency does not qualify for the extension allowed SR "Thereafter" indicates future performances must be established SR 3.0.2, but only after a specified condition is first met (Le., the performance in this example). If reactor power decreases to < 25% the measurement of both intervals stops. New intervals start reactor power reaching 25% Columbia Generating Station 1.4-3 Amendment No. 225 Frequency 1.4 1.4 Frequency EXAMPLES (continued) EXAMPLE 1.4-3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY ----------------------------N OTE Not required to be performed until 12 hours after 25% RTP. 7 days Perform channel adjustment. The interval continues whether or not the unit operation is < 25% RTP between performances. As the Note modifies the required performance of the Surveillance, it is construed to be part of the "specified Frequency." Should the 7 day interval be exceeded while operation is < 25% RTP, this Note allows 12 hours after power reaches 25% RTP to perform the Surveillance. The Surveillance is still considered to be within the "specified Frequency." Therefore, if the Surveillance were not performed within the 7 day interval (plus the extension allowed by SR 3.0.2), but operation was < 25% RTP, it would not constitute a failure of the SR or failure to meet the LCO. Also, no violation of SR 3.0.4 occurs when changing MODES, even with the 7 day Frequency not met, provided operation does not exceed 12 hours (plus the extension allowed by SR 3.0.2) with power 25% RTP. Once the unit reaches 25% RTP, 12 hours would be allowed for completing the Surveillance. If the Surveillance were not performed within this 12 hour interval (plus the extension allowed by SR 3.0.2), there would then be a failure to perform a Surveillance within the specified Frequency, and the provisions of SR 3.0.3 would apply. Columbia Generating Station 1.4-4 Amendment No. 225 Frequency 1.4 1.4 Frequency EXAMPLES (continued) EXAMPLE SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Only required to be met in MODE 1. Verify leakage rates are within limits. 24 hours Example 1.4-4 specifies that the requirements of this Surveillance do not have to be met until the unit is in MODE 1. The interval measurement for the Frequency of this Surveillance continues at all times, as described in Example 1.4-1. However, the Note constitutes an "otherwise stated" exception to the Applicability of this Surveillance. Therefore, if the Surveillance were not performed within the 24 hour interval (plus the extension allowed by SR 3.0.2), but the unit was not in MODE 1, there would be no failure of the SR nor failure to meet the LCO. Therefore, no violation of SR 3.0.4 occurs when changing MODES, even with the 24 hour Frequency exceeded, provided the MODE change was not made into MODE 1. Prior to entering MODE 1 (assuming again that the 24 hour Frequency were not met). SR 3.0.4 would require satisfying the SR. Columbia Generating Station 1.4-5 Amendment No. 225 Frequency 1.4 1.4 Frequency EXAMPLES (continued) EXAMPLE 1.4-5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY -------------------------NO Only required to be performed in MODE 1. Perform complete cycle of the valve. 7 days The interval continues, whether or not the unit operation is in MODE 1, 2, or 3 (the assumed Applicability of the associated LCO) between performances. As the Note modifies the required performance of the Surveillance, the Note is construed to be part of the "specified Frequency." Should the 7 day interval be exceeded while operation is not in MODE 1, this Note allows entry into and operation in MODES 2 and 3 to perform the Surveillance. The Surveillance is still considered to be performed within the "specified Frequency" if completed prior to entering MODE 1. Therefore. if the Surveillance were not performed within the 7 day (plus the extension allowed by SR 3.0.2) interval, but operation was not in MODE 1, it would not constitute a failure of the SR or failure to meet the LCO. Also no violation of SR 3.0.4 occurs when changing MODES. even with the 7 day Frequency not met, provided operation does not result in entry into MODE 1. Once the unit reaches MODE 1, the requirement for the Surveillance to be performed within its specified Frequency applies and would require that the Surveillance had been performed. If the Surveillance were not performed prior to entering MODE 1, there would then be a failure to perform a Surveillance within the specified Frequency, and the provisions of SR 3.0.3 would apply. Columbia Generating Station 1.4-6 Amendment No. 225 Frequency 1.4 1.4 Frequency EXAMPLES (continued) EXAMPLE 1.4-6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY --------------------------NO TE Not required to be met in MODE 3. Verify parameter is within limits. 24 hours Example 1.4-6 specifies that the requirements of this Surveillance do not have to be met while the unit is in MODE 3 (the assumed Applicability of the associated LCO is MODES 1, 2, and 3). The interval measurement for the Frequency of this Surveillance continues at all times, as described in Example 1.4-1. However, the Note constitutes an "otherwise stated" exception to the Applicability of this Surveillance. Therefore, if the Surveillance were not performed within the 24 hour interval (plus the extension allowed by SR 3.0.2), and the unit was in MODE 3, there would be no failure of the SR nor failure to meet the LCO. Therefore, no violation of SR 3.0.4 occurs when changing MODES to enter MODE 3, even with the 24 hour Frequency exceeded, provided the MODE change does not result in entry into MODE 2. Prior to entering MODE 2 (assuming again that the 24 hour Frequency were not met), SR 3.0.4 would require satisfying the SR. Columbia Generating Station 1.4-7 Amendment No. 225 SLs 2.0 SAFETY LIMITS (SLs) 2.1 SLs 2.1.1 Reactor Core SLs 2.1.1.1 With the reactor steam dome pressure < 785 psig or core flow < 10% rated core flow: THERMAL POWER shall be 25% RTP. 2.1.1.2 With the reactor steam dome pressure 785 psig and core flow 10% rated core flow: The MCPR shall be 1.09 for two recirculation loop operation or 1.10 for single recirculation loop operation. 2.1.1.3 Reactor vessel water level shall be greater than the top of active irradiated fuel. 2.1.2 Reactor Coolant System Pressure SL Reactor steam dome pressure shall be 1325 psig. SL Violations With any SL violation, the following actions shall be completed within 2 hours: 2.2.1 Restore compliance with all SLs; and 2.2.2 Insert all insertable control rods. Columbia Generating 2.0-1 Amendment No. 499,4-89 225 LCO Applicability 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY LCO 3.0.1 LCOs shall be met during the MODES or other specified conditions in the Applicability, except as provided in LCO 3.0.2, LCO 3.0.7, and LCO 3.0.8. LCO Upon discovery of a failure to meet an LCO, the Required Actions of the associated Conditions shall be met, except as provided in LCO 3.0.5 and LCO 3.0.6. If the LCO is met or is no longer applicable prior to expiration of the specified Completion Time(s), completion of the Required Action(s) is not required, unless otherwise stated. LCO When an LCO is not met and the associated ACTIONS are not met, an associated ACTION is not provided, or if directed by the associated ACTIONS, the unit shall be placed in a MODE or other specified condition in which the LCO is not applicable. Action shall be initiated within 1 hour to place the unit, as applicable, in: MODE 2 within 7 hours; MODE 3 within 13 hours; and c. MODE 4 within 37 Exceptions to this Specification are stated in the individual Where corrective measures are completed that permit operation accordance with the LCO or ACTIONS, completion of the actions by LCO 3.0.3 is not LCO 3.0.3 is only applicable in MODES 1, 2, and LCO When an LCO is not met, entry into a MODE or other specified condition in the Applicability shall only be made: When the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time; After performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate; exceptions to this Specification are stated in the individual Specifications, or Columbia Generating 3.0-1 Amendment No. -+8-7,4-98225 3.0 LCO Applicability LCO Applicability 3.0.4 (continued) When an allowance is stated in the individual value, parameter, or other Specification. This Specification shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. LCO Equipment removed from service or declared inoperable to comply with ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate its OPERABILITY or the OPERABILITY of other equipment. This IS an exception to LCO 3.0.2 for the system returned to service under administrative control to perform the testing required to demonstrate OPERABILITY. LCO When a supported system LCO is not met solely due to a support system LCO not being met, the Conditions and Required Actions associated with this supported system are not required to be entered. Only the support system LCO ACTIONS are required to be entered. This is an exception to LCO 3.0.2 for the supported system. In this event, additional evaluations and limitations may be required in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP)." If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2. LCO Special Operations LCOs in Section 3.10 allow specified Technical Specifications (TS) requirements to be changed to permit performance of special tests and operations. Unless otherwise specified, all other TS requirements remain unchanged. Compliance with Special Operations LCOs is optional. When a Special Operations LCO is desired to be met but is not met, the ACTIONS of the Special Operations LCO shall be met. When a Special Operations LCO is not desired to be met, entry into a MODE or other specified condition in the Applicability shall only be made in accordance with the other applicable Specifications. Columbia Generating 3.0-2 Amendment No. 4W,4S+ 225 3.0 LCO Applicability LCO Applicability LCO When one or more required snubbers are unable to perform their associated support function(s), any affected supported LCO(s) are not required to be declared not met solely for this reason if risk is assessed and managed, and: The snubbers not able to perform their associated support function(s) are associated with only one train or subsystem of a multiple train or subsystem supported system or are associated with a single train or subsystem supported system and are able to perform their associated support function within 72 hours; or The snubbers not able to perform their associated support function(s) are associated with more than one train or subsystem of a multiple train or subsystem supported system and are able to perform their associated support function within 12 hours. At the end of the specified period the required snubbers must be able to perform their associated support function(s), or the affected supported system LCO(s) shall be declared not met. Columbia Generating 3.0-3 Amendment No. +8{),.:J-98 225 SR Applicability 3.0 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY SR SRs shall be met during the MODES or other specified conditions in the Applicability for individual LCOs, unless otherwise stated in the SR. Failure to meet a Surveillance, whether such failure is experienced during the performance of the Surveillance or between performances of the Surveillance, shall be failure to meet the LCO. Failure to perform a Surveillance within the specified Frequency shall be failure to meet the LCO except as provided in SR 3.0.3. Surveillances do not have to be performed on inoperable equipment or variables outside specified limits. SR The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met. For Frequencies specified as "once," the above interval extension does not apply. If a Completion Time requires periodic performance on a "once per ..." basis, the above Frequency extension applies to each performance after the initial performance. Exceptions to this Specification are stated in the individual Specifications. SR If it is discovered that a Surveillance was not performed within its specified Frequency, then compliance with the requirement to declare the LCO not met may be delayed, from the time of discovery, up to 24 hours or up to the limit of the specified Frequency, whichever is greater. This delay period is permitted to allow performance of the Surveillance. A risk evaluation shall be performed for any Surveillance delayed greater than 24 hours and the risk impact shall be managed. If the Surveillance is not performed within the delay period, the LCO must immediately be declared not met, and the applicable Condition(s) must be entered. When the Surveillance is performed within the delay period and the Surveillance is not met, the LCO must immediately be declared not met, and the applicable Condition(s) must be entered. SR Entry into a MODE or other specified condition in the Applicability of an LCO shall only be made when the LCO's Surveillances have been met within their specified Frequency, except as provided by SR 3.0.3. When an LCO is not met due to Surveillances not having been met, entry into a MODE or other specified condition in the Applicability shall only be made in accordance with LCO 3.0.4. Columbia Generating 3.0-4 Amendment No. -WB,-+W 225 3.0 SR Applicability SR Applicability SR 3.0.4 (continued) This provision shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit. Columbia Generating Station 3.0-5 Amendment No. +00,-1-8+ 225 SDM 3.1.1 REACTIVITY CONTROL SYSTEMS 3.1.1 SHUTDOWN MARGIN (SDM) 3.1.1 SDM shall be: 0.38% Aklk, with the highest worth control rod analytically determined; or 0.28% Ak/k, with the highest worth control rod determined by test. APPLICABILITY: MODES 1, 2, 3, 4, and 5. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A, SDM not within limits in 6 hours MODE 1 or 2. A,1 Restore SDM to within limits. ___ff -B. Required Action and B.1 Be in MODE 3. 12 associated Time of Condition A C. SDM not within limits in C.1 Initiate action to fully insert MODE 3. all insertable control D. SDM not within limits in 0.1 Initiate action to fully insert all insertable control rods. AND 0.2 Initiate action to restore 1 hour secondary containment to OPERABLE status. AND Columbia Generating 3.1.1-1 Amendment No. 225 3.1.1 SDM ACTIONS D. E. CONDITION (continued) SDM not within limits in MODE 5. D.3 AND D.4 E.1 REQUIRED ACTION Initiate action to restore one standby gas treatment (SGT) subsystem to OPERABLE status. Initiate action to restore isolation capability in each required secondary containment penetration flow path not isolated. Suspend CORE ALTERATIONS except for control rod insertion and fuel assembly removal. COMPLETION TIME 1 hour 1 hour Immediately E.2 AND E.3 Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Initiate action to restore secondary containment to OPERABLE status. Immediately 1 hour E.4 Initiate action to restore one SGT subsystem to OPERABLE status. 1 hour Columbia Generating Station 3.1.1-2 Amendment No. 449,499 225 3.1.1 SDM ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. (continued) E.5 Initiate action to restore isolation capability in each required secondary containment penetration flow path not isolated. 1 hour SURVEILLANCE SR 3.1.1.1 Verify SDM is: 0.38% ilklk with the highest worth control rod analytically determined; or 0.28% ilklk with the highest worth control rod determined by test. Prior to each in vessel fuel movement during fuel loading sequence AND Once within 4 hours after criticality following fuel movement within the reactor pressure vessel or control rod replacement Columbia Generating 3.1.1-3 Amendment No. :t49,-ie9 225 Reactivity Anomalies 3.1.2 3.1 REACTIVITY CONTROL SYSTEMS 3.1.2 Reactivity Anomalies 3.1.2 The reactivity difference between the monitored core kef! and the predicted core kef! shall be within +/- 1 % APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Core reactivity difference not within limit. A.1 Restore core reactivity difference to within limit. 72 hours B. Required Action and associated Completion Time not met. B.1 Be in MODE 3. 12 hours Columbia Generating 3.1.2-1 Amendment No. 449,+69 225 3.1.2 SURVEILLANCE SR Verify core reactivity difference between the monitored core kelf and the predicted core kelf is within +/- 1% dklk. Reactivity Anomalies Once within 24 hours after reaching equilibrium conditions following startup after fuel movement within the reactor pressure vessel or control rod replacement AND 1000 MWDIT thereafter during operations in MODE 1 Columbia Generating 3.1.2-2 Amendment No . .t49,4G9 225 3.1.3 Control Rod OPERABILITY 3.1 REACTIVITY CONTROL 3.1.3 Control Rod LCO 3.1.3 Each control rod shall be APPLICABILITY: MODES 1 and 2. ACTIONS Separate Condition entry is allowed for each control rod. CONDITION REQUIRED ACTION I COMPLETION TIME A. One withd rawn control rod stuck. Rod Worth Minimizer (RWM) may be bypassed as allowed by LCO 3.3.2.1, "Control Rod Block Instrumentation," if required, to allow continued operation. A.1 AND A.2 Verify stuck control rod separation criteria are met. Disarm the associated control rod drive (CRD). Immediately 2 hours Columbia Generating Station 3.1.3-1 Amendment No. 225 3.1.3 Control Rod OPERABILITY ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3 AND A.4 Perform SR 3.1.3.2 for each withdrawn OPERABLE control rod. Perform SR 3.1.1.1. 24 hours from discovery of Condition A concurrent with THERMAL POWER greater than the low power setpoint (LPSP) of the RWM 72 hours B. Two or more withdrawn control rods stuck. B.1 Be in MODE 3. 12 hours C. One or more control rods inoperable for reasons other than Condition A or B. C.1 AND C.2 ---------------NO TE RWM may be bypassed as allowed by LCO 3.3.2.1. if required, to allow insertion of inoperable control rod and continued operation. ------------...... _------------...... _..__... _....... Fully insert inoperable control rod. Disarm the associated CRD. 3 hours 4 hours Columbia Generating Station 3.1.3-2 Amendment No. 24-2,2+e 225 3.1.3 Control Rod OPERABILITY ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. ------------N 0 TE Not applicable when THERMAL POWER > 10% RTP. -----------_...... _......._... _----_... Two or more inoperable control rods not in compliance with banked position withdrawal sequence (BPWS) and not separated by two or more OPERABLE control rods. 0.1 OR 0.2 Restore compliance with BPWS. Restore control rod to OPERABLE status. 4 hours 4 hours E. ------------N 0 TE Not applicable when THERMAL POWER > 10% RTP. ---_.... _....... __... _--_.._-_..__... _... One or more groups with four or more inoperable control rods. E.1 Restore the control rod to OPERABLE status. 4 hours F. Required Action and associated Completion Time of Condition A, C, D. or E not met. OR Nine or more control rods inoperable. F.1 Be in MODE 3. 12 hours Columbia Generating Station 3.1.3-3 Amendment No. 225 3.1.3 Control Rod OPERABILITY SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.1.3.1 SR 3.1.3.2 SR 3.1.3.3 Determine the position of each control rod. Not required to be performed until 31 days after the control rod is withdrawn and THERMAL POWER is greater than the LPSP of the RWM. Insert each partially withdrawn control rod at least one notch. Verify each control rod scram time from fully 24 hours 31 days In accordance withdrawn to notch position 5 is ::; 7 seconds. SR 3.1.3.4 Verify each control rod does not go to the withdrawn overtravel position. with SR SR SR 3.1.4.3, SR Each time the control rod is withdrawn to "full out" position Prior to declaring control rod OPERABLE after work on control rodorCRD System that could affect coupling Columbia Generating Station 3.1.3-4 Amendment No. 225 Control Rod Scram Times 3.1.4 REACTIVITY CONTROL SYSTEMS 3.1.4 Control Rod Scram Times LCO 3.1.4 No more than 13 OPERABLE control rods shall be "slow," in accordance with Table 3.1.4-1, and No more than 2 OPERABLE control rods that are "slow" shall occupy adjacent locations. APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A, Requirements of the LCO not met. A,1 Be in MODE 3. 12 hours Columbia Generating 3.1.4-1 Amendment No. 4e9,;M4 225 3.1.4 Control Rod Scram Times SURVEILLANCE REQUIREMENTS During single control rod scram time Surveillances, the control rod drive (CRD) pumps shall be isolated from the associated scram accumulator. SURVEILLANCE SR 3.1.4.1 Verify each control rod scram time is within the limits of Table 3.1.4-1 with reactor steam dome pressure 800 psig. Prior to exceeding 40% RTP after each reactor shutdown 120 days SR 3.1.4.2 Verify, for a representative sample, each tested control rod scram time is within the limits of Table 3.1.4-1 with reactor steam dome pressure 800 psig. 200 days cumulative operation in MODE 1 SR 3.1.4.3 Verify each affected control rod scram time is within the limits of Table 3.1.4-1 with any reactor steam dome pressure. Prior to declaring control rod OPERABLE after work on control rod or CRD System that could affect scram time SR 3.1.4.4 Verify each affected control rod scram time is within the limits of Table 3.1.4-1 with reactor steam dome Prior to exceeding I 40% RTP after pressure 800 psig. fuel movement within the affected core cell Prior to exceeding 40% RTP after work on control rod or CRD System that could affect scram time Columbia Generating Station 3.1.4-2 Amendment No. 225 3.1.4 Control Rod Scram Times Table 3.1.4-1 (page 1 of Control Rod Scram OPERABLE control rods with scram times not within the limits of this Table are considered "slow." Enter applicable Conditions and Required Actions of LCO 3.1.3, "Control Rod OPERABILITY," for control rods with scram times> 7 seconds to notch position 5. These control rods are inoperable, in accordance with SR 3.1.3.3, and are not considered "slow." SCRAM TIMES(a)(b) (seconds) WHEN REACTOR STEAM DOME PRESSURE NOTCH POSITION 800 psig 45 0.528 39 0.866 1.917 3.437 Maximum scram time from fully withdrawn position, based on de-energization of scram pilot valve solenoids at time zero. Scram times as a function of reactor steam dome pressure, when < 800 psig, are within established limits. Columbia Generating 3.1.4-3 Amendment No. 2-1-+,2-1-2 225 3.1.5 Control Rod Scram Accumulators 3.1 REACTIVITY CONTROL 3.1.5 Control Rod Scram LCO 3.1.5 Each control rod scram accumulator shall be APPLICABILITY: MODES 1 and 2. ACTIONS Separate Condition entry is allowed for each control rod scram accumulator. CONDITION REQUIRED ACTION COMPLETION A. One control rod scram accumulator inoperable with reactor steam dome pressure 900 psig. A.1 ---------------NOTEOnly applicable if the associated control rod scram time was within the limits of Table 3.1.4-1 during the last scram time Surveillance. ---_... __....... __........ _...... __... _-----------... --... Declare the associated control rod scram time "slow." 8 hours OR A.2 Declare the associated control rod inoperable. 8 hours Columbia Generating Station 3.1.5-1 Amendment No. 225 3.1.5 Control Rod Scram Accumulators ACTIONS CONDITION I REQUIRED ACTION COMPLETION TIME B. Two or more control rod scram accumulators inoperable with reactor steam dome pressure 900 psig. B.1 AND B.2.1 Restore charging water header pressure to 940 psig. Only applicable if the associated control rod scram time was within the limits of Table 3.1.4-1 during the last scram time Surveillance. 20 minutes from discovery of Condition B concurrent with charging water header pressure < 940 psig Declare the associated control rod scram time "slow." 1 hour B.2.2 Declare the associated control rod inoperable. 1 hour Columbia Generating Station 3.1.5-2 Amendment No. 225 3.1.5 Control Rod Scram Accumulators ACTION CONDITION REQUIRED ACTION COMPLETION TIME C. One or more control rod scram accumulators inoperable with reactor steam dome pressure < 900 psig. C.1 AND C.2 Verify the associated control rod is fully inserted. Declare the associated control rod inoperable. Immediately upon discovery of charging water header pressure < 940 psig 1 hour D. Required Action B.1 or C.1 and associated Completion Time not met. D.1 ---------------NOT Not applicable if all inoperable control rod scram accumulators are associated with fully inserted control rods. ---_..__..Place the reactor mode switch in the shutdown position. Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.1.5.1 Verify each control rod scram accumulator pressure 7 days is 940 psig. Columbia Generating Station 3.1.5-3 Amendment No. 4e9,24-9 225 Rod Pattern Control 3.1.6 3.1 REACTIVITY CONTROL SYSTEMS 3.1.6 Rod Pattern Control LCO OPERABLE control rods shall comply with the requirements of the banked position withdrawal sequence (BPWS). APPLICABILITY: MODES 1 and 2 with THERMAL POWER s 10% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A, One or more OPERABLE control rods not in compliance with BPWS. A,1 OR A,2 --------------N0 Rod Worth Minimizer (RWM) may be bypassed as allowed by LCO 3.3.2.1, "Control Rod Block Instrumentation." ------------------... Move associated control rod(s) to correct position. Declare associated control rod(s) inoperable. 8 hours 8 hours B. Nine or more OPERABLE control rods not in compliance with BPWS. B.1 AND ---------------RWM may be bypassed as allowed by LCO 3.3.2.1. Suspend withdrawal of control rods. Immediately Columbia Generating 3.1.6-1 Amendment No. 225 3.1.6 Rod Pattern Control ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B (continued) B.2 Place the reactor mode 1 hour switch in the shutdown position. SURVEILLANCE SURVEILLANCE SR 3.1.6.1 Verify all OPERABLE control rods comply with 24 hours BPWS. Columbia Generating Station 3.1.6-2 Amendment No. 449,lG9 225 3.1.7 SLC System 3.1 REACTIVITY CONTROL 3.1.7 Standby Liquid Control (SLC) LCO 3.1.7 Two SLC subsystems shall be APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SLC subsystem inoperable. A.1 Restore SLC subsystem to OPERABLE status. 7 days B. Two SLC subsystems inoperable. B.1 Restore one SLC subsystem to OPERABLE status. 8 hours C. Required Action and associated Completion Time not met. C.1 AND C.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.1.7.1 Verify available volume of sodium pentaborate solution is 4587 gallons. 24 hours SR 3.1.7.2 Verify temperature of sodium pentaborate solution is within the limits of Figure 3.1.7-1. 24 hours Columbia Generating Station 3.1.7-1 Amendment No. +&Q,4W 225 3.1.7 SLC System SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.1.7.3 Verify continuity of explosive charge. 31 days SR 3.1.7.4 Verify the concentration of boron in solution is within the limits of Figure 3.1.7-1. 31 days Once within 24 hours after water or boron is added to solution Once within 24 hours after solution temperature is restored within the limits of Figure 3.1.7-1 SR 3.1.7.5 Verify each SLC subsystem manual and power operated valve in 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. 31 days SR 3.1.7.6 Verify each pump develops a flow rate 2 41.2 gpm at a discharge pressure 2 1220 psig. In accordance with the Inservice Testing Program SR 3.1.7.7 Verify flow through one SLC subsystem from pump I 24 months on a into reactor pressure vessel. ,. STAGGERED TEST BASIS Columbia Generating Station 3.1.7-2 Amendment No. -1-W,4-Q9 225 3.1.7 SURVEILLANCE SR 3.1.7.8 Verify all heat traced piping between storage tank and pump suction valve is unblocked. SLC System 24 months Once within 24 hours after solution temperature is restored within the limits of Figure 3.1.7-1 Prior to addition to SR 3.1.7.9 Verify sodium pentaborate enrichment is 44.0 SLC Tank atom percent B-10. Columbia Generating Station 3.1.7-3 Amendment No. 225 3.1.7 SLC System 150 -{13.60;0, 1500 150;0,1500 F)-+-----I 140 I----r-----I 130 I---r-------b 120 1----1-------1 110 1---+-----1 100 1---+-----1: 90 1----+-----1 80 1-----+----; 70 I---I-----f, 15%,700 F t-----Ir-----I (13.6%, 640 F)60 50 401___-+-__-+--_---+_UNACCEPTABLE OPERATION 12.2 13.6 15 16.4 17.8 Tank Concentration (% by weight) 950462 Figure 3.1.7-1 (page 1 of Sodium Pentaborate Solution Temperature/Concentration Columbia Generating 3.1.7-4 Amendment No. 449,+99 225 3.1.8 SDV Vent and Drain Valves REACTIVITY CONTROL SYSTEMS 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves LCO 3.1.8 Each SDV vent and drain valve shall be OPERABLE. APPLICABILITY: MODES 1 and 2. ACTIONS Separate Condition entry is allowed for each SDV vent and drain line. An isolated line may be unisolated under administrative control to allow draining and venting of the SDV. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SDV vent or drain lines with one valve inoperable. A.1 Isolate the associated line. 7 days B. One or more SDV vent or drain lines with both valves inoperable. B.1 Isolate the associated line. 8 hours C. Required Action and associated Completion Time not met. C.1 Be in MODE 3. 12 hours Columbia Generating 3.1.8-1 Amendment No. 449,.:t-99 225 3.1.8 SOV Vent and Orain Valves SURVEILLANCE REQUIREMENTS SR -----------------------------NOTE Not required to be met on vent and drain valves closed during performance of SR 3.1.8.2. Verify each SOV vent and drain valve is open. 31 days SR 3.1.8.2 Cycle each SOV vent and drain valve to the fully closed and fully open position. SR Verify each SOV vent and drain valve: Closes in 30 seconds after receipt of an actual or simulated scram signal; and Opens when the actual or simulated scram signal is reset. 92 days 24 months Columbia Generating 3.1.8-2 Amendment No. 225 APLHGR 3.2.1 3.2 POWER DISTRIBUTION LIMITS 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) LCO All APLHGRs shall be less than or equal to the limits specified in the COLR. APPLICABILITY: THERMAL POWER;;:: 25% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any APLHGR not within limits. A.1 Restore APLHGR(s) to within limits. 2 hours B. Required Action and associated Completion Time not met. B.1 Reduce THERMAL POWER to < 25% RTP. 4 hours SURVEILLANCE SR 3.2.1.1 Verify all APLHGRs are less than or equal to the limits specified in the COLR. Once within 12 hours after ;;::25% RTP 24 hours thereafter Columbia Generating 3.2.1-1 Amendment No. :.t49.4W 225 MCPR 3.2.2 3.2 POWER DISTRIBUTION LIMITS 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR) LCO All MCPRs shall be greater than or equal to the MCPR operating limits specified in the COLR. APPLICABILITY: THERMAL POWER 25% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any MCPR not within limits. A.1 Restore MCPR(s) to within limits. 2 hours B. Required Action and associated Completion Time not met. B.1 Reduce THERMAL POWER to < 25% RTP. 4 hours SURVEILLANCE SR 3.2.2.1 Verify all MCPRs are greater than or equal to the limits specified in the COLR. Once within 12 hours after 25% RTP 24 hours thereafter Columbia Generating 3.2.2-1 Amendment No. 4S9,244 225 3.2.2 MCPR SURVEILLANCE REQUIREMENTS SR 3.2.2.2 Determine the MCPR limits. Once within 72 hours after each completion of SR 3.1.4.1 Once within 72 hours after each completion of SR 3.1.4.2 Once within 72 hours after each completion of SR 3.1.4.4 Columbia Generating Station 3.2.2-2 Amendment No. 2-14 225 3.2.3 3.2 POWER DISTRIBUTION 3.2.3 LINEAR HEAT GENERATION RATE LCO 3.2.3 All LHGRs shall be less than or equal to the limits specified in the APPLICABILITY: THERMAL POWER 25% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Any LHGR not within limits. A.1 Restore LHGR(s) to within limits. 2 hours B. Required Action and associated Completion Time not met. B.1 Reduce THERMAL POWER to < 25% RTP. 4 hours SURVEILLANCE SR 3.2.3.1 Verify all LHGRs are less than or equal to the limits specified in the COLR. Once within 12 hours after RTP 24 hours thereafter Columbia Generating Station 3.2.3-1 Amendment No. 449,4-99 225 APRM Gain and Setpoint 3.2.4 3.2 POWER DISTRIBUTION LIMITS 3.2.4 Average Power Range Monitor (APRM) Gain and Setpoint LCO 3.2.4 a. MFLPD shall be less than or equal to Fraction of RTP (FRTP); or b. Each required APRM Flow Biased Simulated Thermal Power -High Function Allowable Value shall be modified by greater than or equal to the ratio of FRTP and the MFLPD; or Each required APRM gain shall be' adjusted such that the APRM readings are;;:: 100% times MFLPD. APPLICABILITY: THERMAL POWER;;:: 25% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the LCO not met. A.1 Satisfy the requirements of the LCO, 6 hours B. Required Action and associated Completion Time not met. B.1 Reduce THERMAL POWER to < 25% RTP. 4 hours Columbia Generating 3.2.4-1 Amendment No. .:t49,.:t-e9 225 APRM Gain and Setpoint 3.2.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR -----------------------------NaTENot required to be met if SR 3.2.4.2 is satisfied for LCO 3.2.4.b or LCO 3.2.4.c requirements. Verify MFLPD is within limits. Once within 12 hours after 25% RTP 24 hours thereafter SR -------------------------------NOTE Not required to be met if SR 3.2.4.1 is satisfied for LCO 3.2.4.a requirements. Verify each 112 hours APRM Flow Biased Simulated Thermal Power High Function Allowable Value is modified by greater than or equal to the ratio of FRTP and the MFLPD; or APRM gain is adjusted such that the APRM reading is 100% times MFLPD. Columbia Generating 3.2.4-2 Amendment No. 449,-+99 225 RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation LCO The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE. According to Table 3.3.1.1-1. ACTIONS Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A. 1 Place channel in trip. 12 hours channels inoperable. OR A.2 Place associated trip 12 hours system in trip. B. One or more Functions with one or more required channels inoperable in both trip systems. B.1 OR B.2 Place channel in one trip 6 hours system in trip. Place one trip system in 6 hours trip. C. One or more Functions with RPS trip capability not maintained. C.1 I Restore RPS trip capability. I 1 hour D. Required Action and associated Completion Time of Condition A, B, or C not met. D.1 Enter the Condition Immediately referenced in Table 3.3.1.1-1 for the channel. Columbia Generating Station 3.3.1.1-1 Amendment No. -M9,4W 225 RPS Instrumentation 3.3.1.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. As required by Required Action 0.1 and referenced in Table 3.3.1.1-1. E.1 Reduce THERMAL POWER to < 30% RTP. 4 hours F. As required by Required Action 0.1 and referenced in Table 3.3.1.1-1. F.1 Be in MODE 2. 6 hours G. As required by Required Action 0.1 and referenced in Table 3.3.1.1-1. G.1 Bein MODE 3. 12 hours H. As required by Required Action 0.1 and referenced in Table 3.3.1.1-1. H.1 Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Immediately SURVEILLANCE REQUIREMENTS Refer to Table 3.3.1.1-1 to determine which SRs apply for each RPS Function. 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. SR 3.3.1.1.1 Perform CHANNEL 12 hours Columbia Generating Station 3.3.1.1-2 Amendment No. 449,499 225 RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.2 -------------------------------NOTE Not required to be performed until 12 hours after THERMAL POWER 25% RTP. Verify the absolute difference between the average power range monitor (APRM) channels and the calculated power 2% RTP plus any gain adjustment required by LCO 3.2.4, "Average Power Range Monitor (APRM) Gain and Setpoint," while operating at 25% RTP. 7 days SR 3.3.1.1.3 -------------------------------N OTE Not required to be performed when entering MODE 2 from MODE 1 until 12 hours after entering MODE 2. Perform CHANNEL FUNCTIONAL TEST. 7 days SR 3.3.1.1.4 Perform CHANNEL FUNCTIONAL TEST. 7 days SR 3.3.1.1.5 Verify the source range monitor (SRM) and intermediate range monitor (IRM) channels overlap. Prior to withdrawing SRMs from the fully inserted position SR -------------------------------NOTE Only required to be met during entry into MODE 2 from MODE 1. Verify the IRM and APRM channels overlap. SR 3.3.1.1.7 Calibrate the local power range monitors. 7 days 1130 MWD/T average core exposure Columbia Generating Station 3.3.1.1-3 Amendment No. 449,4$ 225 RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SR 3.3.1.1.8 Perform CHANNEL FUNCTIONAL TEST. SR 3.3.1.1.9 Neutron detectors are excluded. For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours after entering MODE 2. Perform CHANNEL CALIBRATION. 92 days 184 days SR 3.3.1.1.10 ------------------------------NO TE 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. 18 months for Functions 1 through 4, 6, 7. and 9 through 11 SR 3.3.1.1.11 SR 3.3.1.1.12 SR 3.3.1.1.13 Verify the APRM Flow Biased Simulated Thermal Power -High Function time constant is ::; 7 seconds. Verify Turbine Throttle Valve -Closure, and Turbine Governor Valve Fast Closure Trip Oil Pressure Low Functions are not bypassed when THERMAL POWER is 30% RTP. Perform CHANNEL FUNCTIONAL TEST. 24 months for Functions 5 and 8 18 months 18 months 24 months Columbia Generating Station 3.3.1.1-4 Amendment No. .:te9,-1+9 225 RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.1.15 1 Neutron detectors are excluded. 2. Channel sensors for Functions 3 and 4 are excluded. 3. For Function 5, "n" equals 4 channels for the purpose of determining the STAGGERED TEST BASIS Frequency. Verify the RPS RESPONSE TIME is within limits. 24 months on a STAGGERED TEST BASIS Columbia Generating Station 3.3.1.1-5 Amendment No. 4aQ * .:t-eQ. 225 RPS Instrumentation Table 3.3.1.1-1 (page 1 of Reactor Protection System APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE FUNCTION CONDITIONS SYSTEM ACTION D,1 REQUIREMENTS Intermediate Range Monitors a, Neutron Flux -High 2 3 SR 3,3,1,1,1 SR 3,3,1,1,3 SR 3,3,1,1,5 SR 3,3.1,1,6 SR 3.3.1,1.10 SR 3,3,1,1.14 5(8) 3 SR 3.3,1.1.1 SR 3.3,1,1.4 SR 3.3,1.1.10 SR 3,3,1.1.14 Inop 2 3 G SR 3.3,1,1,3 SR 3.3,1,1.14 5(8) 3 SR 3,3,1,1.4 SR 3.3,1,1.14 Average Power Range Monitors a. Neutron Flux -High, 2 2 SR 3,3,1,1,1 SR 3.3,1.1,3 SR 3.3,1,1,6 SR 3.3,1.1,7 SR 3.3,1.1,9 SR 3.3,1.1,14 Flow Biased Simulated 2 F SR 3.3,1.1.1 Thermal Power -SR 3,3,1.1.2 SR 3.3.1,1.7 SR 3,3,1.1,8 SR 3,3.1,1,9 SR 3,3,1,1.11 SR 3.3.1,1.14 Fixed Neutron Flux 2 F SR 3,3,1,1.1 SR 3,3.1,1,2 SR 3.3.1,1,7 SR 3.3.1,1.8 SR 3.3.1,1.9 SR 3.3.1,1.14 SR 3.3.1,1.15 d, Inop 1,2 2 SR 3.3.1,1.7 SR 3.3.1.1.8 SR 3.3.1,1,14 s 122/125 divisions of full scale s 122/125 divisions of full scale NA NA s 20% RTP S 0,58 W + 62% RTP and s 114.9% RTP s 120% RTP NA (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies. Columbia Generating Station 3.3.1.1-6 Amendment No. -149,-+69 225 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 0.1 REQUIREMENTS VALUE 3. Reactor Vessel Steam 1,2 2 G SR 3.3.1.1.8 5: 1079 psig Dome Pressure* High SR SR SR 4. Reactor Vessel Water Level 1,2 2 G SR 3.3.1.1.1 2: 9.5 inches
- Low. Level SR SR SR SR 5. Main Steam Isolation 8 F SR 3.3.1.1.8 5: 12.5% closed
- SR SR SR 6. Primary Containment 1.2 2 G SR 3.3.1.1.8 5: 1.88 psig Pressure -SR SR Scram Discharge Water Level -TransmitterfTrip Unit 1.2 2 G SR 3.3.1.1.8 5: 529 fI 9 inches SR 3.3.1.1.10 elevation SR 3.3.1.1.14 51al 2 SR 3.3.1.1.8 5: 529 ft 9 inches SR 3.3.1.1.10 elevation SR 3.3.1.1.14 b. Float Switch 1,2 2 SR 3.3.1.1.8 5: 529 ft 9 inches SR 3.3.1.1.10 elevation SR 3.3.1.1.14 51a) 2 SR 3.3.1.1.8 5: 529 ft 9 inches SR 3.3.1.1.10 elevation SR 3.3.1.1.14 8. Turbine Throttle Valve 2: 30% RTP 4 E SR 3.3.1.1.8 5: 7% closed SR SR SR SR (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies. Columbia Generating Station 3.3.1.1-7 Amendment No . .:J.4Q.,4e9 225 RPS Instrumentation 3.3.1.1 FUNCTION Turbine Governor Valve Fast Closure, Trip Oil Pressure -Low Reactor Mode Shutdown Position Manual Scram Table 3.3.1.1-1 (page 3 of Reactor Protection System APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE CONDITIONS SYSTEM ACTION 0.1 REQUIREMENTS VALUE 30% RTP 2 SR 3.3.1.1.8 1000 psig SR 3.3.1.1.10 SR 3.3.1.1.12 SR 3.3.1.1.14 SR 3.3.1.1.15 1,2 2 SR 3.3.1.1.13 NA SR 3.3.1.1.14 5(a) 2 SR 3.3.1.1.13 SR 3.3.1.1.14 NA 1,2 2 SR 3.3.1.1.4 NA SR 3.3.1.1.14 5(a) 2 SR 3.3.1.1.4 NA SR 3.3.1.1.14 (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies. Columbia Generating Station 3.3.1.1-8 Amendment No. -149,499 225 SRM Instrumentation 3.3.1.2 3.3 3.3.1.2 Source Range Monitor (SRM) LCO 3.3.1.2 The SRM instrumentation in Table 3.3.1.2-1 shall be APPLICABILITY: According to Table 3.3.1.2-1. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required SRMs inoperable in MODE 2 with intermediate range monitors (lRMs) on Range 2 or below. A,1 Restore required SRMs to OPERABLE status. 4 hours B. Three required SRMs inoperable in MODE 2 with IRMs on Range 2 or below. 8.1 Suspend control rod withdrawal. Immediately C. Required Action and associated Completion Time of Condition A or B not met. C.1 Be in MODE 3. 12 hours D. One or more required SRMs inoperable in MODE 3 or 4. D.1 AND D.2 Fully insert all insertable control rods. Place reactor mode switch in the shutdown position. 1 hour 1 hour Columbia Generating Station 3.3.1.2-1 Amendment No. 449,4-@.B 225 SRM Instrumentation 3.3.1.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. One or more required SRMs inoperable in MODE 5. E.1 E.2 Suspend CORE ALTERATIONS except for control rod insertion. Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Immediately Immediately SURVEILLANCE REQUIREMENTS Refer to Table 3.3.1.2-1 to determine which SRs apply for each applicable MODE or other specified conditions. SURVEILLANCE FREQUENCY SR 3.3.1.2.1 Perform CHANNEL CHECK. 12 hours Columbia Generating Station 3.3.1.2-2 Amendment No. +49,:J.e9 225 SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.1.2.2 ----------------------------NO 1. Only required to be met during CORE AL TERA TIONS. 2. One SRM may be used to satisfy more than one of the following. Verify an OPERABLE SRM detector is located in: a. The fueled region; b. The core quadrant where CORE ALTERATIONS are being performed when the associated SRM is included in the fueled region; and c. A core quadrant adjacent to where CORE ALTERATIONS are being performed. when the associated SRM is included in the fueled region. 12 hours SR 3.3.1.2.3 Perform CHANNEL CHECK. 24 hours 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: a. 3.0 cps with a signal to noise ratio 2:1 or b. 0.7 cps with a signal to noise ratio 20:1. 12 hours during CORE AL TERATIONS 24 hours Columbia Generating Station 3.3.1.2-3 Amendment No. 449.4$ 225 SRM Instrumentation 3.3.1.2 SURVEILLANCE REQUIREMENTS SR SR SR The determination of signal to noise ratio is 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. Perform CHANNEL FUNCTIONAL TEST and 7 days determination of signal to noise ratio. ------------------------------N0TE 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. Neutron detectors are excluded. Not required to be performed until 12 hours after IRMs on Range 2 or below. Perform CHANNEL 18 months Columbia Generating Station 3.3.1.2-4 Amendment No. 225 SRM Instrumentation 3.3.1.2 Table 3.3.1.2-1 (page 1 of 1) Source Range Monitor Instrumentation APPLICABLE MODES OR OTHER SPECIFIED REQUIRED SURVEILLANCE FUNCTION CONDITIONS CHANNELS REQUIREMENTS 1. Source Range Monitor 3 3.4 2 5 2(b). (c) SR 3.3.1.2.1 SR 3.3.1.2.4 SR 3.3.1.2.6 SR 3.3.1.2.7 SR 3.3.1.2.3 SR 3.3.1.2.4 SR 3.3.1.2.6 SR 3.3.1.2.7 SR 3.3.1.2.1 SR 3.3.1.2.2 SR 3.3.1.2.4 SR 3.3.1.2.5 SR 3.3.1.2.7 (a) With IRMs on Range 2 or below. (b) Only one SRM channel is required to be OPERABLE during spiral offload or reload when the fueled region includes only that SRM detector. (c) Special movable detectors may be used in place of SRMs if connected to normal SRM circuits. Columbia Generating Station 3.3.1.2-5 Amendment No . .:J.49,-+e9 225 OPRM Instrumentation 3.3.1.3 3.3 INSTRUMENTATION 3.3.1.3 Oscillation Power Range Monitor (OPRM) Instrumentation LCO Four channels of the OPRM instrumentation shall be OPERABLE within the limits as specified in the COLR. THERMAL POWER 25% RTP. ACTIONS Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required channels inoperable. A.1 OR Place channel in trip. 30 days A.2 OR Place associated RPS trip system in trip. 30 days A.3 Initiate alternate method to detect and suppress thermal hydraulic instability oscillations. 30 days B. OPRM trip capability not maintained. B.1 Initiate alternate method to detect and suppress thermal hydraulic instability oscillations. 12 hours C. Required Action and associated Completion Time not met. C.1 Reduce THERMAL POWER < 25% RTP. 4 hours Columbia Generating Station Amendment No, rn-225 OPRM Instrumentation 3.3.1.3 SURVEILLANCE REQUIREMENTS -------------------------------------------------------N OTE 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 OPRM System maintains trip capability. Calibrate the local power range monitors. SURVEILLANCE FREQUENCY SR 3.3.1.3.1 Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.1.3.2 1130 MWDIT average core exposure SR 3.3.1.3.3 ------------------------------NO Neutron detectors are excluded. Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.3.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.1.3.5 Verify OPRM is not bypassed when THERMAL POWER is 2 30% RTP and core flow 60% rated core flow. 24 months SR 3.3.1.3.6 -----------------------------NOT E Neutron detectors are excluded. Verify the RPS RESPONSE TIME is within limits. 24 months on a STAGGERED TEST BASIS Columbia Generating Station 3.3.1.3-2 Amendment No. ++4-,.m 225 Control Rod Block Instrumentation 3.3.2.1 3.3 INSTRUMENTATION 3.3.2.1 Control Rod Block Instrumentation LCO The control rod block instrumentation for each Function in Table 3.3.2.1-1 shall be OPERABLE. APPLICABILITY: According to Table 3.3.2.1-1. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One rod block monitor (RBM) channel inoperable. A.1 Restore RBM channel to OPERABLE status. 24 hours B. Required Action and associated Completion Time of Condition A not met. OR Two RBM channels inoperable. B.1 Place one RBM channel in trip. 1 hour C. Rod worth minimizer (RWM) inoperable during reactor startup. C.1 Suspend control rod movement except by scram. OR C.2.1.1 Verify 12 rods withdrawn. OR Immediately Immediately Columbia Generating Station 3.3.2.1-1 Amendment No. 449A-W 225 Control Rod Block Instrumentation 3.3.2.1 ACTIONS C. (continued) D. RWM inoperable during reactor shutdown. One or more Reactor Mode Switch -Shutdown Position channels inoperable. REQUIRED C.2.1.2 Verify by administrative methods that startup with RWM inoperable has not been performed in the last calendar year. Verify movement of control rods is in compliance with banked position withdrawal sequence (BPWS) by a second licensed operator or other qualified member of the technical staff. Verify movement of control rods is in compliance with BPWS by a second licensed operator or other qualified member of the technical staff. Suspend control rod withdrawal. AND COMPLETION Immediately During control rod movement During control rod movement Immediately E.2 Initiate action to fully insert all insertable control rods in Immediately core cells containing one or more fuel assemblies. Columbia Generating Station 3.3.2.1-2 Amendment No. 449,+69 225 Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS Refer to Table 3.3.2.1-1 to determine which SRs apply for each Control Rod Block Function. 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. SURVEILLANCE FREQUENCY SR 3.3.2.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.1.2 -----------------------------N OTE Not required to be performed until 1 hour after any control rod is withdrawn at 10% RTP in MODE 2. Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.2.1.3 -------------------------------NOTE Not required to be performed until 1 hour after THERMAL POWER is 10% RTP in MODE 1. 92 days Perform CHANNEL FUNCTIONAL TEST. SR -------------------------------NOTE Neutron detectors are excluded. Verify the RBM is not bypassed: a. When THERMAL POWER is 30% RTP; and b. When a peripheral control rod is not selected. 92 days I Columbia Generating Station 3.3.2.1-3 Amendment No. 449,499 225 Control Rod Block Instrumentation 3.3.2.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.3.2.1.5 ------------------------------N 0 TE Neutron detectors are Perform CHANNEL CALIBRATION. 92 days SR 3.3.2.1.6 Verify the RWM is not bypassed when THERMAL 24 months POWER is s 10% RTP. SR 3.3.2.1.7 -------------------------------NOT E 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 in conformance with BPWS. Prior to declaring RWM OPERABLE following loading of sequence into RWM Columbia Generating Station 3.3.2.1-4 Amendment No. -+W,+79 225 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. Upscale (a) 2 SR 3.3.2.1.1 SR 3.3.2.1.4 SR 3.3.2.1.5 :5 0.58W + 51 % RTP b. Inop (a) 2 SR 3.3.2.1.1 SR 3.3.2.1.4 NA c. Downscale (a) 2 SR 3.3.2.1.1 SR 3.3.2.1.4 SR 3.3.2.1.5 3% RTP 2. Rod Worth Minimizer SR 3.3.2.1.2 SR 3.3.2.1.3 SR 3.3.2.1.6 SR 3.3.2.1.8 NA 3. Reactor Mode Switch -Shutdown Position (c) 2 SR 3.3.2.1.7 NA (a) THERMAL POWER 30% RTP and no peripheral control rod selected. (b) With THERMAL POWER:5 10% RTP. (c) Reactor mode switch In the shutdown position. Columbia Generating Station 3.3.2.1-5 Amendment No. 449,.:1-99 225 Feedwater and Main Turbine High Water Level Trip Instrumentation 3.3.2.2 3.3 INSTRUMENTATION 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation LCO Three channels of feedwater and main turbine high water level trip instrumentation shall be OPERABLE. THERMAL POWER;::: 25% RTP. ACTIONS Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One feedwater and main turbine high water level trip channel inoperable. A.1 Place channel in trip. 7 days B. Two or more feedwater and main turbine high , water level trip channels inoperable. B.1 Restore feedwater and 2 hours main turbine high water level trip capability. C. Required Action and associated Completion Time not met. C.1 Reduce THERMAL i 4 hours POWER to < 25% RTP. I Columbia Generating Station 3.3.2.2-1 Amendment No. -i4Q,49Q. 225 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 FUNCTIONAL TEST. 92 days SR 3.3.2.2.3 Perform CHANNEL CALIBRATION. The Allowable 24 months Value shall be s 56.0 inches. SR 3.3.2.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST, I 24 months including valve actuation. Columbia Generating Station 3.3.2.2-2 Amendment No. :t49,.te9 225 PAM Instrumentation 3.3.3.1 3.3 INSTRUMENTATION 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation LCO The PAM instrumentation for each Function in Table 3.3.3.1-1 shall be OPERABLE. MODES 1 and 2. ACTIONS ----------------------------------------------------------NOT E Separate Condition entry is allowed for each Function. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more Functions with one required channel inoperable. A.1 Restore required channel to OPERABLE status. 30 days B. Required Action and associated Completion Time of Condition A not met. B.1 Initiate action in accordance with Specification 5.6.4. Immediately C. One or more Functions with two or more required channels inoperable. C.1 Restore all but one required channel to OPERABLE status. 7 days D. Required Action and associated Completion Time of Condition C not met. D.1 Enter the Condition referenced in Table 3.3.3.1-1 for the channel. Immediately Columbia Generating Station 3.3.3.1-1 Amendment No. 487.4-QG 225 PAM Instrumentation 3.3.3.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. As required by Required Action D.1 and referenced in Table 3.3.3.1-1. E.1 Be in MODE 3. 12 hours F. As required by Required Action D.1 and referenced in Table 3.3.3.1-1. F.1 Initiate action in accordance with Specification 5.6.4. Immediately SURVEILLANCE REQUIREMENTS These SRs apply to each Function in Table 3.3.3.1-1. 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 other required cha nnel(s) in the associated Function is OPERABLE. SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 Deleted SR 3.3.3.1.3 Perform CHANNEL CALIBRATION for Functions 1, 2,4,5, and 10. 18 months SR 3.3.3.1.4 Perform CHANNEL CALIBRATION for Functions 3, 6, and 7. 24 months Colum bia Generating Station 3.3.3.1-2 Amendment No.4SQ.,4-Q.Q. 225 PAM Instrumentation 3.3.3.1 Table 3.3.3.1-1 (page 1 of 1) Post Accident Monitoring Instrumentation CONDITIONS REFERENCED REQUIRED FROM REQUIRED FUNCTION CHANNELS ACTION 0.1 1, Reactor Vessel Pressure 2. Reactor Vessel Water Level a. -150 inches to +60 inches b. -310 inches to -110 inches 3. Suppression Pool Water Level a. -25 inches to +25 inches b. 2 ft to 52 ft 4. Suppression Chamber Pressure 5. Drywell Pressure a. -5 psig to +3 psig b. opsig to 25 psig c. opsig to 180 psig 6. Primary Containment Area Radiation 7. Penetration Flow Path PCIV Position 8. Deleted 9. Deleted ECCS Pump Room Flood Level 2 E 2 E 2 E 2 E 2 E 2 E 2 E 2 E 2 E 2 F 2 per penetration flow path(a) (b) E 5 E Not required for isolation valves whose associated penetration flow path is isolated by at least one closed and de-activated automatic valve, closed manual valve. blind flange. or check valve with flow through the valve secured. Only one position indication channel is required for penetration flow paths with only one installed control room indication channel. Columbia Generating Station 3.3.3.1-3 Amendment No. .:+89,.:w8 225 Remote Shutdown System 3.3.3.2 3.3 3.3.3.2 Remote Shutdown LCO 3.3.3.2 The Remote Shutdown System Functions shall be APPLICABILITY: MODES 1 and 2. ACTIONS Separate Condition entry is allowed for each Function. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required Functions inoperable. A.1 Restore required Function to OPERABLE status. 30 days B. Required Action and associated Completion Time not met. B.1 Be in MODE 3. 12 hours SURVEILLANCE REQUIREMENTS 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. SURVEILLANCE FREQUENCY SR 3.3.3.2.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized. Columbia Generating Station 3.3.3.2-1 Amendment No. 469,48+ 225 SR 3.3.3.2.2 Perform CHANNEL CALIBRATION for each required instrumentation channel, except the suppression pool water level instrumentation channel. 18 months SR 3.3.3.2.3 Perform CHANNEL CALIBRATION for the suppression pool water level instrumentation channel. 24 months SR 3.3.3.2.4 Verify each required control circuit and transfer switch is capable of performing the intended 24 months SURVEILLANCE REQUIREMENTS SU RVEI LLANCE functions. Remote Shutdown System 3.3.3.2 FREQUENCY Columbia Generating Station 3.3.3.2-2 Amendment No. 449,-1-99 225 EOC-RPT Instrumentation 3.3.4.1 INSTRUMENTATION 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation LCO 3.3.4.1 Two channels per trip system for each instrumentation Function listed below shall be OPERABLE: Turbine Throttle Valve (TTV) -Closure; and Turbine Governor Valve (TGV) Fast Closure, Trip Oil Pressure -Low. OR LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," limits for inoperable EOC-RPT as specified in the COLR are made applicable. APPLICABILITY: THERMAL POWER;::: 30% RTP. ACTIONS Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required channels inoperable. A.1 OR A.2 Restore channel to OPERABLE status. Not applicable if inoperable channel is the result of an inoperable breaker. Place channel in trip. 72 hours 72 hours Columbia Generating Station 3.3.4.1-1 Amendment No.449,469 225 EOC-RPT Instrumentation 3.3.4.1 ACTIONS not made applicable. CONDITION REQUIRED ACTION COMPLETION TIME B. One or more Functions with EOC-RPT trip capability not maintained. AND MCPR limit for inoperable EOC-RPT B.1 OR B.2 Restore EOC-RPT trip capability. Apply the MCPR limit for inoperable EOC-RPT as specified in the COLR. 2 hours 2 hours C. Required Action and associated Completion Ti me not met. C.1 Remove the associated recirculation pump from service. 4 hours OR C.2 Reduce THERMAL POWER to < 30% RTP. 4 hours SURVEILLANCE REQUIREMENTS 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 EOC-RPT trip capability. SURVEILLANCE FREQUENCY SR 3.3.4.1.1 Perform CHANNEL FUNCTIONAL TEST. 92 days Columbia Generating Station 3.3.4.1-2 Amendment No. +49,+&9 225 EOC-RPT Instrumentation 3.3.4.1 .SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.4.1.2.a Perform CHANNEL CALIBRATION. The Allowable Value shall be: TTV -Closure: :<:; 7% closed. 24 months SR 3.3.4.1.2.b Perform CHANNEL CALIBRATION. The Allowable Value shall be: TGV Fast Closure, Trip Oil Pressure -Low: 1000 psig. 18 months SR 3.3.4.1.3 Verify TTV Closure and TGV Fast Closure, Trip 18 months Oil Pressure -Low Functions are not bypassed when THERMAL POWER is 30% RTP. SR 3.3.4.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST, including breaker actuation. 24 months SR 3.3.4.1.5 Breaker arc suppression time may be assumed from the most recent performance of SR 3.3.4.1.6. Verify the EOC-RPT SYSTEM RESPONSE TIME is 24 months on a within limits. STAGGERED TEST BASIS SR 3.3.4.1.6 Determine RPT breaker arc suppression time. 60 months Columbia Generating Station 3.3.4.1-3 Amendment No. +e8,+e-9 225 A TWS-RPT Instrumentation 3.3.4.2 3.3 INSTRUMENTATION Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation LCO Two channels per trip system for each ATWS-RPT instrumentation Function listed below shall be OPERABLE: a. Reactor Vessel Water Level-Low Low, Level 2; and b. Reactor Vessel Steam Dome Pressure -High. MODE 1. ACTIONS Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels inoperable. A.1 OR A.2 Restore channel to OPERABLE status. ---------------N OTE Not applicable if inoperable channel is the result of an inoperable breaker. ---_... __... _...... _----------_... _... _-... Place channel in trip. 7 days I 7 days B. One Function with A TWS-RPT trip capability not maintained. B.1 Restore A TWS-RPT trip capability. 72 hours Columbia Generating Station 3.3.4.2-1 Amendment No. 44Q,.:f.6Q 225 ATWS-RPT Instrumentation 3.3.4.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Both Functions with ATWS-RPT trip capability not maintained. C.1 Restore ATWS-RPT trip capability for one Function. 1 hour D. Required Action and associated Completion Time not met. D.1 D.2 , Remove the associated recirculation pump from service. Be in MODE 2. 6 hours 6 hours SURVEILLANCE REQUIREMENTS ------------..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 3.3.4.2.1 Perform CHANNEL CHECK for Reactor Vessel Water Level -Low Low, Level 2 Function. 12 hours SR 3.3.4.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.4,2.3 Perform CHANNEL CALIBRATION. The Allowable Values shall be: a. Reactor Vessel Water Level -Low Low, Level 2: ?::: -58 inches; and b. Reactor Vessel Steam Dome Pressure -High: 18 months s: 1143 psig. Columbia Generating Station 3.3.4.2-2 Amendment No . .:t49,-1W 225 A TWS-RPT Instrumentation 3.3.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.3.4.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST, 24 months including breaker actuation. Columbia Generating Station 3.3.4.2-3 Amendment No. 449,469 225 ECCS Instrumentation 3.3.5.1 3.3 INSTRUMENTATION 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation LCO The ECCS instrumentation for each Function in Table 3.3.5.1-1 shall be OPERABLE. According to Table 3.3.5.1-1. ACTIONS Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels inoperable. A.1 Enter the Condition referenced in Table 3.3.5.1-1 for the channel. Immediately B. As required by Required Action A.1 and referenced in Table 3.3.5.1-1. B.1 AND --------------NO 1. Only applicable in MODES 1, 2, and 3. 2. Only applicable for Functions 1.a, 1.b, 2.a, and 2.b . ..._-..._--...... _-......_......_-...--_... _......_------_..Declare supported feature(s) inoperable when its redundant feature ECCS initiation capability is inoperable. 1 hour from discovery of loss of initiation capability for feature(s) in both divisions Columbia Generating Station 3.3.5.1-1 Amendment No. 225 ECCS Instrumentation 3.3.5.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2 --------------N 1. Only applicable in MODES 1, 2, and 3. 2. Only applicable for Functions 3.a and 3.b. Declare High Pressure Core Spray (HPCS) System inoperable. 1 hour from discovery of loss of HPCS initiation capability AND B.3 Place channel in trip. 24 hours C. As required by Required Action A.1 and referenced in Table 3.3.5.1-1. C.1 , 1. Only applicable in MODES 1, 2, and 3. 2. Only applicable for Functions 1.c, 1.d, 1.e, 1.f, 2.c, 2.d, 2.e, and 2.f. Declare supported feature(s) inoperable when its redundant feature ECCS initiation capability is inoperable. 1 hour from discovery of loss of initiation capability for feature(s) in both divisions AND C.2 Restore channel to OPERABLE status. /24 hours . Columbia Generating Station 3.3.5.1-2 Amendment No. 449,.:1-99 225 ECCS Instrumentation 3.3.5.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. As required by Required Action A.1 and referenced in Table 3.3.5.1-1. 0.1 w _____________ NOTE Only applicable if HPCS pump suction is not aligned to the suppression pool. Declare HPCS System inoperable. 1 hour from discovery of loss of HPCS initiation capability AND 0.2.1 Place channel in trip. 24 hours OR 0.2.2 Align the HPCS pump suction to the suppression pool. 24 hours E. As required by Required Action A.1 and referenced in Table 3.3.5.1-1. E.1 --------------NO 1. Only applicable in MODES 1, 2, and 3. 2. Only applicable for Functions 1.g, 1.h, and 2.g. --_... Declare supported feature(s) inoperable when its redundant feature ECCS initiation capability is inoperable. 1 hour from discovery of loss of initiation capability for feature(s) in both divisions AND E.2 Restore channel to OPERABLE status. 7 days Columbia Generating Station 3.3.5.1-3 Amendment No. 449,+69 225 ECCS Instrumentation 3.3.5.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. As required by Required Action A.1 and referenced in Table 3.3.5.1-1. F.1 AND F.2 Declare Automatic Depressurization System (ADS) valves inoperable. Place channel in trip. 1 hour from discovery of loss of ADS initiation capability in both trip systems 96 hours from discovery of inoperable channel concurrent with HPCS or reactor core isolation cooling (RCIC) inoperable AND 8 days G. As required by Required Action A.1 and referenced in Table 3.3.5.1-1. G.1 ---------------N OTE Only applicable for Functions 4.b, 4.d, 4.e, 5.b, and 5.d . ..__...... __... _-------------------....-_ ... __ ... Declare ADS valves 1 hour from discovery inoperable. AND G.2 Restore channel to OPERABLE status. of loss of ADS initiation capability in both trip systems 96 hours from discovery of inoperable channel concurrent with HPCS or RCIC inoperable AND 8 days Columbia Generating Station 3.3.5.1-4 Amendment No. -MB,.:t-e9 225 ECCS Instrumentation 3.3.5.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H. Required Action and associated Completion Time of Condition B, C, 0, E, F, or G not met. H.1 Declare associated supported feature(s} inoperable. Immediately SURVEILLANCE REQUIREMENTS Refer to Table 3.3.5.1-1 to determine which SRs apply for each ECCS Function. 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, 3.f, and 3.g; and {b} for up to 6 hours for Functions other than 3.c, 3.f, and 3.g 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. 18 months SR 3.3.5.1.5 SR 3.3.5.1.6 Perform CHANNEL CALI BRA TION. Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months 24 months Columbia Generating Station 3.3.5.1-5 Amendment No. 4-a{f,4SQ. 225 ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 1 of 5) 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 1. Low Pressure Coolant Injection-A (LPCI) and Low Pressure Core Spray (LPCS) Subsystems a. Reactor Vessel Water Level -Low Low Low, Level 1 1,2,3,4(a},5(a} 2(b) B SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 -142.3 inches b. Drywell Pressure High 1,2,3 2(b} B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 :0; 1.88 psig c. LPCS Pump Start LOCA Time Delay Relay 1,2,3, 4(a},5(a} 1(&) C SR 3.3.5.1.5 SR 3.3.5.1.6 8.53 seconds and :0; 10.64 seconds d. LPCI Pump A Start-LOCA Time Delay Relay 1,2,3,4(a},5(a) 1(e) C SR 3.3.5.1.5 SR 3.3.5.1.6 z 17.24 seconds and:o; 21.53 seconds e. LPCI Pump A Start LOCAILOOP Time Delay Relay 1(.2,3,4 a), 5(a) C SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 3.04 seconds and :0; 6.00 seconds f. Reactor Vessel Pressure -Low (Injection Permissive) 1.2,3 4(a),S(a} 1 per valve 1 per valve C B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 448 psig and :0;492 psig 2 448 psig and :0; 492 psig (a) When associated subsystem(s) are required to be OPERABLE. (b) Also required to initiate the associated diesel generator (DG). (e) Also supports OPERABILITY of 230 kV offsite power circuit pursuant to LCO 3.8.1 and LCO 3.8.2. Columbia Generating Station 3.3.5.1-6 Amendment No. 4eQ.,.:t.n 225 ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 2 of 5) 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 1. LPCI and LPCS Subsystems g. LPCS Pump Discharge Flow Low (Minimum Flow) \ 2, 3,4 a) 5(a), E SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 668 gpm and 51067 gpm h. LPCI Pump A Discharge Flow Low (Minimum Flow) 1(,2.3.4 a) 5(a), E SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 605 gpm and 5984 gpm i. Manual Initiation 1,2,3,4(a),5(a) 2 C SR 3.3.5.1.6 NA 2. LPCI Band LPCI C Subsystems a. Reactor Vessel Water Level -Low Low Low, Level 1 1,2,3,4(a),5(a) 2(b) B SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 -142.3 inches b. Drywell Pressure High 1,2,3 2(b) B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 51.88 psig c. LPCI Pump B Start LOCA Time Delay Relay 2, 3, 4 a), 5(8) 1(e) C SR SR 3.3.5.1.5 3.3.5.1.6 17.24 seconds and 21.53 seconds d. LPCI Pump C Start LOCA Time Delay Relay 1,2,3,4(a), 5(8) 1(e) C SR 3.3.5.1.5 SR 3.3.5.1.6 8.53 seconds and 10.64 seconds e. LPCI Pump B Start LOCAILOOP Time Delay Relay 1(,2,3,4 a), 5(0) C SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 3.04 seconds and 6.00 seconds (a) When associated subsystem(s) are required to be OPERABLE. (b) Also required to initiate the associated DG. (e) Also supports OPERABILITY of 230 kV offsite power circuit pursuant to LCO 3.8.1 and LCO 3.8.2. Columbia Generating Station 3.3.5.1-7 Amendment No. 499,472-225 ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 3 of 5) Emergency Core Cooling System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTIONA.1 REQUIREMENTS VALUE 2. LPCI Band LPCI C Subsystems f. Reactor Vessel Pressure -Low (Injection Permissive) 1,2,3, 4(a),5(a) 1 per valve 1 per valve C B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 psig and ::;:492 psig 448 psig and ::;: 492 psig g. LPCI Pumps B & C Discharge Flow Low (Minimum flow) 1,2,3, 4(a),5(a) 1 per pump E SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 605 gpm and ::;:984 gpm h. Manual Initiation 1,2,3, 4(a),5(a) 2 C SR 3.3.5.1.6 NA 3. High Pressure Core Spray (HPCS) System a. Reactor Vessel Water Level -Low Low. Level 2 1,2,3, 4(a),5(a) 4(b) B SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 -58 inches b. Drywell Pressure High 1.2,3 4(b) B SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 :::; 1.88 psig c. Reactor Vessel Water Level -High, Level 8 1,2,3, 4(a),5(a) 2 C SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 :::; 56.0 inches d. Condensate Storage Tank Level -Low 1,2,3, 4(C),5(C) 2 D SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 448 ft 1 inch elevation When associated subsystem(s) are required to be OPERABLE. Also required to initiate the associated DG. When HPCS is OPERABLE for compliance with LCO 3.5.2, "ECCS -Shutdown," and aligned to the condensate storage tank while tank water level is not within the limit of SR 3.5.2.2. Columbia Generating Station 3.3.5.1-8 Amendment No. 400,469 225 ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 4 of 5) 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. HPCS System e. Suppression Pool Water Level -High 1,2,3 2 D SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 ., 466 ft 11 inches elevation f. HPCS System Flow Rate -Low (Minimum Flow) 1(.2,3,4 'J, 5(') E SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 1200 gpm and ., 1512 gpm g. Manual Initiation 1,2,3,4('),5(8) 2 C SR 3.3.5.1.6 NA 4. Automatic Depressurization System (ADS) Trip System A a. Reactor Vessel Water Level-Low Low Low, Level 1 1, 2(d), 3(d) 2 F SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 -142.3 inches b. ADS Initiation Timer 1, 2(d), 3(d) G SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 :0; 115.0 seconds c. Reactor Vessel Water Level -Low, Level 3 (Permissive) 1, 2(d), 3(d) F SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 9.5 inches d. LPCS Pump Discharge Pressure -High 1, 2(d), 3(d) 2 G SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 119 psig and ., 171 pSig e. LPCI Pump A Discharge Pressure -High 1, 2(d), 3(d) 2 G SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 ;;: 116 psig and :s; 134 psig (a) When associated subsystem(s) are required to be OPERABLE. (d) With reactor steam dome pressure> 150 psig. Columbia Generating Station 3.3.5.1-9 Amendment No. 4W,!1-69 225 ECCS Instrumentation 3.3.5.1 Table 3.3.5.1-1 (page 5 of 5) 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 f. Accumulator Backup Compressed Gas System Pressure Low 1, 2(d), 3(d) 3 F SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 151.4 psig g. Manual Initiation 1, 2(d), 3(d) 4 G SR 3.3.5.1.6 NA 5. ADS Trip System B a. Reactor Vessel Water Level -Low Low Low, Level 1 1, 2(d), 3(d) 2 F SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 -142.3 inches b. ADS Initiation Timer 1, 2(d), 3(d) G SR 3.3.5.1.2 SR 3.3.5.1.3 SR 3.3.5.1.6 :;; 115.0 seconds c. Reactor Vessel Water Level Low, Level 3 (Permissive) 1 , 2(d), 3(d) F SR 3.3.5.1.1 SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 9.5 inches d. LPCI Pumps B & C Discharge Pressure -High 1, 2(d), 3(d) 2 per pump G SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 116 psig and :;; 134 psig e. Accumulator Backup Compressed Gas System Pressure Low 1, 2(d), 3(d) 3 F SR 3.3.5.1.2 SR 3.3.5.1.4 SR 3.3.5.1.6 151.4 psig f. Manual Initiation 1, 2(d), 3(d) 4 G SR 3.3.5.1.6 NA (d) With reactor steam dome pressure> 150 psig. Columbia Generating Station 3.3.5.1-10 Amendment No. 225 RCIC System Instrumentation 3.3.5.2 3.3 INSTRUMENTATION 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System Instrumentation LCO The RCIC System instrumentation for each Function in Table 3.3.5.2-1 shall be OPERABLE. MODE 1, MODES 2 and 3 with reactor steam dome pressure> 150 psig. ACTIONS ------------------------------------------------------------NOT E Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels inoperable. A.1 Enter the Condition referenced in Table 3.3.5.2-1 for the channel. Immediately B. As required by Required Action A.1 and referenced in Table 3.3.5.2-1. B.1 AND B.2 Declare RCIC System inoperable. Place channel in trip. 1 hour from discovery of loss of RCIC initiation capability 24 hours C. As required by Required Action A.1 and referenced in Table 3.3.5.2-1. C.1 Restore channel to OPERABLE status. 24 hours Columbia Generating Station 3.3.5.2-1 Amendment No. 225 RCIC System Instrumentation 3.3.5.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. As required by Required Action A.1 and referenced in Table 3.3.5.2-1. 0.1 AND 0.2.1 OR 0.2.2 Only applicable if RCIC pump suction is not aligned to the suppression pool. Declare RCIC System inoperable. Place channel in trip. Align RCIC pump suction to the suppression pool. 1 hour from discovery of loss of RCIC initiation capability 24 hours 24 hours E. Required Action and associated Completion Time of Condition B, C, or 0 not met. E.1 Declare RCIC System inoperable. Immediately Columbia Generating Station 3.3.5.2-2 Amendment No. 449,.:teS 225 RCIC System Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS Refer to Table 3.3.5.2-1 to determine which SRs apply for each RCIC Function. 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 2 and 4; 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. 18 months SR 3.3.5.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Columbia Generating Station 3.3.5.2-3 Amendment No. 449,4W 225 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 PER FROM REQUIRED SURVEILLANCE ALLOWABLE FUNCTION FUNCTION ACTION A.1 REQUIREMENTS VALUE 1. Reactor Vessel Water Level -Low Low, Level 2 4 B SR 3.3.5.2.1 SR 3.3.5.2.2 SR 3.3.5.2.3 SR 3.3.5.2.4 :?: -58 inches 2. Reactor Vessel Water Level -High, Level 8 2 C SR 3.3.5.2.1 SR 3.3.5.2.2 SR 3.3.5.2.3 SR 3.3.5.2.4 556 inches 3. Condensate Storage Tank Level-Low 2 D SR 3.3.5.2.1 SR 3.3.5.2.2 SR 3.3.5.2.3 SR 3.3.5.2.4 ;;:. 447 ft 7 inches elevation 4. Manual Initiation 2 C SR 3.3.5.2.4 NA Columbia Generating Station 3.3.5.2-4 Amendment No . .ffi.9,249 225 Primary Containment Isolation Instrumentation 3.3.6.1 3.3 INSTRUMENTATION 3.3.6.1 Primary Containment Isolation Instrumentation LCO The primary containment isolation instrumentation for each Function in Table 3.3.6.1-1 shall be OPERABLE. According to Table 3.3.6.1-1. ACTIONS 1. Penetration flow paths may be unisolated intermittently under administrative controls. 2. Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required channels inoperable. A. 1 Place channel in trip. 12 hours for Functions 2.a, 2.c, 5.d, 6.a, and 6.b AND 24 hours for Functions other than Functions 2.a, 2.c, 5.d, 6.a, and 6.b B. One or more automatic Functions with isolation capability not maintained. B.1 Restore isolation capability. 1 hour C. Required Action and associated Completion Time of Condition A or B not met. C.1 Enter the Condition referenced in Table 3.3.6.1-1 for the channel. Immediately Columbia Generating Station 3.3.6.1-1 Amendment No. +&9,200 225 Primary Containment Isolation Instrumentation 3.3.6.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. As required by Required Action C.1 and referenced in Table 3.3.6.1-1. D.1 OR Isolate associated main steam line (MSL). 12 hours D.2.1 Be in MODE 3. AND 12 hours D.2.2 Be in MODE 4. 36 hours E. As required by Required Action C.1 and referenced in Table 3.3.6.1-1. E.1 Be in MODE 2. 6 hours F. As required by Required Action C.1 and referenced in Table 3.3.6.1-1. F.1 Isolate the affected penetration flow path(s). 1 hour G. As required by Required Action C.1 and referenced in Table 3.3.6.1-1. G.1 Isolate the affected penetration flow path(s). 24 hours H. Required Action and associated Completion Time of Condition F or G not met. H.1 Be in MODE 3. AND 12 hours OR As required by Required Action C.1 and referenced in Table 3.3.6.1-1. H.2 Be in MODE 4. 36 hours Columbia Generating Station 3.3.6.1-2 Amendment No . .:149,469 225 Primary Containment Isolation Instrumentation 3.3.6.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME I. As required by Required Action C.1 and referenced in Table 3.3.6.1-1. 1.1 OR 1.2 Declare associated standby liquid control (SLC) subsystem inoperable. Isolate the Reactor Water Cleanup (RWCU) System. 1 hour 'I hour J. As required by Required Action C.1 and referenced in Table 3.3.6.1-1. J.1 OR J.2 Initiate action to restore channel to OPERABLE status. Initiate action to isolate the Residual Heat Removal (RHR) Shutdown Cooling (SDC) System. Immediately Immediately SURVEILLANCE REQUIREMENTS Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function. 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 Columbia Generating Station 3.3.6.1-3 Amendment No . .:t-49,+e9 225 Primary Containment Isolation Instrumentation 3.3.6.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.6.1.3 Perform CHANNEL FUNCTIONAL TEST. 184 days SR 3.3.6.1.4 Perform CHANNEL CALIBRATION. 18 months SR 3.3.6.1.5 Perform CHANNEL CALIBRATION 24 months SR 3.3.6.1.6 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months SR 3.3.6.1.7 ------------------------------NO TE Channel sensors for Functions 1.a, 1.b, and 1.c are excluded. Verify the ISOLATION SYSTEM RESPONSE TIME is within limits. 24 months on a STAGGERED TEST BASIS Columbia Generating Station 3.3.6.1-4 Amendment No. -1-a(},4$ 225 Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 1 of 6) Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE 1. Main Steam Line Isolation a. Reactor Vessel Water Level -Low Low Low, Level 1 1,2,3 2 D SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 SR 3.3.6.1.7 2:: -142.3 inches b. Main Steam Line Pressure -Low 2 E SR 3.3.6.1.2 SR 3.36.1.4 SR 3.3.6.1.6 SR 3.3.6.1.7 2:: 804 psig c. Main Steam Line Flow -High 1,2,3 2 per MSL D SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 SR 3.3.6.1.7 :5 124.4 psid d. Condenser Vacuum -Low 1, 2(a), 3(a) 2 D SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 2:: 7.2 inches Hg vacuum e. Main Steam Tunnel Temperature -High 1,2,3 2 D SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 :5 HO°F f. Main Steam Tunnel Differential Temperature -High 1,2,3 2 D SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 :5 90°F g. Manual Initiation 1,2,3 4 G SR 3.3.6.1.6 NA 2. Primary Containment Isolation a. Reactor Vessel Water Level -Low, Level 3 1,2,3 2 F SR 3.3,6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 2:: 9.5 inches (a) With any turbine throttle valve not closed. Columbia Generating Station 3.3.6.1-5 Amendment No. 225 Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 2 of 6) Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE 2. Primary Containment Isolation b. Reactor Vessel Water Level -Low Low, Level 2 1,2,3 2(0) H SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 -58 inches c. Drywell Pressure High 1,2,3 2(0) H SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 :$ 1.88 psig d. Reactor Building Vent Exhaust Plenum Radiation High 1,2,3 2 F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 :$ 16.0 mR/hr e. Manual Initiation 1,2,3 4 G SR 3.3.6.1.6 NA 3. Reactor Core Isolation Cooling (RCIC) System Isolation a. RCIC Steam Line Flow -High 1,2,3 F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 :$ 250 inches wg b. RCIC Steam Line Flow -Time Delay 1,2,3 F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 :$ 3.00 seconds c. RCIC Steam Supply Pressure -Low 1,2,3 2 F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 61 pSig d. RCIC Turbine Exhaust Diaphragm Pressure -High 1,2,3 2 F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 :$ 20 psig (e) Also required to initiate the associated LOCA Time Delay Relay Function pursuant to LCO 3.3.5.1. Columbia Generating Station 3.3.6.1-6 Amendment No. 225 Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 3 of 6) Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE 3. RCIC System Isolation e. RCIC Equipment Room Area Temperature -High 1,2,3 F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 :-:; 180°F f. RCIC Equipment Room Area Differential Temperature -High 1,2,3 F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 :-:; 60°F g. RWCU/RCIC Steam Line Routing Area Temperature -High 1,2,3 F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 :-:; 180°F h. Manual Initiation 1,2,3 1(b) G SR 3.3.6.1.6 NA 4. RWCU System Isolation a. Differential Flow High 1,2,3 F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6 :-:; 67.4 gpm b. Differential Flow Time Delay 1,2,3 F SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6 :-:; 46.5 seconds c. Blowdown Flow High 1,2,3 F SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.5 SR 3.3.6.1.6 SR 3.3.6.1.7 :-:; 271.7 gpm d. Heat Exchanger Room Area Temperature -High 1,2,3 F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 :-:; 160°F (b) RCIC Manual Initiation only inputs into one of the two trip systems. Columbia Generating Station 3.3.6.1-7 Amendment No. 225 Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 4 of 6) Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C,1 REQUIREMENTS VALUE 4. RWCU System Isolation e. Heat Exchanger Room Area Ventilation Differential Temperature -High 1,2,3 F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 70a F f. Pump Room Area Temperature -High 1,2,3 1 per room F SR 3.3,6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 $ 180°F g. Pump Room Area Ventilation Differential Temperature -High 1,2,3 1 per room F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 :5 100°F h. RWCUlRCIC Line Routing Area Temperature -High 1,2,3 F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 180°F i. RWCU Line Routing Area Temperature-High 1,2,3 1 per room F SR 3.3.6.1.3 SR 3,3.6.1.4 SR 3.3.6.1.6 Room 409, 509 Areas 175°F Room 408,511 Areas :5 180a F j. Reactor Vessel Water Level -Low Low, Level 2 1,2,3 2 F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 ;:: -58 inches k. SLC System Initiation 1,2,3 2'0) SR 3.3.6.1.6 NA I. Manual Initiation 1,2,3 2 G SR 3.3.6.1.6 NA (c) SLC System Initiation only inputs into one of the two trip systems. Columbia Generating Station 3.3.6.1-8 Amendment No. 4+2AW 225 Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 5 of 6) Primary Containment Isolation Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE 5. RHR SOC System Isolation a. Pump Room Area Temperature -High 3 1 per room F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 150°F b. Pump Room Area Ventilation Differential Temperature -High 3 1 per room F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 70°F c. Heat Exchanger Area Temperature High 3 1 per room F SR 3.3.6.1.3 SR 3.3.6.1.4 SR 3.3.6.1.6 Room 505 Area 140°F Room 507 Area 160°F Room 605 Area 150°F Room 606 Area 140°F d. Reactor Vessel Water Level -Low, Level 3 3,4,5 2(d) J SR 3.3.6.1.1 SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 9.5 inches e. Reactor Vessel Pressure -High 1,2,3 F SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 135 psig f. Manual Initiation 1,2,3 2 G SR 3.3.6.1.6 NA (d) Only one trip system required in MODES 4 and 5 with RHR Shutdown Cooling System integrity maintained. Columbia Generating Station 3.3.6.1-9 Amendment No. -1-e4-,4e9 225 Primary Containment Isolation Instrumentation 3.3.6.1 Table 3.3.6.1-1 (page 6 of 6) Primary Containment Isolation Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION C.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE 6. Traversing Incore Probe Isolation a. Reactor Vessel Water Level -Low, Low, Level 2 1,2,3 2 G SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 -58 inches b. Dryweli Pressure High 1,2,3 2 G SR 3.3.6.1.2 SR 3.3.6.1.4 SR 3.3.6.1.6 .:; 1.88 psig Columbia Generating Station 3.3.6.1-10 Amendment No. 200,22G 225 Secondary Containment Isolation Instrumentation 3.3.6.2 3.3 INSTRUMENTATION 3.3.6.2 Secondary Containment Isolation Instrumentation LCO The secondary containment isolation instrumentation for each Function in Table 3.3.6.2-1 shall be OPERABLE. According to Table 3.3.6.2-1. ACTIONS ------------------------------------------------------------NOT E Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels inoperable. A.1 Place channel in trip. 12 hours for Function 2 AND 24 hours for Functions other than Function 2 B. One or more automatic Functions with isolation capability not maintained. B.1 Restore isolation capability. 1 hour C. Required Action and associated Completion Time not met. C.1.1 Isolate the associated penetration flow path(s). OR 1 hour C.1.2 Declare associated secondary containment isolation valve(s) inoperable. AND 1 hour Columbia Generating Station 3.3.6.2-1 Amendment No. +49,4W 225 Secondary Containment Isolation Instrumentation 3.3.6.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2.1 Place the associated standby gas treatment (SGT) subsystem in operation. 1 hour C.2.2 Declare associated SGT subsystem inoperable. 1 hour SURVEILLANCE REQUIREMENTS --------------------------------------------------------NOTE Refer to Table 3.3.6.2-1 to determine which SRs apply for each Secondary Containment Isolation Function. 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 3.3.6.2.1 Perform CHANNEL CHECK. 12 hours SR 3.3.6.2.2 Perform CHANNEL FUNCTIONAL TEST. 92 days SR 3.3.6.2.3 Perform CHANNEL CALIBRATION. 18 months SR 3.3.6.2.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Columbia Generating Station 3.3.6.2-2 Amendment No. 225 Secondary Containment Isolation Instrumentation 3.3.6.2 Table 3.3.6.2-1 (page 1 of 1) Secondary Containment Isolation Instrumentation APPLICABLE REQUIRED MODES OR CHANNELS OTHER PER SPECIFIED TRIP SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM REQUIREMENTS VALUE Reactor Vessel Water Level -Low 1,2,3, (a) Low, Level 2 Drywell Pressure -High 1,2,3 Reactor Building Vent Exhaust 1,2,3, (a) 2 Plenum Radiation -High Manual Initiation 1,2,3, (a) 4 SR 3.3.6.2.2 SR 3.3.6.2.3 SR 3.3.6.2.4 SR 3.3.6.2.2 SR 3.3.6.2.3 SR 3.3.6.2.4 SR 3.3.6.2.1 SR 3.3.6.2.2 SR 3.3.6.2.3 SR 3.3.6.2.4 SR 3.3.6.2.4 -58 inches 1.88 psig 16.0 mR/hr NA (a) During operations with a potential for draining the reactor vessel. (b) Deleted (c) Also required to initiate the associated LOCA Time Delay Relay Function pursuant to LCO 3.3.5.1. Columbia Generating Station 3.3.6.2-3 Amendment No. +72,-+99 225 CREF System Instrumentation 3.3.7.1 3.3 INSTRUMENTATION 3.3.7.1 Control Room Emergency Filtration (CREF) System Instrumentation LCO The CREF System instrumentation for each Function in Table 3.3.7.1-1 shall be OPERABLE. According to Table 3.3.7.1-1. ACTIONS Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels inoperable. A.1 Enter the Condition referenced in Table 3.3.7.1-1 for the channel. Immediately B. As required by Required Action A.1 and referenced in Table 3.3.7.1-1. B.1 AND B.2 Declare associated CREF subsystem inoperable. Place channel in trip. 1 hour from discovery of loss of CREF initiation capability in both trip systems 24 hours C. As required by Required Action A.1 and referenced in Table 3.3.7.1-1. C.1 AND C.2 Declare associated CREF subsystem inoperable. Place channel in trip. 1 hour from discovery of loss of CREF initiation capability in both trip systems 12 hours Columbia Generating Station 3.3.7.1-1 Amendment No. 449,-te9 225 CREF System Instrumentation 3.3.7.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and associated Completion Time of Condition B or C not met. 0.1 OR 0.2 Place associated CREF subsystem in the pressurization mode of operation. Declare associated CREF subsystem inoperable. 1 hour 1 hour SURVEILLANCE REQUIREMENTS Refer to Table 3.3.7.1-1 to determine which SRs apply for each CREF System Function. 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. 18 months SR 3.3.7.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Columbia Generating Station 3.3.7.1-2 Amendment No. 4-37,499 225 CREF System Instrumentation 3.3.7.1 Table 3.3.7.1-1 (page 1 of 1) Control Room Emergency Filtration System Instrumentation FUNCTION APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTIONA.1 SURVEILLANCE REQUIREMENTS ALLOWABLE VALUE 1. Reactor Vessel Water Level -Low Low, Level 2 1,2,3,(a) 2 B SR 3.3.7.1.1 SR 3.3.7.1.2 SR 3.3.7.1.3 SR 3.3.7.1.4 -58 inches 2. Drywell Pressure -High 1,2,3 2 C SR 3.3.7.1.1 SR 3.3.7.1.2 SR 3.3.7.1.3 SR 3.3.7.1.4 $1.88 psig 3. Reactor Building Vent Exhaust Plenum Radiation -High 1,2,3,(a) 2 B SR 3.3.7.1.1 SR 3.3.7.1.2 SR 3.3.7.1.3 SR 3.3.7.1.4 $ 16.0 mRlhr (a) During operations with a potential for draining the reactor vessel. Columbia Generating Station 3.3.7.1-3 Amendment No. 4eQ,4-Q9 225 LOP Instrumentation 3.3.8.1 3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LCO The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3, When the associated diesel generator (DG) is required to be OPERABLE by LCO 3.8.2, "AC Sources -Shutdown." ACTIONS ------------------------------------------------------------N0 T E Separate Condition entry is allowed for each channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required channels inoperable. A.1 Enter the Condition referenced in Table 3.3.8.1-1 for the channel. Immediately B. As required by Required Action A.1 and referenced in Table 3.3.8.1-1. B.1 AND B.2 Declare associated DG inoperable. Restore channel to OPERABLE status. 1 hour from discovery of loss of initiation capability for the associated DG 24 hours C. As required by Required Action A.1 and referenced in Table 3.3.8.1-1. C.1 Place channel in trip. 1 hour Columbia Generating Station 3.3.8.1-1 Amendment No. 44Q,-+W 225 LOP Instrumentation 3.3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and associated Completion Time of Condition B or C not met. D.1 Declare associated DG inoperable. OR --------------------NOT E Only applicable for Functions 1.c and 1.d. D.2.1 Open offsite circuit supply breaker to associated 4.16 kV ESF bus. D.2.2 Declare associated offsite circuit inoperable. Immediately Immediately Immediately SURVEILLANCE REQUIREMENTS Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function. 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 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. 18 months SR 3.3.8.1.3 Perform CHANNEL CALIBRATION 24 months SR 3.3.8.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months Columbia Generating Station 3.3.8.1-2 Amendment No. 449,-+e9 225 LOP Instrumentation 3.3.8.1 Table 3.3.8.1-1 (page 1 of 1) Loss of Power Instrumentation CONDITIONS REQUIRED REFERENCED CHANNELS FROM PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION DIVISION ACTIONA1 REQUIREMENTS VALUE 1. Divisions 1 and 2 -4.16 kV Emergency Bus Undervoltage a. TR-S Loss of Voltage 4.16 kV Basis 2 B SR 3.3.8.1.2 SR 3.3.8.1.4 2450 V and 3135 V b. TR-S Loss of Voltage Time Delay 2 B SR 3.3.8.1.3 SR 3.3.8.1.4 2.95 seconds and 7.1 seconds c. TR-B Loss of Voltage 4.16 kV Basis C SR 3.3.8.1.3 SR 3.3.8.1.4 2450 V and 3135 V d. TR-B Loss of Voltage Time Delay C SR 3.3.8.1.3 SR 3.3.8.1.4 3.06 seconds and 9.28 seconds e. Degraded Voltage 4.16 kV Basis 2(a) C SR 3.3.8.1.1 SR 3.3.8.1.2 SR 3.3.8.1.4 3685 V and 3755 V f. Degraded Voltage Primary Time Delay 2(a) C SR 3.3.8.1.1 SR 3.3.8.1.2 SR 3.3.8.1.4 5.0 seconds and 5.3 seconds g. Degraded Voltage Secondary Time Delay C SR 3.3.8.1.2 SR 3.3.8.1.4 2.63 seconds and 3.39 seconds 2. Division 3 -4.16 kV Emergency Bus Undervoltage a. Los of Voltage 4.16 kV Basis 2 B SR 3.3.8.1.2 SR 3.3.8.1.4 2450 V and 3135 V b. Loss of voltage Time Delay 2 B SR 3.3.8.1.3 SR 3.3.8.1.4 1.87 seconds and 3.73 seconds c. Degraded Voltage 4.16 kV Basis 2 C SR 3.3.8.1.2 SR 3.3.8.1.4 3685 V and S; 3755 V d. Degraded Voltage Time Delay 2 C SR 3.3.8.1.2 SR 3.3.8.1.4 7.36 seconds and < 8.34 seconds (a) The Degraded Voltage -4.16 kV Basis and -Primary Time Delay Functions must be associated with one another. Columbia Generating Station 3.3.8.1-3 Amendment NO.449,4*).9 225 RPS Electric Power Monitoring 3.3.8.2 3.3 INSTRUMENTATION 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring LCO Two RPS electric power monitoring assemblies shall be OPERABLE for each inservice RPS motor generator set or alternate power supply that supports equipment required to be OPERABLE. APPLICABILITY: MODES 1, 2, and 3, MODES 4 and 5 with both residual heat removal (RHR) shutdown cooling (SDC) suction isolation valves open, MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or both required inservice power supplies with one electric power monitoring assembly inoperable. A.1 Remove associated inservice power supply(s) from service. 72 hours B. One or both required inservice power supplies with both electric power monitoring assemblies inoperable. B.1 Remove associated inservice power supply(s) from service. 1 hour C. Required Action and associated Completion Time of Condition A or B not met in MODE 1,2, C.1 AND Be in MODE 3. 12 hours or 3. C.2 Be in MODE 4. 36 hours Columbia Generating Station 3.3.8.2-1 Amendment No. -+49,4-99 225 RPS Electric Power Monitoring 3.3.8.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and associated Completion Time of Condition A or B not met in MODE 4 or 5 with both RHR SDC suction isolation valves open. D.1 OR D.2 Initiate action to restore one electric power monitoring assembly to OPERABLE status for inservice power supply(s) supplying required instrumentation. Initiate action to isolate the RHR SDC System. Immediately Immediately E. Required Action and associated Completion Time of Condition A or B not met in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. E.1 Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Immediately SURVEILLANCE REQUIREMENTS -----------------------------------------------------------NOT E When an RPS electric power monitoring assembly is placed in an inoperable status solely for performance of required Surveillances, entry into the associated Conditions and Required Actions may be delayed for up to 6 hours provided the other RPS electric power monitoring assembly for the associated power supply maintains trip capability. SR -------------------------------NOT E Only required to be performed prior to entering MODE 2 or 3 from MODE 4, when in MODE 4 for 24 hours. Perform CHANNEL FUNCTIONAL TEST. 184 days Columbia Generating Station 3.3.8.2-2 Amendment No. -+49,4W 225 RPS Electric Power Monitoring 3.3.8.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.8.2.2 Perform CHANNEL CALIBRATION. The Allowable Values shall be: a. Overvoltage 133.8 V, with time delay s; 3.46 seconds; b. Undervoltage 110.8 V, with time delay s; 3.46 seconds; and c. Underfrequency 57 Hz, with time delay s; 3.46 seconds. 24 months SR 3.3.8.2.3 Perform a system functional test. 24 months Columbia Generating Station 3.3.8.2-3 Amendment No. 225 3.4.1 Recirculation Loops Operating REACTOR COOLANT SYSTEM (RCS) 3.4.1 Recirculation Loops Operating LCO 3.4.1 Two recirculation loops with matched flows shall be in operation. One recirculation loop shall be in operation provided that the following limits are applied when the associated LCO is applicable: LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," single loop operation limits specified in the COLR; and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," single loop operation limits specified in the COLR. APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Recirculation loop flow mismatch not within limits. A.1 Declare the recirculation loop with lower flow to be "not in operation." 2 hours B. Requirements of the LCO not met for reasons other than Condition A. B.1 Satisfy the requirements of the LCO. 4 hours C. Required Action and associated Completion Time of Condition A or B not met. OR No recirculation loops in operation. C.1 Be in MODE 3. 12 hours Columbia Generating 3.4.1-1 Amendment 225 3.4.1 Recirculation Loops Operating SURVEILLANCE REQUIREMENTS SR -------------------------------NOT E Not required to be performed until 24 hours after both recirculation loops are in operation. Verify recirculation loop drive flow mismatch with both recirculation loops in operation is: 24 hours a. 10% of rated recirculation loop drive flow when operating at < 70% of rated core flow; and b. 5% of rated recirculation loop drive flow when operating at;::: 70% of rated core flow. Columbia Generating Station 3.4.1-2 Amendment No. -+e9,:J-7.1. 225 3.4.2 Jet Pumps 3.4 REACTOR COOLANT SYSTEM 3.4.2 Jet LCO 3.4.2 All jet pumps shall be APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more jet pumps inoperable. A.1 Be in MODE 3. 12 hours Columbia Generating Station 3.4.2-1 Amendment No. 449,400 225 3.4.2 Jet Pumps SURVEILLANCE REQUIREMENTS FREQUENCY SR 3.4.2.1 24 hours SURVEILLANCE Not required to be performed until 4 hours after associated recirculation loop is in operation. Not required to be performed until 24 hours after> 25% RTP. Verify at least two of the following criteria (a, b, and c) are satisfied for each operating recirculation loop: Recirculation loop drive flow versus recirculation pump speed differs by :s; 10% from established patterns. Recirculation loop drive flow versus total core flow differs by:s; 10% from established patterns. Each jet pump diffuser to lower plenum differential pressure differs by :s; 20% from established patterns, or each jet pump flow differs by :s; 10% from established patterns. Columbia Generating 3.4.2-2 Amendment No. -+49,-+99 225 SRVs -;:: 25% RTP 3.4.3 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.3 Safety/ReliefValves (SRVs) -;:: 25% RTP LCO The safety function of 12 SRVs shall be OPERABLE, with two SRVs in the lowest two lift setpoint groups OPERABLE. APPLICABILITY: THERMAL POWER 25% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required SRVs inoperable. A.1 Reduce THERMAL POWER to < 25% RTP. 4 hours SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.3.1 Verify the safety function lift setpoints of the required SRVs are as follows: Number of SRVs 2 4 4 4 4 Setpoint jQ§jg) 1165 +/- 34.9 1175 +/- 35.2 1185 +/-35.5 1195 +/- 35.8 1205 +/- 36.1 In accordance with the Inservice Testing Program SR 3.4.3.2 Verify each required SRV opens when manually actuated. 24 months Columbia Generating 3.4.3-1 Amendment No. 449,-ie9 225 SRVs -< 25% RTP 3.4.4 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.4 Safety/ReliefValves (SRVs) -< 25% RTP LCO The safety function of four SRVs shall be OPERABLE. MODE 1 with THERMAL POWER < 25% RTP, MODES 2 and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Be in MODE 3. 12 hours SRVs inoperable. AND A.2 Be in MODE 4. 36 hours SURVEILLANCE SR Verify the safety function lift setpoints of the required SRVs are as follows: Number of Setpoint SRVs ..illm! 2 1165 +/- 34.9 4 1175 +/- 35.2 4 1185 +/- 35.5 4 1195 +/- 35.8 4 1205 +/- 36.1 In accordance with the Inservice . Testing Program Columbia Generating 3.4.4-1 Amendment No. 449,..:t.69 225 3.4.4 SRVs -< 25% RTP SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.4.2 -------------------------------NOT E Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. Verify each required SRV opens when manually actuated. 24 months Columbia Generating Station 3.4.4-2 Amendment No. -M9,4G9 225 RCS Operational LEAKAGE 3.4.5 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.5 RCS Operational LEAKAGE LCO 3.4.5 RCS operational LEAKAGE shall be limited to: No pressure boundary LEAKAGE; S; 5 gpm unidentified LEAKAGE; S; 25 gpm total LEAKAGE averaged over the previous 24 hour period; and S; 2 gpm increase in unidentified LEAKAGE within the previous 24 hour period in MODE 1. APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Unidentified LEAKAGE not within limit. OR Total LEAKAGE not within limit. A.1 Reduce LEAKAGE to within limits. 4 hours B. Unidentified LEAKAGE increase not within limit. B.1 OR Reduced unidentified LEAKAGE increase to within limit. 4 hours B.2 Verify source of unidentified LEAKAGE increase is not service sensitive type 304 or type 316 austenitic stainless steel. 4 hours Columbia Generating 3.4.5-1 Amendment No. 449,499 225 3.4.5 RCS Operational LEAKAGE ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and associated Completion Time of Condition A or B not met. Pressure boundary LEAKAGE exists. C.1 AND C.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.4.5.1 Verify RCS unidentified and total LEAKAGE and 12 hours unidentified LEAKAGE increase are within limits. Columbia Generating Station 3.4.5-2 Amendment No. -14B,4e9 225 3.4.6 RCS PIV Leakage 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.6 RCS Pressure Isolation Valve (PIV) Leakage LCO 3.4.6 The leakage from each RCS PIV shall be within limit. APPLICABILITY: MODES 1 and 2, MODE 3, except valves in the residual heat removal shutdown cooling flowpath when in, or during transition to or from, the shutdown cooling mode of operation. ACTIONS 1. Separate Condition entry is allowed for each flow path. 2. Enter applicable Conditions and Required Actions for systems made inoperable by PIVs. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more flow paths with leakage from one or more RCS PIVs not within limit. Each check valve used to satisfy Required Action A.1 shall have been verified to meet SR 3.4.6.1 and be in the reactor coolant pressure boundary. A.1 Isolate the high pressure portion of the affected system from the low pressure portion by use of one closed manual, deactivated automatic, or check valve. 4 hours Columbia Generating Station 3.4.6-1 Amendment No. 225 3.4.6 RCS PIV Leakage ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SR ------------------------------NO Only required to be performed in MODES 1 and 2. Verify equivalent leakage of each RCS PIV is 0.5 gpm per nominal inch of valve size up to a maximum of 5 gpm, at an RCS pressure of 1035 psig. The actual test pressure shall be 935 psig. In accordance with Inservice Testing Program Columbia Generating 3.4.6-2 Amendment No. 225 RCS Leakage Detection Instrumentation 3.4.7 REACTOR COOLANT SYSTEM (RCS) 3.4.7 RCS Leakage Detection Instrumentation LCO The following RCS leakage detection instrumentation shall be OPERABLE: Drywell floor drain sump flow monitoring system; and One channel of either drywell atmospheric particulate or atmospheric gaseous monitoring system. MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Drywell floor drain sump flow monitoring system inoperable. A.1 Restore drywell floor drain sump flow monitoring system to OPERABLE status. 30 days B. Required drywell atmospheric monitoring system inoperable. B.1 AND B.2 Analyze grab samples of drywell atmosphere. Restore required drywell atmospheric monitoring system to OPERABLE status. Once per 12 hours 30 days Columbia Generating 3.4.7-1 Amendment No. -+eg,+37 225 3.4.7 RCS Leakage Detection Instrumentation ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME Only applicable when the drywell atmospheric gaseous monitoring system is the only OPERABLE C.1 AND Analyze grab samples of the drywell atmosphere. Once per 12 hours monitor. ...............__... __... _-------... _----...--------_....... C. Drywell floor drain sump flow monitoring system C.2 AND Monitor RCS LEAKAGE by administrative means . Once per 12 hours inoperable. C.3 Restore drywell floor drain sump flow monitoring system to OPERABLE status. 7 days D. Required Action and associated Completion Time of Condition A, B, or C not met. 0.1 AND Be in MODE 3. 12 hours 0.2 Be in MODE 4. 36 hours E. All required leakage detection systems inoperable. E.1 Enter LCO 3.0.3. Immediately Columbia Generating Station 3.4.7-2 Amendment No . 225 3.4.7 RCS Leakage Detection Instrumentation SURVEILLANCE REQUIREMENTS 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 other required leakage detection instrumentation is OPERABLE. SURVEILLANCE FREQUENCY SR 3.4.7.1 Perform CHANNEL CHECK of required drywell atmospheric monitoring system. 12 hours SR 3.4.7.2 Perform CHANNEL FUNCTIONAL TEST of required leakage detection instrumentation. 31 days SR 3.4.7.3 Perform CHANNEL CALIBRATION of required leakage detection instrumentation. 18 months Columbia Generating Station 3.4.7-3 Amendment No. 225 RCS Specific Activity 3.4.8 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.8 RCS Specific Activity LCO The specific activity of the reactor coolant shall be limited to DOSE EQUIVALENT 1-131 specific activity S 0.2 MODE 1, MODES 2 and 3 with any main steam line not isolated. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Reactor coolant specific activity> 0.2 and :-:; 4.0 J.lCi/gm DOSE EQUIVALENT 1-131. --------------------NOT E LCO 3.0.4.c is applicable. A.1 Determine DOSE EQUIVALENT 1-131. AND Once per 4 hours A.2 Restore DOSE EQUIVALENT 1-131 to within limits. 48 hours B. Required Action and associated Completion Time of Condition A not met. B.1 Determine DOSE EQUIVALENT 1-131. AND Once per 4 hours OR Reactor coolant specific activity> 4.0 J.lCi/gm B.2.1 Isolate all main steam lines. OR 12 hours DOSE EQUIVALENT 1-131. B.2.2.1 Be in MODE 3. AND 12 hours B.2.2.2 Be in MODE 4. 36 hours Columbia Generating 3.4.8-1 Amendment No. 4W,.:l37 225 3.4.8 RCS Specific Activity SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.8.1 ------------------------------N 0 Only required to be performed in MODE 1. Verify reactor coolant DOSE EQUIVALENT 1-131 specific activity is 0.2 ,..Ci/gm. 7 days Columbia Generating Station 3.4.8-2 Amendment No. 225 RHR Shutdown Cooling System -Hot Shutdown 3.4.9 REACTOR COOLANT SYSTEM (RCS) 3.4.9 Residual Heat Removal (RHR) Shutdown Cooling System -Hot Shutdown LCO Two RHR shutdown cooling subsystems shall be OPERABLE, and, with no recirculation pump in operation, at least one RHR shutdown cooling subsystem shall be in operation. --------------------------------------------NOT E S Both RHR shutdown cooling subsystems and recirculation pumps may be removed from operation for up to 2 hours per 8 hour period. One RHR shutdown cooling subsystem may be inoperable for up to 2 hours for performance of Surveillances. MODE 3 with reactor steam dome pressure less than 48 psig. ACTIONS ------------------------------------------------------------NOT E Separate Condition entry is allowed for each RHR shutdown cooling subsystem. REQUIRED ACTION COMPLETION A. One or two RHR shutdown cooling subsystems inoperable. A.1 Initiate action to restore RHR shutdown cooling subsystem to OPERABLE status. Immediately AND A.2 Verify an alternate method of decay heat removal is available for each inoperable RHR shutdown cooling subsystem. 1 hour AND A.3 Be in MODE 4. 24 hours Columbia Generating 3.4.9-1 Amendment No. 4$,4-8+ 225 3.4.9 RHR Shutdown Cooling System -Hot Shutdown ACTIONS REQUIRED ACTION COMPLETION No RHR shutdown cooling subsystem in operation. AND No recirculation pump in operation. B.1 AND B.2 AND B.3 Initiate action to restore one RHR shutdown cooling subsystem or one recirculation pump to operation. Verify reactor coolant circulation by an alternate method. Monitor reactor coolant temperature and pressure. Immediately 1 hour from discovery of no reactor coolant circulation AND Once per 12 hours thereafter Once per hour SURVEILLANCE SR ------------------------------NO TE Not required to be met until 2 hours after reactor steam dome pressure is less than 48 psig. Verify one RHR shutdown cooling subsystem or recirculation pump is operating. 12 hours Columbia Generating 3.4.9-2 Amendment No. 4-64,4W 225 RHR Shutdown Cooling System -Cold Shutdown 3.4.10 REACTOR COOLANT SYSTEM (RCS) 3.4.10 Residual Heat Removal (RHR) Shutdown Cooling System -Cold Shutdown LCO Two RHR shutdown cooling subsystems shall be OPERABLE, and, with no recirculation pump in operation, at least one RHR shutdown cooling subsystem shall be in operation. Both RHR shutdown cooling subsystems and recirculation pumps may be removed from operation for up to 2 hours per 8 hour period. One RHR shutdown cooling subsystem may be inoperable for up to 2 hours for the performance of Surveillances. MODE 4. ACTIONS Separate Condition entry is allowed for each RHR shutdown cooling subsystem. CONDITION REQUIRED ACTION COMPLETION TIME A. One or two RH R shutdown cooling subsystems inoperable. A.1 Verify an alternate method of decay heat removal is available for each inoperable RHR shutdown cooling subsystem. 1 hour Once per 24 hours thereafter Columbia Generating Station 3.4.10-1 Amendment No. 225 3.4.10 RHR Shutdown Cooling System -Cold Shutdown ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. No RHR shutdown B.1 Verify reactor coolant 1 hour from discovery cooling subsystem in circulating by an alternate of no reactor coolant operation. method. circulation AND AND No recirculation pump in Once per 12 hours operation. thereafter AND Monitor reactor coolant Once per hour temperature and pressure. SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.4.10.1 Verify one RHR shutdown cooling subsystem or 12 hours recirculation pump is operating. Columbia Generating Station 3.4.10-2 Amendment No. +49,-1-69 225 RCS PIT Limits 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 RCS Pressure and Temperature (PIT) Limits 3.4.11 RCS pressure, RCS temperature, RCS heatup and cooldown rates, and the recirculation loop temperature requirements shall be maintained within limits. APPLICABI LlTY: At all times. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Required Action A.2 shall be completed if this Condition is entered . ..------------.._-_... _..... A.1 AND Restore parameter( s) to within limits. 30 minutes Requirements of the LCO not met in MODE 1, 2, or 3. A.2 Determine RCS is acceptable for continued operation. 72 hours B. Required Action and associated Completion Time of Condition A not met. B.1 AND Be in MODE 3. 12 hours C. Required Action C.2 shall be completed if this Condition is entered. Requirements of the LCO not met in other than MODES 1, 2, and 3. B.2 C.1 AND C.2 Be in MODE4. Initiate action to restore parameter(s) to within limits. Determine RCS is acceptable for operation. 36 hours Immediately Prior to entering MODE 2 or 3 Columbia Generating Station 3.4.11-1 Amendment No. .::t49,-W9 225 RCS PIT Limits 3.4.11 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1 Only required to be performed during RCS heatup and cooldown operations, and RCS inservice leak and hydrostatic testing. Verify: a. RCS pressure and RCS temperature are within the applicable limits specified in Figures 3.4.11-1, 3.4.11-2, and 3.4.11-3; b. RCS heatup and cooldown rates are S 100°F in any 1 hour period; and c. RCS temperature change during inservice leak and hydrostatic testing is S 20°F in any 1 hour period when the RCS pressure and RCS temperature are not within the limits of Figure 3.4.11-2. 30 minutes SR 3.4.11.2 Verify RCS pressure and RCS temperature are within the criticality limits specified in Figure 3.4.11-3. Once within 15 minutes prior to control rod withdrawal for the purpose of achieving criticality SR 3.4.11.3 -------------------------------NOT E Only required to be met in MODES 1, 2, 3, and 4 during recirculation pump startup. Verify the difference between the bottom head coolant temperature and the reactor pressure vessel (RPV) coolant temperature is :-s; 145°F. Once within 15 minutes prior to each startup of a recirculation pump Columbia Generating Station 3.4.11-2 Amendment No. 449,4-&9 225 RCS PIT Limits 3.4.11 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.4 -------------------------------N0TEOnly required to be met in MODES 1, 2, 3, and 4 during recirculation pump startup. Verify the difference between the reactor coolant temperature in the recirculation loop to be started and the RPV coolant temperature is s 50°F. Once within 15 minutes prior to each startup of a recirculation pump SR 3.4.11.5 Only required to be met in a single loop operation with THERMAL POWER 25% RTP or the operating recirculation loop flow s 10% rated loop flow. Verify the difference between the bottom head coolant temperature and the RPV coolant temperature is 145°F. Once within 15 minutes prior to an increase in THERMAL POWER or an increase in loop flow SR 3.4.11.6 -------------------------------NOTE Only required to be met in single loop operation when the idle recirculation loop is not isolated from the RPV, and with THERMAL POWER 25% RTP or the operating recirculation loop flow 10% rated loop flow. Verify the difference between the reactor coolant temperature in the recirculation loop not in operation and the RPV coolant temperature is s 50°F. Once within 15 minutes prior to an increase in THERMAL POWERoran increase in loop flow Columbia Generating Station 3.4.11-3 Amendment No. 225 3.4.11 RCS P!T Limits SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.7 -------------------------------NOTE Only required to be performed when tensioning the reactor vessel head bolting studs. Verify reactor vessel flange and head flange temperatures are 80°F. 30 minutes SR 3.4.11.8 -------------------------------N aTE Not required to be performed until 30 minutes after RCS temperature $ 90°F in MODE 4. Verify reactor vessel flange and head flange temperatures are 80°F. 30 minutes SR 3.4.11.9 -------------------------------NO TE Not required to be performed until 12 hours after RCS temperature $ 100°F in MODE 4. Verify reactor vessel flange and head flange temperatures are 80°F. 12 hours Columbia Generating Station 3.4.11-4 Amendment No. 225 RCS PIT Limits 3.4.11 Ii 'iii : 1000 w:z: g 900 ..J lSOOPSIGIee"F800(./) 700 wa:: 600 !; .... i SOD BOTTOM:::i HEAOw a:: ee'F ;:) fJ) 4000 wa: Q. 300 200 100 0 0 25 50 L. i I i I ! i j / I:' ; ,..:,f i : . { . * ...--v 1 t * ** 75 100 INITIAL RTndt VALUES 28°F FOR BEL 34°F FOR UPPER 34°F FOR BOTTOM BEL TLINE CURVES ADJUSTED AS SHOWN: EFPV SHIFT (OF) 33.1 35 HEATUP/COOLDOWN RATE OF COOLANT 20"F/HR ACCEPTABLE AREA OF OPERA TION TO THE RIGHT OF THIS CURVE ., .-UPPER VESSEL IFLANGE AND BEL TUNE REGION
- LIMITS8O"F '-r----' *** ". -BOTTOM HEAD CURVE 125 150 175 200 MINIMUM REACTOR VESSEL METAL TEMPERATURE C-F) Figure 3.4.11-1 (page 1 of Inservice Leak and Hydrostatic Testing Columbia Generating Station 3.4.11-5 Amendment No. -1-9Q,-1-Q3 225 i 3.4.11 1400 1300 1200 1100 400 300 200 100 o --+----I-t-----+--------1-----+---1 , 790PSIG ---,-i---r---t--i------r---1400F --+---,----1 I : +----tl---,----+: -+-------+--+-. ---L--------r--+----I/-+______+ ______+I_____ I 1-----------+ r-,. . o RCS prr Limits INITIAL RTndt VALUES 2soF FOR BEL 34"F FOR UPPER 34"F FOR BOTTOM BEL TLINE CURVES ADJUSTED AS SHOWN: EFPY SHIFT (OF) 33.1 35 HEATUP/COOLDOWN RATE OF COOLANT :! 100"FIHR ACCEPTABLE AREA OF OPERATION TO THE RIGHT OF THIS CURVE LIMITS-_____ -I. ***** -BOTTOM HEAD ![_ CURVE 25 50 75 100 125 150 175 200 225 250 MINIMUM REACTOR VESSEL METAL TEMPERATURE (OF) Figure 3.4.11-2 (page 1 of Non-Nuclear Heating and Cool down Columbia Generating Station 3.4.11-6 Amendment No . .:l$*.m 225 3.4.11 RCS PIT Limits 1400 1300 1200 1100 Ii.. 1000 w :z: g 900 ...J W CI') SooCI') 0:: 0 700 Wa:: 600 !:: ::II! 500::::i wa:: :::;) CI') 400CI') wa:: t:L 300 200 100 0 I 312PSIGI ! I . i ..-1-___. 'JL, Temperature 80°F 1/ 1 INITIAL RTndt 2soF FOR BEL 34°F FOR 34°F FOR BOTTOM BEL TLINE CURVE ADJUSTED AS SHOWN: EFPY SHIFT (OF) 33.1 35 HEATUP/COOLDOWN RATE OF COOLANT 100°F/HR ACCEPTABLE AREA OF OPERATION TO THE RIGHT OF THIS CURVE -BELTLINE AND NON* BEL TUNE LIMITS o 25 50 75 100 125 150 175 200 225 250 275 300 MINIMUM REACTOR VESSEL METAL TEMPERATURE (OF) Figure 3.4.11-3 (page 1 of 1) Nuclear Heating and Cooldown Curve Columbia Generating Station 3.4.11-7 Amendment No. 4e9,4-Q3 225 3.4.12 Reactor Steam Dome Pressure 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 Reactor Steam Dome Pressure LCO 3.4.12 The reactor steam dome pressure shall be 1035 psig. APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Reactor steam dome pressure not within limit. A.1 Restore reactor steam dome pressure to within limit. 15 minutes B. Required Action and associated Completion Time not met. B.1 Be in MODE 3. 12 hours SURVEILLANCE SURVEILLANCE FREQUENCY 12 hoursSR 3.4.12.1 Verify reactor steam dome pressure is :5 1035 psig. Columbia Generating Station 3.4.12-1 Amendment No. 449,+99 225 ECCS -Operating 3.5.1 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS -Operating LCO Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE. APPLICABILITY: MODE 1, MODES 2 and 3, except ADS valves are not required to be OPERABLE with reactor steam dome pressure::; 150 psig. ACTIONS LCO 3.0.4.b is not applicable to HPCS. CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS injection/spray subsystem inoperable. A.1 Restore low pressure ECCS injection/spray subsystem to OPERABLE status. 7 days B High Pressure Core Spray (HPCS) System inoperable. B.1 AND B.2 Verify by administrative means RCIC System is OPERABLE when RCIC System is required to be OPERABLE. Restore HPCS System to OPERABLE status. Immediately 14 days Columbia Generating 3.5.1-1 Amendment No. 499,48+ 225 3.5.1 ECCS -Operating ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Two ECCS injection subsystems inoperable. OR One ECCS injection and one ECCS spray C.1 Restore ECCS injection/spray subsystem to OPERABLE status. 72 hours subsystem inoperable. D. Required Action and associated Completion Time of Condition A, B, or C not met. D.1 AND D.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours E. One required ADS valve inoperable. E.1 Restore ADS valve to OPERABLE status. 14 days F. One required ADS valve inoperable. AND One low pressure ECCS injection/spray subsystem inoperable. F.1 OR F.2 Restore ADS valve to OPERABLE status. Restore low pressure ECCS injection/spray subsystem to OPERABLE status. 72 hours 72 hours G. Required Action and G.1 Be in MODE 3. 12 hours associated Completion Time of Condition E or F AND not met. G.2 Reduce reactor steam 36 hours OR dome pressure to 150 psig. Two or more required ADS valves inoperable. Columbia Generating Station 3.5.1-2 Amendment No. 44B,4eQ 225 3.5.1 ECCS -Operating ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H. HPCS and Low Pressure Core Spray (LPCS) Systems inoperable. OR Three or more ECCS injection/spray subsystems inoperable. OR HPCS System and one or more required ADS valves inoperable. OR Two or more ECCS injection/spray subsystems and one or more required ADS valves inoperable. H.1 Enter LCO 3.0.3. Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.5.1.1 Verify, for each ECCS injection/spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve. 31 days Columbia Generating Station 3.5.1-3 Amendment No. 225 3.5.1 ECCS -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.2 Low pressurmay be consand operatiosteam dome if capable of otherwise inoperable. Verify each manual, powflow path, thsecured in p-------------NOTE e coolant injection {LPCI} subsystems idered OPERABLE during alignment n for decay heat removal with reactor pressure less than 48 psig in MODE 3, being manually realigned and not ECCS injection/spray subsystem er operated, and automatic valve in the at is not locked, sealed, or otherwise osition, is in the correct position. 31 days SR Verify ADS accumulator backup compressed gas 31 days system average pressure in the required bottles is 2200 psig. SR SR Verify each ECCS pump develops the specified flow rate with the specified differential pressure between reactor and suction source. DIFFERENTIAL SYSTEM FLOW RATE PRESSURE BETWEEN REACTOR AND SUCTION SOURCE LPCS LPCI HPCS 6350 gpm 7450 gpm 6350 gpm 128 psid 26 psig 200 psig -------------------------------NOTE Vessel injection/spray may be excluded. Verify each ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal. In accordance with the Inservice Testing Program 24 months Columbia Generating 3.5.1-4 Amendment No. 469,2Q& 225 3.5.1 ECCS -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.1.6 -------------------------------NO TE Valve actuation may be excluded. Verify the ADS actuates on an actual or simulated automatic initiation signal. 24 months SR 3.5.1.7 ------------------------------N0TE Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. Verify each required ADS valve opens when manually actuated. 24 months on a STAGGERED TEST BASIS for each valve solenoid SR 3.5.1.8 ---------------------------NOTE ECCS actuation instrumentation is excluded. Verify the ECCS RESPONSE TIME for each ECCS injection/spray subsystem is within limits. 24 months Columbia Generating Station 3.5.1-5 Amendment No. 4eO,469 225 ECCS -Shutdown 3.5.2 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.2 ECCS -Shutdown LCO 3.5.2 Two ECCS injection/spray subsystems shall be OPERABLE. APPLICABILITY: MODE 4, MODE 5 except with the spent fuel storage pool gates removed and water level 22 ft over the top of the reactor pressure vessel flange. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required ECCS injection/spray subsystem inoperable. A.1 Restore required ECCS injection/spray subsystem to OPERABLE status. 4 hours B. Required Action and associated Completion Time of Condition A not met. B.1 Initiate action to suspend operations with a potential for draining the reactor vessel (OPDRVs). Immediately C. Two required ECCS injection/spray subsystems inoperable. C.1 AND C.2 Initiate action to suspend OPDRVs. Restore one ECCS injection/spray subsystem to OPERABLE status. Immediately 4 hours Columbia Generating 3.5.2-1 Amendment No. -taG,4W 225 3.5.2 ECCS -Shutdown ACTIONS REQUIRED ACTION CONDITION Required Action C.2 and 0.1 Initiate action to restore associated Completion secondary containment to Time not met. OPERABLE status. AND Initiate action to restore one standby gas treatment subsystem to OPERABLE status. AND Initiate action to restore isolation capability in each required secondary containment penetration flow path not isolated. SURVEILLANCE COMPLETION Immediately Immediately Immediately SURVEILLANCE FREQUENCY SR 3.5.2.1 Verify, for each required low pressure ECCS injection/spray subsystem, the suppression pool water level is z 18 ft 6 inches. 12 hours SR 3.5.2.2 Verify, for the required High Pressure Core Spray (HPCS) System, the: a. Suppression pool water level is z 18 ft 6 inches; or b. Condensate storage tank (CST) water level is z 16.5 ft in a single CST or 10.5 ft in each CST. 12 hours Columbia Generating 3.5.2-2 Amendment No. +e9,2-+Q 225 3.5.2 ECCS -Shutdown SURVEILLANCE REQUIREMENTS otherwise inoperable. SURVEILLANCE FREQUENCY SR 3.5.2.3 Verify, for each required ECCS injection/spray subsystem, the piping is filled with water from the pump discharge valve to the injection valve. 31 days SR 3.5.2.4 One low pressure coolant injection (LPCI) subsystem may be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned and not Verify each required ECCS injection/spray subsystem manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position. 31 days SR 3.5.2.5 Verify each required ECCS pump develops the specified flow rate with the specified differential pressure between reactor and suction source. SYSTEM FLOW RATE LPCS LPCI HPCS ;?: 6350 gpm ;?: 7450 gpm ;?: 6350 gpm DIFFERENTIAL PRESSURE BETWEEN REACTOR AND SUCTION SOURCE ;?: 128 psid ;?: 26 psig ;?: 200 psig In accordance with the Inservice Testing Program SR 3.5.2.6 Vessel injection/spray may be excluded. Verify each required ECCS injection/spray subsystem actuates on an actual or simulated automatic initiation signal. 24 months Columbia Generating Station 3.5.2-3 Amendment No. 225 RCIC System 3.5.3 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.3 RCIC System LCO The RCIC System shall be OPERABLE. MODE 1, MODES 2 and 3 with reactor steam dome pressure> 150 psig. ACTIONS LCO 3.0.4.b is not applicable to RCIC. CONDITION REQUIRED ACTION COMPLETION TIME A. RCIC System inoperable. A.1 AND A.2 Verify by administrative means High Pressure Core Spray System is OPERABLE. Restore RCIC System to OPERABLE status. Immediately 14 days B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Reduce reactor steam dome pressure to ::; 150 psig. 12 hours 36 hours Columbia Generating 3.5.3-1 Amendment No . .:te9,+87 225 3.5.3 RCIC System SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.5.3.1 Verify the RCIC System piping is filled with water from the pump discharge valve to the injection valve. 31 days SR 3.5.3.2 Verify each RCIC System manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position. 31 days SR 3.5.3.3 -------------------------------NOT E Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. Verify, with reactor pressure s 1035 psig and 935 psig, the RCIC pump can develop a flow rate 600 gpm against a system head corresponding to reactor pressure. 92 days SR 3.5.3.4 -------------------------------NOT E Not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. Verify, with reactor pressure s 165 pSig, the RCIC pump can develop a flow rate 600 gpm against a system head corresponding to reactor pressure. 24 months SR 3.5.3.5 -------------------------------NOT E Vessel injection may be excluded. Verify the RCIC System actuates on an actual or simulated automatic initiation signal. 24 months Columbia Generating Station 3.5.3-2 Amendment No. 225 Primary Containment 3.6.1.1 3.6 CONTAINMENT 3.6.1.1 Primary LCO 3.6.1.1 Primary containment shall be APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment inoperable. A.1 Restore primary containment to OPERABLE status. 1 hour B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SR Perform required visual examinations and leakage rate testing except for primary containment air lock testing, in accordance with the Primary Containment Leakage Rate Testing Program. In accordance with the Primary Containment Leakage Rate Testing Program Columbia Generating Station 3.6.1.1-1 Amendment No . .:t49,:ffi9 225 Primary Containment 3.6.1.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.6.1.1.2 Verify drywell to suppression chamber bypass 120 months leakage is S 10% of the acceptable A /.JK design value of 0.050 tr at an initial differential pressure of 1.5 psid. 48 months following a test with bypass leakage greater than the bypass leakage limit 24 months following two consecutive tests with bypass leakage greater than the bypass leakage limit until two consecutive tests are less than or equal to the bypass leakage limit SR 3.6.1.1.3 -------------------------------NOTE Performance of SR 3.6.1.1.2 satisfies this surveillance. Verify individual drywell to suppression chamber 24 months vacuum relief valve bypass pathway leakage is S 1.2% of the acceptable A /.JK design value of 0.050 tr at an initial differential pressure of 1.5 psid. Columbia Generating Station 3.6.1.1-2 Amendment No. 225 Primary Containment 3.6.1.1 SURVEILLANCE REQUIREMENTS SR Performance of SR 3.6.1.1.2 satisfies this surveillance. Verify total drywell to suppression chamber vacuum relief valve bypass leakage is S 3.0% of the acceptable A I JK design value of 0.050 fe at an initial differential pressure of <::: 1.5 psid. 24 months Columbia Generating Station 3.6.1.1-3 Amendment No. 2G4 225 Primary Containment Air Lock 3.6.1.2 3.6 CONTAINMENT SYSTEMS 3.6.1.2 Primary Containment Air Lock LCO 3.6.1.2 The primary containment air lock shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS 1. Entry and exit is permissible to perform repairs of the air lock components. 2. Enter applicable Conditions and Required Actions of LCO 3.6.1.1, "Primary Containment:' . when air lock leakage results in exceeding overall containment leakage rate acceptance criteria. CONDITION REQUIRED ACTION COMPLETION TIME A. One pri mary containment air lock door inoperable. 1. Required Actions A.1 t A.2, and A.3 are not applicable if both doors in the air lock are inoperable and Condition C is entered. 2. Entry and exit is permissible for 7 days under administrative controls. A.1 Verify the OPERABLE door is closed. AND 1 hour A.2 Lock the OPERABLE door closed. 24 hours Columbia Generating Station 3.6.1.2-1 Amendment No. 225 Primary Containment Air Lock 3.6.1.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3 ---------------N Air lock doors in high radiation areas or areas with limited access due to inerting may be verified locked closed by administrative means. ------------------------------_... __ ... Verify the OPERABLE door is locked closed. Once per 31 days B. Primary containment air lock interlock mechanism inoperable. 1. Required Actions B.1, B.2, and B.3 are not applicable if both doors in the air lock are inoperable and Condition C is entered. 2. Entry into and exit from primary containment is permissible under the control of a dedicated individual. --_... _...... _-_... _----------------------------_... B.1 Verify an OPERABLE door is closed. AND 1 hour B.2 Lock an OPERABLE door closed. AND 24 hours Columbia Generating Station 3.6.1.2-2 Amendment No. 449,499 225 Primary Containment Air Lock 3.6.1.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3 ---------------NO TE Air lock doors in high radiation areas or areas with limited access due to inerting may be verified locked closed by administrative means. Verify an OPERABLE door is locked closed. Once per 31 days C. Primary containment air lock inoperable for reasons other than Condition A or B. C.1 Initiate action to evaluate primary containment overall leakage rate per LCO 3.6.1.1, using current air lock test results. Immediately AND C.2 Verify a door is closed. 1 hour AND C.3 Restore air lock to OPERABLE status. 24 hours D. Required Action and associated Completion Time not met. D.1 AND Be in MODE 3. 12 hours D.2 Be in MODE 4. 36 hours Columbia Generating Station 3.6.1.2-3 Amendment No . .:t4Q.,+99 225 Primary Containment Air Lock 3.6.1.2 SURVEILLANCE REQUIREMENTS 3.6.1.2.1 -----------------------------N An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test. Results shall be evaluated against acceptance criteria applicable to SR 3.6.1.1.1. Perform required primary containment air lock leakage rate testing in accordance with the Primary Containment Leakage Rate Testing Program. In accordance with the Primary Containment Leakage Rate Testing Program SR 3.6.1.2.2 Verify only one door in the primary containment air 24 months lock can be opened at a time. Columbia Generating Station 3.6.1.2-4 Amendment No. -1-49,.:\.99 225 PCIVs 3.6.1.3 CONTAINMENT SYSTEMS 3.6.1.3 Primary Containment Isolation Valves (PCIVs) LCO Each PCIV, except reactor building-to-suppression chamber vacuum breakers, shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3, When associated instrumentation is required to be OPERABLE per LCO 3.3.6.1, "Primary Containment Isolation Instrumentation." ACTIONS ----------------------------------------------------------NOT E S Penetration flow paths may be unisolated intermittently under administrative controls. Separate Condition entry is allowed for each penetration flow path. Enter applicable Conditions and Required Actions for systems made inoperable by PCIVs. Enter applicable Conditions and Required Actions of LCO 3.6.1.1, "Primary Containment," when PCIV leakage results in exceeding overall containment leakage rate acceptance criteria. CONDITION REQUIRED ACTION COMPLETION TIME A -----------NO TE A1 Isolate the affected 4 hours except for Only applicable to penetration flow path by main steam line penetration flow paths use of at least one closed with two PCIVs. and de-activated automatic AND valve, closed manual valve, blind flange, or check valve 8 hours for main One or more penetration with flow through the valve steam line flow paths with one secured. PCIV inoperable for reasons other than AND Condition D. Columbia Generating Station 3.6.1.3-1 Amendment No. 4e9,200 225 PCIVs 3.6.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 --------------N OTE 1. Isolation devices in high radiation areas may be verified by use of administrative means. 2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means. Verify the affected penetration flow path is isolated. Once per 31 days for isolation devices outside primary containment Prior to entering MODE 2 or 3 from MODE 4 if primary containment was inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment Columbia Generating Station 3.6.1.3-2 Amendment No. 469,200 225 PCIVs 3.6.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. ------------NOTE Only applicable to penetration flow paths with two PCIVs. ------------------_...--...----_... One or more penetration flow paths with two PCIVs inoperable for reasons other than Condition D. B.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange. 1 hour C. ------------NOTE Only applicable to penetration flow paths with only one PCIV. One or more penetration flow paths with one PCIV inoperable for reasons other than Condition D. C.1 AND Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange. 4 hours except for excess flow check valves (EFCVs) AND 72 hours for EFCVs Columbia Generating Station 3.6.1.3-3 Amendment No . .:ffi9.,2Q8 225 PCIVs 3.6.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. (continued) C.2 --------------N 0 TE 1. Isolation devices in high radiation areas may be verified by use of administrative means. 2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means. Verify the affected penetration flow path is isolated. Once per 31 days for isolation devices outside primary containment Prior to entering MODE 2 or 3 from MODE 4 if primary containment was inerted while in MODE 4, if not performed within the previous 92 days, for isolation devices inside primary containment Columbia Generating Station 3.6.1.3-4 Amendment No. 225 PCIVs 3.6.1.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. One or more secondary containment bypass leakage rate, MSIV leakage rate, or hydrostatically tested lines leakage rate not within limit. D.1 Restore leakage rate to within limit. 4 hours for hydrostatically tested line leakage not on a closed system AND 4 hours for secondary containment bypass leakage AND 8 hours for MSIV leakage AND 72 hours for hydrostatically tested line leakage on a closed system E. Required Action and associated Completion Time of Condition A, B, C, or D not met in MODE 1, 2, or 3. E.1 AND E.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours F. Required Action and associated Completion Time of Condition A, B. C. or D not met for PCIV(s) required to be OPERABLE during MODE4 or 5. F.1 OR F.2 Initiate action to suspend operations with a potential for draining the reactor vessel (OPDRVs). Initiate action to restore valve(s) to OPERABLE Immediately Immediately status. Columbia Generating Station 3.6.1.3-5 Amendment No. 225 PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.1 -------------------------------N 0 TE Not required to be met when the 24 inch and 30 inch primary containment purge valves are open for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. Verify each 24 inch and 30 inch primary containment purge valve is closed. 31 days SR 3.6.1.3.2 ------------------------------NOTE1. Valves and blind flanges in high radiation areas may be verified by use of administrative means. 2. Not required to be met for PCIVs that are open under administrative controls. Verify each primary containment isolation manual valve and blind flange that is located outside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. 31 days Columbia Generating Station 3.6.1.3-6 Amendment No. 499,200 225 PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.3 ------------------------------NOT E 1. Valves and blind flanges in high radiation areas may be verified by use of administrative means. 2. Not required to be met for PCIVs that are open under administrative controls. Verify each primary containment isolation manual valve and blind flange that is located inside primary containment and not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. Prior to entering MODE 2 or 3 from MODE 4 if primary containment was de-inerted while in MODE 4, if not performed within the previous 92 days SR 3.6.1.3.4 Verify continuity of the traversing incore probe (TIP) shear isolation valve explosive charge. 31 days SR 3.6.1.3.5 Verify the isolation time of each power operated, automatic PCIV, except for MSIVs, is within limits. In accordance with the Inservice Testing Program SR 3.6.1.3.6 Verify the isolation time of each MSIV is 3 seconds and::; 5 seconds. In accordance with the Inservice Testing Program SR 3.6.1.3.7 Verify each automatic PCIV actuates to the isolation position on an actual or simulated isolation signal. 24 months SR 3.6.1.3.8 Verify a representative sample of reactor instrument line EFCVs actuate to the isolation position on an actual or simulated instrument line break signal. 24 months Columbia Generating Station 3.6.1.3-7 Amendment No. 225 PCIVs 3.6.1.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.1.3.9 Remove and test the explosive squib from each shear isolation valve of the TIP System. 24 months on a STAGGERED TEST BASIS SR 3.6.1.3.10 Verify the combined leakage rate for all secondary containment bypass leakage paths is 0.04% primary containment volume/day when pressurized to Pa . In accordance with the Primary Containment Leakage Rate Testing Program SR 3.6.1.3.11 Verify leakage rate through each MSIV is 16.0 scth when tested at 25.0 psig. In accordance with the Primary Containment Leakage Rate Testing Program SR 3.6.1.3.12 Verify combined leakage rate through hydrostatically tested lines that penetrate the primary containment is within limits. In accordance with the Primary Containment Leakage Rate Testing Program Columbia Generating Station 3.6.1.3-8 Amendment No. 499,2()g 225 Drywell Air Temperature 3.6.1.4 3.6 CONTAINMENT SYSTEMS 3.6.1.4 Drywell Air LCO 3.6.1.4 Drywell average air temperature shall be :s:; APPLICABI LlTY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Drywell average air temperature not within limit. A.1 Restore drywell average air temperature to within limit. 8 hours B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.1.4.1 Verify drywell average air temperature is within limit. 24 hours Columbia Generating Station 3.6.1.4-1 Amendment No. -+49,499 225 RHR Drywell Spray 3.6.1.5 3.6 CONTAINMENT SYSTEMS 3.6.1.5 Residual Heat Removal (RHR) Drywell LCO 3.6.1.5 Two RHR dryweli spray subsystems shall be APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR drywell spray subsystem inoperable. A.1 Restore RHR drywell spray subsystem to OPERABLE status. 7 days B. Two RHR drywell spray subsystems inoperable. B.1 Restore one RHR drywell spray subsystem to OPERABLE status. 8 hours C. Required Action and associated Completion Time not met. C.1 AND C.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SR Verify each RHR drywell spray subsystem manual, 31 days power operated, and automatic valve in 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 Verify each spray nozzle is unobstructed. 10 years Columbia Generating Station 3.6.1.5-1 Amendment No. 449,4eQ. 225 Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.6 3.6 CONTAINMENT SYSTEMS 3.6.1.6 Reactor Building-to-Suppression Chamber Vacuum Breakers LCO Each reactor building-to-suppression chamber vacuum breaker shall be OPERABLE. MODES 1, 2, and 3. ACTIONS Separate Condition entry is allowed for each line. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more lines with one reactor suppression chamber vacuum breaker not closed. A.1 Close the open Vacuum breaker. 72 hours B. One or more lines with two reactor suppression chamber vacuum breakers not closed. B.1 Close one open vacuum breaker. 1 hour C. One line with one or more reactor suppression chamber vacuum breakers inoperable for opening. C.1 Restore the vacuum breaker(s) to OPERABLE status. 72 hours D. Two or more lines with one or more reactor building-to-suppression chamber vacuum breakers inoperable for opening. 0.1 Restore all vacuum breakers in two lines to OPERABLE status. 1 hour Columbia Generating Station 3.6.1.6-1 Amendment No. -149,-1-99 225 Reactor Building-to-Suppression Chamber Vacuum Breakers 3.6.1.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. Required Action and associated Completion Time not met. E.1 AND E.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.1.6.1 1. Not required to be met for vacuum breakers that are open during Surveillances. 2. Not required to be met for vacuum breakers open when performing their intended function. Verify each vacuum breaker is closed. 14 days SR 3.6.1.6.2 Perform a functional test of each vacuum breaker. In accordance with the Inservice Testing Program SR 3.6.1.6.3 Verify the full open setpoint of each vacuum breaker is S 0.5 psid. 24 months Columbia Generating Station 3.6.1.6-2 Amendment No. 449,-W9 225 Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.7 3.6 CONTAINMENT SYSTEMS 3.6.1.7 Suppression Chamber-to-Drywell Vacuum Breakers LCO Seven suppression chamber-to-drywell vacuum breakers shall be OPERABLE for opening. Nine suppression chamber-to-drywell vacuum breakers shall be closed, except when performing their intended function. APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required suppression drywell vacuum breaker inoperable for opening. A.1 Restore one vacuum breaker to OPERABLE status. 72 hours B. Separate Condition entry is allowed for each suppression drywell vacuum breaker. One or more suppression drywell vacuum breakers with one disk not closed. B.1 Close the open vacuum breaker disk. 72 hours C. One or more suppression drywell vacuum breakers with two disks not closed. C.1 Close one open vacuum breaker disk. 2 hours Columbia Generating Station 3.6.1.7-1 Amendment No. 225 Suppression Chamber-to-Drywell Vacuum Breakers 3.6.1.7 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and associated Completion Time not met. D.1 AND D.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.1.7.1 -------------------------------NOT E Not required to be met for vacuum breakers that are open during Surveillances. Verify each vacuum breaker is closed. 14 days SR 3.6.1.7.2 Perform a functional test of each required vacuum breaker. 31 days Within 12 hours after any discharge of steam to the suppression chamber from the safety/relief valves SR 3.6.1.7.3 Verify the full open setpoint of each required vacuum breaker is :-:; 0.5 psid. 24 months Columbia Generating Station 3.6.1.7-2 Amendment No. 225 Suppression Pool Average Temperature 3.6.2.1 CONTAINMENT SYSTEMS 3.6.2.1 Suppression Pool Average Temperature LCO 3.6.2.1 Suppression pool average temperature shall be: gO°F when THERMAL POWER is > 1 % RTP and no testing that adds heat to the suppression pool is being performed; 105°F when THERMAL POWER is > 1 % RTP and testing that adds heat to the suppression pool is being performed; and 110°F when THERMAL POWER is 1 % RTP. APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Suppression pool A.1 Verify suppression pool Once per hour average temperature average temperature > gO°F but 110°F. 110°F. AND 24 > 1% RTP. average temperature THERMAL POWER A.2 Restore suppression pool Not performing that adds heat to suppression B. Required Action and B.1 Reduce THERMAL 12 associated Completion POWER to 1% Time of Condition A Columbia Generating Station 3.6.2.1-1 Amendment No. 449,+99 225 Suppression Pool Average Temperature 3.6.2.1 Suppression pool average temperature > 105°F. AND THERMAL POWER > 1% RTP. AND Performing testing that adds heat to the suppression pool. REQUIRED ACTION COMPLETION TIME C.1 Suspend all testing that adds heat to the suppression pool. Immediately D. Suppression pool average temperature > 110°F but s; 120°F. D.1 Place the reactor mode switch in the shutdown position. Immediately I ANDD.2 Verify suppression pool average temperature S; 120°F. Once per 30 minutes AND D.3 Be in MODE 4. 36 hours Suppression pool E.1 Depressurize the reactor 12 hours average temperature vessel to < 200 psig. > 120°F. AND E.2 Be in MODE 4. 36 hours Columbia Generating Station 3.6.2.1-2 Amendment No. 449,-1-99 225 Suppression Pool Average Temperature 3.6.2.1 SURVEILLANCE REQUIREMENTS SR 3.6.2.1.1 Verify suppression pool average temperature is within the applicable limits. 24 hours 5 minutes when performing testing that adds heat to the suppression pool Columbia Generating Station 3.6.2.1-3 Amendment No. 449.469 225 Suppression Pool Water Level 3.6.2.2 3.6 CONTAINMENT SYSTEMS 3.6.2.2 Suppression Pool Water Level 3.6.2.2 Suppression pool water level shall be 30 ft 9.75 inches and 31 ft 1.75 inches. APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A, Suppression pool water level not within limits. A,1 Restore suppression pool water level to within limits. 2 hours B. Required Action and associated Completion Time not met. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.2.2.1 Verify suppression pool water level is within limits. 24 hours Columbia Generating Station 3.6.2.2-1 Amendment No. :t49,:tW 225 RHR Suppression Pool Cooling 3.6.2.3 3.6 CONTAINMENT SYSTEMS 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool LCO 3.6.2.3 Two RHR suppression pool cooling subsystems shall be APPLICABILITY: MODES 1 J 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RHR suppression pool cooling subsystem inoperable. A.1 Restore RHR suppression pool cooling subsystem to OPERABLE status. 7 days B. Required Action and associated Completion Time of Condition A not met. OR Two RHR suppression pool cooling subsystems inoperable. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.2.3.1 Verify each RHR suppression pool cooling subsystem manual, power operated, and automatic valve in 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. 31 days Columbia Generating Station 3.6.2.3-1 Amendment No. 449,-1-99 225 RHR Suppression Pool Cooling 3.6.2.3 SURVEILLANCE REQUIREMENTS SR Verify each RHR pump develops a flow rate 7100 gpm through the associated heat exchanger while operating in the suppression pool cooling mode. In accordance with the Inservice Testing Program Columbia Generating Station 3.6.2.3-2 Amendment No. -t49,.:tS9 225 Primary Containment Atmosphere Mixing System 3.6.3.2 3.6 CONTAINMENT SYSTEMS 3.6.3.2 Primary Containment Atmosphere Mixing System LCO 3.6.3.2 Two head area return fans shall be OPERABLE. APPLICABILITY: MODES 1 and 2. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One head area return fan inoperable. A.1 Restore head area return fan to OPERABLE status. 30 days B. Two head area return fans inoperable. B.1 AND B.2 Verify by administrative means that the hydrogen and oxygen control function is maintained. Restore one head area return fan to OPERABLE status. 1 hour 7 days C. Required Action and associated Completion Time not met. C.1 Be in MODE 3. 12 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.3.2.1 Operate each head area return fan for 2 15 minutes. 92 days Columbia Generating Station 3.6.3.2-1 Amendment No. +99,437 225 Primary Containment Oxygen Concentration 3.6.3.3 CONTAINMENT SYSTEMS 3.6.3.3 Primary Containment Oxygen Concentration LCO The primary containment oxygen concentration shall be < 3.5 volume percent. MODE 1 during the time period: From 24 hours after THERMAL POWER is > 15% RTP following startup, to 24 hours prior to reducing THERMAL POWER to < 15% RTP prior to the next scheduled reactor shutdown. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Primary containment oxygen concentration not within limit. A.1 Restore oxygen concentration to within limit. 24 hours B. Required Action and associated Completion Time not met. B.1 Reduce THERMAL POWER to 15% RTP. 8 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.3.3.1 Verify primary containment oxygen concentration is 7 days within limits. Columbia Generating Station 3.6.3.3-1 Amendment No. 449,+00 225 Secondary Containment 3.6.4.1 3.6 CONTAINMENT SYSTEMS 3.6.4.1 Secondary Containment LCO 3.6.4.1 The secondary containment shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs). ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Secondary containment inoperable in MODE 1. 2, or 3. A.1 Restore secondary containment to OPERABLE status. 4 hours B. Required Action and associated Completion Time of Condition A not met. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours C. Secondary containment inoperable during OPDRVs. C.1 Initiate action to suspend OPDRVs. Immediately Columbia Generating Station 3.6.4.1-1 Amendment No. -iWA*Q9 225 Secondary Containment 3.6.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.1.1 Verify secondary containment vacuum is 0.25 inch of vacuum water gauge. 24 hours SR 3.6.4.1.2 Verify all secondary containment equipment hatches are closed and sealed. 31 days SR 3.6.4.1.3 Verify each secondary containment access inner 31 days door or each secondary containment access outer door in each access opening is closed. SR Verify each standby gas treatment (SGT) subsystem will draw down the secondary containment to 0.25 inch of vacuum water gauge in s 120 seconds. 24 months on a STAGGERED TEST BASIS SR Verify each SGT subsystem can maintain 0.25 inch of vacuum water gauge in the secondary containment for 1 hour at a flow rate s 2240 cfm. 24 months on a STAGGERED TEST BASIS Columbia Generating Station 3.6.4.1-2 Amendment No. +99,+99 225 SCIVs 3.6.4.2 3.6 CONTAINMENT SYSTEMS 3.6.4.2 Secondary Containment Isolation Valves (SCIVs) LCO 3.6.4.2 Each SCIV shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs). ACTIONS 1. Penetration flow paths may be unisolated intermittently under administrative controls. 2. Separate Condition entry is allowed for each penetration flow path. 3. Enter applicable Conditions and Required Actions for systems made inoperable by SCIVs. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more penetration flow paths with one SCIV inoperable. A.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange. 8 hours Columbia Generating Station 3.6.4.2-1 Amendment No. 225 SCIVs 3.6.4.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 1. Isolation devices in high radiation areas may be verified by use of administrative means. 2. Isolation devices that are locked, sealed, or otherwise secured may be verified by use of administrative means. ---------------_... Verify the affected penetration flow path is isolated. Once per 31 days B. Only applicable to penetration flow paths with two isolation valves. ------_... __...One or more penetration flow paths with two SCIVs inoperable. B.1 Isolate the affected penetration flow path by use of at least one closed and de-activated automatic valve, closed manual valve, or blind flange. 4 hours C. Required Action and associated Completion Time of Condition A or B not met in MODE 1. 2, C.1 AND Be in MODE 3. 12 hours or 3. C.2 Be in MODE 4. 36 hours D. Required Action and associated Completion Time of Condition A or B not met during OPDRVs. 0.1 Initiate action to suspend OPDRVs. Immediately Columbia Generating Station 3.6.4.2-2 Amendment No. 225 SCIVs 3.6.4.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.4.2.1 1. Valves and blind flanges in high radiation areas may be verified by use of administrative controls. 2. Not required to be met for SCIVs that are open under administrative controls. Verify each secondary containment isolation manual valve and blind flange that is not locked, sealed, or otherwise secured, and is required to be closed during accident conditions is closed. 31 days SR 3.6.4.2.2 Verify the isolation time of each power operated, automatic SCIV is within limits. In accordance with the Inservice Testing Program SR 3.6.4.2.3 Verify each automatic SCIV actuates to the isolation position on an actual or simulated automatic isolation signal. 24 months Columbia Generating Station 3.6.4.2-3 Amendment No. 2G8 225 SGT System 3.6.4.3 3.6 CONTAINMENT SYSTEMS 3.6.4.3 Standby Gas Treatment (SGT) System LCO 3.6.4.3 Two SGT subsystems shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs). ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SGT subsystem inoperable. A.1 Restore SGT subsystem to OPERABLE status. 7 days B. Required Action and associated Completion Time of Condition A not met in MODE 1, 2, or 3. B.1 AND B.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours C. Required Action and associated Completion Time of Condition A not met during OPDRVs. C.1 OR C.2 Place OPERABLE SGT subsystem in operation. Initiate action to suspend OPDRVs. Immediately Immediately D. Two SGT subsystems inoperable in MODE 1, 2, or 3. D.1 Enter LCO 3.0.3. Immediately Columbia Generating Station 3.6.4.3-1 Amendment No. 225 SGT System 3.6.4.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. Two SGT subsystems E.1 Initiate action to suspend Immediately inoperable during OPDRVs. OPDRVs. SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.6.4.3.1 Operate each SGT subsystem for 10 continuous hours with heaters operating. 31 days SR 3.6.4.3.2 Perform required SGT filter testing in accordance with the Ventilation Filter Testing Program (VFTP). In accordance 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 each SGT filter cooling recirculation valve can 24 months be opened and the fan started. Columbia Generating Station 3.6.4.3-2 Amendment No. 4-99,-i9S 225 3.7.1 SW System and UHS 3.7 PLANT SYSTEMS 3.7.1 Standby Service Water (SW) System and Ultimate Heat Sink (UHS) LCO 3.7.1 Division 1 and 2 SW subsystems and UHS shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Average sediment depth in one or both spray ponds 2: 0.5 ft and < 1.0 ft. A.1 Restore average sediment depth to within limits. 30 days B. One SW subsystem inoperable. B.1 --------------NO 1. Enter applicable Conditions and Required Actions of LCO 3.8.1, nAC Sources Operating," for diesel generator made inoperable by SW System. 2. Enter applicable Conditions and Required Actions of LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown Cooling System -Hot Shutdown," for RHR shutdown cooling subsystem made inoperable by SW System. Restore SW subsystem to OPERABLE status. 72 hours Columbia Generating Station 3.7.1-1 Amendment No. 49&,2Qa 225 3.7.1 SW System and UHS ACTIONS CONDITION Required Action and associated Completion Time of Condition A or B not met. OR Both SW subsystems inoperable. OR UHS inoperable for reasons other than Condition A. REQUIRED ACTION C.1 Be in MODE 3. AND C.2 Be in MODE 4. COMPLETION TIME 12 hours 36 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.7.1.1 Verify the water level of each UHS spray pond is 432 ft 9 inches mean sea level. 24 hours SR 3.7.1.2 Verify the average water temperature of each UHS spray pond is 7rF. 24 hours SR Isolation of flow to individual components does not render SW subsystem inoperable. Verify each SW subsystem manual, power operated, and automatic valve in the flow path servicing safety related systems or components, that is not locked, sealed, or otherwise secured in 31 days position, is in the correct position. Columbia Generating 3.7.1-2 Amendment No . .:149,499 225 3.7.1 SW System and UHS SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.1.4 Verify average sediment depth in each UHS spray pond is < 0.5 ft. 92 days SR 3.7.1.5 Verify each SW subsystem actuates on an actual or simulated initiation signal. 24 months Columbia Generating Station 3.7.1-3 Amendment No. 449,469 225 3.7.2 HPCS SW System 3.7 PLANT SYSTEMS 3.7.2 High Pressure Core Spray (HPCS) Service Water (SW) System LCO 3.7.2 The HPCS SW System shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. HPCS SW System inoperable. A.1 Declare HPCS System inoperable. Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.2.1 -------------------------------N0TE Isolation of flow to individual components does not render HPCS SW System inoperable. Verify each HPCS SW System manual, power operated, and automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position. 31 days SR 3.7.2.2 Verify the HPCS SW System actuates on an actual or simulated initiation signal. 24 months Columbia Generating Station 3.7.2-1 Amendment No . 225 CREF System 3.7.3 3.7 PLANT SYSTEMS 3.7.3 Control Room Emergency Filtration (CREF) System LCO 3.7.3 Two CREF subsystems shall be OPERABLE. --------------------------------------------NO TE The control room envelope (CRE) boundary may be opened intermittently under administrative control. APPLICABILITY: MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs). ACTIONS CONDITION A. One CREF subsystem inoperable for reasons other than Condition B. A.1 REQUIRED ACTION Restore CREF subsystem to OPERABLE status. COMPLETION TIME 7 days B. One or more CREF subsystems inoperable due to inoperable CRE boundary in MODE 1, 2, and 3. B.1 AND B.2 AND B.3 Initiate action to implement mitigating actions. Verify mitigating actions ensure CRE occupant exposures to radiological, chemical, and smoke hazards will not exceed limits. Restore CRE boundary to OPERABLE status. Immediately 24 hours 90 days Columbia Generating Station 3.7.3-1 Amendment No. -1-99,207 225 3.7.3 CREF System ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and associated Completion Time of Condition A or B not met in MODE 1, 2, or 3. C.1 AND C.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours D. Required Action and associated Completion Time of Condition A not met during OPDRVs. 0.1 OR 0.2 Place OPERABLE CREF subsystem in pressurization mode. Initiate action to suspend OPDRVs. Immediately Immediately E. Two CREF subsystems inoperable in MODE 1, 2, or 3 for reasons other than Condition B. E.1 Enter LCO 3.0.3. Immediately F. Two CREF subsystems inoperable during OPDRVs. OR One or more CREF subsystems inoperable due to inoperable CRE boundary during OPDRVs. F.1 Initiate action to suspend OPDRVs. Immediately Columbia Generating Station 3.7.3-2 Amendment No. 2Q7,249 225 3.7.3 CREF System SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.3.1 Operate each CREF subsystem for 10 continuous hours with the heaters operating. 31 days SR 3.7.3.2 Perform required CREF filter testing in accordance with the Ventilation Filter Testing Program (VFTP). In accordance with the VFTP SR 3.7.3.3 Verify each CREF subsystem actuates on an actual or simulated initiation signal. 24 months SR 3.7.3.4 Perform required CRE unfiltered air inleakage testing in accordance with the Control Room Envelope Habitability Program. In accordance with the Control Room Envelope Habitability Program Columbia Generating Station 3.7.3-3 Amendment No . .:t.9Q,2G+ 225 Control Room AC System 3.7.4 3.7 PLANT SYSTEMS 3.7.4 Control Room Air Conditioning (AC) System LCO 3.7.4 Two control room AC subsystems shall be OPERABLE. APPLICABI LlTY: MODES 1, 2, and 3, During operations with a potential for draining the reactor vessel (OPDRVs). ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One control room AC subsystem inoperable. A.1 Restore control room AC subsystem to OPERABLE status. 30 days B. C. Required Action and associated Completion Time of Condition A not met in MODE 1, 2, or 3. Required Action and associated Completion Time of Condition A not met during OPDRVs. B.1 AND B.2 C.1 OR C.2 Be in MODE 3. Be in MODE 4. Place OPERABLE control room AC subsystem in operatIon. Initiate action to suspend OPDRVs. 12 hours 36 hours IImmediately Immediately D. Two control room AC subsystems inoperable in MODE 1,2, or 3. I D.1 Enter LCO 3.0.3. Immediately Columbia Generating Station 3.7.4-1 Amendment No. +99,4-99 225 3.7.4 Control Room AC System ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. Two control room AC subsystems inoperable during OPDRVs. E.1 Initiate action to suspend OPDRVs. Immediately SURVEILLANCE SURVEILLANCE SR 3.7.4.1 Verify each control room AC subsystem has the 24 months capability to remove the assumed heat load. Columbia Generating Station 3.7.4-2 Amendment No. -iSB.+99 225 Main Condenser Offgas 3.7.5 3.7 PLANT SYSTEMS 3.7.5 Main Condenser Offgas LCO The gross gamma activity rate of the noble gases measured at the main condenser air ejector shall be s 332 mCi/second after decay of 30 minutes. APPLICABILITY: MODE 1, MODES 2 and 3 with any main steam line not isolated and steam jet air ejector (SJAE) in operation. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Gross gamma activity rate of the noble gases not within limit. A.1 Restore gross gamma activity rate of the noble gases to within limit. 72 hours B. Required Action and associated Completion Time not met. B.1 Isolate all main steam lines. OR B.2 Isolate SJAE. OR B.3.1 Be in MODE 3. AND B.3.2 Be in MODE 4. 12 hours 12 hours 12 hours 36 hours Columbia Generating 3.7.5-1 Amendment No. 225 3.7.5 Main Condenser Offgas SURVEILLANCE SR -------------------------------NOT E Not required to be performed until 31 days after any main steam line not isolated and SJAE in operation. Verify the gross gamma activity rate of the noble gases is ::; 332 mCi/second after decay of 30 minutes. 31 days Once within 4 hours after a 50% increase in the nominal steady state fission gas release after factoring out increases due to changes in THERMAL POWER level Columbia Generating 3.7.5-2 Amendment No. +49,.:+e9 225 3.7.6 Main Turbine Bypass System 3.7 PLANT 3.7.6 Main Turbine Bypass LCO 3.7.6 The Main Turbine Bypass System shall be LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR),"limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are made applicable. APPLICABILITY: THERMAL POWER 25% RTP. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the LCO not met. A.1 Satisfy the requirements of the LCO. 2 hours B. Required Action and associated Completion Time not met. B.1 Reduce THERMAL POWER to < 25% RTP. 4 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.7.6.1 Verify one complete cycle of each main turbine bypass valve. 31 days SR 3.7.6.2 Perform a system functional test. 24 months SR 3.7.6.3 Verify the TURBINE BYPASS SYSTEM RESPONSE TIME is within limits. 24 months Columbia Generating Station 3.7.6-1 Amendment No. -MS,+@9 225 Spent Fuel Storage Pool Water Level 3.7.7 3.7 PLANT SYSTEMS 3.7.7 Spent Fuel Storage Pool Water Level LCO The spent fuel storage pool water level shall be 22 ft over the top of irradiated fuel assemblies seated in the spent fuel storage pool racks. APPLICABILITY: During movement of irradiated fuel assemblies in the spent fuel storage pool. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Spent fuel storage pool water level not within limit. A.1 ---------------NOTE LCO 3.0.3 is not applicable. Suspend movement of irradiated fuel assemblies in the spent fuel storage pool. Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 Verify the spent fuel storage pool water level is ;::: 22 ft over the top of irradiated fuel assemblies seated in the spent fuel storage pool racks. 7 days Columbia Generating 3.7.7-1 Amendment No. 449,+99 225 AC Sources -Operating 3.8.1 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources -Operating 3.8.1 The following AC electrical power sources shall be OPERABLE: Two qualified circuits between the offsite transmission network and the onsite Class 1 E AC Electric Power Distribution System; and Three diesel generators (DGs). MODES 1, 2, and 3. --------------------------------------------N0TE Division 3 AC electrical power sources are not required to be OPERABLE when High Pressure Core Spray System is inoperable. ACTIONS LCO 3.0A.b is not applicable to DGs. CONDITION REQUIRED ACTION COMPLETION TIME A. One offsite circuit A.1 Perform SR 3.8.1.1 for 1 hour inoperable. OPERABLE offsite circuit. Once per 8 hours thereafter Columbia Generating 3.8.1-1 Amendment No. 4-99,487 225 3.8.1 AC Sources -Operating ACTIONS REQUIRED ACTION CONDITION A. (continued) A.2 AND A.3 B. One required DG inoperable. B.1 AND B.2 Declare required feature(s) with no offsite power available inoperable when the redundant required feature(s) are inoperable. Restore offsite circuit to OPERABLE status. Perform SR 3.8.1.1 for OPERABLE offsite circuit(s). Declare required feature(s), supported by the inoperable DG, inoperable when the redundant required feature(s) are inoperable. COMPLETION 24 hours from discovery of no offsite power to one division concurrent with inoperability of redundant required feature(s) 72 hours AND 6 days from discovery of failure to meet LCO when not associated with Required Action B.4.2.2 AND 17 days from discovery of failure to meet LCO 1 hour AND Once per 8 hours thereafter 4 hours from discovery of Condition B concurrent with inoperability of redundant required feature(s) Columbia Generating Station 3.8.1-2 Amendment No. 4-9&,497 225 3.8.1 AC Sources -Operating ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3.1 Determine OPERABLE DG(s) are not inoperable due to common cause failure. 24 hours B.3.2 Perform SR 3.8.1.2 for OPERABLE DG(s). 24 hours if not performed within the past 24 hours B.4.1 Restore required DG to OPERABLE status. 72 hours from discovery of an inoperable DG 6 days from discovery of failure to meet LCO B.4.2.1 Establish risk management actions for the alternate AC sources. B.4.2.2 Restore required DG to OPERABLE status. 72 hours 14 days 17 days from discovery of failure to meet LCO Columbia Generating Station Amendment No. 225 3.8.1 AC Sources -Operating ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Two offsite circuits inoperable. C.1 AND C.2 Declare required feature(s) inoperable when the redundant required feature(s) are inoperable. Restore one offsite circuit to OPERABLE status. 12 hours from discovery of Condition C concurrent with inoperability of redundant required feature(s) 24 hours D. One offsite circuit inoperable. AND One required DG inoperable. Enter applicable Conditions and Required Actions of LCO 3.8.7. "Distribution Systems -Operating." when Condition D is entered with no AC power source to any division. ----------------------_... D.1 Restore offsite circuit to OPERABLE status. OR D.2 Restore required DG to OPERABLE status. 12 hours 12 hours E. Two required DGs inoperable. I E.1 Restore one required DG to OPERABLE status. 2 hours OR 24 hours if Division 3 DG is inoperable Columbia Generating Station 3.8.1-4 Amendment No. 469,49-7225 3.8.1 AC Sources -Operating ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. Required Action and associated Completion Time of Condition A, B, C, D, or E not met. F.1 AND F.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours G. Three or more required AC sources inoperable. G.1 Enter LCO 3.0.3. Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.8.1.1 Verify correct breaker alignment and indicated power availability for each offsite circuit. 7 days SR 3.8.1.2 1. All DG starts may be preceded by an engine prelube period and followed by a warmup period prior to loading. 2. A modified DG start involving idling and gradual acceleration to synchronous speed may be used for this SR as recommended by the manufacturer. When modified start procedures are not used, the time, voltage, and frequency tolerances of SR 3.8.1.7 must be met. Verify each required DG star1s from standby conditions and achieves steady state: a. Voltage 2': 3910 V and 4400 V and frequency 2': 58.8 Hz and 61.2 Hz for DG-1 and DG-2; and b. Voltage 2': 3910 V and 4400 V and frequency 2': 58.8 Hz and 61.2 Hz for DG-3. 31 days Columbia Generating Station 3.8.1-5 Amendment No.1e9,-1-84 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.3 1. DG loadings may include gradual loading as recommended by the manufacturer. 2. Momentary transients outside the load range do not invalidate this test. 3. This Surveillance shall be conducted on only one DG at a time. 4. This SR shall be preceded by. and immediately follow, without shutdown, a successful performance of SR 3.8.1.2 or SR 3.8.1.7. 5. The endurance test of SR 3.8.1.14 may be performed in lieu of the load-run test in SR 3.8.1.3 provided the requirements, except the upper load limits, of SR 3.8.1.3 are met. Verify each required DG is synchronized and loaded and operates for 60 minutes at a load 4000 kW and::;; 4400 kW for DG-1 and DG-2, and 2340 kW and::;; 2600 kW for DG-3. 31 days SR 3.8.1.4 Verify each required day tank contains fuel oil to support greater than or equal to one hour of operation at full load plus 10%. 31 days SR 3.8.1.5 Check for and remove accumulated water from each required day tank. 31 days SR 3.8.1.6 Verify each required fuel oil transfer subsystem operates to automatically transfer fuel oil from the storage tank to the day tank. 92 days Columbia Generating Station 3.8.1-6 Amendment No. 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.7 -------------------------------NOTE All OG starts may be preceded by an engine prelube period. Verify each required OG starts from standby condition and achieves: a. For OG-1 and OG-2 in :::; 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and:::; 4400 V and frequency 58.8 Hz and:::; 61.2 Hz; and b. For OG-3, in:::; 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and:::; 4400 V and frequency 58.8 Hz and:::; 61.2 Hz. 184 days SR 3.8.1.8 -------------------------------NOTE The automatic transfer function of this Surveillance shall not normally be performed in MOOE 1 or 2. However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR. Verify automatic and manual transfer of the power supply to safety related buses from the startup offsite circuit to the backup offsite circuit. 24 months Columbia Generating Station 3.8.1-7 Amendment No. 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS FREQUENCYSURVEILLANCE SR 3.8.1.9 ------------------------------NOTE Credit may be taken for unplanned events that satisfy this SR If performed with the DG synchronized with offsite power, it shall be performed at a power factor as close to the power factor of the single largest post-accident load as practicable. 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 required DG rejects a load greater than or equal to its associated single largest accident load, and following load rejection, the frequency is :s; 66.75 Hz. 24 months SR 3.8.1.10 Credit may be taken for unplanned events that satisfy this SR If performed with the DG synchronized with offsite power, it shall be performed at a power factor of s; 0.9 for DG-1 and DG-2, and s; 0.91 for DG-3. 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 required DG does not trip and voltage is maintained s; 4784 V during and following a load rejection of a load;;::: 4400 kW for DG-1 and DG-2 and;;::: 2600 kW for DG-3. 24 months Columbia Generating 3.8.1-8 Amendment No. ;w3,;ID4 225 3.8.1 AC Sources -Operating SURVEILLANCE SR 3.8.1.11 All DG starts may be preceded by an engine prelube period. This Surveillance shall not normally be performed in MODE 1,2, or 3 (not applicable to DG-3). However, portions of the Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR. Verify on an actual or simulated loss of offsite power signal: De-energization of emergency buses; Load shedding from emergency buses for Divisions 1 and 2; and DG auto-starts from standby condition and: energizes permanently connected loads in 15 seconds for DG-1 and DG-2, and in 18 seconds for DG-3, energizes auto-connected shutdown loads, maintains steady state voltage ;::: 3910 V and 4400 V, maintains steady state frequency ;::: 58.8 Hz and 61.2 Hz, and supplies permanently connected and auto-connected shutdown loads for ;::: 5 minutes. 24 months Columbia Generating 3.8.1-9 Amendment No. 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SR 3.8.1.12 ------------------------------NOT E S All OG starts may be preceded by an engine prelube period. This Surveillance shall not normally be performed in MOOE 1 or 2 (not applicable to OG-3). However, portions of the Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR. Verify on an actual or simulated Emergency Core Cooling System (ECCS) initiation signal each required OG auto-starts from standby condition and: For OG-1 and OG-2, in 15 seconds achieves voltage 3910 V, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V and, for OG-3, in 15 seconds achieves voltage 3910 V, and after steady state conditions are reached, maintains voltage 3910 V and 4400 V; In 15 seconds, achieves frequency 58.8 Hz and after steady state conditions are achieved, maintains frequency 58.8 Hz and 61.2 Hz; Operates for 5 minutes; Permanently connected loads remain energized from the offsite power system; and Emergency loads are auto-connected to the offsite power system. 24 months Columbia Generating Station 3.8.1-10 Amendment No. 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.13 -------------------------------NOTE Credit may be taken for unplanned events that satisfy this SR. Verify each required OG's automatic trips are bypassed on an actual or simulated ECCS initiation signal except: a. Engine overspeed; b. Generator differential current; and c. Incomplete starting sequence. 24 months SR 3.8.1.14 1. Momentary transients outside the load, excitation current, and power factor ranges do not invalidate this test. 2. Credit may be taken for unplanned events that satisfy this SR. 3. If performed with the OG synchronized with offsite power, it shall be performed at a power factor of:<::; 0.9 for OG-1 and OG-2, and :<::; 0.91 for OG-3. 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 required OG operates for 24 hours: a. For 2 hours loaded 4650 kW for OG-1 and OG-2, and 2850 kW for OG-3; and b. For the remaining hours of the test loaded 4400 kW for OG-1 and OG-2, and 2600 kW for OG-3. 24 months Columbia Generating Station 3.8.1-11 Amendment No. 225 3.8.1 AC Sources -Operating SURVEILLANCE FREQUENCY SR 3.8.1.15 24 months SURVEILLANCE This Surveillance shall be performed within 5 minutes of shutting down the DG after the DG has operated 1 hour loaded 4000 kW for DG-1 and DG-2, and 2340 kW for DG-3. Momentary transients outside of load range do not invalidate this test. All DG starts may be preceded by an engine prelube period. Verify each required DG starts and achieves: For DG-1 and DG-2, in s 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and s 4400 V and frequency 58.8 Hz and s 61.2 Hz; and For DG-3, in s 15 seconds, voltage 3910 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 3910 V and s 4400 V and frequency 58.8 Hz and s 61.2 Hz. Columbia Generating Station 3.8.1-12 Amendment No. 2W,2Q4 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.16 SR 3.8.1.17 -------------------------------NOTE This Surveillance shall not normally be performed in MODE 1, 2, or 3 (not applicable to DG-3). However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR. Verify each required DG: a. Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power; b. Transfers loads to offsite power source; and c. Returns to ready-to-Ioad operation. -------------------------------NOTE Credit may be taken for unplanned events that satisfy this SR. Verify, with a DG operating in test mode and connected to its bus, an actual or simulated ECCS initiation signal overrides the test mode by: a. Returning DG to ready-to-Ioad operation; and b. Automatically energizing the emergency load from offsite power. 24 months 24 months Columbia Generating Station 3.8.1-13 Amendment No. 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SR This Surveillance shall not normally be performed in MODE 1, 2, or 3. However, this Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR. Verify interval between each sequenced load block is within +/- 10% of design interval for each time delay relay. 24 months Columbia Generating Station 3.8.1-14 Amendment No. 225 3.8.1 AC Sources -Operating SURVEILLANCE FREQUENCY SR 3.8.1.19 24 months SURVEILLANCE All DG starts may be preceded by an engine prelube period. This Surveillance shall not normally be performed in MODE 1, 2, or 3 (not applicable to DG-3). However, portions of the Surveillance may be performed to re-establish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR. Verify, on an actual or simulated loss of offsite power signal in conjunction with an actual or simulated ECCS initiation signal: De-energization of emergency buses; Load shedding from emergency buses for DG-1 and DG-2; and DG auto-starts from standby condition and: energizes permanently connected loads in 15 seconds, energizes auto-connected emergency loads, maintains steady state voltage;?: 3910 V and 4400 V, maintains steady state ;?: 58.8 Hz and 61.2 Hz, supplies permanently connected and auto-connected emergency loads for ;?: 5 minutes. Columbia Generating Station 3.8.1-15 Amendment No. 2W.2M 225 3.8.1 AC Sources -Operating SURVEILLANCE REQUIREMENTS SR All DG starts may be preceded by an engine prelube period. Verify, when started simultaneously from standby condition, DG-1 and DG-2 achieves, in 15 seconds, voltage;:?: 3910 V and frequency ;:?: 58.8 Hz, and DG-3 achieves, in 15 seconds, voltage;:?: 3910 V and frequency;:?: 58.8 Hz. 10 years Columbia Generating Station 3.8.1-16 Amendment No. 204 225 AC Sources -Shutdown 3.8.2 ELECTRICAL POWER SYSTEMS 3.8.2 AC Sources -Shutdown LCO 3.8.2 The following AC electrical power sources shall be OPERABLE: One qualified circuit between the offsite transmission network and the onsite Class 1 E AC electrical power distribution subsystem(s) required by LCO 3.8.8, "Distribution Systems -Shutdown;" One diesel generator (DG) capable of supplying one division of the Division 1 or 2 onsite Class 1 E AC electrical power distribution subsystem(s) required by LCO 3.8.8; and The Division 3 DG capable of supplying the Division 3 onsite Class 1 E AC electrical power distribution subsystem, when the Division 3 onsite Class 1E electrical power distribution subsystem is required by LCO 3.B.B. APPLICABILITY: MODES 4 and 5. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Required offsite circuit inoperable. --------------------N0TE Enter applicable Condition and Required Actions of LCO 3.8.8, when any required division is energized as a result of Condition A. A.1 Declare affected required feature(s) with no offsite power available inoperable. Immediately Columbia Generating 3.B.2-1 Amendment No. 4-e9,.:t-99 225 3.8.2 AC Sources -Shutdown ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.1 Initiate action to suspend operations with a potential for draining the reactor vessel (OPDRVs). AND A.2.2 Initiate action to restore required offsite power circuit to OPERABLE status. Immediately Immediately B. Division 1 or 2 required DG inoperable. B.1 Initiate action to suspend OPDRVs. AND B.2 Initiate action to restore required DG to OPERABLE status. Immediately Immediately C. Required Division 3 DG inoperable. C.1 Declare High Pressure Core Spray System inoperable. 72 hours Columbia Generating Station 3.8.2-2 Amendment No . .:t-S9,499 225 3.8.2 AC Sources -Shutdown SURVEILLANCE REQUIREMENTS SR -------------------------------NOTE The following SRs are not required to be SR 3.8.1.3, SR 3.8.1.9 through SR SR 3.8.1.13 through SR 3.8.1.16, SR 3.8.1.18, SR For AC sources required to be OPERABLE, the for Specification 3.8.1, except SR SR 3.8.1.17, and SR 3.8.1.20, are In accordance with applicable SRs Columbia Generating Station 3.8.2-3 Amendment No. 225 Diesel Fuel Oil, Lube Oil, and Starting Air 3.8.3 3.8 ELECTRICAL POWER SYSTEMS 3.8.3 Diesel Fuel Oil, Lube Oil. and Starting Air LCO The stored diesel fuel oil, lube oil. and starting air subsystem shall be within limits for each required diesel generator (DG). When associated DG is required to be OPERABLE. ACTIONS Separate Condition entry is allowed for each DG. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more DGs with fuel oil level less than a 7 day supply and greater than a 6 day supply. A.1 Restore stored fuel oil level to within limit. 48 hours B. One or more DGs with lube oil inventory less than a 7 day supply and greater than a 6 day supply. 8.1 Restore lube oil inventory to within limit. 48 hours C. One or more DGs with stored fuel oil total particulates not within limit. C.1 Restore stored fuel oil total particulates to within limit. 7 days D. One or more DGs with new fuel oil properties not within limits. D.1 Restore stored fuel oil properties to within limits. 30 days Columbia Generating 3.8.3-1 Amendment No. 225 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME E. One or more DGs with required starting air receiver pressure: 1. For DG-1 and DG-2, < 230 psig and ;?: 150 psig; and 2. For DG-3, < 223 psig and;?: 150 psig. E.1 Restore required starting air receiver pressure to within limit. 48 hours F. Required Action and associated Completion Time of Condition A, B, C, D, or E not met. F.1 Declare associated DG inoperable. Immediately One or more DGs with stored diesel fuel 011, lube oil, or starting air subsystem not within limits for reasons other than Condition A, S, C, D, orE. SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.8.3.1 Verify each fuel oil storage subsystem contains greater than or equal to a seven day supply of fuel. 31 days SR 3.8.3.2 Verify lube oil inventory is greater than or equal to a 31 days seven day supply. Columbia Generating Station 3.8.3-2 Amendment No. 225 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.3.3 Verify 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. In accordance with the Diesel Fuel Oil Testing Program SR 3.8.3.4 Verify each required DG air start receiver pressure is: a. 230 psig for DG-1 and DG-2; and b. 223 psig for DG-3. 31 days SR 3.8.3.5 Check for and remove accumulated water from each fuel oil storage tank. 92 days Columbia Generating Station 3.8.3-3 Amendment No . 225 DC Sources -Operating 3.8.4 3.8 ELECTRICAL POWER SYSTEMS 3.8.4 DC Sources -Operating LCO The Division 1, Division 2, and Division 3 DC electrical power subsystems shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTIONS One required Division 1 or 2 125 V DC battery charger inoperable. One required Division 3 125 V DC battery charger inoperable. REQUIRED A.1 AND A.2 AND A.3 B.1 AND B.2 AND B.3 Restore battery terminal voltage to greater than or equal to the minimum established float voltage. Verify battery float current ::; 2 amps. Restore required battery charger to OPERABLE status. Restore battery terminal voltage to greater than or equal to the minimum established float voltage. Verify battery float current ::; 2 amps. Restore required battery charger to OPERABLE status. COMPLETION 2 hours Once per 12 hours 72 hours 2 hours Once per 12 hours 72 hours Columbia Generating 3.8.4*1 Amendment 225 3.8.4 DC Sources -Operating ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. One required Division 1 250 V DC battery charger inoperable. C.1 AND C.2 AND C.3 Restore battery terminal voltage to greater than or equal to the minimum established float voltage. Verify battery float current s; 2 amps. Restore required battery charger to OPERABLE status. 2 hours Once per 12 hours 72 hours D. One required Division 1 or 2 125 V DC battery inoperable. D.1 Restore battery to OPERABLE status. 2 hours One required Division 3 125 V DC battery inoperable. E.1 Restore battery to OPERABLE status. 2 hours F. One required Division 1 250 V DC battery inoperable. F.1 Restore battery to OPERABLE status. 2 hours G. Division 1 or 2 125 V DC electrical power subsystem inoperable for reasons other than Condition A or D. G.1 Restore Division 1 and 2 125 V DC electrical power subsystems to OPERABLE status. 2 hours Columbia Generating Station 3.8.4-2 Amendment 4-69,2G4 225 3.8.4 DC Sources -Operating ACTIONS Required Action and associated Completion Time of Condition B or E not met. OR Division 3 DC electrical power subsystem inoperable for reasons other than Condition B orE. Required Action and associated Completion Time of Condition C or F not met. OR Division 1 250 V DC electrical power subsystem inoperable for reasons other than Condition C or F. Required Action and associated Completion Time of Condition A or D not met. OR Required Action and associated Completion Time of Condition G not met. REQUIRED Declare High Pressure Core Spray System inoperable. Declare associated supported features inoperable. J.1 Be in MODE 3. AND J.2 Be in MODE 4. COMPLETION Immediately Immediately 12 hours 36 hours Columbia Generating 3.8.4-3 Amendment 4-9Q,;m4 225 3.8.4 DC Sources -Operating SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.4.1 Verify battery terminal voltage is greater than or equal to the minimum established float voltage. 7 days SR 3.8.4.2 Verify each required battery charger supplies the required load for;::: 1.5 hours at: a. ;::: 126 V for the 125 V battery chargers; and b. ;::: 252 V for the 250 V battery charger. 24 months SR 3.8.4.3 1. The modified performance discharge test in SR 3.8.6.6 may be performed in lieu of SR 3.8.4.3. 2. This Surveillance shall not be performed in MODE 1, 2, or 3 for the Division 1 and 2 125 V DC batteries. However, credit may taken for unplanned events that satisfy this 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. Columbia Generating Station 3.8.4-4 Amendment 4W,2G4 225 DC Sources -Shutdown 3.8.5 3.8 ELECTRICAL POWER SYSTEMS 3.8.5 DC Sources -Shutdown LCO DC electrical power subsystem(s) shall be OPERABLE to support the electrical power distribution subsystem(s) required by LCO 3.8.8, "Distribution Systems -Shutdown." APPLICABILITY: MODES 4 and 5. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A One required battery charger inoperable. AND The redundant division battery and battery charger OPERABLE. A1 AND A2 AND A3 Restore battery terminal voltage to greater than or equal to the minimum established float voltage. Verify battery float current :S 2 amps. Restore required battery charger to OPERABLE status. 2 hours Once per 12 hours 7 days Columbia Generating 3.8.5-1 Amendment 499,:w4 225 3.8.5 DC Sources -Shutdown ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. One or more required DC electrical power subsystems inoperable, for reasons other than Condition A. Required Action and Completion Time of Condition A not met. B.1 B.2.1 B.2.2 Declare affected required feature(s) inoperable. Initiate action to suspend operations with a potential for draining the reactor vessel. Initiate action to restore required DC electrical power subsystems to OPERABLE status. Immediately Immediately Immediately SURVEILLANCE SR -------------------------------NOT E The following SRs are not required to be performed: SR 3.8.4.2, and SR 3.8.4.3. For DC electrical power subsystems required to be OPERABLE the following SRs are applicable: SR 3.8.4.1, SR 3.8.4.2, and SR 3.8.4.3. In accordance with applicable SRs Columbia Generating 3.8.5-2 Amendment 225 Battery Parameters 3.8.6 3.8 ELECTRICAL POWER SYSTEMS 3.8.6 Battery Parameters LCO Battery parameters for the Division 1, 2, and 3 batteries shall be within limits. APPLICABILITY: When associated DC electrical power subsystems are required to be OPERABLE. ACTIONS ------------------------------------------------------------NOT E Separate Condition entry is allowed for each battery. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more batteries with one or more battery cells float voltage < 2.07 V. A.1 AND A.2 AND A.3 Perform SR 3.8.4.1. Perform SR 3.8.6.1. Restore affected cell voltage 2.07 V. 2 hours 2 hours 24 hours B. One or more batteries with float current > 2 amps. B.1 AND B.2 Perform SR 3.8.4.1. Restore battery float current to 2 amps. 2 hours 12 hours Columbia Generating 3.8.6-1 Amendment 225
3.8.6 Battery Parameters ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME ---------------------NOT E Required Action C.2 shall be Required Actions C.1 and C.2 are completed if electrolyte level only applicable if electrolyte level was below the top of plates. was below the top of plates. C. One or more batteries C.1 Restore electrolyte level to 8 with one or more above top of electrolyte level than established C.2 Verify no evidence of 12 hours leakage. AND C.3 Restore electrolyte level to 31 days greater than or equal to minimum established design limits. D. One or more batteries 0.1 Restore battery pilot cell 12 with pilot cell temperature to greater temperature less or equal to minimum established design limits. E. Two or more redundant E.1 Restore battery parameters 2 division batteries for affected battery in battery parameters division to within within Columbia Generating Station 3.8.6-2 Amendment -1-W,2W 225 3.8.6 Battery Parameters ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F. One or more batteries with a required battery parameter not met for reasons other than Condition A, B, C, D, or E. F.1 Declare associated battery inoperable. Immediately Required Action and associated Completion Time of Condition A, B, C, D, or E not met. One or more batteries with one or more battery cell(s) float voltage < 2.07 V and float current> 2 amps. SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.8.6.1 -------------------------------NOTE Not required to be met when battery terminal voltage is less than the minimum established float voltage of SR 3.8.4.1. Verify each battery float current is 2 amps. 7 days SR 3.8.6.2 Verify each battery pilot cell voltage is 2:: 2.07 V. 31 days Columbia Generating Station 3.8.6-3 Amendment 225 3.8.6 Battery Parameters SURVEILLANCE REQUIREMENTS SR 3.8.6.3 SR 3.8.6.4 SR 3.8.6.5 SR 3.8.6.6 SURVEILLANCE Verify each battery connected cell electrolyte level is greater than or equal to minimum established design limits. Verify each battery pilot cell temperature is greater than or equal to minimum established design limits. Verify each battery connected cell voltage is 2.07 V. This Surveillance shall not be performed in MODE 1, 2, or 3 for the Division 1 and 2 125 V DC batteries. However, credit may be taken for unplanned events that satisfy this SR. Verify battery capacity is 80% of the manufacturer's rating for the 125 V batteries and 2: 83.4% of the manufacturer's rating for the 250 V battery, when subjected to a performance discharge test or a modified performance discharge test. FREQUENCY 31 days 31 days 92 days 60 months 12 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 Columbia Generating Station 3.8.6-4 Amendment 225 Distribution Systems -Operating 3.8.7 ELECTRICAL POWER SYSTEMS 3.8.7 Distribution Systems -Operating LCO The following AC and DC electrical power distribution subsystems shall be OPERABLE: Division 1 and Division 2 AC electrical power distribution subsystems; Division 1 and Division 2 125 V DC electrical power distribution subsystems; Division 1 250 V DC electrical power distribution subsystem; and Division 3 AC and DC electrical power distribution sUbsystems. MODES 1, 2, and 3. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Division 1 or 2 AC electrical power distribution subsystem inoperable. A.1 Restore Division 1 and 2 AC electrical power distribution subsystems to OPERABLE status. 8 hours AND 16 hours from discovery of failure to meet LCO 3.8.7.a or b B. Division 1 or 2 125 V DC electrical power distribution subsystem inoperable. B.1 Restore Division 1 and 2 125 V DC electrical power distribution subsystems to OPERABLE status. 2 hours AND 16 hours from discovery of failure to meet LCO 3.8.7.a or b Columbia Generating 3.8.7-1 Amendment 225 3.8.7 Distribution Systems -Operating ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and associated Completion Time of Condition A or B not met. C.1 AND C.2 Be in MODE 3. Be in MODE 4. 12 hours 36 hours D. Division 1 250 V DC electrical power distribution subsystem inoperable. 0.1 Declare associated supported feature(s) inoperable. Immediately E. One or more Division 3 AC or DC electrical power distribution subsystems inoperable. E.1 Declare High Pressure Core Spray System inoperable. Immediately F. Two or more divisions with inoperable electrical power distribution subsystems that result in a loss of function. F.1 Enter LCO 3.0.3. Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.8.7.1 Verify correct breaker alignments and indicated 7 days power availability to required AC and DC electrical power distribution subsystems. Columbia Generating Station 3.8.7-2 Amendment 449,469 225 Distribution Systems -Shutdown 3.8.8 3.8 ELECTRICAL POWER SYSTEMS 3.8.8 Distribution Systems -Shutdown LCO The necessary portions of the Division 1, Division 2, and Division 3 AC and DC electrical power distribution subsystems shall be OPERABLE to support equipment required to be OPERABLE. MODES 4 and 5. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required AC or DC electrical power distribution subsystems inoperable. A.1 A.2.1 Declare associated supported required feature(s) inoperable. Initiate action to suspend operations with a potential for draining the reactor vessel. Immediately Immediately A.2.2 Initiate actions to restore required AC and DC electrical power distribution subsystems to OPERABLE status. Immediately A.2.3 Declare associated required shutdown cooling subsystem(s) inoperable and not in operation. Immediately Columbia Generating 3.8.8-1 Amendment -%9,-1-99 225 3.8.8 Distribution Systems -Shutdown SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.8.1 Verify correct breaker alignments and indicated 7 days power availability to required AC and DC electrical power distribution subsystems. Columbia Generating Station 3.8.8-2 Amendment 4W-,4-99 225 Refueling Equipment Interlocks 3.9.1 3.9 REFUELING OPERATIONS 3.9.1 Refueling Equipment Interlocks LCO The refueling equipment interlocks associated with the refuel position shall be OPERABLE. APPLICABILITY: During in-vessel fuel movement with equipment associated with the interlocks when the reactor mode switch is in the refuel position. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required refueling equipment interlocks inoperable. A.1 Suspend in-vessel fuel movement with equipment associated with the inoperable interlock(s). Immediately SURVEILLANCE SR Perform CHANNEL FUNCTIONAL TEST on each of the following required refueling equipment interlock inputs: AII-rods-in, Refueling platform position, Refueling platform fuel grapple fuel-loaded, Refueling platform frame-mounted hoist loaded, and Refueling platform trolley-mounted hoist loaded. 7 days Columbia Generating 3.9.1-1 Amendment 449,4-99 225 3.9.2 Refuel Position One-Rod-Out Interlock 3.9 REFUELING OPERATIONS 3.9.2 Refuel Position One-Rod-Out LCO 3.9.2 The refuel position one-rod-out interlock shall be APPLICABILITY: MODE 5 with the reactor mode switch in the refuel position and any control rod withdrawn. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Refuel position out interlock inoperable. A.1 A.2 Suspend control rod withdrawal. Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Immediately Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.2.1 Verify reactor mode switch locked in refuel position. 12 hours SR 3.9.2.2 ------------------------------N 0 Not required to be performed until 1 hour after any control rod is withdrawn. Perform CHANNEL FUNCTIONAL TEST. 7 days Columbia Generating Station 3.9.2-1 Amendment .:f49,.w9 225 3.9.3 Control Rod Position 3.9 REFUELING 3.9.3 Control Rod LCO 3.9.3 All control rods shall be fully APPLICABILITY: When loading fuel assemblies into the core. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more control rods not fully inserted. A.1 Suspend loading fuel assemblies into the core. Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify all control rods are fully inserted. 12 hours Columbia Generating Station 3.9.3-1 Amendment 449,4-99 225 3.9.4 Control Rod Position Indication 3.9 REFUELING 3.9.4 Control Rod Position LCO 3.9.4 Each control rod "full-in" position indication channel shall be APPLICABILITY: MODE 5. ACTIONS Separate Condition entry is allowed for each required channel. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required control rod position indication channels inoperable. A.1.1 A.1.2 Suspend in-vessel fuel movement. Suspend control rod withdrawal. Immediately Immediately A.1.3 Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Immediately A.2.1 Initiate action to fully insert the control rod associated with the inoperable position indicator. Immediately Columbia Generating Station 3.9.4-1 Amendment 449,-1-99 225 3.9.4 Control Rod Position Indication ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2.2 Initiate action to disarm the control rod drive associated with the fully inserted control rod. Immediately SURVEILLANCE SR 3.9.4.1 Verify each channel has no "full-in" indication on each control rod that is not "full-in." Each time the control rod is withdrawn from the "full-in" position Columbia Generating Station 3.9.4-2 Amendment 449,-1-99 225 3.9.5 Control Rod OPERABILITY -Refueling 3.9 REFUELING 3.9.5 Control Rod OPERABILITY -LCO 3.9.5 Each withdrawn control rod shall be APPLICABILITY: MODE 5. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more withdrawn control rods inoperable. A.1 Initiate action to fully insert inoperable withdrawn control rods. Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.5.1 -------------------------------NOT E Not required to be performed until 7 days after the control rod is withdrawn. Insert each withdrawn control rod at least one notch. 7 days SR 3.9.5.2 Verify each withdrawn control rod scram accumulator pressure is 940 psig. 7 days Columbia Generating Station 3.9.5-1 Amendment 449,4-W 225 RPV Water Level -Irradiated Fuel 3.9.6 3.9 REFUELING OPERATIONS 3.9.6 Reactor Pressure Vessel (RPV) Water Level -Irradiated LCO 3.9.6 RPV water level shall be 22 ft above the top of the RPV APPLICABILITY: During movement of irradiated fuel assemblies within the RPV. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RPV water level not within limit. A.1 Suspend movement of irradiated fuel assemblies within the RPV. Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.9.6.1 Verify RPV water level is 22 ft above the top of the 24 hours RPV flange. Columbia Generating Station 3.9.6-1 Amendment 44B,.tW 225 RPV Water Level -New Fuel or Control Rods 3.9.7 3.9 REFUELING OPERATIONS 3.9.7 Reactor Pressure Vessel (RPV) Water Level -New Fuel or Control Rods LCO RPV water level shall be 23 ft above the top of irradiated fuel assemblies seated within the RPV. APPLICABILITY: During movement of new fuel assemblies or handling of control rods within the RPV when irradiated fuel assemblies are seated within the RPV. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RPV water level not within limit. A.1 Suspend movement of new fuel assemblies and handling of control rods within the RPV. Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.7.1 Verify RPV water level is 23 ft above the top of 24 hours irradiated fuel assemblies seated within the RPV. Columbia Generating 3.9.7-1 Amendment +99,-+99 225 RHR -High Water Level 3.9.8 3.9 REFUELING OPERATIONS 3.9.8 Residual Heat Removal (RHR) -High Water Level LCO One RHR shutdown cooling subsystem shall be OPERABLE and in operation. ---------------------------------------------NOT E The required RHR shutdown cooling subsystem may be removed from operation for up to 2 hours per 8 hour period. APPLICABILITY: MODE 5 with irradiated fuel in the reactor pressure vessel (RPV) and with the water level 22 ft above the top of the RPV flange. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Required RHR shutdown cooling subsystem inoperable. A.1 Verify an alternate method of decay heat removal is available. 1 hour AND Once per 24 hours thereafter B. Required Action and associated Completion Time of Condition A not met. B.1 AND B.2 AND Suspend loading irradiated fuel assemblies into the RPV. Initiate action to restore secondary containment to OPERABLE status. Immediately Immediately Columbia Generating 3.9.8-1 Amendment +49,499 225 3.9.8 RHR -High Water Level ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3 AND B.4 Initiate action to restore one standby gas treatment subsystem to OPERABLE status. Initiate action to restore isolation capability in each required secondary containment penetration flow path not isolated. Immediately Immediately C. No RHR shutdown cooling subsystem in operation. C.1 AND C.2 Verify reactor coolant circulation by an alternate method. Monitor reactor coolant temperatu re. 1 hour from discovery of no reactor coolant circulation AND Once per 12 hours thereafter Once per hour SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.9.8.1 Verify one RHR shutdown cooling subsystem is 12 hours operating. Columbia Generating Station 3.9.8-2 Amendment 225 RHR -Low Water Level 3.9.9 3.9 REFUELING OPERATIONS 3.9.9 Residual Heat Removal (RHR) -Low Water Level LCO Two RHR shutdown cooling subsystems shall be OPERABLE, and one RHR shutdown cooling subsystem shall be in operation. The required operating shutdown cooling subsystem may be removed from operation for up to 2 hours per 8 hour period. APPLICABILITY: MODE 5 with irradiated fuel in the reactor pressure vessel (RPV) and with the water level < 22 ft above the top of the RPV flange. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or two RH R shutdown cooli ng subsystems inoperable. A.1 Verify an alternate method of decay heat removal is available for each inoperable RHR shutdown cooling subsystem. 1 hour AND Once per 24 hours thereafter B. Required Action and associated Completion Time of Condition A not met. B.1 AND B.2 AND Initiate action to restore secondary containment to OPERABLE status. Initiate action to restore one standby gas treatment subsystem to OPERABLE status. Immediately Immediately Columbia Generating 3.9.9-1 Amendment ..:t49,.:J..e9 225 3.9.9 RHR -Low Water Level ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.3 Initiate action to restore isolation capability in each required secondary containment penetration flow path not isolated. Immediately C. No RHR shutdown cooling subsystem in operation. C.1 AND C.2 Verify reactor coolant circulation by an alternate method. Monitor reactor coolant temperature. 1 hour from discovery of no reactor coolant circulation AND Once per 12 hours thereafter Once per hour SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.9.9.1 Verify one RHR shutdown cooling subsystem is 12 hours operating. Columbia Generating Station 3.9.9-2 Amendment -149,-1-99 225 3.9.10 Decay Time 3.9 REFUELING 3.9.10 Decay LCO 3.9.10 The reactor shall be subcritical for at least 24 APPLICABILITY: During in-vessel fuel movement. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. With the reactor subcritical for less than 24 hours. A.1 Suspend in-vessel fuel movement. Immediately SURVEILLANCE REQUIREMENTS SURVEILLANCE SR 3.9.10.1 Verify the reactor has been subcritical for at least 24 hours. FREQUENCY Once prior to the movement of irradiated fuel in the reactor vessel. Columbia Generating Station 3.9.10-1 Amendment +99 225 Inservice Leak and Hydrostatic Testing Operation 3.10.1 SPECIAL OPERATIONS 3.10.1 Inservice Leak and Hydrostatic Testing Operation LCO The average reactor coolant temperature specified in Table 1.1-1 for MODE 4 may be changed to "NA," and operation considered not to be in MODE 3; and the requirements of LCO 3.4.10, "Residual Heat Removal (RHR) Shutdown Cooling System -Cold Shutdown," may be suspended to allow reactor coolant temperature> 200°F: For performance of an inservice leak or hydrostatic test, As a consequence of maintaining adequate pressure for an inservice leak or hydrostatic test, or As a consequence of maintaining adequate pressure for control rod scram time testing initiated in conjunction with an inservice leak or hydrostatic test, provided the following MODE 3 LCOs are met: LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," Functions 1, 3, and 4 of Table 3.3.6.2-1; LCO 3.6.4.1, "Secondary Containment"; LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs)"; and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System." MODE 4 with average reactor coolant temperature> 200°F. Columbia Generating Station 3.10.1-1 Amendment -1-99,200 225 Inservice Leak and Hydrostatic Testing Operation 3.10.1 ACTIONS Separate Condition entry is allowed for each requirement of the LCO. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the above requirements not met. A.1 Required Actions to be in MODE 4 include reducing average reactor coolant temperature to :5 200°F. Enter the applicable Condition of the affected LCO. Immediately A.2.1 Suspend activities that could increase the average reactor coolant temperature or pressure. Immediately A.2.2 Reduce average reactor coolant temperature to :5 200°F. 24 hours SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.10.1.1 Perform the applicable SRs for the required According to the MODE 3 LCOs. applicable SRs Columbia Generating Station 3.10.1-2 Amendment 225 Reactor Mode Switch Interlock Testing 3.10.2 3.10 SPECIAL OPERATIONS 3.10.2 Reactor Mode Switch Interlock Testing LCO 3.10.2 APPLICABILITY: ACTIONS The reactor mode switch position specified in Table 1.1-1 for MODES 3, 4, and 5 may be changed to include the run, startup/hot standby, and refuel position, and operation considered not to be in MODE 1 or 2, to allow testing of instrumentation associated with the reactor mode switch interlock functions, provided: All control rods remain fully inserted in core cells containing one or more fuel assemblies; and No CORE ALTERATIONS are in progress. MODES 3 and 4 with the reactor mode switch in the run, startup/hot standby, or refuel position, MODE 5 with the reactor mode switch in the run or startup/hot standby position. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the above requirements not met. A.1 A.2 A.3.1 Suspend CORE ALTERATIONS except for control rod insertion. Fully insert all insertable control rods in core cells containing one or more fuel assemblies. Place the reactor mode switch in the shutdown position. Immediately 1 hour 1 hour
- Columbia Generating Station 3.10.2-1 Amendment 449,499 225 Reactor Mode Switch Interlock Testing 3.10.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3.2 ---------------N Only applicable in MODE 5. Place the reactor mode switch in the refuel position. 1 hour SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.10.2.1 Verify all control rods are fully inserted in core cells containing one or more fuel assemblies. 12 hours SR 3.10.2.2 Verify no CORE ALTERATIONS are in progress. 24 hours Columbia Generating Station 3.10.2-2 Amendment -149,-+69 225 Single Control Rod Withdrawal -Hot Shutdown 3.10.3 SPECIAL OPERATIONS 3.10.3 Single Control Rod Withdrawal-Hot Shutdown LCO 3.10.3 APPLICABILITY: The reactor mode switch position specified in Table 1.1-1 for MODE 3 may be changed to include the refuel position, and operation considered not to be in MODE 2, to allow withdrawal of a single control rod, provided the following requirements are met: a. LCO 3.9.2, "Refuel Position One-Rod-Out Interlock"; b. LCO 3.9.4, "Control Rod Position Indication"; c. All other control rods are fully inserted; and 1. LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," MODE 5 requirements for Functions 1.a, 1.b, 7.a, 7.b, 10, and 11 of Table 3.3.1.1-1, and LCO 3.9.5, "Control Rod OPERABILITY -Refueling," All other control rods in a five by five array centered on the control rod being withdrawn are disarmed, at which time LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," MODE 3 requirements may be changed to allow the single control rod withdrawn to be assumed to be the highest worth control rod. MODE 3 with the reactor mode switch in the refuel position. Columbia Generating Station 3.10.3-1 Amendment -149,4-W 225 3.10.3 Single Control Rod Withdrawal -Hot Shutdown ACTIONS Separate Condition entry is allowed for each requirement of the LCO. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the above requirements not met. A.1 --------------N OTE 1. Required Actions to fully insert all insertable control rods include placing the reactor mode switch in the shutdown position. 2. Only applicable if the requirement not met is a required LCO. Enter the applicable Condition of the affected LCO. Immediately A.2.1 Initiate action to fully insert all insertable control rods. Immediately A.2.2 Place the reactor mode switch in the shutdown position. 1 hour SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.10.3.1 Perform the applicable SRs for the required LCOs. According to the applicable SRs Columbia Generating Station 3.10.3-2 Amendment -149,4-69 225 3.10.3 Single Control Rod Withdrawal -Hot Shutdown SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.10.3.2 -------------------------------NOT E Not required to be met if SR 3.10.3.1 is satisfied for LCO 3.10.3.d.1 requirements. Verify all control rods, other than the control rod being withdrawn, in a five by five array centered on the control rod being withdrawn, are disarmed. 24 hours SR 3.10.3.3 Verify all control rods, other than the control rod being withdrawn, are fully inserted. 24 hours Columbia Generating Station 3.10.3-3 Amendment .:J..49,.:tW 225 Single Control Rod Withdrawal -Cold Shutdown 3.10.4 SPECIAL OPERATIONS 3.10.4 Single Control Rod Withdrawal -Cold Shutdown LCO The reactor mode switch position specified in Table 1.1-1 for MODE 4 may be changed to include the refuel position, and operation considered not to be in MODE 2, to allow withdrawal of a single control rod, and subsequent removal of the associated control rod drive (CRD) if desired, provided the following requirements are met: a. All other control rods are fully inserted; b. LCO 3.9.2, "Refuel Position One-Rod-Out Interlock," and LCO 3.9.4, "Control Rod Position Indication," OR A control rod withdrawal block is inserted; and 1. LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," MODE 5 requirements for Functions 1.a, 1.b, 7.a, 7.b, 10, and 11 of Table 3.3.1.1-1, LCO 3.3.8.2, "Reactor Protection System (RPS) Electric Power Monitoring," MODE 5 requirements, and LCO 3.9.5, "Control Rod OPERABILITY -Refueling," All other control rods in a five by five array centered on the control rod being withdrawn are disarmed, at which time LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," MODE 5 requirements may be changed to allow the single control rod withdrawn to be assumed to be the highest worth control rod. APPLICABI MODE 4 with the reactor mode switch in the refuel position. Columbia Generating Station 3.10.4-1 Amendment +49,+99 225 3.10.4 Single Control Rod Withdrawal-Cold Shutdown ACTIONS Separate Condition entry is allowed for each requirement of the LCO. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the above requirements not met with the affected control rod insertable. A.1 --------------N OTE 1. Required Actions to fully insert all insertable control rods include placing the reactor mode switch in the shutdown position. 2. Only applicable if the requirement not met is a required LCO. --------_....... _... Enter the applicable Condition of the affected LCO. OR A.2.1 Initiate action to fully insert all insertable control rods. AND A.2.2 Place the reactor mode Immediately Immediately 1 hour switch in the shutdown position. B. One or more of the above requirements not met with the affected control rod not insertable. B.1 Suspend withdrawal of the control rod and removal of associated CRD. AND Immediately B.2.1 Initiate action to fully insert all control rods. Immediately OR Columbia Generating Station 3.10.4-2 Amendment 44B . .tW 225 Single Control Rod Withdrawal -Cold Shutdown 3.10.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. (continued) B.2.2 Initiate action to satisfy the requirements of this LCO. Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.10.4.1 Perform the applicable SRs for the required LCOs. According to the applicable SRs SR 3.10.4.2 -------------------------------NOTE Not required to be met if SR 3.10.4.1 is satisfied for LCO 3.1 0.4.c.1 requirements. Verify all control rods, other than the control rod being withdrawn, in a five by five array centered on the control rod being withdrawn, are disarmed. 24 hours SR 3.10.4.3 Verify all control rods, other than the control rod being withdrawn, are fully inserted. 24 hours SR 3.10.4.4 -------------------------------NOTE Not required to be met if SR 3.10.4.1 is satisfied for LCO 3.10.4.b.1 requirements. Verify a control rod withdrawal block is inserted. 24 hours Columbia Generating Station 3.10.4-3 Amendment 449,4-99 225 Single CRD Removal -Refueling 3.10.5 3.10 SPECIAL OPERATIONS 3.10.5 Single Control Rod Drive (CRD) Removal -Refueling LCO 3.10.5 APPLICABILITY: ACTIONS The requirements of LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"; LCO 3.3.8.2, "Reactor Protection System (RPS) Electric Power Monitoring"; LCO 3.9.1, "Refueling Equipment Interlocks"; LCO 3.9.2, "Refuel Position One-Rod-Out Interlock"; LCO 3.9.4, "Control Rod Position Indication"; and LCO 3.9.5, "Control Rod OPERABILITY Refueling," may be suspended in MODE 5 to allow the removal of a single CRD associated with a control rod withdrawn from a core cell containing one or more fuel assemblies, provided the following requirements are met: All other control rods are fully inserted; All other control rods in a five by five array centered on the withdrawn control rod are disarmed; A control rod withdrawal block is inserted, and LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," MODE 5 requirements may be changed to allow the single control rod withdrawn to be assumed to be the highest worth control rod; and No other CORE ALTERATIONS are in progress. MODE 5 with LCO 3.9.5 not met. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the above requirements not met. A.1 A.2.1 A.2.2 Suspend removal of the CRD mechanism. Initiate action to fully insert all control rods. Initiate action to satisfy the requirements of this LCO. Immediately Immediately Immediately Columbia Generating Station 3.10.5-1 Amendment -MB,+6Q 225 3.10.5 Single CRD Removal -Refueling SURVEILLANCE REQUIREMENTS SR Verify all control rods, other than the control rod
- 24 hours withdrawn for the removal of the associated CRD, are fully inserted. SR Verify all control rods, other than the control rod 24 hours withdrawn for the removal of the associated CRD, in a five by five array centered on the control rod withdrawn for the removal of the associated CRD, are disarmed. SR 3.10.5.3 Verify a control rod withdrawal block is inserted. 24 hours SR 3.10.5.4 Perform SR
- According to : SR 3.1.1.1 SR 3.10.5.5 Verify no other CORE ALTERATIONS are in 24 hours progress. Columbia Generating Station 3.10.5-2 Amendment 449,+&9 225 Multiple Control Rod Withdrawal -Refueling 3.10.6 SPECIAL OPERATIONS 3.10.6 Multiple Control Rod Withdrawal -Refueling 3.10.6 APPLICABILITY: ACTIONS The requirements of LCO 3.9.3, "Control Rod Position"; LCO 3.9.4, "Control Rod Position Indication"; and LCO 3.9.5, "Control Rod OPERABILITY -Refueling," may be suspended, and the "full-in" position indicators may be bypassed for any number of control rods in MODE 5, to allow withdrawal of these control rods, removal of associated control rod drives (CRDs), or both, provided the following requirements are met: The four fuel assemblies are removed from the core cells associated with each control rod or CRD to be removed; All other control rods in core cells containing one or more fuel assemblies are fully inserted; and Fuel assemblies shall only be loaded in compliance with an approved spiral reload sequence. MODE 5 with LCO 3.9.3, LCO 3.9.4, or LCO 3.9.5 not met. CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the above requirements not met. A.1 AND A.2 Suspend withdrawal of control rods and removal of associated CRDs. Suspend loading fuel assemblies. Immediately Immediately Columbia Generating Station 3.10.6-1 Amendment .:+49,499 225 Multiple Control Rod Withdrawal -Refueling 3.10.6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.3.1 A.3.2 Initiate action to fully insert all control rods in core cells containing one or more fuel assemblies. Initiate action to satisfy the requirements of this LCO. Immediately Immediately SURVEILLANCE SURVEILLANCE FREQUENCY SR 3.10.6.1 Verify the four fuel assemblies are removed from core cells associated with each control rod or CRD removed. 24 hours SR 3.10.6.2 Verify all other control rods in core cells containing one or more fuel assemblies are fully inserted. 24 hours SR 3.10.6.3 -------------------------------NOT E Only required to be met during fuel loading. Verify fuel assemblies being loaded are in compliance with an approved spiral reload sequence. 24 hours Columbia Generating Station 3.10.6-2 Amendment 225 Control Rod Testing -Operating 3.10.7 SPECIAL OPERATIONS 3.10.7 Control Rod Testing -Operating LCO The requirements of LCO 3.1.6, "Rod Pattern Control," may be suspended to allow performance of SDM demonstrations, control rod scram time testing, and control rod friction testing provided: The banked position withdrawal sequence requirements of SR 3.3.2.1.8 are changed to require the control rod sequence to conform to the specified test sequence. The RWM is bypassed; the requirements of LCO 3.3.2.1, "Control Rod Block Instrumentation," Function 2 are suspended; and conformance to the approved control rod sequence for the specified test is verified by a second licensed operator or other qualified member of the technical staff. MODES 1 and 2 with LCO 3.1.6 not met. ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the A.1 Suspend performance of Immediately LCO not met. the test and exception to LCO 3.1.6. Columbia Generating Station 3.10.7-1 Amendment 449.400 225 3.10.7 Control Rod Testing -Operating SURVEILLANCE REQUIREMENTS SR SR Not required to be met if SR 3.10.7.2 satisfied. Verify movement of control rods is in compliance with the approved control rod sequence for the specified test by a second licensed operator or other qualified member of the technical staff. Not required to be met if SR 3.10.7.1 satisfied. Verify control rod sequence input to the RWM is in conformance with the approved control rod sequence for the specified test. During control rod movement Prior to control rod movement Columbia Generating Station 3.10.7-2 Amendment 449,4-69 225 SDM Test -Refuellng 3.10.8 SPECIAL OPERATIONS 3.10.8 SHUTDOWN MARGIN (SDM) Test -Refueling LCO The reactor mode switch position specified in Table 1.1-1 for MODE 5 may be changed to include the startup/hot standby position, and operation considered not to be in MODE 2, to allow SDM testing, provided the following requirements are met: LCO 3.3.1.1, "Reactor Protection System Instrumentation," MODE 2 requirements for Functions 2.a and 2.d of Table 3.3.1.1-1; 1. LCO 3.3.2.1, "Control Rod Block Instrumentation," MODE 2 requirements for Function 2 of Table 3.3.2.1-1, with banked position withdrawal sequence requirements of SR 3.3.2.1.8 changed to require the control rod sequence to conform to the SDM test sequence, Conformance to the approved control rod sequence for the SDM test is verified by a second licensed operator or other qualified member of the technical staff; Each withdrawn control rod shall be coupled to the associated control rod drive (CRD); All control rod withdrawals during out of sequence control rod moves shall be made in notch out mode; No other CORE ALTERATIONS are in progress; and CRD charging water header pressure z 940 psig. MODE 5 with the reactor mode switch in startup/hot standby position. Columbia Generating Station 3.10.8-1 Amendment -14B,4e9 225 3.10.8 SDM Test -Refueling ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. ------------N Separate Condition entry is allowed for each control rod. -----------_... One or more control rods not coupled to its associated CRD. -------------------N Rod worth minimizer may be bypassed as allowed by LCO 3.3.2.1, "Control Rod Block Instrumentation," if required, to allow insertion of inoperable control rod and continued operation. -------------_... _----------------------_... A.1 Fully insert inoperable control rod. AND 3 hours A.2 Disarm the associated CRD. 4 hours B. One or more of the above requirements not met for reasons other than Condition A. B.1 Place the reactor mode switch in the shutdown or refuel position. Immediately SURVEILLANCE SR Perform the MODE 2 applicable SRs for LCO 3.3.1.1, Functions 2.a and 2.d of Table 3.3.1.1-1. SR Not required to be met if SR 3.10.8.3 satisfied. Perform the MODE 2 applicable SRs for LCO 3.3.2.1, Function 2 of Table 3.3.2.1-1. According to the applicable SRs According to the applicable SRs Columbia Generating Station 3.10.8-2 Amendment 225 3.10.8 SDM Test -Refueling SURVEILLANCE SR ------------------------------NO TE Not required to be met if SR 3.10.8.2 satisfied. Verify movement of control rods is in compliance with the approved control rod sequence for the SDM test by a second licensed operator or other qualified During control rod movement member of the technical staff. SR 3.10.8.4 Verify no other CORE ALTERATIONS are in 12 hours progress. SR 3.10.8.5 Verify each withdrawn control rod does not go to the Each time the withdrawn overtravel position. control rod is withdrawn to "full out" position Prior to satisfying LCO 3.10.8.c requirement after i work on control rod or CRD System that could affect coupling SR 3.10.8.6 Verify CRD charging water header pressure 7 days 940 psig. Columbia Generating Station 3.10.8-3 Amendment 449,499 225 Design Features 4.0 DESIGN FEATURES Site Location 4.1.1 Site and Exclusion Area Boundaries The site area shall include the area enclosed by the exclusion area plus the plant property lines that fall outside the exclusion area, as shown in Figure 4.1-1. The exclusion area boundary is a circle with its center at the reactor and a radius of 1950 meters. 4.1.2 Low Population Zone The low population zone is all the land within a circle with its center at the reactor and a radius of 4827 meters. Reactor Core 4.2.1 Fuel Assemblies The reactor shall contain 764 fuel assemblies. Each assembly shall consist of a matrix of Zircaloy clad fuel rods with an initial composition of depleted, natural, or slightly enriched uranium dioxide (U02) as fuel material and water rods or channels. Limited substitutions of zirconium alloy or stainless steel filler rods for fuel rods, in accordance with approved applications of fuel rod configurations, may be used. Fuel assemblies shall be limited to those fuel designs that have been analyzed with applicable NRC staff approved codes and methods and shown by tests or analyses to comply with all safety design bases. A limited number of lead fuel assemblies that have not completed representative testing may be placed in nonlimiting core regions. 4.2.2 Control Rod Assemblies The reactor core shall contain 185 cruciform shaped control rod assemblies. The control material shall be boron carbide and hafnium metal as approved by the NRC. Fuel Storage 4.3.1 Criticality 4.3.1 .1 The spent fuel storage racks are designed and shall be maintained with: keff 0.95 if fully flooded with unborated water, which includes an allowance for uncertainties as described in Section 9.1.2 of the FSAR; and A nominal 6.5 inch center to center distance between fuel assemblies placed in the storage racks. Columbia Generating 4.0-1 Amendment +W,48§. 225 Design Features 4.0 DESIGN FEATURES Fuel Storage (continued) The new fuel storage racks are designed and, with fuel assemblies inserted, shall be maintained with: kef! ::; 0.95 if fully flooded with unborated water, which includes an allowance for uncertainties as described in Section 9.1.1 of the FSAR; and A maximum of 60 new fuel assemblies stored in the new fuel storage racks, arranged in 6 spatially separated zones. Within a storage zone, the nominal center-to-center distance between cells for storing fuel assemblies is 14 inches. The nominal center distance between cells for storing fuel assemblies in adjacent zones is 37 inches. Design features relied upon to spatially limit the placement of fuel bundles within the new fuel vault are required to be installed prior to placement of new fuel bundles in the vault. Drainage The spent fuel storage pool is designed and shall be maintained to prevent inadvertent draining of the pool below elevation 583 ft 1.25 inches. Capacity The spent fuel storage pool is designed and shall be maintained with a storage capacity limited to no more than 2658 fuel assemblies. Columbia Generating 4.0-2 Amendment 225 4.0 Design Features
- Pum p House!t NORTH Site Area Boundary WNP.... , I l" GROUND
- MeT ToweR EMERGENcy OPERATIONS FACtl..JTY \ ACCESSftOAD TO ROUTE < Figure 4.1-1 (page 1 of 1) Site Area Boundary Columbia Generating Station 4.0-3 Amendment 225 Responsibility 5.1 5.0 ADMINISTRATIVE CONTROLS 5.1 Responsibility The Plant General Manager shall be responsible for overall unit operation and shall delegate in writing the succession to this responsibility during his absence. The Plant General Manager or his designee shall approve, prior to implementation, each proposed test, experiment, and modification to systems or equipment that affect nuclear safety. The Shift Manager (SM) shall be responsible for the control room command function. During any absence of the SM from the control room while the unit is in MODE 1, 2, or 3, an individual with an active Senior Reactor Operator (SRO) license shall be designated to assume the control room command function. During any absence of the SM from the control room while the unit is in MODE 4 or 5, an individual with an active SRO license or Reactor Operator license shall be designated to assume the control room command function. Columbia Generating 5.1-1 Amendment 449,.:1-&9 225 Organization 5.2 5.0 ADMINISTRATIVE CONTROLS 5.2 Organization 5.2.1 Onsite and Offsite Organizations Onsite and offsite organizations shall be established for unit operation and corporate management, respectively. The onsite and offsite organizations shall include the positions for activities affecting safety of the nuclear power plant. Lines of authority, responsibility, and communication shall be defined and established throughout highest management levels, intermediate levels, and all operating organization positions. These relationships shall be documented and updated, as appropriate, in organization charts, functional descriptions of departmental responsibilities and relationships, and job descriptions for key personnel positions, or in equivalent forms of documentation. These requirements shall be documented in the FSAR. The Plant General Manager shall be responsible for overall safe operation of the plant and shall have control over those onsite activities necessary for safe operation and maintenance of the plant. The Chief Executive Officer shall have corporate responsibility for overall plant nuclear safety and shall take any measures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plant to ensure nuclear safety. The individuals who train the operating staff, carry out health physics, or perform quality assurance functions may report to the appropriate onsite manager; however, these individuals shall have sufficient organizational freedom to ensure their independence from operating pressures. 5.2.2 Unit Staff The unit staff organization shall include the following: At least two Equipment Operators shall be assigned when the unit is in MODES 1, 2, or 3; and at least one Equipment Operator shall be assigned when the unit is in MODE 4 or 5. Shift crew composition may be less than the minimum requirement of 10 CFR 50.54(m)(2)(i) and 5.2.2.a and 5.2.2.f for a period of time not to exceed 2 hours in order to accommodate unexpected absence of on-duty shift crew members provided immediate action is taken to restore the shift crew composition to within the minimum requirements. Columbia Generating 5.2-1 Amendment 225 5.2.2 Organization 5.2 Organization Unit Staff (continued) An individual qualified to implement radiation protection procedures shall be on site when fuel is in the reactor. The position may be vacant for not more than 2 hours, in order to provide for unexpected absence, provided immediate action is taken to fill the required position. Deleted. The Operations Manager or Assistant Operations Manager shall hold an SRO license. An individual shall provide advisory technical support to the unit operations shift crew in the areas of thermal hydraulics, reactor engineering, and plant analysis with regard to the safe operation of the unit. This individual shall meet the qualifications specified by the Commission Policy Statement on Engineering Expertise on Shift. Columbia Generation 5.2-2 Amendment 225 Unit Staff Qualifications 5.3 5.0 ADMINISTRATIVE CONTROLS 5.3 Unit Staff Qualifications Each member of the unit staff shall meet or exceed the minimum qualifications of ANSIIANS N18.1-1971, for comparable positions described in the FSAR, except for: The Operations Manager, who shall meet the requirements of ANSI/ANS N 18.1-1971 with the exception that in lieu of meeting the stated ANSIIANS requirement to hold a Senior Reactor Operator (SRO) license at the time of appointment to the position, the Operations Manager shall: Hold an SRO license at the time of appointment; Have held an SRO license; or Have been certified for equivalent SRO knowledge; and The Radiation Protection Manager, who shall meet or exceed the qualifications of Regulatory Guide 1.8, Revision 1-R, May 1977, For the purpose of 10 CFR 55.4, a licensed SRO and a licensed Reactor Operator (RO) are those individuals who, in addition to meeting the requirements of Specification 5.3.1, perform the functions described in 10 CFR 50,54(m), Columbia Generation 5.3-1 Amendment 225 5.4.1 Procedures 5.4 ADMINISTRATIVE CONTROLS Procedures Written procedures shall be established, implemented, and maintained covering the following activities: The applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978; The emergency operating procedures required to implement the requirements of NUREG-0737 and NUREG-0737, Supplement 1, as stated in Generic Letter 82-33; Quality assurance program for radioactive effluent and radiological environmental monitoring; Fire Protection Program implementation; and All programs specified in Specification 5.5. Columbia Generating 5.4-1 Amendment 449,4W 225 5.5.1 Programs and Manuals 5.5 5.0 ADMINISTRATIVE CONTROLS Programs and Manuals The following programs shall be established, implemented, and maintained. Offsite Dose Calculation Manual (ODCM) The ODCM shall contain the methodology and parameters used in the calculation of offsite doses resulting from radioactive gaseous and liquid effluents, in the calculation of gaseous and liquid effluent monitoring alarm and trip setpoints, and in the conduct of the radiological environmental monitoring program; and The ODCM shall also contain the radioactive effluent controls and radiological environmental monitoring activities, and descriptions of the information that should be included in the Annual Radiological Environmental Operating and Radioactive Effluent Release reports required by Specification 5.6.1 and Specification 5.6.2. Licensee initiated changes to the ODCM: Shall be documented and records of reviews performed shall be retained. This documentation shall contain: Sufficient information to support the change(s) together with the appropriate analyses or evaluations justifying the change(s), and A determination that the change(s) maintain the levels of radioactive effluent control required pursuant to 10 CFR 20.1302, 40 CFR 190,10 CFR 50.36a, and 10 CFR 50, Appendix I, and do not adversely impact the accuracy or reliability of effluent. dose, or setpoint calculations; Shall become effective after review and acceptance by the Plant Operations Committee and the approval of the Plant General Manager; and Shall be submitted to the NRC in the form of a complete, legible copy of the entire ODCM as a part of, or concurrent with, the Radioactive Effluent Release Report for the period of the report in which any change in the ODCM was made. Each change shall be identified by 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. Columbia Generating 5.5-1 Amendment .ffi9,4-W 225 Programs and Manuals 5.5 Programs and Manuals 5.5.2 Primary Coolant Sources Outside Containment 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 Low Pressure Core Spray, High Pressure Core Spray, Residual Heat Removal, Reactor Core Isolation Cooling, process sampling, (the program requirements shall apply to the Post Accident Sampling System until such time as administrative controls provide for continuous isolation of the associated penetration(s) or a modification eliminates the potential leakage path{s)), containment monitoring, and Standby Gas Treatment. The program shall include the following: Preventive maintenance and periodic visual inspection requirements; and Integrated leak test requirements for each system at 24 month intervals or less. The provisions of SR 3.0.2 are applicable to the 24 month Frequency for performing integrated system leak test activities. 5.5.3 Deleted 5.5.4 Radioactive Effluent Controls Program This program, conforming to 10 CFR 50.36a, provides for the control of radioactive effluents and for maintaining the doses to members of the public from radioactive effluents as low as reasonably achievable. The program shall be contained in the ODCM, shall be implemented by procedures, and shall include remedial actions to be taken whenever the program limits are exceeded. The program shall include the following elements: Limitations on the functional capability of radioactive liquid and gaseous monitoring instrumentation including surveillance tests and setpoint determination in accordance with the methodology in the ODCM; Limitations on the concentrations of radioactive material released in liquid effluents to unrestricted areas, conforming to 10 times the concentration values in Appendix B, Table 2, Column 2 to 10 CFR 20.1001 -20.2402; Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents pursuant to 10 CFR 20.1302 and with the methodology and parameters in the ODCM; Limitations on the annual and quarterly doses or dose commitment to a member of the public from radioactive materials in liquid effluents released from each unit to unrestricted areas, conforming to 10 CFR 50, Appendix I; Columbia Generating 5.5-2 Amendment 225 Programs and Manuals 5.5 Programs and Manuals 5.5.4 Radioactive Effluent Controls Program (continued) Determination of cumulative and projected dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days; Limitations on the functional capability and use of the liquid and gaseous effluent treatment systems to ensure that appropriate portions of these systems are used to reduce releases of radioactivity when the projected doses in a period of 31 days would exceed 2% of the guidelines for the annual dose or dose commitment, conforming to 10 CFR 50, Appendix I; Limitations on the dose rate resulting from radioactive material released in gaseous effluents from the site to areas at or beyond the site boundary shall be limited to the following: For noble gases: less than or equal to a dose rate of 500 mrems/yr to the whole body and less than or equal to a dose rate of 3000 mrems/yr to the skin, and For iodine-131, iodine-133, tritium, and for all radionuclides in particulate form with half lives> 8 days: less than or equal to a dose rate of 1500 mrems/yr to any organ; Limitations on the annual and quarterly air doses resulting from noble gases released in gaseous effluents from each unit to areas beyond the site boundary, conforming to 10 CFR 50, Appendix I; Limitations on the annual and quarterly doses to a member of the public from iodine-131, iodine-133, tritium, and all radionuclides in particulate form with half lives> 8 days in gaseous effluents released from each unit to areas beyond the site boundary, conforming to 10 CFR 50, Appendix I; Limitations on the annual dose or dose commitment to any member of the public, beyond the site boundary, due to releases of radioactivity and to radiation from uranium fuel cycle sources, conforming to 40 CFR 190; and Limitations on venting and purging of the primary containment through the Standby Gas Treatment System to maintain releases as low as reasonably achievable. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Radioactive Effluent Controls Program surveillance frequency. Columbia Generating 5.5-3 Amendment 225 Programs and Manuals 5.5 Programs and Manuals 5.5.5 Component Cyclic or Transient Limit This program provides controls to track the FSAR, Table 3.9-1, Note 1, cyclic and transient occurrences to ensure that components are maintained within the design limits. 5.5.6 Inservice Testing Program This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 pumps and valves. Testing Frequencies applicable to the ASME Code for Operations and Maintenance of Nuclear Power Plants (ASME OM Code) and applicable Addenda as follows: ASME OM Code and applicable Required Frequencies for Addenda terminology for performing inservice testing inservice testing activities activities Weekly Monthly Quarterly or every 3 months Semiannually or every 6 months Every 9 months Yearly or annually Biennially or every 2 years At least once per 7 days At least once per 31 days At least once per 92 days At least once per 184 days At least once per 276 days At least once per 366 days At least once per 731 days b. The provisions of SR 3.0.2 are applicable to the above required Frequencies and to other normal and accelerated Frequencies specified as 2 years or less in the Inservice Testing Program for performing inservice testing activities; c. The provisions of SR 3.0.3 are applicable to inservice testing activities; and d. Nothing in the ASME OM Code shall be construed to supersede the requirements of any TS. Columbia Generating 5.5-4 Amendment 225 Programs and Manuals 5.5 Programs and Manuals 5.5.7 Ventilation Filter Testing Program (yFTP) The VFTP shall establish the required testing of Engineered Safety Feature (ESF) filter ventilation systems. Tests described in Specification 5.5.7.a and 5.5.7.b shall be performed once per 24 months; after each complete or partial replacement of the HEPA filter train or charcoal adsorber filter; after any structural maintenance on the system housing; and, following significant painting, fire, or chemical release in any ventilation zone communicating with the system while it is in operation. Tests described in Specification 5.5.7.c shall be performed once per 24 months; after 720 hours of system operation; after any structural maintenance on the system housing; and, following significant painting, fire, or chemical release in any ventilation zone communicating with the system while it is in operation. Tests described in Specification 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. Demonstrate for each of the ESF systems that an inplace test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass < 0.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1989 at the system flowrate specified below: ESF Ventilation System Flowrate (cfm) SGT System 4320 to 5280 CREF System 900 to 1100 Demonstrate for each of the ESF systems that an inplace test of the charcoal absorber shows a penetration and system bypass < 0.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1989 at the system flowrate specified below: ESF Ventilation System Flowrate (cfm) SGT System 4320 to 5280 CREF System 900 to 1100 Columbia Generating 5.5-5 Amendment 225 Programs and Manuals 5.5 Programs and Manuals 5.5.7 Ventilation Filter Testing Program (continued) Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal absorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than the value specified below when tested in accordance with ASTM D3803-1989 at a temperature of 30°C (86°F) and the relative humidity specified below. Testing of the SGT System will also be conducted at a face velocity of 75 feet per minute. ESF Ventilation System Penetration (%) RH (%) SGT System 0.5 70 CREF System 2.5 70 Allowed tolerances in the above testing parameters of temperature, relative humidity, and face velocity are as specified in ASTM D3803-1989. Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters and the charcoal absorbers is less than the value specified below when tested at the system flowrate specified below: ESF Ventilation System Delta P Flowrate (inches wg) (cfm) SGT System <8 4320 to 5280 CREF System <6 900 to 1100 Demonstrate that the heaters for each of the ESF systems dissipate the nominal value specified below when tested in accordance with ASME N510-1989: ESF Ventilation System Wattage (kW) SGT System 18.6 to 22.8 CREF System 4.5 to 5.5 5.5.8 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the Main Condenser Offgas Treatment System and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. Columbia Generating 5.5-6 Amendment +82,4W 225 Programs and Manuals 5.5 Programs and Manuals 5.5.8 Explosive Gas and Storage Tank Radioactivity Monitoring Program (continued) The program shall include: The limits for concentrations of hydrogen in the Main Condenser Offgas Treatment System and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion); and A surveillance program to ensure that the quantity of radioactivity contained in all outside temporary liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overHows and surrounding area drains connected to the Liquid Radwaste Treatment System is less than the amount that would result in concentrations greater than the limits of Appendix B, Table 2, Column 2 to 10 CFR 20.1001 -20.2402, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program Surveillance Frequencies. 5.5.9 Diesel Fuel Oil Testing Program A diesel fuel oil testing program shall establish the required testing of both new fuel oil and stored fuel oil. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following: Acceptability of new fuel oil for use prior to addition to storage tanks by determining that the fuel oil has: An API gravity, a specific gravity, or an absolute specific gravity within limits, A kinematic viscosity, if gravity was not determined by comparison with the supplier's certificate, and a flash point within limits for ASTM 2-D fuel oil, A water and sediment content within limits or a clear and bright appearance with proper color; Columbia Generating 5.5-7 Amendment 449AW 225 Programs and Manuals 5.5 Programs and Manuals 5.5.9 5.5.10 5.5.11 Diesel Fuel Oil Testing Program (continued) b. Other properties for ASTM 2-D fuel oil are within limits within 31 days following sampling and addition to storage tanks; and c. Total particulate concentration of the fuel oil in the storage tanks is 10 mg/I when tested every 31 days. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program test Frequencies. Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following: A change in the TS incorporated in the license; or A change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR. Proposed changes that meet the criteria of Specification 5.5.1 O.b above shall be reviewed and approved by the NRC prior to implementation. Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71(e). Safety Function Determination Program (SFDP) This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other appropriate limitations and remedial or compensatory actions may be identified to be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. Columbia Generating 5.5-8 Amendment 225 Programs and Manuals 5.5 Programs and Manuals 5.5.11 Safety Function Determination Program (SFDP) (continued) The SFDP shall contain the following: Provisions for cross division checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected; Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists; Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and Other appropriate limitations and remedial or compensatory actions. A loss of safety function exists when, assuming no concurrent single failure, a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and: A required system redundant to system(s) supported by the inoperable support system is also inoperable; or A required system redundant to system(s) in turn supported by the inoperable supported system is also inoperable; or A required system redundant to support system(s) for the supported systems described in b.1 and b.2 above is also inoperable. The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. 5.5.12 Primary Containment Leakage Rate Testing Program The Primary Containment Leakage Rate Testing Program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(0) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exceptions: The next Type A test Columbia Generating 5.5-9 Amendment 4++,.:1-9+ 225 Programs and Manuals 5.5 Programs and Manuals 5.5.12 Primary Containment Leakage Rate Testing Program (continued) performed after the July 20. 1994, Type A test shall be performed no later than July 20, 2009, and compensation for flow meter inaccuracies in excess of those specified in ANSI/ANS 56.8-1994 will be accomplished by increasing the actual instrument reading by the amount of the full scale inaccuracy when assessing the effect of local leak rates against the criteria established in Specification 5.5.12.a. The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa* is 38 psig. The maximum allowable primary containment leakage rate, La, at Pa, shall be 0.5% of primary containment air weight per day. Leakage rate acceptance criteria are: Primary containment leakage rate acceptance criterion is :5 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are < 0.60 La for the Type B and Type C tests (except for main steam isolation valves) and < 0.75 La for Type A tests; Primary containment air lock testing acceptance criteria are: Overall primary containment air lock leakage rate is :5 0.05 La when tested at Pa; and For each door, leakage rate is :5 0.025 La when pressurized to 10 psig. The provisions of SR 3.0.3 are applicable to the Primary Containment Leakage Rate Testing Program. 5.5.13 Battery Monitoring and Maintenance Program This Program provides for restoration and maintenance, which includes the following: Actions to restore battery cells with float voltage < 2.13 V; and Actions to equalize and test battery cells that had been discovered with electrolyte level below the top of the plates; and Actions to verify that the remaining cells are 2.07 V when a cell or cells have been found to be < 2.13 V. Columbia Generating 5.5-10 Amendment 225 Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Control Room Envelope Habitability Program A Control Room Envelope (CRE) Habitability Program shall be established and implemented to ensure that CRE habitability is maintained such that, with an OPERABLE Control Room Emergency Filtration (CREF) System, CRE occupants can control the reactor safely under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The program shall ensure that adequate radiation protection is provided to permit access and occupancy of the CRE under design basis accident (DBA) conditions without personnel receiving radiation exposures in excess of 5 rem total effective dose equivalent (TEDE) for the duration of the accident. The program shall include the following elements: a. The definition of the CRE and the 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 Frequencies specified in Sections C.1 and C.2 of Regulatory Guide 1.197, Revision O. 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 one subsystem of the CREF System, operating at the flow rate required by the VFTP, at a Frequency of 24 months on a STAGGERED TEST BASIS. The results shall be trended and used as part of the 24 month 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 for 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 inleakage, and measuring CRE pressure and assessing the CRE boundary as required by paragraphs c and d, respectively. Columbia Generating Station 5.5-11 Amendment 225 Reporting Requirements 5.6 5.0 ADMINISTRATIVE CONTROLS Reporting Requirements The following reports shall be submitted in accordance with 10 CFR 50.4. 5.6.1 Annual Radiological Environmental Operating Report The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted by May 15 of each year. The report shall include summaries, interpretations, and analyses of trends of the results of the Radiological Environmental Monitoring Program for the reporting period. The material provided shall be consistent with the objectives outlined in the Offsite Dose Calculation Manual (ODCM), and in 10 CFR 50, Appendix I, Sections IV.B.2, IV.B.3, and IV.C. The Annual Radiological Environmental Operating Report shall include the results of analyses of all radiological environmental samples and of all environmental radiation measurements taken during the period pursuant to the locations specified in the table and figures in the ODCM, as well as summarized and tabulated results of these analyses and measurements in the format of the table in the Radiological Assessment Branch Technical Position, Revision 1, November 1979. In the event that some individual results are not available for inclusion with the report, the report shall be submitted noting and explaining the reasons for the missing results. The missing data shall be submitted in a supplementary report as soon as possible. 5.6.2 Radioactive Effluent Release Report The Radioactive Effluent Release Report covering the operation of the unit shall be submitted in accordance with 10 CFR 50.36a. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit. The material provided shall be consistent with the objectives outlined in the ODCM and the Process Control Program and in conformance with 10 CFR 50.36a and 10 CFR 50, Appendix I, Section IV.B.1. 5.6.3 CORE OPERATING LIMITS REPORT (COLR) Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following: The APLHGR for Specification 3.2.1; The MCPR for Specification 3.2.2; The LHGR for Specification 3.2.3; and LCO 3.3.1.3, "Oscillation Power Range Monitor (OPRM) Instrumentation." Columbia Generating 5.6-1 Amendment 4W,.:f.OO 225 5.6.3 Reporting Requirements 5.6 Reporting Requirements CORE OPERATING LIMITS REPORT (COLR) (continued) The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents: XN-NF-B1-5B(P)(A), "RODEX2 Fuel Rod Thermal-Mechanical Response Evaluation Model," Exxon Nuclear Company XN-NF-B5-67(P)(A), "Generic Mechanical Design for Exxon Nuclear Jet Pump BWR Reload Fuel," Exxon Nuclear Company EMF-B5-74(P) Supplement 1(P)(A) and Supplement 2(P)(A), "RODEX2A (BWR) Fuel Rod Thermal-Mechanical Evaluation Model," Siemens Power Corporation ANF-B9-9B(P)(A), "Generic Mechanical Design Criteria for BWR Fuel Designs," Advanced Nuclear Fuels Corporation XN-NF-BO-19(P)(A) Volume 1, "Exxon Nuclear Methodology for Boiling Water Reactors -Neutronic Methods for Design and Analysis," . Exxon Nuclear Company XN-NF-BO-19(P)(A) Volume 4, "Exxon Nuclear Methodology for Boiling Water Reactors: Application of the ENC Methodology to BWR Reloads," Exxon Nuclear Company EMF-215B(P)(A), "Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of 4/MICROBLIRN-B2," Siemens Power Corporation XN-NF-BO-19(P)(A) Volume 3, "Exxon Nuclear Methodology for Boiling Water Reactors, THERMEX: Thermal Limits Methodology Summary Description," Exxon Nuclear Company XN-NF-B4-105(P)(A) Volume 1, "XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis," Exxon Nuclear Company ANF-524(P)(A), "ANF Critical Power Methodology for Boiling Water Reactors," Advanced Nuclear Fuels Corporation ANF-913(P)(A) Volume 1, "COTRANSA2: A Computer Program for Boiling Water Reactor Transient Analysis," Advanced Nuclear Fuels Corporation Columbia Generating 5.6-2 Amendment 225 Reporting Requirements 5.6 Reporting Requirements 5.6.3 CORE OPERATING LIMITS REPORT (COLR) (continued) ANF-1358(P)(A) "The Loss of Feedwater Heating Transient in Boiling Water Reactors," Advanced Nuclear Fuels Corporation EMF-2209(P)(A), "SPCB Critical Power Correlation," Siemens Power Corporation EMF-2245(P)(A), "Application of Siemens Power Corporation's Critical Power Correlations to Co-Resident Fuel," Siemens Power Corporation EMF-2361 (P)(A), "EXEM BWR-2000 ECCS Evaluation Model," Framatome ANP Richland EMF-2292(P)(A), ATRIUMŽ -10: Appendix K Spray Heat Transfer Coefficients," Siemens Power Corporation EMF-CC-074(P)(A) Volume 4, "BWR Stability Anaiysis-Assessment of STAIF with Input from MICROBURN-B2," Siemens Power Corporation CENPD-300-P-A, "Reference Safety Report for Boiling Water Reactor Reload Fuel," ABB Combustion Engineering Nuclear Operations NEDO-32465-A, "BWR Owners' Group Reactor Stability Detect and Suppress Solutions licenSing Basis Methodology and Reload Applications" NEDC-33419P, "GEXL97 Correlation Applicable to ATRIUM-10 Fuel," Global Nuclear Fuel NEDE-24011-P-A and NEDE-24011-P-A-US, "General Electric Standard Application for Reactor Fuel (GESTAR II) and Supplement for United States," Global Nuclear Fuel The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analYSis are met. The COLR, including any midcycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC. Columbia Generating 5.6-3 Amendment -1-9-0,2++ 225 5.6.4 Reporting Requirements 5.6 5.6 Reporting Requirements Post Accident Monitoring (PAM) Instrumentation Report When a report is required by Condition B or F of LCO 3.3.3.1, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status. Columbia Generating Station 5.6-4 Amendment 4-8a,+OO 225 5.7.1 High Radiation Area 5.7 ADMINISTRATIVE CONTROLS High Radiation Area As provided in paragraph 20.1601 (c) of 10 CFR Part 20, the following controls shall be applied to high radiation areas in place of the controls required by paragraph 20.1601 (a) and (b) of 10 CFR Part 20. High Radiation Areas with Dose Rates not Exceeding 1.0 rem/hour (at 30 centimeters from the radiation sources or from any surface penetrated by the radiation) Each entryway to such an area shall be barricaded and conspicuously posted as a high radiation area. Such barricades may be opened as necessary to permit entry or exit of personnel or equipment. Access to, and activities in, each such area shall be controlled by means of a Radiation Work Permit (RWP) or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures. Individuals qualified in radiation protection procedures and personnel continuously escorted by such individuals may be exempted from the requirement for an RWP or equivalent while performing their assigned duties provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas. Each individual or group entering such an area shall possess: A radiation monitoring device that continuously displays radiation dose rates in the area; or A radiation monitoring device that continuously integrates the radiation dose rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint; or A radiation monitoring device that continuously transmits dose rate and cumulative dose to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area; or A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel radiation exposure within the area, or Columbia Generating 5.7-1 Amendment 4-69,+82 225 High Radiation Area 5.7 High Radiation Area High Radiation Areas with Dose Rates not Exceeding 1.0 rem/hour (at 30 centimetersfrom the radiation sources or from any surface penetrated by the radiation) (continued) Be under the surveillance, as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with individuals in the area who are covered by such surveillance. Except for individuals qualified in radiation protection procedures, or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them. These continuously escorted personnel will receive a pre-job briefing prior to entry into such areas. This dose rate determination, knowledge, and pre-job briefing does not require documentation prior to initial entry. High Radiation Areas with Dose Rates Greater than 1.0 rem/hour (at 30 centimeters from the radiation sources or from any surface penetrated by the radiation), but less than 500 rads/hour (at 1 meter from the radiation sources or from any surface penetrated by the radiation) Each entryway to such an area shall be conspicuously posted as a high radiation area and shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry, and in addition: All such door and gate keys shall be maintained under the administrative control of the Shift Supervisor, Radiation Protection Manager, or his or her designee. Doors and gates shall remain locked except during periods of personnel or equipment entry or exit. Access to, and activities in, each such area shall be controlled by means of an RWP or equivalent that includes specification of radiation dose rates in the immediate work area(s) and other appropriate radiation protection equipment and measures. IndividualS qualified in radiation protection procedures may be exempted from the requirement for an RWP or equivalent while performing radiation surveys in such areas provided that they are otherwise following plant radiation protection procedures for entry to, exit from, and work in such areas. Columbia Generating 5.7-2 Amendment 225 High Radiation Area 5.7 High Radiation Area High Radiation Areas with Dose Rates Greater than 1.0 rem/hour (at 30 centimeters from the radiation sources or from any surface penetrated by the radiationl, but less than 500 rads/hour (at 1 meter from the radiation sources or from any surface penetrated by the radiationl (continued) d. Each individual or group entering such an area shall possess: A radiation monitoring device that continuously integrates the radiation rates in the area and alarms when the device's dose alarm setpoint is reached, with an appropriate alarm setpoint. or A radiation monitoring device that continuously transmits dose rate and cumulative dose to a remote receiver monitored by radiation protection personnel responsible for controlling personnel radiation exposure within the area with the means to communicate with and control every individual in the area, or A self-reading dosimeter (e.g., pocket ionization chamber or electronic dosimeter) and, Be under the surveillance, as specified in the RWP or equivalent, while in the area, of an individual qualified in radiation protection procedures, equipped with a radiation monitoring device that continuously displays radiation dose rates in the area; who is responsible for controlling personnel exposure within the area, or Be under the surveillance, as specified in the RWP or equivalent, while in the area, by means of closed circuit television, of personnel qualified in radiation protection procedures, responsible for controlling personnel radiation exposure in the area, and with the means to communicate with and control every individual in the area. In those cases where options 2. and 3., above are impractical or determined to be inconsistent with the "As Low As is Reasonably Achievable" principle, a radiation monitoring device that continuously displays radiation dose rates in the area. Except for individuals qualified in radiation protection procedures, or personnel continuously escorted by such individuals, entry into such areas shall be made only after dose rates in the area have been determined and entry personnel are knowledgeable of them. These continuously escorted personnel will receive a pre-job briefing prior to entry into such areas. This dose rate determination, knowledge, and pre-job briefing does not require documentation prior to initial entry. Columbia Generating 5.7-3 Amendment 225 High Radiation Area 5.7 High Radiation Area High Radiation Areas with Dose Rates Greater than 1.0 rem/hour (at 30 centimeters from the radiation sources or from any surface penetrated by the radiation), but less than 500 rads/hour (at 1 meter from the radiation sources or from any surface penetrated by the radiation) (continued) Such individual areas that are within a larger area where no enclosure exists for purpose of locking and where no enclosure can reasonably be constructed around the individual area need not be controlled by a locked door or gate, nor continuously guarded, but shall be barricaded, conspicuously posted, and a clearly visible flashing light shall be activated at the area as a warning device. Columbia Generating Station Amendment 4-69,+82 225 APPENDIX TO FACILITY OPERATING LICENSE NO. ENERGY COLUMBIA GENERATING DOCKET NO. ENVIRONMENTAL PROTECTION Amendment No. 157,169 225 ENERGY COLUMBIA GENERATING ENVIRONMENTAL PROTECTION TABLE OF Section 1.0 Objectives of the Environmental Protection Plan .......................................................... 2.0 Environmental Protection Issues ..................................................................................2.1 Aquatic Resources Issues ............................................................................................2.2 Terrestrial Resources Issues ........................................................................................3.0 Consistency Requirements ......................................................................................... 3.1 Plant Design and Operation ..........................................................................................3.2 Reporting Related to the NPDES Permit and State Certification ................................... 3.3 Changes Required for Compliance with Other Environmental Regulations ................... 4.0 Environmental Conditions .............................................................................................4.1 Unusual or Important Environmental Events ................................................................. 4.2 Environmental Monitoring .............................................................................................5.0 Administrative Procedures ...........................................................................................5.1 Review and Audit. .........................................................................................................5.2 Records Retention ........................................................................................................5.3 Changes in Environmental Protection Plan ..................................................................5.4 Plant Reporting Requirements ......................................................................................Amendment No. 157,169 225 Objectives of the Environmental Protection Plan The Environmental Protection Plan (EPP) is to provide for protection of nonradiological environmental values during operation of the Columbia Generating Station facility. The principal objectives of the EPP are as follows: Verity that the plant is operated in an environmentally acceptable manner, as established by the FES-OL and other NRC environmental impact assessments. Coordinate NRC requirements and maintain consistency with other Federal, State and local requirements for environmental protection. Keep NRC informed of the environmental effects of facility construction and operation and of actions taken to control those effects. Environmental concerns identified in the FES-OL which relate to water quality matters are regulated by way of the licensee's NPDES permit. Amendment No . .:t-e9 225 2.0 Environmental Protection Issues In the FES-OL dated December 1981, the staff considered the environmental impacts associated with the operation of Columbia Generating Station. Certain environmental issues were identified which required study or license conditions to resolve environmental concerns and to assure adequate protection of the environment. 2.1 Aquatic Resources Issues The one aquatic issue raised by the staff in the FES-OL was that the disposal of chlorinated effluents in the river could have significant impacts on Hanford Reach biota if chlorine content were not carefully controlled (Section 5.5.2.2). This matter is addressed by the NPDES permit issued by the State of Washington Energy Facility Site Evaluation Council (EFSEC). Also, in the FES-OL (Section 5.5.3.2), the staff acknowledged that entrainment and impingement studies might be performed in accordance with special conditions of the water withdrawal permit, issued by the U.S. Army Corps of Engineers. The NRC will rely on these agencies for regulation of matters involving water quality and aquatic biota. 2.2 Terrestrial Resources Issues There is uncertainty in predicting the potential impact of cooling tower drift on vegetation surrounding the site (FES Section 5.5.1.1). To resolve the uncertainty, the staff recommended a monitoring program to detect any effects of cooling tower drift on vegetation (FES Section 5.5.3.1 ). NRC requirements with regard to the terrestrial issues are specified in Subsection 4.2 of this EPP. 2-1 Amendment No. .:tOO 225 3.0 Consistency Requirements 3.1 Plant Design and Operation The licensee may make changes in station design or operation or perform tests or experiments affecting the environment provided such activities do not involve an unreviewed environmental question and do not involve a change in the EPP. Changes in plant design or operation or performance of tests or experiments which do not affect the environment are not subject to the requirements of this EPP. Activities governed by Section 3.3 are not subject to the requirements of this Section. Before engaging in unauthorized construction or operation activities which may significantly affect the environment, the licensee shall prepare and record an environmental evaluation of such activity. Activities are excluded from this requirement if all measurable nonradiological effects are confined to the on-site areas previously disturbed during site preparation and plant construction. When the evaluation indicates that such activity involves an unreviewed environmental question, the licensee shall provide a written evaluation of such activity and obtain prior NRC approval. When such activity involves a change in the EPP, such activity and change to the EPP may be implemented only in accordance with an appropriate license amendment as set forth in Section 5.3 of this EPP. A proposed change, test or experiment shall be deemed to involve an unreviewed environmental question if it concerns: (1) a matter which may result in a significant increase in any adverse environmental impact previously evaluated in the FES-OL, environmental impact appraisals, or in any decisions of the Atomic Safety and Licensing Board; or (2) a significant change in effluents or power level or (3) a matter, not previously reviewed and evaluated in the documents specified in (1) of this Subsection, which may have a significant adverse environmental impact. The licensee shall maintain records of changes in facility design or operation and of tests and experiments carried out pursuant to this Subsection. These records shall include written evaluations which provide bases for the determination that the change, test, or experiment does not involve an unreviewed environmental question or constitute a decrease in the effectiveness of this EPP to meet the objectives specified in Section 1.O. The licensee shall include as part of its Annual Environmental Operating Report (per Subsection 5.4.1) brief descriptions, analyses, interpretations, and evaluations of such changes, tests and experiments. 3-1 Amendment No. 225 3.2 Reporting Related to the NPDES Permit and State Certification Changes to, or renewals of, the NPDES Permit or the State certification shall be reported to the NRC within 30 days following the date the change or renewal is approved. If a permit or certification, in part or in its entirety, is appealed and stayed, the NRC shall be notified within 30 days following the date the stay is granted. The NRC shall be notified of changes to the effective NPDES Permit proposed by t.he licensee by providing NRC with a copy of the proposed change at the same time it is submitted to the permitting agency. The licensee shall provide the NRC a copy of the application for renewal of the NPDES Permit at the same time the application is submitted to the permitting agency. 3.3 Changes Required for Compliance with Other Environmental Regulations Changes in plant design or operation and performance of tests or experiments which are required to achieve compliance with other Federal, State, and local environmental regulations are not sUbject to the requirements of Section 3.1. 3-2 Amendment No. 225 4.0 Environmental Conditions 4.1 Unusual or Important Environmental Events Any occurrence of an unusual or important event that indicates or could result in significant environmental impact causally related to plant operation shall be recorded and reported to the NRC within 24 hours followed by a written report per Subsection 5.4.2. The following are examples: excessive bird impaction events, onsite plant or animal disease outbreaks, mortality or unusual occurrence of any species protected by the Endangered Species Act of 1973, fish kills, increase in nuisance organisms or conditions, and a significant, unanticipated or emergency discharge of waste water or chemical substances. No routine monitoring programs are required to implement this condition. 4.2 Environmental Monitoring 4.2.1 Cooling Tower Drift Study A terrestrial monitoring program shall be conducted to verify the level of effect from cooling tower drift. Soil and vegetation samples will be collected at locations subject to drift deposition and at control stations and analyzed for relevant chemical and physical parameters. Samples will be collected once per year during the seasonal peak of plant growth commencing no later than 18 months after issuance of a full power (100%) license. This program shall be terminated when data from three growing seasons after commencement of full power operation have been collected, provided the data support hypotheses of no adverse effects. Results and interpretation shall be included as part of the Annual Environmental Operating Report (Subsection 5.4.1). 4-1 Amendment No. 225 5.0 Administrative Procedures 5.1 Review and Audit The licensee shall provide for review and audit of compliance with the Environmental Protection Plan. The audits shall be conducted independently of the individual or groups responsible for performing the specific activity. A description of the organization structure utilized to achieve the independent review and audit function and results of the audit activities shall be maintained and made available for inspection. 5.2 Records Retention Records and logs relative to the environmental aspects of station operation shall be made and retained in a manner convenient for review and inspection. These records and logs shall be made available to NRC on request. Records of modifications to plant structures, systems and components determined to potentially affect the continued protection of the environment shall be retained for the life of the plant. All other records, data and logs relating to this EPP shall be retained for five years or, where applicable, in accordance with the requirements of other agencies. 5.3 Changes in Environmental Protection Plan Request for change in the Environmental Protection Plan shall include an assessment of the environmental impact of the proposed change and a supporting justification. Implementation of such changes in the EPP shall not commence prior to NRC approval of the proposed changes in the form of a license amendment incorporating the appropriate revision to the Environmental Protection Plan. 5-1 Amendment No. 225 Plant Reporting Requirements Routine Reports An Annual Environmental Operating Report describing implementation of this EPP for the previous year shall be submitted to the NRC prior to May 1 of each year. The initial report shall be submitted prior to May 1 of the year following issuance of the operating license. The period of the first report shall begin with the date of issuance of the operating license. The report shall include summaries and analyses of the results of the environmental protection activities required by Subsection 4.2 of this Environmental Protection Plan for the report period, including a comparison with and related preoperational studies, operational controls (as appropriate), and previous non-radiological environmental monitoring reports, and an assessment of the observed impacts of the plant operation on the environment. If harmful effects or evidence of trends toward irreversible damage to the environment are observed, the licensee shall provide a detailed analysis of the data and a proposed course of mitigating action. The Annual Environmental Operating Report shall also include: A list of EPP noncompliances and the corrective actions taken to remedy them. A list of all changes in station design or operation, tests, and experiments made in accordance with Subsection 3.1 which involved a potentially significant unreviewed environmental question. A list of nonroutine reports submitted in accordance with Subsection 5.4.2. A summary of NPDES permit related water quality reports sent to EFSEC during the report period. In the event that some results are not available by the report due date, the report shall be submitted noting and explaining the missing results. The missing results shall be submitted as soon as possible in a supplementary report. Amendment No. 225 5.4.2 Nonroutine Reports A written report shall be submitted to the NRC within 30 days of occurrence of a nonroutine event. The report shall (a) describe. analyze, and evaluate the event, including extent and magnitude of the impact and plant operating characteristics, (b) describe the probable cause of the event. (c) indicate the action taken to correct the reported event, (d) indicate the corrective action taken to preclude repetition of the event and to prevent similar occurrences involving similar components or systems, and (e) indicate the agencies notified and their preliminary responses. Events reportable under this subsection which also require reports to other Federal. State or local agencies shall be reported in accordance with those reporting requirements in lieu of the requirements of this subsection. The NRC shall be provided a copy of such report at the same time it is submitted to the other agency. This subsection does not apply to nonradiological water quality matters within the scope of the NPDES permit. 5-3 Amendment No. 225 APPENDIX Amendment No. 157,223225 UNITED NUCLEAR REGULATORY WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 225 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-21 ENERGY NORTHWEST COLUMBIA GENERATING STATION DOCKET NO. 50-397 1.0 INTRODUCTION By application to the U.S. Nuclear Regulatory Commission (NRC) dated January 9,2012 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML 12023A026) as supplemented by letters dated July 30 and November 14,2012 (ADAMS Accession Nos. ML 12220A548 and ML 12334A379, respectively), Energy Northwest (the licensee), requested an amendment to the Facility Operating License and Technical Specifications (TSs) for Columbia Generating Station (Columbia). The supplemental letters dated July 30 and November 14, 2012, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the NRC staff's original proposed no significant hazards consideration determination as published in the Federal Register on July 24,2012 (77 FR 43374). The proposed amendment implements formatting changes to the Operating License and TSs resulting from a change in the word proceSSing programs and the adoption of TSTF-GG-05-01, "Writers Guide for Plant-Specific Improved Technical Specifications," Revision 1. In addition to these administrative changes, the amendment implements editorial changes which do not result in any changes to the technical or operating requirements. 2.0 REGULATORY EVALUATION Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include TSs as part of the license. The NRC's regulatory requirements related to the content of the TSs are contained in Title 10 of the Code of Federal Regulations (10 CFR), Section 50.36, "Technical specifications." The TS requirements in 10 CFR 50.36 include the following categories: (1) safety limits, limiting safety systems settings and control settings, (2) limiting conditions for operation (LCOs), (3) surveillance requirements (SRs), (4) design features, (5) administrative controls, (6) decommissioning, (7) initial notification, and (8) written reports. Enclosure 2
-3.0 TECHNICAL EVALUATION 3.1 Global Administrative Changes 3.1.1 Use of "(Continued)" The licensee is proposing to restrict the use of the identifier "(continued)" to those instances when an LCO, Applicability, Required Action, or SR is split across pages. The placement of the identifier would be dependent upon the information being continued as noted in the licensee's response to the request for additional information. This change is administrative. 3.1.2 New Software The licensee is proposing to use new software for revising their TS and Operating License. The change will result in formatting changes to include font size, relocation or addition of page breaks, section and table pages to be re-numbered and information moved from one page to another. This change is administrative. 3.1.3 Removal of Amendment Numbers The licensee is proposing to remove all but the previous two revision numbers and to remove commas between amendment numbers. This change is administrative. In the supplement dated November 14, 2012, the licensee withdrew the request to remove revision bars from the footer. 3.2 Editorial Changes 3.2.1 TS 1.4 Freguency, Example 1.4-6 The licensee is proposing to correct the misspelling of the word "again." It is incorrectly written as "agin." This is an editorial change. 3.2.2 TS Table 3.1.4-1 and Figure 4.1-1 As the licensee stated in the January 9, 2012, submittal: "Page identifiers '(page x of y)' are missing. These identifiers are added to conform to the guidance of TSTF-GG-05-01 Sections 2.1.7.e and 2.1.B.c." This is an editorial change. 3.2.3 TS LCO 3.3.2.1, Reguired Action D.1 As the licensee stated in the January 9, 2012, submittal: "The's' in SPWs should be capitalized and appear as 'SPWS.' LCO 3.1.6 defines the acronym 'banked position withdrawal sequence (SPWS).' This typographical error is corrected." This is an editorial change. 3.2.4 TS LCO 3.3.4.1 As the licensee stated in the January 9,2012, submittal: "The Frequency for both SR 3.3.4.1.2.a and 3.3.4.1.2.b is misaligned at the bottom (lined up with the setpoint not the surveillance). The -alignment is corrected to conform to the guidance in TSTF-GG-05-01 Section 2.5.[6].dA." This is an editorial change. 3.2.5 TS Table 3.3.5.2-1 The licensee is proposing to add the header that is missing on page 3.3.5.2-4 in order to conform to the guidance in TSTF-GG-05-01 Section 2.1.2.e. This is an editorial change. 3.2.6 TS SR 3.6.1.7.1 As the licensee stated in the January 9,2012, submittal: Footnote 1 provides an allowance for SR 3.6.1.7.1 to not be met until startup from refueling outage R-18. Startup from this refueling outage occurred in 2007. Therefore, there is no further need for this footnote. This footnote is removed as it serves no purpose and the formatting does not comply with the guidance in TSTF-GG-05-01 Section 2.1.9.a. This is an editorial change. 3.2.7 TS LCO 3.6.3.1 As the licensee stated in the January 9, 2012, submittal: Pages 3.6.3.1-1 and 3.6.3.1-2 are removed. The Table of Contents (TOC) identifies TS 3.6.3.1 as "Deleted." The LCO was removed in Amendment 189. However, pages 3.6.3.1-1 and 3.6.3.1-2 remained in the body of TS, and the physical pages should be removed as they serve no purpose. This is an editorial change. 3.2.8 TS SRs 3.8.1.8,3.8.1.11,3.8.1.12,3.8.1.16,3.8.1.18, and 3.8.1.19 As the licensee stated in the January 9, 2012, submittal: In the Note for each SR, the word surveillance is in lower case "s." The "S" should be capitalized as the term refers to a specific surveillance to conform to the guidance in TSTF-GG-05-01 Section 3.3.2.d.8. This formatting error is corrected. This is an editorial change. 3.2.9 TS LCO 3.8.2 The licensee is proposing to revise the word "subsystem9s0" to "subsystem(s)" to correct a typographical error. This is an editorial change. -3.2.10 TS LCO 3.8.2, ACTION B The licensee is proposing to underline the logical connector in order to conform to the guidance in TSTF-GG-05-01 Section 2.1.5.a. This is an editorial change. 3.2.11 TS SR 3.8.2.1 The licensee is proposing to correct a missing period at the end of the sentence in the Surveillance. This is an editorial change. 3.2.12 TS SRs 3.8.3.1 and 3.8.3.2 As the licensee stated in the January 9, 2012, submittal: The text .. a 7" should be restated to "greater than or equal to a seven." This formatting error is corrected to conform to the guidance in TSTF-GG-05-01 Section 3.3.3.a. This is an editorial change. 3.2.13 TS LCO 3.8.6, ACTION F As the licensee stated in the January 9, 2012, submittal: The words Battery and Parameter should not be capitalized. This formatting error is corrected to conform to the guidance in TSTF-GG-05-01 Section 3.3.2. This is an editorial change. 3.2.14 TS SR 3.9.10.1 The licensee is proposing to correct the misspelling of "reactor" as "rector." This is an editorial change. 3.2.15 TS 5.3.2 As the licensee stated in the January 9, 2012, submittal: The acronym for Senior Reactor Operator was already defined in Specification 5.3.1 and does not need to be repeated in 5.3.2. This formatting error corrected to conform to the guidance in TSTF-GG-05-01 Section This is an editorial change. -3.2.16 TS 5.3.2 As the licensee stated in the January 9,2012, submittal: The acronym "TS" is not defined in Section 5.3 and is not standard usage. This acronym is replaced with the word "Specification" to conform to standard language in other places in Chapter 5. This is an editorial change. 3.2.17 TS 5.7.1.e and 5.7.2.e As the licensee stated in the January 9, 2012, submittal: The final sentence in both specifications contains a typographical error in that the word "dose" in the following sentence "and pre-job briefing dose not require documentation." should be replaced with the word "does". This error is corrected. This is an editorial change. 3.2.18 TS 5.7.2 As the licensee stated in the January 9,2012, submittal: The phrase "radiation source" in the title should be plural to conform to the language in TS 5.7.1. This formatting error is corrected. This is an editorial change. 3.3 Conclusion The NRC staff concludes that the global administrative changes and editorial changes are acceptable. 4.0 STATE CONSULTATION In accordance with the Commission's regulations, the Washington State official was notified of the proposed issuance of the amendment. The State official had no comments. 5.0 ENVIRONMENTAL CONSIDERATION The amendment changes a requirement with respect to the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendment involves no significant hazards consideration and there has been no public comment on such finding -published in the Federal Register on July 24,2012 (77 FR 43374). Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment. 6.0 CONCLUSION The Commission has concluded, based on the descriptions and changes discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that 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. Principal Contributor: S. Anderson Date: January 29. 2013 M. Reddemann -A copy of the related Safety Evaluation is also enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice. Sincerely, IRAJ Lauren K. Gibson, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-397 Enclosures: 1. Amendment No. 225 to NPF-21 2. Safety Evaluation cc w/encls: Distribution via Listserv DISTRIBUTION: PUBLIC LPLIV Reading RidsAcrsAcnw _MailCTR Resource RidsNrrDorlDpr Resource RidsNrrDorlLpl4 Resource RidsNrrDssStsb Resource RidsNrrLAJBurkhardt Resource RidsNrrPMColumbia Resource RidsOgcRp Resource RidsRgn4MailCenter Resource SAnderson, NRR/DSS/STSB ADAMS Accession No.: ML12269A254 *SE memo dated September 14,2012 ::OFFICE NAME .DATE OFFICE IINAME DATE NRRIDORLlLPL4/PM JRankin 1/8/13 OGC-NLO LSubin 1/14/13 NRR/DORLlLPL4/PM LGibson 1/8/13 NRRIDORLlLPL4/BC MMarkley 1/25/13 NRR/DORLlLPL4/LA JBurkhardt 1/8/13 NRR/DORLlLPL4/PM LGibson 1/29/13 NRR/DSS/STSB/BC RElliott* 9/14/12 i ! I I: ! il OFFICIAL RECORD COpy }}