ML20302A302
| ML20302A302 | |
| Person / Time | |
|---|---|
| Site: | Davis Besse  |
| Issue date: | 09/25/2020 |
| From: | Energy Harbor Nuclear Corp |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML20302A348 | List:
|
| References | |
| L-20-234 | |
| Download: ML20302A302 (151) | |
Text
Davis-Besse Technical Requirements Manual
6.0 INTRODUCTION
7.0 USE AND APPLICATION 7.1 Definitions 7.2 Logical Connectors/Restoration Times 7.3 Failure to Meet a Technical Normal Condition (TNC) or Technical Verification Requirement (TVR) 7.4 Frequency 8.1 REACTIVITY CONTROL SYSTEMS 8.1.1 Boration Systems Operating 8.1.2 Boration Systems Shutdown 8.1.3 Rod Program 8.2 Not Used 8.3 INSTRUMENTATION 8.3.1 Reactor Protection System Instrumentation Parameters 8.3.2 Incore Detectors 8.3.3 Seismic Instrumentation 8.3.4 Meteorological Instrumentation 8.3.5 Safety Features Actuation System Response Times 8.3.6 Waste Gas System Oxygen Monitoring 8.3.7 Post Accident Monitoring (PAM)
Instrumentation 8.3.8 EDG Loss of Power Start 8.3.9 Not Used 8.3.10 Source and Intermediate Range Overlap 8.3.11 Steam and Feedwater Rupture Control System Instrumentation Parameters 8.3.12 Ultrasonic Flow Meter Instrumentation 8.4 REACTOR COOLANT SYSTEM (RCS) 8.4.1 Chemistry 8.4.2 Pressurizer 8.4.3 Pressurizer Heater Interlock 8.4.4 Reactor Coolant System Vents 8.4.5 Pilot Operated Relief Valve (PORV) 8.4.6 ASME Code class 1, 2, and 3 Components 8.5 EMERGENCY CORE COOLING SYSTEM (ECCS) 8.5.1 ECCS Subsystems - Operating 8.5.2 ECCS Subsystems - Shutdown 8.5.3 Emergency Sump Debris 8.6 CONTAINMENT SYSTEMS 8.6.1 Combustible Gas Control - Hydrogen Analyzers 8.7 PLANT SYSTEMS 8.7.1 Steam Generator Pressure/Temperature Limitation 8.7.2 Sealed Source Contamination 8.7.3 Snubbers 8.7.4 Liquid Storage Tanks 8.7.5 Explosive Gas Mixture 8.7.6 Auxiliary Feedwater System 8.7.7 Motor Driven Feedwater Pump Lube Oil Interlocks 8.8 ELECTRICAL SYSTEMS 8.8.1. AC Sources - Operating 8.8.2 SBODG Availability 8.9 REFUELING OPERATIONS 8.9.1 Communications 8.9.2 Crane Travel - Fuel Handling Building 8.9.3 Spent Fuel Assembly Storage 8.9.4 Fuel Handling Bridge 9.0 Not Used ADMINISTRATIVE CONTROLS 10.1 Not Used 10.2 ORGANIZATION 10.2.1 Facility Staff 10.3 Not Used 10.4 PROCEDURES 10.4.1 Process Control Program Procedures 10.5 PROGRAMS AND MANUALS 10.5.1 Process Control Program (PCP) Changes 10.5.2 In-Plant Rad Monitoring 10.6 REPORTING REQUIREMENTS 10.6.1 Annual Radiological Environmental Operating Report 10.6.2 Radioactive Effluent Release Report 10.6.3 Core Operating Limits Report (COLR) 10.6.4 Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR) 10.6.5 Post Accident Monitoring Report 10.6.6 Steam Generator Tube Inspection Report 10.6.7 Remote Shutdown System Report Appendix A - Access Openings Required to be Closed to Ensure Shield Building Integrity
DAVIS-BESSE NUCLEAR POWER STATION NUMBER 1 a-1 Revision 21 PAGE/REVISION INDEX - TECHNICAL REQUIREMENTS MANUAL Page Rev.
No.
Date of Revision Page Rev.
No.
Date of Revision a-1 21 01/10/20 8.3.5-4 3
08/12/09 a-2 21 01/10/20 8.3.5-5 3
08/12/09 TOC-i 7
10/14/10 8.3.5-6 3
08/12/09 TOC-ii 7
10/14/10 8.3.5-7 3
08/12/09 TOC-iii 7
10/14/10 8.3.5-8 3
08/12/09 6.0-1 0
12/13/08 B 8.3.5-1 0
12/13/08 6.0-2 0
12/13/08 8.3.6-1 0
12/13/08 7.1-1 0
12/13/08 8.3.6-2 0
12/13/08 7.2-1 7
10/14/10 B 8.3.6-1 0
12/13/08 7.3-1 21 01/10/20 8.3.7-1 7
10/14/10 7.4-1 0
12/13/08 8.3.7-2 7
10/14/10 8.1.1-1 7
10/14/10 B 8.3.7-1 0
12/13/08 8.1.1-2 7
10/14/10 8.3.8-1 3
08/12/09 8.1.1-3 7
10/14/10 8.3.8-2 3
08/12/09 8.1.1-4 7
10/14/10 B 8.3.8-1 0
12/13/08 B 8.1.1-1 9
09/07/11 8.3.10-1 1
12/13/08 8.1.2-1 3
08/12/09 B 8.3.10-1 1
12/13/08 8.1.2-2 3
08/12/09 8.3.11-1 3
08/12/09 8.1.2-3 3
08/12/09 8.3.11-2 3
08/12/09 B 8.1.2-1 9
09/07/11 8.3.11-3 3
08/12/09 8.1.3-1 17 04/15/16 B 8.3.11-1 0
12/13/08 8.1.3-2 17 04/15/16 8.3.12-1 0
12/13/08 B 8.1.3-1 1
12/13/08 B 8.3.12-1 0
12/13/08 8.3.1-1 3
08/12/09 8.4.1-1 13 06/14/13 8.3.1-2 3
08/12/09 8.4.1-2 13 06/14/13 8.3.1-3 3
08/12/09 8.4.1-3 13 06/14/13 B 8.3.1-1 0
12/13/08 8.4.1-4 13 06/14/13 8.3.2-1 0
12/13/08 B 8.4.1-1 0
12/13/08 8.3.2-2 0
12/13/08 8.4.2-1 0
12/13/08 B 8.3.2-1 0
12/13/08 8.4.2-2 0
12/13/08 8.3.3-1 16 04/13/16 B 8.4.2-1 0
12/13/08 8.3.3-2 16 04/13/16 8.4.3-1 0
12/13/08 8.3.3-3 16 04/13/16 8.4.3-2 0
12/13/08 8.3.3-4 16 04/13/16 B 8.4.3-1 0
12/13/08 B 8.3.3-1 16 04/13/16 8.4.4-1 7
10/14/10 8.3.4-1 4
09/14/09 8.4.4-2 7
10/14/10 8.3.4-2 4
09/14/09 B 8.4.4-1 0
12/13/08 8.3.4-3 4
09/14/09 8.4.5-1 6
07/14/10 B 8.3.4-1 4
09/14/09 8.4.5-2 6
07/14/10 8.3.5-1 3
08/12/09 B 8.4.5-1 0
12/13/08 8.3.5-2 3
08/12/09 8.4.6-1 19 10/03/18 8.3.5-3 3
08/12/09 8.4.6-2 19 10/03/18
DAVIS-BESSE NUCLEAR POWER STATION NUMBER 1 a-2 Revision 21 PAGE/REVISION INDEX - TECHNICAL REQUIREMENTS MANUAL Page Rev.
No.
Date of Revision Page Rev.
No.
Date of Revision B 8.4.6-1 19 10/03/18 8.8.2-2 7
10/14/10 8.5.1-1 0
12/13/08 B 8.8.2-1 0
12/13/08 8.5.1-2 0
12/13/08 8.9.1-1 0
12/13/08 B 8.5.1-1 0
12/13/08 B 8.9.1-1 0
12/13/08 8.5.2-1 1
12/13/08 8.9.2-1 18 07/07/17 8.5.2-2 1
12/13/08 B 8.9.2-1 18 07/07/17 B 8.5.2-1 0
12/13/08 8.9.3-1 7
10/14/10 8.5.3-1 5
03/30/10 8.9.3-2 7
10/14/10 B 8.5.3-1 5
03/30/10 B 8.9.3-1 0
12/13/08 8.6.1-1 0
12/13/08 8.9.4-1 0
12/13/08 8.6.1-2 0
12/13/08 8.9.4-2 0
12/13/08 B 8.6.1-1 0
12/13/08 B 8.9.4-1 0
12/13/08 8.7.1-1 0
12/13/08 10.2.1-1 11 12/21/12 B 8.7.1-1 0
12/13/08 10.4.1-1 5
03/30/10 8.7.2-1 21 01/10/20 10.5.1-1 5
03/30/10 8.7.2-2 21 01/10/20 10.5.2-1 5
03/30/10 B 8.7.2-1 21 01/10/20 10.6-1 5
03/30/10 8.7.3-1 15 12/16/15 10.6.1-1 5
03/30/10 8.7.3-2 15 12/16/15 10.6.2-1 5
03/30/10 8.7.3-3 15 12/16/15 10.6.3-1 5
03/30/10 8.7.3-4 15 12/16/15 10.6.4-1 5
03/30/10 8.7.3-5 15 12/16/15 10.6.5-1 5
03/30/10 8.7.3-6 15 12/16/15 10.6.6-1 5
03/30/10 B 8.7.3-1 15 12/16/15 10.6.7-1 5
03/30/10 B 8.7.3-2 15 12/16/15 A-1 0
12/13/08 8.7.4-1 0
12/13/08 8.7.4-2 0
12/13/08 B 8.7.4-1 0
12/13/08 8.7.5-1 0
12/13/08 8.7.5-2 0
12/13/08 B 8.7.5-1 0
12/13/08 8.7.6-1 8
05/05/11 8.7.6-2 8
05/05/11 B 8.7.6-1 7
10/14/10 8.7.7-1 0
12/13/08 B 8.7.7-1 0
12/13/08 8.8.1-1 20 09/13/19 8.8.1-2 20 09/13/19 B 8.8.1-1 20 09/13/19 8.8.2-1 7
10/14/10
TABLE OF CONTENTS TECHNICAL REQUIREMENTS MANUAL DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 TOC-i Revision 7
6.0 INTRODUCTION
7.0 USE AND APPLICATION....................................................................................
7.1 Definitions................................................................................................. 7.1-1 7.2 Logical Connectors/Restoration Times..................................................... 7.2-1 7.3 Failure to Meet a Technical Normal Condition (TNC) or Technical Verification Requirement (TVR)............................................... 7.3-1 7.4 Frequency................................................................................................ 7.4-1 TECHNICAL NORMAL CONDITIONS (TNC) and TECHNICAL VERIFICATION REQUIREMENTS (TVR).................................................................................................
8.1 REACTIVITY CONTROL SYSTEMS 8.1.1 Borated Water Sources Operating........................................... 8.1.1-1 8.1.2 Borated Water Sources Shutdown........................................... 8.1.2-1 8.1.3 Rod Program............................................................................... 8.1.3.1 8.2 Not Used 8.3 INSTRUMENTATION 8.3.1 Reactor Protection System Instrumentation Parameters.............. 8.3.1-1 8.3.2 Incore Detectors........................................................................... 8.3.2-1 8.3.3 Seismic Instrumentation............................................................... 8.3.3-1 8.3.4 Meteorological Instrumentation..................................................... 8.3.4-1 8.3.5 Safety Features Actuation System Response Times................... 8.3.5-1 8.3.6 Waste Gas System Oxygen Monitoring........................................ 8.3.6-1 8.3.7 Post Accident Monitoring (PAM) Instrumentation........................ 8.3.7-1 8.3.8 EDG Loss of Power Start.............................................................. 8.3.8-1 8.3.9 Not Used 8.3.10 Source and Intermediate Range Overlap..................................... 8.3.10-1 8.3.11 Steam and Feedwater Rupture Control System Instrumentation Parameters.................................................................................. 8.3.11-1 8.3.12 Ultrasonic Flow Meter Instrumentation........................................ 8.3.12-1 8.4 REACTOR COOLANT SYSTEM (RCS) 8.4.1 Chemistry...................................................................................... 8.4.1-1 8.4.2 Pressurizer.................................................................................... 8.4.2-1 8.4.3 Pressurizer Heater Interlock........................................................ 8.4.3-1 8.4.4 Reactor Coolant System Vents..................................................... 8.4.4-1 8.4.5 Pilot Operated Relief Valve (PORV)............................................ 8.4.5-1 8.4.6 ASME Code class 1, 2, and 3 Components................................ 8.4.5-1
TABLE OF CONTENTS TECHNICAL REQUIREMENTS MANUAL DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 TOC-ii Revision 7 8.5 EMERGENCY CORE COOLING SYSTEM (ECCS) 8.5.1 ECCS Subsystems - Operating................................................... 8.5.1-1 8.5.2 ECCS Subsystems - Shutdown................................................... 8.5.2-1 8.5.3 Emergency Sump Debris............................................................. 8.5.3-1 8.6 CONTAINMENT SYSTEMS 8.6.1 Combustible Gas Control - Hydrogen Analyzers......................... 8.6.1-1 8.7 PLANT SYSTEMS 8.7.1 Steam Generator Pressure/Temperature Limitation.................... 8.7.1-1 8.7.2 Sealed Source Contamination..................................................... 8.7.2-1 8.7.3 Snubbers..................................................................................... 8.7.3-1 8.7.4 Liquid Storage Tanks................................................................... 8.7.4-1 8.7.5 Explosive Gas Mixture................................................................. 8.7.5-1 8.7.6 Auxiliary Feedwater System........................................................ 8.7.6-1 8.7.7 Motor Driven Feedwater Pump Lube Oil Interlocks..................... 8.7.7-1 8.8 ELECTRICAL SYSTEMS 8.8.1.
AC Sources - Operating............................................................. 8.8.1-1 8.8.2 SBODG Availability....................................................................... 8.8.2-1 8.9 REFUELING OPERATIONS 8.9.1 Communications........................................................................... 8.9.1-1 8.9.2 Crane Travel - Fuel Handling Building......................................... 8.9.2-1 8.9.3 Spent Fuel Assembly Storage...................................................... 8.9.3-1 8.9.4 Fuel Handling Bridge................................................................... 8.9.4-1 9.0 Not Used ADMINISTRATIVE CONTROLS 10.1 Not Used 10.2 ORGANIZATION 10.2.1 Facility Staff................................................................................. 10.2.1-1 10.3 Not Used 10.4 PROCEDURES 10.4.1 Process Control Program Procedures.......................................... 10.4.1-1
TABLE OF CONTENTS TECHNICAL REQUIREMENTS MANUAL DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 TOC-iii Revision 7 10.5 PROGRAMS AND MANUALS 10.5.1 Process Control Program (PCP) Changes................................... 10.5.1-1 10.5.2 In-Plant Rad Monitoring............................................................... 10.5.2-1 10.6 REPORTING REQUIREMENTS 10.6.1 Annual Radiological Environmental Operating Report................. 10.6.1-1 10.6.2 Radioactive Effluent Release Report........................................... 10.6.2-1 10.6.3 Core Operating Limits Report (COLR).......................................... 10.6.3-1 10.6.4 Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR)................................................................... 10.6.4-1 10.6.5 Post Accident Monitoring Report................................................. 10.6.5-1 10.6.6 Steam Generator Tube Inspection Report................................... 10.6.6-1 10.6.7 Remote Shutdown System Report.............................................. 10.6.7-1 Appendix A Access Openings Required to be Closed to Ensure Shield Building Integrity............................................................... A-1
TRM INTRODUCTION TRM 6.0 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 6.0-1 Revision 0
6.0 INTRODUCTION
6.1 BACKGROUND
Based on the NRC's Final Policy Statement on Technical Specification Improvements for nuclear power plants, and 10 CFR 50.36, "Technical Specifications, " as amended in the Final Rule published in the Federal Register dated July 13, 1995, certain requirements may be relocated from the Operating License Technical Specifications to other licensee-controlled documents. In an effort to centralize the requirements relocated from the Technical Specifications and to ensure the necessary administrative controls are applied to these requirements, these requirements have been relocated as "Technical Requirements" into the Davis-Besse Technical Requirements Manual (TRM).
The TRM provides one location for relocated items in a consistent format. The Technical Requirements are formatted in a manner consistent with NRC Regulatory Issue Summary 2005-20: Revision To Guidance Formerly Contained in NRC Generic Letter 91-18, Information to Licensees Regarding Two NRC Inspection Manual Sections On Resolution of Degraded and Nonconforming Conditions and on Operability. Although many of the terms defined in the Technical Specifications apply within the TRM, the TRM contains additional Definitions which are specific to the TRM and not defined in the Technical Specification Definitions.
6.2 REGULATORY STATUS/REQUIREMENTS The requirements in the TRM are part of the licensing basis for the Davis-Besse Nuclear Power Station. Furthermore, the TRM is incorporated by reference in the Updated Safety Analysis Report (USAR) and is considered to be part of the USAR. Violations of the TRM requirements should be documented by the corrective action process. Deviations from the TRM will be screened for reportability in accordance with the corrective action process.
These controls are in place because the purpose of relocating the requirements for Technical Specifications is not to reduce the level of control on the items, but to provide flexibility for change under 10 CFR 50.59, Changes, Tests and Experiments.
Technical Requirements Manual Section 10.6, Reporting Requirements has been developed to provide a central location for various Technical Specification reports. These reports are not controlled or revised under the change process for the Technical Requirements Manual. The reports contained in Section 10.6 are revised and issued as required by Technical Specification Section 5.6.
6.3 CHANGES TO THE TRM Design modifications, procedure changes, license amendments, etc. have the potential to affect the TRM. If this occurs, the initiating department must follow the administrative controls in NOP-LP-4008, "Licensing Documents Change Process." This program requires that the TRM's Technical Requirements be considered in a manner similar to the USAR when evaluating changes. Changes to the TRM will be reported, as a minimum, to the NRC as part of the USAR update submittal in accordance with 10 CFR 50.71(e). Related 10 CFR 50.59 evaluations will be reported as part of the 10 CFR 50.59(d) report to the NRC.
TRM INTRODUCTION TRM 6.0 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 6.0-2 Revision 0 6.4 TECHNICAL VERIFICATION REQUIREMENTS Each Verification Requirement shall be performed within the specified time interval with a maximum allowable extension not to exceed 25% of the specified Technical Verification Requirement interval.
The provisions of this requirement provide allowable tolerances for performing technical verification activities beyond those specified in the nominal Technical Verification Requirement interval. These tolerances are necessary to provide operational flexibility because of scheduling and performance considerations. The phrase "at least" associated with a Technical Verification Requirement frequency does not negate this allowable tolerance value and permits the performance of more frequent verification activities.
The allowable tolerance for performing verification activities is sufficiently restrictive to ensure that the reliability associated with the verification activity is not significantly degraded beyond that obtained from the nominal specified interval. It is not intended that the allowable tolerance be used as a convenience to repeatedly schedule the performance of verification requirements at the allowable tolerance limit.
The allowable tolerance for performing verification activities also provides flexibility to accommodate the length of a fuel cycle for Technical Verification Requirements that are specified to be performed at least once each 24 Months. It is the intent that 24 Month verification requirements be performed in a MODE consistent with safe plant operation.
Definitions TRM 7.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 7.1-1 Revision 0 7.0 USE AND APPLICATION 7.1 Definitions
NOTES-----------------------------------------------------------
- 1.
Definitions are defined in Section 1.1 of the Technical Specifications and are applicable throughout the Technical Requirements Manual (TRM) and Bases. Only definitions specific to the TRM will be defined in this section.
- 2.
The defined terms of this section and the Technical Specifications (TS) appear in capitalized type and are applicable throughout the TRM and the TRM Bases.
- 3.
When a term is defined in both the TS and the TRM, TRM definition takes precedence within the TRM and the TRM Bases.
Term Definition FUNCTIONAL A structure, system or component (SSC), shall be FUNCTIONALITY FUNCTIONAL or have FUNCTIONALITY when it is capable of performing its specified function(s) as set forth in the Current License Basis. FUNCTIONALITY does not apply to specified safety functions, but does apply to the ability of non-TS SSCs to perform other specified functions that have a necessary support function.
TECHNICAL NORMAL Specify minimum requirements for ensuring safe operation of CONDITIONS (TNC) the Unit. The Contingency Measures associated with a TNC state Nonconformances that typically describe the ways in which the requirements of the TNC can fail to be met.
Specified with each stated Nonconformance are Contingency Measures and Restoration Time(s).
Logical Connectors/Restoration Times TRM 7.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 7.2-1 Revision 7 7.0 USE AND APPLICATION 7.2 Logical Connectors/Restoration Times Logical Connectors are discussed in Section 1.2 of the Technical Specifications and are applicable throughout the Technical Requirements Manual and Bases.
Completion Times are discussed in Section 1.3 of the Technical Specifications and are applicable throughout the Technical Requirements Manual and Bases. Completion Times in the Technical Specifications are equivalent to Restoration Times in the Technical Requirements Manual.
When "Immediately" is used as a Restoration Time, the Contingency Measure should be pursued without delay in a controlled manner.
Failure to Meet TNC or TVR TRM 7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 7.3-1 Revision 21 7.0 USE AND APPLICATION 7.3 Failure to Meet a Technical Normal Condition (TNC) or Technical Verification Requirement (TVR).
When a TNC and the associated Contingency Measures are not met, an associated Contingency Measure is not provided, or if directed by the associated Contingency Measures, action shall be initiated immediately to communicate the situation to the Shift Manager and document the condition in accordance with the company corrective action program. The safety significance of the condition shall be evaluated per NOP-OP-1009 Operability Determinations and Functionality Assessments and appropriate corrective actions initiated, within the time frame determined by the Shift Manager that shall not exceed 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> from the time of entry into TRM 7.3. The time frame for completion of the corrective actions shall be commensurate with the safety significance of the condition, consistent with the guidance of NOP-OP-1009.
Where corrective measures are completed that permit operation in accordance with the TNC or Contingency Measures, completion of the actions required by TRM 7.3 is not required.
When it is discovered that a TVR frequency (including the 1.25 times extension) has not been met, the equipment subject to the TVR is in a nonconforming condition. In this situation, a Condition Report shall be initiated and, if indicated, determination to evaluate the impact on plant safety shall be performed in a timely fashion and in accordance with plant procedures.
Actions should be taken to restore conformance with the TNCs / TVRs in a timely fashion.
If equipment has been removed from service or declared nonfunctional, it may be returned to service under administrative control to perform testing required to demonstrate its functionality.
Frequency TRM 7.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 7.4-1 Revision 0 7.0 USE AND APPLICATION 7.4 Frequency Frequency is discussed in Section 1.4 of the Technical Specifications and is applicable throughout the Technical Requirements Manual and Bases, with the exception that Technical Verification Requirements are used in the place of Surveillance Requirements.
Boration Systems - Operating TRM 8.1.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.1-1 Revision 7 8.1 REACTIVITY CONTROL SYSTEMS 8.1.1 Boration Systems - Operating TECHNICAL NORMAL CONDITIONS TNC 8.1.1 The Boration Systems shall be FUNCTIONAL consisting of the following:
- a.
A flow path from the concentrated FUNCTIONAL boric acid addition system (BAAS) via a FUNCTIONAL boric acid pump and a FUNCTIONAL makeup pump to the Reactor Coolant System (RCS);
AND
- b.
A flow path from the OPERABLE borated water storage tank via a FUNCTIONAL makeup pump to the RCS System.
NOTES-------------------------------------------------
Separate Makeup pumps are required to be FUNCTIONAL in MODES 1, 2 and 3, and in MODE 4 when RCS pressure is 150 psig.
A FUNCTIONAL decay heat removal (DHR) pump may be used in place of a makeup pump in MODE 4 when RCS pressure is < 150 psig.
APPLICABILITY:
MODES 1, 2, 3, and 4.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A One Boron System flow path Nonfunctional.
A.1 Restore the nonfunctional flow path to FUNCTIONAL status.
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B. Contingency Measures and associated Restoration Time of Nonconformance A not met.
B.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately
Boration Systems - Operating TRM 8.1.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.1-2 Revision 7 CONTINGENCY MEASURES (continued)
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME C. The boron injection flow path from the borated water storage tank is Nonfunctional.
C.1 Restore the nonfunctional flow path to FUNCTIONAL status.
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> D. Contingency Measures and associated Restoration Time of Nonconformance C not met.
D.1 Be in MODE 3 AND D.2 Be in MODE 5 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 36 hours
Boration Systems - Operating TRM 8.1.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.1-3 Revision 7 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.1.1.1 Verify BAAS solution temperature is > 105F.
7 days 8.1.1.2
NOTE------------------------------------
If the 7 day verification falls during transfers of makeup water or dilute boron solutions (fluid source concentration of less than 5000 ppmB), the verification period may be extended up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the addition of dilute boron solution has been stopped for a period of at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
Verify the pipe temperature of the heat traced portion of the boron injection flow path from the concentrated boric acid storage system is 105°F.
7 days 8.1.1.3 Verify borated water volume of BAAS is in accordance with TRM Figure 8.1.1-1.
31 days 8.1.1.4 Verify the boron concentration in BAAS is > 7,875 ppm and < 13,125 ppm.
31 days 8.1.1.5 Verify each valve (manual, power operated or automatic) in the boron injection flow path that is not locked, sealed or otherwise secured in position, is in its correct position.
31 days
Boration Systems - Operating TRM 8.1.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.1-4 Revision 7 Figure 8.1.1-1 Boric Acid Addition System Volume vs Boric Acid Concentration in Modes 1-4
Boration Systems - Operating TRM B 8.1.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.1.1-1 Revision 9 BASES 8.1.1 Boration Systems - Operating The boron injection system ensures that negative reactivity control is available during each mode of facility operation.
The boric acid addition system (BAAS) is one of the borated water sources for the boron injection system. The maximum boration capability requirement occurs from full power equilibrium xenon conditions and requires the equivalent of 12,200 gallons of 7875 ppm borated water from the BAAS, or borated water from the BWST at a volume and concentration as specified in Technical Specification 3.5.4. The minimum value for the BAAS of 12,200 gallons at a concentration of 7875 ppm boron is a lower value than that shown in TRM Figure 8.1.1-1 because the Bases value is the minimum required actual value, whereas TRM Figure 8.1.1-1 shows the minimum indicated value, which was conservatively increased to account for instrument and chemical analysis tolerance.
The components required for the boron injection function, depending on operating conditions, include (1) borated water sources, (2) makeup or DHR pumps, (3) separate flow paths, (4) boric acid pumps, and (5) associated heat tracing systems.
With the RCS average temperature above 200°F, a minimum of two separate and redundant boron injection systems are provided to ensure single functional capability in the event an assumed failure renders one of the systems nonfunctional. Allowable out-of-service periods ensure that minor component repair or corrective action may be completed without undue risk to overall facility safety from injection system failures during the repair period.
The boration capability of either system is sufficient to provide a SHUTDOWN MARGIN from all operating conditions of 1.0% k/k after xenon decay and cooldown to 200°F. The available borated water volume range and boron concentration range for the Boric Acid Addition System (BAAS), required to support this boration capability, are provided in the Updated Safety Analysis Report. The requirements relative to the Borated Water Storage Tank (BWST) are provided in Technical Specification 3.5.4.
Boration Systems - Shutdown TRM 8.1.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.2-1 Revision 3 8.1 REACTIVITY CONTROL SYSTEMS 8.1.2 Boration Systems - Shutdown TECHNICAL NORMAL CONDITIONS TNC 8.1.2 The Boration Systems shall be FUNCTIONAL consisting of the following:
- a.
A flow path from the FUNCTIONAL boric acid addition system (BAAS) via a FUNCTIONAL boric acid pump and a FUNCTIONAL makeup pump to the Reactor Coolant System (RCS); or
- b.
A flow path from the borated water storage tank via a FUNCTIONAL makeup pump to the RCS.
NOTE---------------------------------------------
The makeup pump is only required to be FUNCTIONAL in MODE 5 with the RCS pressure 150 psig.
A FUNCTIONAL decay heat removal (DHR) pump may be used in place of a makeup pump when RCS pressure is < 150 psig APPLICABILITY:
MODES 5 and 6 CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Required Boration System flow path Nonfunctional.
A.1 Suspend movement of irradiated fuel assemblies.
AND A.2 Suspend operations involving positive reactivity additions.
AND A.3 Initiate actions to restore Boration System flow path to functional status.
Immediately Immediately Immediately
Boration Systems - Shutdown TRM 8.1.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.2-2 Revision 3 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.1.2.1 Verify BWST solution temperature > 35°F.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, if the BWST is used as a borated water source and the outside air temperature is < 35°F 8.1.2.2 Verify boron concentration in BWST is > 2600 ppm.
7 days, if the BWST is used as a borated water source 8.1.2.3
NOTE------------------------------------
If the 7 day verification falls during transfers of makeup water or dilute boron solutions (fluid source concentration of less than 5000 ppmB), the verification period may be extended up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the addition of dilute boron solution has been stopped for a period of at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
Verify the pipe temperature of the heat traced portion of the boron injection flow path is 105°F.
7 days, when a flow path from the concentrated boric acid storage system is used 8.1.2.4 Verify BAAS solution temperature is > 105°F.
7 days, if the BAAS is used as borated source 8.1.2.5 Verify BWST water volume is > 3000 gallons 7 days, if the BWST is used as a borated water source 8.1.2.6 Verify available borated water volume > 900 gallons.
31 days, if the BAAS is used as borated source
Boration Systems - Shutdown TRM 8.1.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.2-3 Revision 3 TECHNICAL VERIFICATION REQUIREMENTS (continued)
TVR VERIFICATION FREQUENCY 8.1.2.7 Verify the boron concentration in BAAS is > 7,875 ppm and < 13,125 ppm.
31 days, if the BAAS is used as borated source 8.1.2.8 Verify each valve (manual, power operated or automatic) in the boron injection flow path that is not locked, sealed or otherwise secured in position, is in its correct position.
31 days
Boration Systems - Shutdown TRM B 8.1.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.1.2-1 Revision 9 BASES 8.1.2 Boration Systems - Shutdown A description of the boration system and component requirements is provided in the Bases for TRM 8.1.1, Boration Systems - Operating.
With the RCS temperature below 200°F, one injection system is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting movement of irradiated fuel assemblies and positive reactivity changes in the event the single injection system becomes nonfunctional.
The boration capability required below 200°F is sufficient to provide a SHUTDOWN MARGIN of 1% k/k after xenon decay and cooldown from 200°F to 70°F. This condition requires either 900 gallons of 7875 ppm borated water from the BAAS or 3,000 gallons of 2600 ppm borated water from BWST.
The FUNCTIONALITY of one boron injection system during REFUELING ensures that this system is available for reactivity control while in MODE 6.
Rod Program TRM 8.1.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.3-1 Revision 17 8.1 REACTIVITY CONTROL SYSTEMS 8.1.3 Rod Program TECHNICAL NORMAL CONDITIONS TNC 8.1.3 Each control rod assembly (safety, regulating and APSR) shall be programmed to operate in the core location and rod group specified in the CORE OPERATING LIMITS REPORT.
NOTES-------------------------------------------
During the performance of PHYSICS TESTS in MODE 1, the requirements of TNC 8.1.3 may be suspended, if the requirements of Technical Specification 3.1.8 are in effect.
During the performance of PHYSICS TESTS, in MODE 2, the requirements of TNC 8.1.3 may be suspended, if the requirements of Technical Specification 3.1.9 are in effect.
APPLICABILITY:
MODES 1 and 2.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Any control rod assembly not programmed to operate as specified above.
A.1 Be in MODE 3.
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.1.3.1 Verify all control rod assemblies are programmed to operate in the specified core location and rod group by selection and actuation from the control room and verification of movement of the proper rod as indicated by both the absolute and relative position indicators.
After the Control Rod Drive Control System (CRDCS) programming is complete, or following maintenance or reprogramming within the CRDCS that could affect the rod or group assignment.
Rod Program TRM 8.1.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.1.3-2 Revision 17 TECHNICAL VERIFICATION REQUIREMENTS (continued)
TVR VERIFICATION FREQUENCY 8.1.3.2 Verify that the specifically affected individual control rod assemblies are programmed to operate in the specified core location and rod group by selection and actuation from the control room and verification of movement of the proper rod as indicated by both the absolute and relative position indicators.
After maintenance, test, reconnection or modification of power or instrumentation cables from the control rod drive control system to the control rod drive 8.1.3.3 Verify each control rod assembly cable has been properly matched and reconnected to the specified control rod drive.
After disconnection of control rod assembly cable
Rod Program TRM 8.1.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.1.3-1 Revision 1 BASES None
Reactor Protection System Instrumentation Parameters TRM 8.3.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.1-1 Revision 3 8.3 INSTRUMENTATION 8.3.1 Reactor Protection System Instrumentation Parameters TECHNICAL NORMAL CONDITIONS TNC 8.3.1 The Reactor Protection System (RPS) instrumentation RPS RESPONSE TIMES listed in TRM Table 8.3.1-1 shall be maintained in the manner specified in Technical Specification 3.3.1.
AND The RPS instrumentation RPS SETPOINTS listed in TRM Table 8.3.1-2 shall be maintained in the manner specified in Technical Specification
3.3.1. APPLICABILITY
As specified in Technical Specification Table 3.3.1-1.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME NONE TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY NONE
Reactor Protection System Instrumentation Parameters TRM 8.3.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.1-2 Revision 3 Table 8.3.1-1 (page 1 of 1)
Reactor Protection System Instrumentation Response Times FUNCTION RESPONSE TIMES (b)
(seconds)
- 1.
High Flux (a)
< 0.266
- 2.
RC High Temperature Not Applicable
- 3.
RC High Pressure
< 0.341
- 4.
RC Low Pressure
< 0.341
- 5.
RC Pressure - Temperature - Constant Temperature Not applicable
- 6.
Containment High Pressure Not applicable
- 7.
High Flux / Number of Reactor Coolant Pumps On (a)(c)
< 0.631
- 8.
Flux - Flux - Flow (a)
- a. Variable Flow
- b. Constant Flow
< 1.77
< 0.266 (a)
Neutron detectors are exempt from response time testing. Response time of the neutron flux signal portion of the channel shall be measured from detector output or input of first electronic component in channel.
(b)
Including sensor (except as noted), RPS instrument delay and the breaker delay.
(c)
A delay time has been assumed for the Reactor Coolant Pump monitor in the determination of the response time of the High Flux / Number of Reactor Coolant Pumps On functional unit.
Reactor Protection System Instrumentation Parameters TRM 8.3.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.1-3 Revision 3 Table 8.3.1-2 (page 1 of 1)
Reactor Protection System Instrumentation Trip Setpoints FUNCTION (Note 1)
Setpoint 1.a High Flux Four Pump Limiting Trip Setpoint (Ultrasonic) 104.5875% FP Four Pump Limiting Trip Setpoint (Venturi) 102.9875% FP Three Pump Limiting Trip Setpoint (Ultrasonic or Venturi) 80.2875% FP Four Pump Normal Trip Setpoint (Note 2) (Ultrasonic) 104.5% FP Four Pump Normal Trip Setpoint (Note 2) (Venturi) 102.9% FP Three Pump Normal Trip Setpoint (Note 2) (Ultrasonic or Venturi) 80.1% FP As-Found Acceptance Criteria (Note 3)
[Previous As-Left - Current As-Found]
NTSP < 0.3125% Power As-Left Acceptance Criteria (Note 3)
NTSP +/- 0.0875% Power
- 5. RC Pressure - Temperature Limiting Trip Setpoint (LTSP) 16.25 Tout - 7886.602 psig Nominal Trip Setpoint (NTSP) (Note 2) 16.25 Tout - 7885.5 psig As-Found Acceptance Criteria Band (Note 3)
[Previous As-Left - Current As-found]
11.2 psi As-Left Setpoint Tolerance Band (Note 3)
NTSP +/- 6.0 psi Note 1 Setpoint information is not provided for Tech Spec Table 3.3.1-1 Functions 2, 3, 4, 6, 7, 8, 9.
Note 2 Nominal Trip Setpoint is a value more conservative than the Limiting Trip Setpoint.
Conservative margin is added (subtracted) to the Limiting Trip Setpoint to generate the Nominal Trip Setpoint.
Note 3 Compliance with the As-Found Acceptance Criteria Band is determined by taking the absolute value of the difference between the As-Left value from the previous surveillance test and the As-Found value from the current surveillance test. This must be evaluated separate from compliance with the Technical Specification Allowable Value. (Applicable to Functional Unit 5 only).
Reactor Protection System Instrumentation Parameters TRM B 8.3.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.1-1 Revision 0 BASES 8.3.1 Reactor Protection System Instrumentation Parameters The measurement of response time at the specified frequencies provides assurance that the RPS action function associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable.
Response time may be demonstrated by any series of sequential, overlapping or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either 1) in place, onsite or offsite test measurements or 2) utilizing replacement sensors with certified response times.
The measurement of trip setpoints at the specified frequencies provides assurance that the RPS function associated with each channel is in conformance with the trip requirements assumed in the safety analysis. The trip setpoint is established by addition (or subtraction depending on the conservative direction) of instrument uncertainties to the Analytical Limit (value used in the safety analysis).
This assurance is based on compliance with the methodology for establishment of nuclear safety related setpoints. The setpoint and acceptance criteria are established in compliance with Regulatory Guide 1.105, Setpoints for Safety-Related Instrumentation. The setpoint and acceptance criteria are established using Method 1 or Method 2 from Section 7 of ISA RP67.04.02-2000, Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation. Reset of the setpoint within the assumed As-Left Setpoint Tolerance Band will provide assurance that the channel is in compliance with the methodology and the calculation establishing the setpoint. Additional assurance is provided by repeated, successful setpoint verification at the prescribed surveillance frequency.
Setpoints found outside of the prescribed values require evaluation to ensure the equipment is able to perform within the calculational values and to determine if the equipment is able to perform the intended protective function.
Incore Detectors TRM 8.3.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.2-1 Revision 0 8.3 INSTRUMENTATION 8.3.2 Incore Detectors TECHNICAL NORMAL CONDITIONS TNC 8.3.2 The Incore Detection System shall be FUNCTIONAL as specified below:
- a. > 75% of the Symmetric Incore Detectors in each core quadrant shall be FUNCTIONAL for QUADRANT POWER TILT measurements.
- b. > 75% of all incore detectors in each core quadrant shall be FUNCTIONAL for AXIAL POWER IMBALANCE, FNH and measurements.
Q F
APPLICABILITY:
When the Incore Monitoring System is used for measurement of:
- a. AXIAL POWER IMBALANCE;
- b. QUADRANT POWER TILT;
- c. FNH; or
- d.
Q F
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Less than the specified number of incore detectors FUNCTIONAL.
A.1 Do not use the Incore Monitoring System for the above applicable measurement.
Immediately
Incore Detectors TRM 8.3.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.2-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.3.2.1 Perform CHANNEL CHECK.
Within 7 days prior to its use for measurement of the AXIAL POWER IMBALANCE or the QUADRANT POWER TILT AND 7 days thereafter 8.3.2.2
NOTE-----------------------------------
Channel calibration does not include neutron detectors.
Perform CHANNEL CALIBRATION.
24 months
Incore Detectors TRM B 8.3.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.2-1 Revision 0 BASES 8.3.2 Incore Detectors The FUNCTIONALITY of the incore detectors ensures that the measurements obtained from the Incore Monitoring System accurately represent the spatial neutron flux distribution of the reactor core.
Technical Specification 3.2.4, Quadrant Power Tilt becomes applicable in plant MODE 1 above 20% of Rated Thermal Power. This requires a determination of Quadrant Power Tilt at least once every 7 days, under Technical Specification SR 3.2.4.1. The channel check of the incore detector system (TRM TVR 8.3.2.1) must be performed within 7 days prior to this initial performance of TS SR 3.2.4.1, without the benefit of TRM 6.4.
Therefore, assuming the continued applicability of TS 3.2.4, for each subsequent performance of TRM TVR 8.3.2.1, the 25 percent allowable verification test interval extension of TRM 6.4 may be applied.
REFERENCES
- 1. NRC Letter Log No. 5382, dated December 3, 1998, to Centerior Service Company
Seismic Instrumentation TRM 8.3.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.3-1 Revision 16 8.3 INSTRUMENTATION 8.3.3 Seismic Instrumentation TECHNICAL NORMAL CONDITIONS TNC 8.3.3 The seismic monitoring instrumentation for each Location in TRM Table 8.3.3-1 shall be FUNCTIONAL.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES
NOTE-----------------------------------------------------------------
Separate Nonconformance entry is allowed for each channel.
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. -------------NOTE-------------
Contingency Measures A.2, A.3, and A.4 shall be completed whenever Nonconformance A is entered.
One or more seismic monitoring instrumentation Nonfunctional due to being actuated during a seismic event.
A.1 Restore instrument to FUNCTIONAL status.
AND A.2 Perform TVR 8.3.3.3 and TVR 8.3.3.4 AND A.3 Analyze data retrieved from instrument to determine the magnitude of the vibratory ground motion.
AND A.4 Prepare and submit a special report to the Commission describing the magnitude, frequency, spectrum, and resultant effect upon the facility features important to safety.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 5 days 10 days 10 days
Seismic Instrumentation TRM 8.3.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.3-2 Revision 16 CONTINGENCY MEASURES (continued)
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME B. One or more seismic monitoring instrumentations Nonfunctional for reasons other than Nonconformance A.
B.1 Restore instrument to FUNCTIONAL status.
30 days C. Contingency Measures and associated Restoration Time of Nonconformance B not met.
C.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately
Seismic Instrumentation TRM 8.3.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.3-3 Revision 16 TECHNICAL VERIFICATION REQUIREMENTS
NOTE-----------------------------------------------------------
Refer to TRM Table 8.3.3-1 to determine which TVRs apply for each seismic monitoring instrumentation.
TVR VERIFICATION FREQUENCY 8.3.3.1
NOTE------------------------------
Channel Check for Instrument 1.d shall include seismic trigger and cabinet room indication of trigger.
Perform CHANNEL CHECK for Instrument 1.
31 days 8.3.3.2 Perform CHANNEL FUNCTIONAL TEST for Instrument 1.
184 days 8.3.3.3 Perform CHANNEL CALIBRATION for Instruments 1.c, 1.d, and 2.
18 months 8.3.3.4 Perform CHANNEL CALIBRATION for Instruments 1.a and 1.b.
24 months
Seismic Instrumentation TRM 8.3.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.3-4 Revision 16 Table 8.3.3-1 (page 1 of 1)
Seismic Monitoring Instrumentation INSTRUMENTS AND SENSOR LOCATIONS MINIMUM INSTRUMENT FUNCTIONAL MEASUREMENT RANGE
- 1.
Strong Motion Triaxial Accelerographs
- a. Containment Concrete Foundation, Elev. 565 (inside containment) 1
+ 1g
- b. Containment Interior Secondary Shield Wall Elev. 653 (inside containment) 1
+ 1g
- c. Auxiliary Building Basement Floor, Elev.
545 (outside containment) 1
+ 1g
- d. Station site - Minimum of 300 feet from containment vessel within the site boundary (outside containment) 1(a)
+ 1g(b)
- 2. Peak Recording Accelerometers
- a. Shield Building Top, Minimum Elev. 812 1
+ 1g
- b. Auxiliary Building Roof, Elev. 660 1
+ 1g
- c. Control Room, Elev. 623 1
+ 1g (a)
Includes Seismic Trigger function with cabinet room indication (b)
Seismic Trigger function characteristics:
- a. Minimum Frequency Response Range: 1 - 10 Hz
- b. Actuation Range: 0.005g - 0.02g
Seismic Instrumentation TRM B 8.3.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.3-1 Revision 16 BASES 8.3.3 Seismic Instrumentation The FUNCTIONALITY of the seismic instrumentation ensures that sufficient capability is available to promptly determine the magnitude of a seismic event so that the response of those features important to safety may be evaluated. This capability is required to permit comparison of the measured response to that used in the design basis for the facility. Item 1.d on Table 8.3.3-1 is credited with the required seismic trigger function because it is the only free-field sensor.
TVR 8.3.3.1 includes a note indicating the extent to which the seismic trigger and control room indication functions are required to be verified during channel checks of the strong motion triaxial accelerographs. Although all of these instruments are capable of triggering the system, a check of the trigger function is only required for instrument 1.d and is optional for the others.
Check of the trigger function should confirm that recording is initiated at all recorders and that appropriate indication of the triggered condition occurs in the cabinet room.
This instrumentation is consistent with the recommendations of Regulatory Guide 1.12 "Instrumentation for Earthquakes," April 1974.
Meteorological Instrumentation TRM 8.3.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.4-1 Revision 4 8.3 INSTRUMENTATION 8.3.4 Meteorological Instrumentation TECHNICAL NORMAL CONDITIONS TNC 8.3.4 The meteorological monitoring instrumentation channels for each function shown in TRM Table 8.3.4-1 shall be FUNCTIONAL.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES
NOTE-------------------------------------------------------------------
Separate entry is allowed for each instrumentation channel.
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One or more meteorological monitoring instrumentation channels Nonfunctional.
A.1 Restore channels to FUNCTIONAL status.
7 days B. Contingency Measures and associated Restoration Time of Nonconformance A not met.
B.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately
Meteorological Instrumentation TRM 8.3.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.4-2 Revision 4 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.3.4.1 Perform CHANNEL CHECK of each required channel.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 8.3.4.2
NOTE------------------------------
Wind direction and wind speed sensors are excluded from CHANNEL CALIBRATION.
Perform CHANNEL CALIBRATION of each required channel.
184 days
Meteorological Instrumentation TRM 8.3.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.4-3 Revision 4 Table 8.3.4-1 (page 1 of 1)
Meteorological Monitoring Instrumentation FUNCTION LOCATION REQUIRED CHANNELS
- 1. Wind Speed
- a.
Nominal Elev.
612 1
- b.
Nominal Elev.
827 1
- 2. Wind Direction
- a.
Nominal Elev.
612 1
- b.
Nominal Elev.
827 1
- 3. Air Temperature - Delta T
- a.
Nominal Elev.
827 - 612 1
Meteorological Instrumentation TRM B 8.3.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.4-1 Revision 4 BASES 8.3.4 Meteorological Instrumentation The FUNCTIONALITY of the meteorological instrumentation ensures that sufficient meteorological data is available for estimating potential radiation doses to the public as a result of routine or accidental release or radioactive materials to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public. This instrumentation is consistent with the recommendations of Regulatory Guide 1.23 "Meteorological Programs in Support of Nuclear Power Plants," September 1980.
TVR 8.3.4.2 includes a Note. The Note indicates that the sensors for wind speed and wind direction are excluded from CHANNEL CALIBRATION. This note is necessary because the sensors are pre-calibrated by a vendor in offsite wind tunnel facilities. The vendor certified calibrations are valid for 5 years after the date of performance when stored in a temperature controlled storage, and are valid for 1 year in service.
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-1 Revision 3 8.3 INSTRUMENTATION 8.3.5 Safety Features Actuation System Response Times TECHNICAL NORMAL CONDITIONS TNC 8.3.5 The Safety Features Actuation System (SFAS) instrumentation RESPONSE TIMES listed in TRM Table 8.3.5-1 shall be maintained in the manner specified in Technical Specification 3.3.5.
APPLICABILITY:
As specified in Technical Specification Table 3.3.5-1.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME NONE TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY NONE
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-2 Revision 3 Table 8.3.5-1 (Page 1 of 7)
Safety Features System Instrumentation Response Times INITIATING SIGNAL AND FUNCTION RESPONSE TIME (seconds) 1 Manual
- a.
Fans
- 1.
Emergency Vent Fan NA
- 2.
Containment Cooler Fan NA
- b.
- 1.
ECCS Room NA
- 2.
Emergency Ventilation NA
- 3.
Containment Air Sample NA
- 4.
Penetration Room Purge NA
- c.
- d.
High Pressure Injection
- 1.
High Pressure Injection Pumps NA
- 2.
High Pressure Injection Valves NA
- e.
Component Cooling Water
- 1.
Component Cooling Water Pumps NA
- 2.
Component Cooling Aux. Equip. Inlet Valves NA
- 3.
Component Cooling to Makeup Pump Header Inlet Valve NA
- f.
Service Water System
- 1.
Service Water Pumps NA
- 2.
Service Water From Component Cooling Heat Exchanger Isolation Valves NA
- g.
Containment Spray Isolation Valves NA
- h.
- i.
Containment Isolation Valves
- 1.
Vacuum Relief NA
- 2.
Normal Sump NA
- 3.
RCS Letdown Delay Coil Outlet NA
- 4.
RCS Letdown High Temperature NA (1)
Diesel generator starting and sequence loading delays included when applicable. Response time limit includes movement of valves and attainment of pump or blower discharge pressure.
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-3 Revision 3 Table 8.3.5-1 (page 2 of 7)
Safety Features System Instrumentation Response Times INITIATING SIGNAL AND FUNCTION RESPONSE TIME (seconds)
- i.
Containment Isolation Valves (cont'd)
- 5.
Pressurizer Sample NA
- 6.
Service Water to Cooling Water NA
- 7.
Vent Header NA
- 8.
Drain Tank NA
- 9.
Core Flood Tank Vent NA
- 10.
Core Flood Tank Fill NA
- 11.
Steam Generator Sample NA 12 Quench Tank NA
- 13.
Emergency Sump NA
- 14.
RCP Seal Return NA
- 15.
Air Systems NA
- 16.
N2 System NA
- 17.
Quench Tank Sample NA
- 18.
RCP Seal Inlet NA
- 19.
Core Flood Tank Sample NA
- 20.
RCP Standpipe Demin Water Supply NA
- 21.
Containment H2 Dilution Inlet NA
- 22.
Containment H2 Dilution Outlet NA
- j.
BWST Outlet Valves NA
- k.
Low Pressure Injection
- 1.
Decay Heat Pumps NA
- 2.
Low Pressure Injection Valves NA
- 3.
Decay Heat Pump Suction Valves NA
- 4.
Decay Heat Cooler Outlet Valves NA
- 5.
Decay Heat Cooler Bypass Valves NA
- l.
Containment Spray Pump NA (1)
Diesel generator starting and sequence loading delays included when applicable. Response time limit includes movement of valves and attainment of pump or blower discharge pressure.
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-4 Revision 3 Table 8.3.5-1 (page 3 of 7)
Safety Features System Instrumentation Response Times INITIATING SIGNAL AND FUNCTION RESPONSE TIME (seconds)
- m.
Component Cooling Isolation Valves
- 1.
Inlet to Containment NA
- 2.
Outlet from Containment NA
- 3.
Inlet to CRDM's NA
- 4.
CRDM Booster Pump Suction NA
- 5.
Component Cooling from Decay Heat Coolers NA
- 2.
Containment Pressure - High
- a.
Fans
- 1.
Emergency Vent Fans 25(1)
- 2.
Containment Cooler Fans 45(1)
- b.
- 1.
ECCS Room 75(1)
- 2.
Emergency Ventilation 75(1)
- 3.
Containment Air Sample 30(1)
- 4.
Penetration Room Purge 75(1)
- c.
Control Room HV & AC Units 10(1)
- d.
High Pressure Injection
- 1.
High Pressure Injection Pumps 30(1)
- 2.
High Pressure Injection Valves 30(1)
- e.
Component Cooling Water
- 1.
Component Cooling Water Pumps 180(1)
- 2.
Component Cooling Aux. Equip. Inlet Valves 180(1)
- 3.
Component Cooling to Makeup Pump Header Inlet Valve 180(1)
- 4.
Component Cooling from Decay Heat Cooler NA(1)
- f.
Service Water System
- 1.
Service Water Pumps 45(1)
- 2.
Service Water From Component Cooling Heat Exchanger Isolation Valves NA(1)
- g.
Containment Spray Isolation Valves 80(1)
- h.
Emergency Diesel Generator 15(1)
(1) Diesel generator starting and sequence loading delays included when applicable.
Response time limit includes movement of valves and attainment of pump or blower discharge pressure.
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-5 Revision 3 Table 8.3.5-1 (page 4 of 7)
Safety Features System Instrumentation Response Times INITIATING SIGNAL AND FUNCTION RESPONSE TIME (seconds)
- 2.
Containment Pressure - High (Continued)
- i.
Containment Isolation Valves
- 1.
Vacuum Relief 30(1)
- 2.
Normal Sump 30(1)
- 3.
RCS Letdown Delay Coil Outlet 30(1)
- 4.
RCS Letdown High Temperature 30(1)
- 5.
Pressurizer Sample 45(1)
- 6.
Service Water to Cooling Water 45(1)
- 7.
Vent Header 15(1)
- 8.
Drain Tank 15(1)
- 9.
Core Flood Tank Vent 15(1)
- 10.
Core Flood Tank Fill 15(1)
- 11.
Steam Generator Sample 15(1)
- 12.
Quench Tank 15(1)
- 13.
Emergency Sump NA(1)
- 14.
RCP Seal Return 45(1)
- 15.
Air System 15(1)
- 16.
N2 System 15(1)
- 17.
Quench Tank Sample 35(1)
- 18.
RCP Seal Inlet 17(1)
- 19.
Core Flood Tank Sample 15(1)
- 20.
RCP Standpipe Demin Water Supply 15(1)
- 21.
Containment H2 Dilution Inlet 75(1)
- 22.
Containment H2 Dilution Outlet 75(1)
- j.
BWST Outlet Valves NA(1)
- k.
Low Pressure Injection
- 1.
Decay Heat Pumps 30(1)
- 2.
Low Pressure Injection Valves NA(1)
- 3.
Decay Heat Pump Suction Valves NA(1)
- 4.
Decay Heat Cooler Outlet Valves NA(1)
- 5.
Decay Heat Cooler Bypass Valves NA(1)
(1)
Diesel generator starting and sequence loading delays included when applicable. Response time limit includes movement of valves and attainment of pump or blower discharge pressure.
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-6 Revision 3 Table 8.3.5-1 (page 5 of 7)
Safety Features System Instrumentation Response Times INITIATING SIGNAL AND FUNCTION RESPONSE TIME (seconds)
- 3.
Containment Pressure--High-High
- a.
Containment Spray Pump 80(1)
- b.
Component Cooling Isolation Valves
- 1.
Inlet to Containment 30(1)
- 2.
Outlet from Containment 30(1)
- 3.
Inlet to CRDM's 35(1)
- 4.
CRDM Booster Pump Suction 35(1)
- 4.
RCS Pressure-Low
- a.
Fans
- 1.
Emergency Vent Fans 25(1)
- 2.
Containment Cooler Fans 45(1)
- b.
- 1.
ECCS Room 75(1)
- 2.
Emergency Ventilation 75(1)
- 3.
Containment Air Sample 30(1)
- 4.
Penetration Room Purge 75(1)
- c.
Control Room HV & AC Units 10(1)
- d.
High Pressure Injection
- 1.
High Pressure Injection Pumps 30(1)
- 2.
High Pressure Injection Valves 30(1)
- e.
Component Cooling Water
- 1.
Component Cooling Water Pumps 180(1)
- f.
Service Water System
- 1.
Service Water Pumps 45(1)
- 2.
Service Water from Component Cooling Heat Exchanger Isolation Valves NA(1)
- g.
Containment Spray Isolation Valves 80(1)
- h.
Emergency Diesel Generator 15(1)
(1)
Diesel generator starting and sequence loading delays included when applicable. Response time limit includes movement of valves and attainment of pump or blower discharge pressure.
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-7 Revision 3 Table 8.3.5-1 (page 6 of 7)
Safety Features System Instrumentation Response Times INITIATING SIGNAL AND FUNCTION RESPONSE TIME (seconds)
- 4.
RCS Pressure-Low (continued)
- i.
Containment Isolation Valves
- 1.
Vacuum Relief 30(1)
- 2.
Normal Sump 30(1)
- 3.
RCS Letdown Delay Coil Outlet 30(1)
- 4.
RCS Letdown High Temperature 30(1)
- 5.
Pressurizer Sample 45(1)
- 6.
Service Water to Cooling Water 45(1)
- 7.
Vent Header 15(1)
- 8.
Drain Tank 15(1)
- 9.
Core Flood Tank Vent 15(1)
- 10.
Core Flood Tank Fill 15(1)
- 11.
Steam Generator Sample 15(1)
- 12.
Quench Tank 15(1)
- 13.
Emergency Sump NA(1)
- 14.
Air Systems 15(1)
- 15.
N2 System 15(1)
- 16.
Quench Tank Sample 35(1)
- 17.
Core Flood Tank Sample 15(1)
- 18.
RCP Standpipe Demin Water Supply 15(1)
- 19.
Containment H2 Dilution Inlet 75(1)
- 20.
Containment H2 Dilution Outlet 75(1)
- j.
BWST Outlet Valves NA(1)
(1) Diesel generator starting and sequence loading delays included when applicable.
Response time limit includes movement of valves and attainment of pump or blower discharge pressure.
Safety Features Actuation System Response Times TRM 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.5-8 Revision 3 Table 8.3.5-1 (page 7 of 7)
Safety Features System Instrumentation Response Times INITIATING SIGNAL AND FUNCTION RESPONSE TIME (seconds)
- 5.
RCS Pressure--Low-Low
- a.
Low Pressure Injection
- 1.
Decay Heat Pumps 30(1)
- 2.
Low Pressure Injection Valves NA(1)
- 3.
Decay Heat Pump Suction Valves NA(1)
- 4.
Decay Heat Cooler Outlet Valves NA(1)
- 5.
Decay Heat Cooler Bypass Valves NA(1)
- b.
Component Cooling Isolation Valves
- 1.
Auxiliary Equipment Inlet 90(1)
- 2.
Inlet to Makeup Pump Header 90(1)
- 3.
Component Cooling from Decay Heat Cooler NA(1)
- c.
Containment Isolation Valves
- 1.
RCP Seal Return 45(1)
- 2.
RCP Seal Inlet 17(1)
(1) Diesel generator starting and sequence loading delays included when applicable.
Response time limit includes movement of valves and attainment of pump or blower discharge pressure.
Safety Features Actuation System Response Times TRM B 8.3.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.5-1 Revision 0 BASES 8.3.5 Safety Features Actuation System Instrumentation The measurement of response time at the specified frequencies provides assurance that the SFAS action function associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable.
Response time may be demonstrated by any series of sequential, overlapping or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either 1) in place, onsite or offsite test measurements or 2) utilizing replacement sensors with certified response times.
Waste Gas System Oxygen Monitoring TRM 8.3.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.6-1 Revision 0 8.3 INSTRUMENTATION 8.3.6 Waste Gas System Oxygen Monitoring TECHNICAL NORMAL CONDITIONS TNC 8.3.6 Waste Gas System Oxygen monitoring shall be FUNCTIONAL with its alarm setpoints set to ensure the limits of TRM 8.7.5 are not exceeded.
APPLICABILITY:
During additions to the waste gas surge tank.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Both Waste gas system oxygen monitor alarm setpoint less conservative than required by TRM 8.7.5.
A.1 Declare the channel Nonfuntional and comply with Contingency Measures B.1 and B.2.
Immediately B. Both Waste gas system oxygen monitor Nonfunctional.
B.1 Additions to waste gas surge tank may continue provided another method for ascertaining oxygen concentrations, such as grab sample analysis, is implemented to provide measurements.
AND B.2 Exert best efforts to return the waste gas system oxygen monitor to FUNCTIONAL status.
Every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> during degassing AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during operations other than degassing 30 days C. Contingency Measures and associated Restoration Time of Nonconformance B not met.
C.1 Explain in the next Radioactive Effluent Release Report why the Nonconformance was not corrected in a timely manner.
Date of next Radioactive Effluent Release Report
Waste Gas System Oxygen Monitoring TRM 8.3.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.6-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.3.6.1 Perform CHANNEL CHECK.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during additions to the waste gas surge tank 8.3.6.2 Perform CHANNEL CALIBRATION using standard gas samples containing a nominal:
- a.
1 volume % oxygen, balance nitrogen; and
- b.
4 volume % oxygen, balance nitrogen.
92 days
Waste Gas System Oxygen Monitoring TRM B 8.3.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.6-1 Revision 0 BASES 8.3.6 Waste Gas System Oxygen Monitor The waste gas system oxygen monitor is provided to monitor oxygen concentration of gaseous radwaste being admitted to the waste gas surge tank. Oxygen concentration is monitored to ensure that the concentration of potentially explosive gas mixtures contained in the waste gas treatment system is maintained below the flammability limits of hydrogen with oxygen.
Post Accident Monitoring (PAM) Instrumentation TRM 8.3.7 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.7-1 Revision 7 8.3 INSTRUMENTATION 8.3.7 Post Accident Monitoring (PAM) Instrumentation TECHNICAL NORMAL CONDITIONS TNC 8.3.7 The PAM instrumentation for each Function in Table 8.3.7-1 shall be FUNCTIONAL.
APPLICABILITY:
MODES 1, 2 and 3.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One or more Functions with one required channel Nonfunctional.
A.1 Restore required channel to FUNCTIONAL status.
30 days B. Contingency Measure and associated Restoration Time of Nonconformance A not met.
B.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately TECHNICAL VERIFICATION REQUIREMENTS
NOTE-----------------------------------------------------------
The below TVRs apply to each PAM instrumentation Function in Table 8.3.7-1.
TVR VERIFICATION FREQUENCY 8.3.7.1 Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.
31 days 8.3.7.2 Perform CHANNEL CALIBRATION.
24 months
Post Accident Monitoring (PAM) Instrumentation TRM 8.3.7 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.7-2 Revision 7 Table 8.3.7-1 (page 1 of 1)
Post Accident Monitoring Instrumentation FUNCTION REQUIRED CHANNELS
- 1. RC System Subcooling Margin Monitor 1
- 2. PORV Position Indicator 1
- 3. PORV Block Valve Position Indicator 1
- 4. Pressurizer Safety Valve Position Indicator 1/valve
- 5. Containment Normal Sump Level 1
Post Accident Monitoring (PAM) Instrumentation TRM B 8.3.7 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.7-1 Revision 0 BASES 8.3.7 Post Accident Monitoring (PAM) Instrumentation The primary purpose of the PAM instrumentation is to display unit variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Events.
The FUNCTIONALITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected unit parameters to monitor and to assess unit status and behavior following an accident.
The availability of accident monitoring instrumentation is important so that responses to corrective actions can be observed, and so that the need for and magnitude of further actions can be determined. These essential instruments are identified by UFSAR Section 7.13 (Ref. 1) addressing the recommendations of Regulatory Guide 1.97 (Ref. 2) as required by Supplement 1 to NUREG-0737 (Ref. 3).
Only those instruments monitoring Type A and Category 1 variables are required to be included in Technical Specifications. The instruments in this Technical Requirement did not meet the criterion for inclusion into Technical Specifications.
EDG Loss of Power Start TRM 8.3.8 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.8-1 Revision 3 8.3 INSTRUMENTATION 8.3.8 EDG Loss of Power Start TECHNICAL NORMAL CONDITIONS TNC 8.3.8 The EDG Loss of Power Start (LOPS) instrumentation setpoints listed in TRM Table 8.3.8-1 shall be maintained in the manner specified in Technical Specification 3.3.8.
APPLICABILITY:
As specified in Technical Specification 3.3.8.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME NONE TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY NONE
EDG Loss of Power Start TRM 8.3.8 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.8-2 Revision 3 Table 8.3.8-1 (page 1 of 1)
EDG Loss of Power Start Setpoints FUNCTIONS TRIP SETPOINTS Degraded Voltage Function 3734 Volts, +/- 7 Volts (Dropout) 3759 Volts, Max (Pickup) 7.5 +/- 0.2 Seconds (Delay)
Loss of Voltage Function 2429 Volts, +/- 7 Volts (Dropout) 2466 Volts, Max (Pickup) 0.5 +/- 0.05 Seconds (Delay)
EDG Loss of Power Start Instrumentation TRM B 8.3.8 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.8-1 Revision 0 BASES 8.3.8 EDG Loss of Power Start Instrumentation Compliance with TNC 8.3.8 provides assurance that the SFAS function associated with each channel is in conformance with the trip requirements assumed in the safety analysis. The trip setpoint is established by addition (or subtraction depending on the conservative direction) of instrumentation uncertainties to the Analytical Limit (value used in the AC Power System Analysis).
This assurance is based on compliance with the methodology for establishment of nuclear safety related setpoints. The setpoint and acceptance criteria are established in compliance with Regulatory Guide 1.105, Setpoints for Safety-Related Instrumentation. The setpoint and acceptance criteria are established using Method 2 from section 7 of ISA RP67.04.02-2000, Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation.
Reset of the setpoint within the assumed Setpoint Tolerance Band will provide assurance that the channel is in compliance with the methodology and the calculation establishing the setpoint.
Additional assurance is provided by repeated, successful setpoint verification at the prescribed surveillance frequency.
Source and Intermediate Range Overlap TRM 8.3.10 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.10-1 Revision 1 8.3 INSTRUMENTATION 8.3.10 Source and Intermediate Range Overlap TECHNICAL NORMAL CONDITIONS TNC 8.3.10 The requirements of TVR 8.3.10.1 shall be performed.
APPLICABILITY:
When transitioning between the source range and intermediate range neutron flux instrumentation during a reactor startup.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. TVR 8.3.10.1 not met.
A.1 Evaluate OPERABILITY requirements of Technical Specifications 3.3.9 and 3.3.10.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.3.10.1 Verify at least one decade overlap between Source and Intermediate Range Monitors.
Each reactor startup during the transition between source and intermediate range monitors, if not verified in previous 7 days
Source and Intermediate Range Overlap TRM B 8.3.10 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.10-1 Revision 1 BASES 8.3.10 Source and Intermediate Range Overlap The overlap check requires an expectation of one decade of overlap when transitioning between the source range and intermediate range neutron flux instrumentation during a reactor startup.
During a power increase near the top scale for the source range monitors, an intermediate range monitor reading is expected with at least on decade overlap. Without such an overlap, the intermediate range monitors are considered inoperable unless it is clear that a source range monitor inoperability is responsible for the lack of the expected overlap.
Steam And Feedwater Rupture Control System Instrumentation Parameters TRM 8.3.11 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.11-1 Revision 3 8.3 INSTRUMENTATION 8.3.11 Steam And Feedwater Rupture Control System Instrumentation Parameters TECHNICAL NORMAL CONDITIONS TNC 8.3.11 The Steam and Feedwater Rupture Control System (SFRCS) instrumentation RESPONSE TIMES listed in TRM Table 8.3.11-1 shall be maintained in the manner specified in Technical Specification 3.3.11.
AND The SFRCS Trip Setpoints listed in TRM Table 8.3.11-2 shall be maintained in the manner specified in Technical Specification 3.3.11.
APPLICABILITY:
As specified in Technical Specification Table 3.3.11-1.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME NONE TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY NONE
Steam And Feedwater Rupture Control System Instrumentation Parameters TRM 8.3.11 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.11-2 Revision 3 Table 8.3.11-1 (page 1 of 1)
Steam and Feedwater Rupture Control System Response Time ACTUATED EQUIPMENT RESPONSE TIME (seconds)
- 1.
Auxiliary Feed Pump 40
- 2.
Main Steam Isolation Valves (1)
- a.
Main Steam Low Pressure Channels 6
- b.
Feedwater/Steam Generator High Differential Pressure Channels 6.5
- 3.
Main Feedwater Valves
- a.
Main Control 8
- b.
Startup Control 13
- c.
Stop Valve 16
- 4.
Turbine Stop Valves (2) 1 (1)
The response time is to be the time elapsed from the monitored variable exceeding the trip setpoint until the Main Steam Isolation Valve is fully closed.
(2)
The response time is to be the time elapsed from the Main Steam Line Pressure Low trip condition until the Turbine Stop Valve is fully closed.
Steam And Feedwater Rupture Control System Instrumentation Parameters TRM 8.3.11 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.11-3 Revision 3 Table 8.3.11-2 (page 1 of 1)
Steam and Feedwater Rupture Control System (SFRCS) Trip Setpoints FUNCTION
- 1.
Main Steam Line Pressure - Low (3)
Limiting Trip Setpoint (LTSP) 625.65 psig Nominal Trip Setpoint (NTSP) 630 psig As-Found Acceptance Criteria Band NTSP +/- 14.0 psig As-Left Setpoint Tolerance Band NTSP +/- 10.0 psig
- 2.
Feedwater / Steam Generator Differential Pressure - High (2, 3)
Limiting Trip Setpoint (LTSP) 132.90 psid Nominal Trip Setpoint (NTSP) 125.0 psid As-Found Acceptance Criteria Band NTSP +/- 10.0 psid As-Left Setpoint Tolerance Band NTSP +/- 7.14 psid
- 3.
Steam Generator Level - Low (1, 3)
Limiting Trip Setpoint (LTSP) 23.30 inches Indicated Nominal Trip Setpoint (NTSP) 23.50 inches Indicated As-Found Acceptance Criteria Band NTSP +/- 0.25 inches As-Left Setpoint Tolerance Band NTSP +/- 0.135 inches
- 4.
Loss of Reactor Coolant Pumps-Trip Setpoint - High 1384.6 amps Trip Setpoint - Low 106.5 amps (1) Steam Generator Level - Low Function references actual water level above the lower steam generator tubesheet, with this setpoint being consistent with the Allowable Value listed in the Technical Specifications.
(2) Differential Pressure is steam generator pressure minus feedwater pressure.
(3) Compliance with the As-Found Acceptance Criteria Band is determined by evaluating the current surveillance test value and comparing it to the As-Found Acceptance Criteria Band with respect to the Nominal Trip Setpoint. This must be evaluated separate from compliance with the Technical Specification Allowable Value.
Steam And Feedwater Rupture Control System Instrumentation Parameters TRM B 8.3.11 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.11-1 Revision 0 BASES 8.3.11 Steam And Feedwater Rupture Control System Instrumentation The measurement of response time at the specified frequencies provides assurance that the SFRCS action function associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable.
Response time may be demonstrated by any series of sequential, overlapping or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either 1) in place, onsite or offsite test measurements or 2) utilizing replacement sensors with certified response times.
The SFRCS response time for the turbine stop valve closure is based on the combined response times of main steam line low pressure sensors, logic cabinet delay for main steam line low pressure signals and closure time of the turbine stop valves. This SFRCS response time ensures that the auxiliary feedwater to the unaffected steam generator will not be isolated due to a SFRCS low pressure trip during a main steam line break accident.
The measurement of trip setpoints at the specified frequencies provides assurance that the SFRCS function associated with each channel is in conformance with the trip requirements assumed in the safety analysis. The trip setpoint is established by addition (or subtraction depending on the conservative direction) of instrument uncertainties to the Analytical Limit (value used in the safety analysis).
This assurance is based on compliance with the methodology for establishment of nuclear safety related setpoints. The setpoint and acceptance criteria are established in compliance with Regulatory Guide 1.105, Setpoints for Safety-Related Instrumentation. The setpoint and acceptance criteria are established using Method 1 or Method 2 from Section 7 of ISA RP67.04.02-2000, Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation. Reset of the setpoint within the assumed As-Left Setpoint Tolerance Band will provide assurance that the channel is in compliance with the methodology and the calculation establishing the setpoint. Additional assurance is provided by repeated, successful setpoint verification at the prescribed surveillance frequency.
Setpoints found outside of the prescribed values require evaluation to ensure the equipment is able to perform within the calculational values and to determine if the equipment is able to perform the intended protective function.
Ultrasonic Flow Meter Instrumentation TRM 8.3.12 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.3.12-1 Revision 0 8.3 INSTRUMENTATION 8.3.12 Ultrasonic Flow Meter Instrumentation TECHNICAL NORMAL CONDITIONS TNC 8.3.12 Ultrasonic Flow Meter Instrumentation shall be FUNCTIONAL.
APPLICABILITY:
MODE 1 when greater than 50% RATED THERMAL POWER.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Ultrasonic Flow Meter instrumentation Nonfunctional.
A.1 Restore Ultrasonic Flow Meter to FUNCTIONAL status.
Prior to the next required daily calorimetric heat balance measurement B. Contingency Measure and associated Restoration Time is not met.
B.1 Comply with the applicable actions of Technical Specification 3.3.1.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.3.12.1 Perform CHANNEL CHECK for Ultrasonic Flow Meter instrumentation.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
Ultrasonic Flow Meter Instrumentation TRM B 8.3.12 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.3.12-1 Revision 0 BASES 8.3.12 Ultrasonic Flow Meter instrumentation The LEFM includes a flow meter measurement section in each of the two main feedwater flow headers. Each measurement section consists of sixteen ultrasonic transducers. With any transducer nonfunctional, the Ultrasonic Flow Meter instrumentation system is considered nonfunctional.
The daily CHANNEL CHECK utilizes the on-line verification and self-diagnostic features of the LEFM to ensure the instrumentation is performing as designed.
Chemistry TRM 8.4.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.1-1 Revision 13 8.4 REACTOR COOLANT SYSTEM 8.4.1 Chemistry TECHNICAL NORMAL CONDITIONS TNC 8.4.1 The Reactor Coolant System chemistry shall be maintained within the limits specified in TRM Table 8.4.1-1.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME
NOTE---------------
Only applicable in MODES 1, 2, 3, or 4.
A. With any one or more chemistry parameter in excess of its Steady State Limit but within its Transient Limit.
A.1 Restore the parameter to within its Steady State Limit.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
NOTE---------------
Only applicable in MODES 1, 2, 3, or 4.
B. Contingency Measures and associated Restoration Time of Nonconformance A not met OR With any one or more chemistry parameter in excess of its Transient Limit.
B.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately
Chemistry TRM 8.4.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.1-2 Revision 13 CONTINGENCY MEASURES (continued)
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME
NOTE---------------
Not applicable in MODES 1, 2, 3, or 4.
C. With the concentration of either chloride or fluoride in the Reactor Coolant System in excess of its Steady State Limit for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or in excess of its Transient Limit.
C.1 Reduce the Reactor Coolant System pressure to 500 psig, if applicable.
AND C.2 Initiate action to perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the Reactor Coolant System.
AND C.3 Determine that the Reactor Coolant System remains acceptable for continued operation.
Immediately Immediately Prior to increasing the system pressure above 500 psig or prior to proceeding to MODE 4 D. ----------NOTE----------
Not applicable in MODES 1, 2, 3, 4, 5, or 6.
Unable to determine limits of chloride and fluoride in the Reactor Coolant System due to the inability to sample the RCS.
D.1 ------------NOTE---------------
Applicable only when the ability to sample the RCS is restored Initiate action to perform TVR 8.4.1.1 Immediately
Chemistry TRM 8.4.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.1-3 Revision 13 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.4.1.1 Determine by analysis, the parameters listed in TRM Table 8.4.1-1 are within their specified limits.
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
Chemistry TRM 8.4.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.1-4 Revision 13 TABLE 8.4.1-1 (page 1 of 1)
REACTOR COOLANT SYSTEM CHEMISTRY LIMITS PARAMETER STEADY STATE LIMIT TRANSIENT LIMIT Dissolved Oxygen(1) 0.10 ppm 1.00 ppm Chloride 0.15 ppm 1.50 ppm Fluoride 0.15 ppm 1.50 ppm (1)
Limit not applicable with Tavg 250 F.
Chemistry TRM B 8.4.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.4.1-1 Revision 0 BASES 8.4.1 CHEMISTRY The limitations on Reactor Coolant System chemistry ensure that corrosion of the Reactor Coolant System is minimized and reduce the potential for Reactor Coolant System leakage or failure due to stress corrosion. Maintaining the chemistry within the Steady State Limits shown on TRM Table 8.4.1-1 provides adequate corrosion protection to ensure the structural integrity of the Reactor Coolant System over the life of the plant. The associated effects of exceeding the oxygen, chloride and fluoride limits are time and temperature dependent. Corrosion studies show that operation may be continued with contaminant concentration levels in excess of the Steady State Limits, up to the Transient Limits, for the specified limited time intervals without having a significant effect on the structural integrity of the Reactor Coolant System. The time interval permitting continued operation within the restrictions of the Transient Limits provides time for taking corrective actions to restore the contaminant concentrations to within the Steady State Limits.
The verification requirements provide adequate assurance that concentrations in excess of the limits will be detected in sufficient time to take corrective action.
Pressurizer TRM 8.4.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.2-1 Revision 0 8.4 REACTOR COOLANT SYSTEM 8.4.2 Pressurizer TECHNICAL NORMAL CONDITIONS TNC 8.4.2 The pressurizer temperature shall be limited to:
- a.
A maximum heatup and cooldown of 100°F in any one hour period;
- b.
A maximum spray water temperature differential of 410°F and
- c.
A minimum temperature of 120°F when the pressurizer pressure is 625 psig.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Pressurizer temperature limits in excess of any of the above limits.
A.1 Restore the temperature to within limits.
AND A.2 Initiate action to perform an engineering evaluation to determine the effects of the out-of-limit condition on the fracture toughness properties of the pressurizer.
30 minutes Immediately B. Pressurizer not acceptable for continued operation.
B.1 Be in MODE 3.
AND B.2 Reduce pressurizer pressure to < 500 psig.
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 36 hours
Pressurizer TRM 8.4.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.2-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.4.2.1
NOTE------------------------------
Only required during heatup or cooldown operation.
Determine pressurizer temperature within limits.
30 minutes 8.4.2.2
NOTE------------------------------
Only required during spray operation with pressurizer temperature 440°F.
Determine spray water temperature differential within limits.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
Pressurizer TRM B 8.4.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.4.2-1 Revision 0 BASES 8.4.2 Pressurizer The conditions, actions and verification requirements for the pressurizer temperature limits define the limitations on the pressurizer heatup and cooldown, spray water temperature differential, and minimum temperature when pressure is greater than 625 psig to assure that the pressurizer remains within the design criteria assumed for the pressurizer fatigue analysis. As discussed in Section 5.5.10 of the Davis-Besse UFSAR, the total stresses resulting from thermal expansion, pressure and mechanical and seismic loadings are considered in the design of the pressurizer. The total stresses expected in the pressurizer are within the maximum allowed by the American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vessel Code,Section III.
Pressurizer Heater Interlock TRM 8.4.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.3-1 Revision 0 8.4 REACTOR COOLANT SYSTEM 8.4.3 Pressurizer Heater Interlock TECHNICAL NORMAL CONDITIONS TNC 8.4.3 Two Pressurizer Heater Interlock channels shall be FUNCTIONAL.
APPLICABILITY:
MODE 3 when either decay heat removal (DHR) isolation valve DH-11 or DH-12 is open.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One or more Pressurizer Heater Interlock channels Nonfunctional.
A.1 Place nonfunctional channel(s) in trip.
OR A.2
NOTE--------------
Only applicable if RCS pressure < 328 psig.
Restore nonfunctional channel(s) to FUNCTIONAL status.
Immediately Prior to increasing RCS pressure 328 psig
Pressurizer Heater Interlock TRM 8.4.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.3-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.4.3.1 Perform CHANNEL CHECK.
12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 8.4.3.2 Perform CHANNEL CALIBRATION. The Allowable Value shall be < 328 psig and is referenced to the RCS Pressure instrumentation tap.
24 months 8.4.3.3 Verify Pressurizer Heater Interlock deenergizes the pressurizer heaters on a actual or simulated RCS pressure which is greater than the Allowable Value with either DH-11 or DH-12 open.
24 months
Pressurizer Heater TRM B 8.4.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.4.3-1 Revision 0 BASES 8.4.3 Pressurizer Heaters Pressurizer Heater Interlock setpoint is based on preventing over-pressurization of the Decay Heat Removal System normal suction line piping. The value stated is the RCS pressure at the sensing instrument's tap. It has been adjusted to reflect the elevation difference between the sensor's location and the pipe of concern.
Reactor Coolant System Vents TRM 8.4.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.4-1 Revision 7 8.4 REACTOR COOLANT SYSTEM 8.4.4 Reactor Coolant System Vents TECHNICAL NORMAL CONDITIONS TNC 8.4.4 The following Reactor Coolant System vent paths shall be FUNCTIONAL:
- a.
Reactor Coolant System Loop 1 with vent path through valves RC 4608A and RC 4608B;
- b.
Reactor Coolant System Loop 2 with vent path through valves RC 4610A and RC 4610B; and
- c.
Pressurizer with vent path through either valves RC11 and RC2A (PORV) or valves RC 239A and RC 200.
APPLICABILITY:
MODES 1, 2, and 3.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One vent path Nonfunctional.
A.1 Restore the Nonfunctional vent path to FUNCTIONAL status.
30 days B. Two or more vent paths Nonfunctional.
B.1 Restore all but one Nonfunctional vent paths to FUNCTIONAL status.
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> C. Contingency Measure and associated Restoration Time of Nonconformance A or B not met.
C.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately
Reactor Coolant System Vents TRM 8.4.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.4-2 Revision 7 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.4.4.1 Verify all manual isolation valves in each required vent path are locked in the open position.
24 months 8.4.4.2 Cycle each valve in each required vent path through at least one complete cycle of full travel from the Control Room.
24 months 8.4.4.3 Verify flow through each required reactor coolant vent system vent paths.
24 months
Reactor Coolant System Vents TRM B 8.4.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.4.4-1 Revision 0 BASES 8.4.4 High Point Vents The Reactor Coolant System high point vents are installed per NUREG-0737 item II.B.1 requirements. The functionality of the system ensures capability of venting steam or noncondensable gas bubbles in the reactor cooling system to restore natural circulation following a small break loss of coolant accident.
Pressurizer PORV TRM 8.4.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.5-1 Revision 6 8.4 REACTOR COOLANT SYSTEM 8.4.5 Pressurizer Pilot Operated Relief Valve (PORV)
TECHNICAL NORMAL CONDITIONS TNC 8.4.5 The requirement of TVR 8.4.5.1 shall be performed with an Allowable Value of 2435 psig.
APPLICABILITY:
As specified in Technical Specification 3.4.11.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. TVR 8.4.5.1 not met.
A.1 Evaluate PORV OPERABILITY in accordance with Technical Specification 3.4.11.
Immediately
Pressurizer PORV TRM 8.4.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.5-2 Revision 6 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.4.5.1 Perform CHANNEL CALIBRATION of the PORV opening setpoint.
24 months
Pilot Operated Relief Valve (PORV)
TRM B 8.4.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.4.5-1 Revision 0 BASES 8.4.5 Pilot Operated Relief Valve (PORV)
None.
ASME Code Class 1, 2, and 3 Components TRM 8.4.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.6-1 Revision 19 8.4 REACTOR COOLANT SYSTEM 8.4.6 ASME Code Class 1, 2, and 3 Components TECHNICAL NORMAL CONDITIONS TNC 8.4.6 The structural integrity of ASME Code Class 1, 2, and 3 components shall be maintained in accordance with the Inservice Inspection Program.
APPLICABILITY:
MODES 1, 2, 3, 4, 5, and 6.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Structural integrity of one or more ASME Code Class 1 not meeting the TNC.
A.1 Isolate the affected component.
Prior to increasing the RCS temperature to
> 50F above the minimum temperature required by NDT considerations B. Structural integrity of one or more ASME Code Class 2 not meeting the TNC.
B.1 Isolate the affected component.
Prior to increasing the RCS temperature to
> 200F C. Structural integrity of one or more ASME Code Class 3 not meeting the TNC.
C.1 Isolate the affected component.
Immediately
ASME Code Class 1, 2, and 3 Components TRM 8.4.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.4.6-2 Revision 19 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.4.6.1 Verify the structural integrity of ASME Code Class 1, 2, and 3 components.
In accordance with the Inservice Inspection Program
ASME Code Class 1, 2, and 3 Components TRM B 8.4.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.4.6-1 Revision 19 BASES 8.4.6 ASME Code Class 1, 2, and 3 Components The inspection and testing programs for ASME Code Class 1, 2, and 3 components, except the Steam Generator tubes, ensure that the structural integrity of these components will be maintained at an acceptable level throughout the life of the plant. To the extent possible, the inspection program for these components is in compliance with Section XI of the ASME Boiler and Pressure Vessel Code.
The reference to ASME Code Class 1, 2, and 3 Components in this Technical Requirements Manual (TRM) section pertains to components within the sites Inservice Inspection boundary (i.e., ASME Section XI, Code Class 1, 2, or 3.) This is not to be confused with other sections of the ASME Code. The Inservice Inspection boundary diagrams are depicted on the ISID2 series of drawings.
If containment air cooling (CAC) service water (SW) piping is ever isolated due to a breach of the piping in containment, that system is no longer acting as a penetration boundary. Because the CAC SW piping does not connect with either the reactor coolant system or the containment atmosphere, and post LOCA operation is for the system to be in service, CAC SW penetrations are not subject to testing under the Containment Leakage Rate Testing Program. Therefore, breached CAC SW piping in containment that is isolated would represent unquantifiable secondary containment bypass leakage for the associated CAC SW outlet penetration (LCO 3.6.3).
ECCS Subsystems - Operating TRM 8.5.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.5.1-1 Revision 0 8.5 EMERGENCY CORE COOLING SYSTEMS 8.5.1 ECCS Subsystems - Operating TECHNICAL NORMAL CONDITIONS TNC 8.5.1 The requirements of TVR 8.5.1.1 and 8.5.1.2 shall be performed.
APPLICABILITY:
MODES 1, 2 and 3.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. TNC 8.5.1 not met.
A.1 Comply with the applicable ACTIONS of Technical Specification 3.5.2.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.5.1.1
NOTE--------------------------------
Only the subsystem(s) directly affected by the flowpath modification needs to be tested in accordance with this Verification Requirement.
Each HPI and LPI ECCS subsystem shall be demonstrated OPERABLE by performing a flow test, during shutdown, to verify the injection phase flow rate and flow distribution (for HPI only) meet or exceed the LOCA requirements.
Following completion of a modification to the subsystem flowpath that could alter the subsystem flow characteristics
ECCS Subsystems - Operating TRM 8.5.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.5.1-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS (continued)
TVR VERIFICATION FREQUENCY 8.5.1.2
NOTE--------------------------------
The inspection port on the watertight enclosure may be opened without requiring performance of the vacuum leakage rate test, to perform inspections. After use, the inspection port must be verified as closed in its correct position. Provisions of TS 3.0.3 are not applicable during these inspections.
Each ECCS subsystem shall be demonstrated OPERABLE by performing a vacuum leakage rate test of the watertight enclosure for valves DH-11 and DH-12 that assures the motor operators on valves DH-11 and DH-12 will not be flooded for at least 7 days following a LOCA.
24 months AND After each opening of the watertight enclosure AND After any maintenance on or modification to the watertight enclosure which could affect its integrity
ECCS Subsystems - Operating TRM 8.5.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.5.1-1 Revision 0 BASES 8.5.1 ECCS Subsystems - Operating The verification requirement for flow and flow distribution (HPI only) testing provides assurance that proper ECCS flows will be maintained in the event of a LOCA. Maintenance of proper flow resistance and pressure drop in the piping system to each injection point is necessary to:
(1) prevent total pump flow from exceeding runout conditions when the system is in its minimum resistance configuration, (2) ensure an amount of ECCS flow that is equal to or greater than the flow assumed in the ECCS-LOCA analyses, and (3) ensure proper flow distribution between HPI injection points, in accordance with the assumptions used in the ECCS-LOCA analyses.
The frequency of Technical Verification Requirement 8.5.1.1 ensures that changes in system performance are detected and verified not to degrade the subsystem's ability to provide the flows that are required for accident mitigation. The HPI and LPI pumps are monitored in accordance with other surveillance requirements that specifically measure pump performance.
Therefore, this surveillance does not apply to subsystem modifications that are limited to only the pumps.
The intent of Technical Verification Requirement 8.5.1.1 is to verify that the subsystem flow characteristics have not been unacceptably altered by modifications that could affect the resistance of the subsystem flowpath. Taken together, the pump verifications and this verification ensure that the LOCA analyses remain valid.
Technical Verification Requirement 8.5.1.1 requires verification of flow rate and flow distribution (HPI only) for the injection phase. This may be accomplished by testing in an alternate system lineup (e.g., RCS recirculation) and verifying equivalent flow rates by calculation, as long as the affected portion of the flowpath is in the tested flowpath.
Decay Heat Removal System valves DH-11 and DH-12 are located in an area that would be flooded following a LOCA. These valves are located in a watertight enclosure to ensure their functionality up to seven days following a LOCA. Verification Requirements are provided to verify the acceptable leak tightness of this enclosure. An inspection port is located on this watertight enclosure, which is typically used for performing inspections inside the enclosure.
During the vacuum leakage rate test, the inspection port is in a closed position and subject to the test. This inspection port may be subsequently opened for use in viewing inside the enclosure. Opening this inspection port will not require performance of the vacuum leakage rate test because of the design of the closure fitting, which will preclude leakage under LOCA conditions, when properly installed. Proper installation includes independent verification.
ECCS Subsystems - Shutdown TRM 8.5.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.5.2-1 Revision 1 8.5 EMERGENCY CORE COOLING SYSTEMS 8.5.2 ECCS Subsystems - Shutdown TECHNICAL NORMAL CONDITIONS TNC 8.5.2 The requirements of TVR 8.5.2.1 and 8.5.2.2 shall be performed.
APPLICABILITY:
MODE 4.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. TNC 8.5.2 not met.
A.1 Comply with the applicable ACTIONS of Technical Specification 3.5.3.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.5.2.1
NOTE--------------------------------
Only the subsystem(s) directly affected by the flowpath modification needs to be tested in accordance with this Verification Requirement.
Each LPI ECCS subsystem shall be demonstrated OPERABLE by performing a flow test, during shutdown, to verify the injection phase flow rate meets or exceeds the LOCA requirements.
Following completion of a modification to the subsystem flowpath that could alter the subsystem flow characteristics
ECCS Subsystems - Shutdown TRM 8.5.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.5.2-2 Revision 1 TECHNICAL VERIFICATION REQUIREMENTS (continued)
TVR VERIFICATION FREQUENCY 8.5.2.2
NOTE--------------------------------
The inspection port on the watertight enclosure may be opened without requiring performance of the vacuum leakage rate test, to perform inspections. After use, the inspection port must be verified as closed in its correct position. Provisions of TS 3.0.3 are not applicable during these inspections.
Each LPI ECCS subsystem shall be demonstrated OPERABLE by performing a vacuum leakage rate test of the watertight enclosure for valves DH-11 and DH-12 that assures the motor operators on valves DH-11 and DH-12 will not be flooded for at least 7 days following a LOCA.
24 months AND After each opening of the watertight enclosure AND After any maintenance on or modification to the watertight enclosure which could affect its integrity
ECCS Subsystems - Shutdown TRM 8.5.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.5.2-1 Revision 0 BASES 8.5.2 ECCS Subsystems - Shutdown The verification requirement for flow testing provides assurance that proper ECCS flows will be maintained in the event of a LOCA. Maintenance of proper flow resistance and pressure drop in the piping system to each injection point is necessary to:
(1) prevent total pump flow from exceeding runout conditions when the system is in its minimum resistance configuration, and (2) ensure an amount of ECCS flow that is equal to or greater than the flow assumed in the ECCS-LOCA analyses.
The frequency of Technical Verification Requirement 8.5.2.1 ensures that changes in system performance are detected and verified not to degrade the subsystem's ability to provide the flows that are required for accident mitigation. The LPI pumps are monitored in accordance with other surveillance requirements that specifically measure pump performance. Therefore, Technical Verification Requirement 8.5.2.1 does not apply to subsystem modifications that are limited to only the pumps.
The intent of Technical Verification Requirement 8.5.2.1 is to verify that the subsystem flow characteristics have not been unacceptably altered by modifications that could affect the resistance of the subsystem flowpath. Taken together, the pump surveillances and this verification ensure that the LOCA analyses remain valid.
Technical Verification Requirement 8.5.2.1 requires verification of flow rate for the injection phase. This may be accomplished by testing in an alternate system lineup (e.g.,
RCS recirculation) and verifying equivalent flow rates by calculation, as long as the affected portion of the flowpath is in the tested flowpath.
Decay Heat Removal System valves DH-11 and DH-12 are located in an area that would be flooded following a LOCA. These valves are located in a watertight enclosure to ensure their operability up to seven days following a LOCA. Verification Requirements are provided to verify the acceptable leak tightness of this enclosure. An inspection port is located on this watertight enclosure, which is typically used for performing inspections inside the enclosure. During the vacuum leakage rate test, the inspection port is in a closed position and subject to the test. This inspection port may be subsequently opened for use in viewing inside the enclosure. Opening this inspection port will not require performance of the vacuum leakage rate test because of the design of the closure fitting, which will preclude leakage under LOCA conditions, when properly installed. Proper installation includes independent verification.
Emergency Sump Debris TRM 8.5.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.5.3-1 Revision 5 8.5 EMERGENCY CORE COOLING SYSTEMS 8.5.3 Emergency Sump Debris TECHNICAL NORMAL CONDITIONS TNC 8.5.3 The requirements of TVR 8.5.3.1 and TVR 8.5.3.2 shall be met.
APPLICABILITY:
MODES 1, 2, 3 and 4.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. TNC 8.5.3 not met.
A.1 Evaluate OPERABILITY of ECCS per Technical Specification 3.5.2 and 3.5.3.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.5.3.1 Perform a visual inspection of all accessible areas of the containment to verify that no loose debris (rags, trash, clothing, etc) is present in the containment which could be transported to the containment emergency sump and cause restriction of the pump suction during LOCA conditions.
Prior to establishing Containment OPERABILITY 8.5.3.2 Perform a visual inspection of all areas of containment affected by an entry to verify that no loose debris (rags, trash, clothing, etc) is present in the containment which could be transported to the containment emergency sump and cause restriction of the pump suction during LOCA conditions.
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> while work is ongoing AND During final exit after completion of work (containment closeout) when containment OPERABILITY is established
Emergency Sump Debris TRM B 8.5.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.5.3-1 Revision 5 BASES 8.5.3 Emergency Sump Debris None
Combustible Gas Control - Hydrogen Analyzers TRM 8.6.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.6.1-1 Revision 0 8.6 CONTAINMENT SYSTEMS 8.6.1 Combustible Gas Control - Hydrogen Analyzers TECHNICAL NORMAL CONDITIONS TNC 8.6.1 Two independent containment hydrogen analyzers shall be FUNCTIONAL.
APPLICABILITY:
MODES 1 and 2.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One hydrogen analyzer Nonfunctional.
A.1 Restore the non-functional analyzer to FUNCTIONAL status.
30 days B. Both hydrogen analyzers Nonfunctional.
B.1 Restore one analyzer to FUNCTIONAL status.
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> C. Contingency Measures and associated Restoration Time of Nonconformance A or B not met.
C.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately
Combustible Gas Control - Hydrogen Analyzers TRM 8.6.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.6.1-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.6.1.1 Perform a CHANNEL CHECK.
31 days 8.6.1.2 Perform a CHANNEL CALIBRATION using sample gases containing:
- a.
0 volume % hydrogen, balance nitrogen; and
- b.
2.0 to 3.0 volume % hydrogen, balance nitrogen.
46 days on a STAGGERED TEST BASIS
Combustible Gas Control - Hydrogen Analyzers TRM 8.6.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.6.1-1 Revision 0 BASES 8.6.1 Combustible Gas Control - Hydrogen Analyzers Two redundant hydrogen analyzers are available to determine the content of hydrogen within the containment vessel. The hydrogen analyzers provide diagnostic capability for beyond design-basis accidents.
A rule change to 10 CFR 50 dated September 16, 2003 (68 FR 54123) eliminated the requirement that the hydrogen analyzers be safety-related components, and allowed their requirements to be relocated from the Technical Specifications.Section III.D of the final rule (68 FR 54127) categorized the hydrogen monitoring system as Category 3 of Regulatory Guide 1.97 because the monitors are required to diagnose the course of significant beyond design-basis accidents.Section III.D further stated that Category 3 applies to high-quality, off-the-shelf backup and diagnostic instrumentation.
Steam Generator Pressure / Temperature Limitation TRM 8.7.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.1-1 Revision 0 8.7 PLANT SYSTEMS 8.7.1 Steam Generator Pressure / Temperature Limitation TECHNICAL NORMAL CONDITIONS TNC 8.7.1 The temperature of the secondary coolant in the steam generators shall be
> 110°F when the pressure of the secondary coolant in the steam generator is > 237 psig.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Requirements of TNC not met.
A.1 Reduce the steam generator pressure of the applicable side to
< 237 psig.
AND A.2 Determine by engineering evaluation the effects of the overpressurization on the structural integrity of the steam generator and that the steam generator remains acceptable for continued operation.
30 minutes Prior to increasing steam generator pressure > 237 psig TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.7.1.1
NOTE--------------------------------
Only required when the secondary pressure in the steam generator is > 237 psig and Tavg is < 200°F Verify temperature of secondary coolant in each steam generator is > 110°F.
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />
Steam Generator Pressure / Temperature Limitation TRM 8.7.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.1-1 Revision 0 BASES 8.7.1 Steam Generator Pressure / Temperature Limitation The limitation on steam generator pressure and temperature ensures that the pressure induced stresses in the steam generators do not exceed the maximum allowable fracture toughness stress limits. The limitations of 110°F and 237 psig are based on a steam generator RTndt of 40°F and are sufficient to prevent brittle fracture.
Sealed Source Contamination TRM 8.7.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.2-1 Revision 21 8.7 PLANT SYSTEMS 8.7.2 Sealed Source Contamination TECHNICAL NORMAL CONDITIONS TNC 8.7.2 Each sealed source containing radioactive material > 100 Ci of beta and/or gamma emitting material or > 5 Ci of alpha emitting material, shall be free of > 0.005 Ci of removable contamination.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES
NOTE-----------------------------------------------------------------
Separate Nonconformance entry is allowed for each sealed source.
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One or more sealed sources with removable contamination not within limits.
A.1 Withdraw the sealed source from use.
AND A.2.1 Initiate action to decontaminate and repair the sealed source.
OR A.2.2 Initiate action to dispose of the sealed source in accordance with NRC Regulations.
Immediately Immediately Immediately
Sealed Source Contamination TRM 8.7.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.2-2 Revision 21 TECHNICAL VERIFICATION REQUIREMENTS
NOTES----------------------------------------------------------
- 1. The TVRs shall be performed by company personnel or other personnel specifically authorized by the NRC or Agreement State.
- 2. The test method used shall have a detection sensitivity of < 0.005 Ci per test sample.
TVR VERIFICATION FREQUENCY 8.7.2.1
NOTE--------------------------------
Startup sources and fission detectors previously subjected to core flux are excluded.
Perform leakage and contamination testing on each sealed source in use containing radioactive materials with a half-life > 30 days (excluding Hydrogen 3) and in any form other than gas.
184 days 8.7.2.2 Perform leakage and contamination testing for each sealed source and fission detector not in use.
Prior to placing in use or transferring to another licensee, if not performed within the previous 184 days 8.7.2.3 Perform leakage and contamination testing on each sealed source and fission detector not in use that was received without a certificate indicating the last test date.
Prior to placing in use 8.7.2.4 Perform leakage and contamination testing on each sealed startup source and fission detector.
Once within 31 days prior to being subjected to core flux or installed in the core AND Following repair or maintenance to the sealed source 8.7.2.5 Submit report to NRC for sealed source or fission detector leakage tests revealing the presence of 0.005 Ci of removable contamination.
12 months
Sealed Source Contamination TRM B 8.7.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.2-1 Revision 21 BASES 8.7.2 Sealed Source Contamination The limitations on removable contamination for sources requiring leak testing, including alpha emitters, are based on 10 CFR 70.39(c) limits for plutonium. This limitation will ensure that leakage from by-product, source and special nuclear material sources will not exceed allowable intake values.
Snubbers TRM 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.3-1 Revision 15 8.7 PLANT SYSTEMS 8.7.3 Snubbers TECHNICAL NORMAL CONDITIONS TNC 8.7.3 Each safety related snubber shall perform its associated support function(s).
APPLICABILITY:
MODES 1, 2, 3, and 4, MODES 5 and 6 for snubbers located on systems required OPERABLE in those MODES.
CONTINGENCY MEASURES
NOTE--------------------------------------------------------------------
Separate entry is allowed for each snubber.
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One or more required snubbers unable to perform their associated support function.
A.1 Declare the supported system or train LCO(s) not met.
AND A.2.2 Verify at least one train (or subsystem) of systems supported by the inoperable snubbers would remain capable of performing their required safety or support function for postulated design loads other than seismic loads.
AND Immediately Immediately Immediately
Snubbers TRM 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.3-2 Revision 15 CONTINGENCY MEASURES (continued)
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. (continued)
A.2.3 ---------NOTE------------------
Only applicable if LCO 3.0.8.a is used in MODES 1,2,3 or 4.
Verify at least one EFW train not associated with the inoperable snubber is available.
AND A.2.4 ---------NOTE------------------
Only applicable if LCO 3.0.8.b is used in MODES 1,2,3 or 4.
Verify at least one EFW train not associated with the inoperable snubber(s), or some alternative means of core cooling is available.
Immediately Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.7.3.1 Perform snubber inservice inspections in accordance to Inservice Testing Program.
In accordance with Table 8.7.3-1
Snubbers TRM 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.3-3 Revision 15 Table 8.7.3-1 (page 1 of 4)
Snubber Inservice Testing Program Safety-related snubbers are listed in the latest revision of applicable verification test procedure(s). Snubbers may be added to, or removed from, safety-related systems and their assigned groups without a License Amendment.
In accordance with 10 CFR 50.55a(b)(3)(v)B with Conditions and Clarifications - the snubber population, as defined in ASME OM Code, 2004 Edition with OMa 2005 and OMb 2006 Addenda, Section IST, Subsection ISTA, article ISTA-1100(c) - complies with the requirements for Examination and Testing of the ASME OM Code, 2004 Edition with OMa-2006 and OMb-2006 Addenda, Section IST, Subsections ISTA and ISTD, and Code Case OMN-13. The Snubber IST Program complies with the requirements set forth in the Snubber Program Plan and the Snubber Program Procedure.
A. Visual Inspection Program
- 1. General Requirements At least once per inspection interval, each group of snubbers in use in the plant shall be visually inspected in accordance with Section A.2 and A.3. Visual inspections may be performed with binoculars, or other visual support devices, for those snubbers that are difficult to access and where required to keep exposure as low as reasonably achievable. Response to failures shall be in accordance with Section A.4.
- 2. Inspection Interval The inspection interval may be applied on the basis of snubber groups. The snubber groups may be established based on physical characteristics and accessibility.
Inaccessible snubbers are defined as those located: (a) inside containment, (b) in high radiation exposure zones, or (c) in areas where accessibility is limited by physical constraints such as the need for scaffolding.
Each of the groups may be inspected independently according to the schedule determined by ASME OM Code Case OMN-13, not to exceed 120 months.
- 3. Acceptance Criteria A snubber shall be considered able to perform its associated support function as a result of visual inspection if: (1) there is no visible indication of damage or inoperability, and (2) attachments to the foundation or supporting structure are secure.
Snubbers TRM 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.3-4 Revision 15 Table 8.7.3-1 (page 2 of 4)
Snubber Inservice Testing Program
- 4. Response to Failures For each snubber unit which does not meet the visual inspection acceptance criteria of Section A.3:
- a.
Determine the snubber is able to perform its associated support function by functionally testing the snubber in the as-found condition per Section B, unless the (hydraulic) snubber was determined Nonfunctional because the fluid port was found uncovered; and
- b.
Perform an evaluation to determine the cause of the unacceptability.
- 5. Transient Event Inspection An inspection shall be performed of all hydraulic and mechanical snubbers attached to sections of systems that have experienced unexpected, potentially damaging transients as determined from a review of operational data. The affected snubber(s) and system(s) shall be reviewed and any appropriate corrective action taken. In addition to satisfying the visual inspection acceptance criteria, freedom-of-motion of mechanical snubbers shall be verified using at least one of the following: (1) manually induced snubber movement; or (2) evaluation of in-place snubber piston setting; or (3) stroking the mechanical snubber through its full range of travel.
Snubbers TRM 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.3-5 Revision 15 Table 8.7.3-1 (page 3 of 4)
Snubber Inservice Testing Program B.
Functional Test Program
- 1. General Requirements At least once per inspection interval, a representative sample of each group of snubbers in use in the plant shall be functionally tested in accordance with Section B.2 and B.3.
Response to the failures shall be in accordance with Section B.4.
For all snubbers, functional testing shall consist of either bench testing or in-place testing.
- 2. Inspection Interval and Sample Criteria The snubbers may be categorized into groups based on physical characteristics and accessibility. Each group may be tested independently from the standpoint of performing additional tests if failures are discovered. The snubbers (if any) attached to the Steam Generators and Reactor Coolant Pumps shall be considered their own group.
The inspection interval for functional testing shall be every fuel cycle, and may not begin any earlier than 60 days before a scheduled refueling outage.
Snubbers which are scheduled for removal for seal maintenance may be included in the test sample prior to any maintenance on the snubber.
The representative sample shall consist of at least 10 percent (rounded off to next highest integer) of each group of snubbers in use in the Plant.
- 3. Acceptance Criteria For hydraulic snubbers (either inplace testing or bench testing), the test shall verify that:
- a.
Snubber piston will allow the hydraulic fluid to "bypass" from one side of the piston to the other to assure unrestrained action is achieved within the specified range of velocity or acceleration in both tension and compression.
- b.
When the snubber is subjected to a movement which creates a load condition that exceeds the specified range of velocity or acceleration, the hydraulic fluid is trapped in one end of the snubber causing suppression of that movement.
- c.
Snubber release rate or bleed rate, where required, occurs in compression and tension.
Snubbers TRM 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.3-6 Revision 15 Table 8.7.3-1 (page 4 of 4)
Snubber Inservice Testing Program For mechanical snubber in place and bench testing, the test shall verify that:
- a.
The force that initiates free movement of the snubber rod in either tension or compression is less than the specified maximum drag force.
- b.
Activation (restraining action) is achieved in both tension and compression within the specified range.
- 4. Response to Failures For each snubber failure per Section B.3:
- a.
Declare the supported system or train LCO(s) not met or enter Tech Spec 3.0.8 and TNC 8.7.3; and
- b.
Within the specified inspection interval, functionally test an additional sample of at least 5 percent of the snubber units from the group that the Nonfunctional snubber unit is in.
The functional testing of an additional sample of at least 5 percent from the Nonfunctional snubbers group is required for each snubber unit determined to be Nonfunctional in subsequent functional tests, or until all snubbers in that group have been tested; and
- d.
The cause of the snubber failure will be evaluated and, if caused by a manufacturing or design deficiency, all snubbers of the same or similar design subject to the same defect shall be functionally tested within the current inspection interval.
Snubbers TRM B 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.3-1 Revision 15 BASES 8.7.3 Snubbers The following basis has been left largely intact as a historical reference that also complies with the current ASME OM Code snubber requirements. The historical snubber bases for Davis-Besse has been based in the Technical Specifications and/or Technical Requirements manual under approved relief requests. The 4th 10 year Interval for Inservice Inspection (ISI) and Inservice Testing (IST) began on September 21st, 2012 and will expire on September 20th, 2022.
During this time interval, the snubber program will comply with all requirements of the 2004 edition of the ASME OM Code with the 2005 OMa and 2006 OMb Addenda. This requires a Snubber Program Plan and Snubber Program Procedure. Both of these documents are available in the document management system and contain the additional detail for implementatioin of the Davis-Besse Snubber Program in accordance with the ASME OM Code.
All safety-related snubbers are required to meet their associated support function(s) to ensure the structural integrity of the reactor coolant system and all other safety-related systems is maintained during and following a dynamic event. Snubbers excluded from this inspection program are those installed on safety-related systems for loads other than dynamic or on nonsafety-related systems and then only if their failure or failure of the system on which they are installed, would have no adverse effect on any safety related system during a dynamic event.
A Nonfuntional Snubber is defined as:
- 1.
For Visual test
- a.
The fluid no longer is supplied to the valve block, or b
Mounting pins are disengaged from the snubber.
- c.
Attachment to foundation or supporting structure is not secure.
- 2.
For Functional test:
- a.
The snubber (excluding and anchors, i.e., pin-to-pin) does not meet specified test criteria.
The visual inspection frequency is based upon maintaining a constant level of snubber protection to systems. Therefore, the required inspection interval is determined by the number of nonfunctional snubbers found during and inspection, the total population or group size for each snubber type, and the previous inspection interval. Inspections performed before that interval has elapsed may be used as a new reference point to determine the next inspection.
Any inspection whose results require a shorter inspection interval will override the previous schedule.
When the cause of the rejection of a snubber is clearly established and remedied for that snubber and for any other snubbers that may be generically susceptible, and verified by functional testing, that snubber may be exempted from being counted as nonfunctional.
Snubbers TRM B 8.7.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.3-2 Revision 15 BASES 8.7.3 Snubbers (Cont)
When a snubber is found not meeting its associated support function through a visual inspection or functional test, entry into Tech Spec 3.0.8 and TNC 8.7.3 is required and an engineering evaluation is performed as part of the Corrective Action Program response, in addition to the determination of the snubber mode of failure, in order to determine if any safety-related component or system has been adversely affected by the nonfunctional snubber.
To provide assurance of snubber functional reliability, a representative sample of the installed snubbers will be functionally tested every fuel cycle. Observed failures of these sample snubbers shall require functional testing of additional units. When a snubber is found not meeting its associated support function due to failure to lock up or failure to move (i.e., frozen in place), the cause will be evaluated for further action or testing.
In cases where the case of failure has been identified, additional snubbers that have a high probability for the same type of failure or are being used in the same application that caused the failure shall be tested. This requirement increases the probability of locating snubbers not meeting its associated support function without testing 100% of the snubbers.
Hydraulic snubbers and mechanical snubbers may each be treated as a different entity for the above programs.
Contingency Measures A.2.2, A.2.3, and A.2.4 are described below. Those verifications are required to satisfy regulatory commitment O21964.
Every time the provisions of LCO 3.0.8 are used, verification of at least one train (or subsystem) of systems supported by the inoperable snubbers would remain capable of performing their required safety or support functions for postulated design loads other than seismic loads is required. LCO 3.0.8 does not apply to non-seismic snubbers. In addition, a record of the design function of the inoperable snubber (i.e., seismic vs. non-seismic), implementation of any restrictions, and the associated plant configuration shall be available on a recoverable basis for NRC inspection.
When LCO 3.0.8.a is used in MODES 1,2,3 or 4, at least one EFW train (including a minimum set of supporting equipment required for its successful operation) not associated with the inoperable snubber(s), must be available.
When LCO 3.0.8.b is used in MODES 1,2,3 or 4, at least one EFW train (including a minimum set of supporting equipment required for its successful operation) not associated with the inoperable snubber(s), or some alternative means of core cooling (e.g., feed and bleed, fire water system or "aggressive secondary cooldown" using the steam generators) must be available.
Liquid Storage Tanks TRM 8.7.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.4-1 Revision 0 8.7 PLANT SYSTEMS 8.7.4 Liquid Storage Tanks TECHNICAL NORMAL CONDITIONS TNC 8.7.4 The quantity of radioactivity contained in each outdoor liquid storage tank that is not surrounded by liners, dikes, or walls, capable of holding the tank contents and that does not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System, shall be within the limit of Technical Specification 5.5.11.b.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES
NOTE-----------------------------------------------------------------
Separate Nonconformance entry is allowed for each unprotected outdoor liquid storage tank.
NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. The quantity of radioactivity contained in any unprotected outdoor liquid storage tank not within limit.
A.1 Suspend addition of radioactive material to the tank.
AND A.2 Reduce tank contents to within the limit.
AND A.3 Describe the event leading to this condition.
Immediately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> In the next Radioactive Effluent Release Report
Liquid Storage Tanks TRM 8.7.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.4-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.7.4.1 Verify the quantity of radioactivity contained in each unprotected outdoor liquid storage tank is within the limit by analyzing a representative sample of the tank contents.
7 days when radioactive materials are being added to the tank
Liquid Storage Tanks TRM B 8.7.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.4-1 Revision 0 BASES 8.7.4 Liquid Storage Tanks Restricting the quantity of radioactive material contained in the specified tanks provides assurance that in the event of an uncontrolled release of the tank contents, the resulting concentrations would be less than the limits of 10 CFR Part 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area.
Explosive Gas Mixture TRM 8.7.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.5-1 Revision 0 8.7 PLANT SYSTEMS 8.7.5 Explosive Gas Mixture TECHNICAL NORMAL CONDITIONS TNC 8.7.5 The concentration of oxygen in the Waste Gas System shall be limited to 2% by volume when the hydrogen concentration exceeds 4% by volume.
APPLICABILITY:
At all times.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Oxygen concentration in the Waste Gas System
> 2% by volume and 4% by volume.
A.1 Reduce Waste Gas System oxygen concentration to within the limit.
48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> B. Contingency Measure and associated Restoration Time of Nonconformance A not met.
OR Oxygen concentration contained in the waste gas system is > 4% by volume, and Hydrogen is
> 4% by volume.
B.1 Suspend additions of waste gases to the system.
AND B.2 Initiate action to reduce the oxygen concentration to 2% by volume.
Immediately Immediately
Explosive Gas Mixture TRM 8.7.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.5-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.7.5.1 Verify the oxygen concentration contained in the Waste Gas System is within the limit by monitoring the waste gases in the Waste Gas System.
Continuously
Explosive Gas Mixture TRM B 8.7.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.5-1 Revision 0 BASES 8.7.5 Explosive Gas Mixture This specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the waste gas system is maintained below the flammability limits of hydrogen with oxygen. Maintaining the concentration of hydrogen or oxygen below their flammability limits provides assurance that the releases of radioactive materials will be controlled in conformance with the requirements of General Design Criterion 60 of Appendix A to 10 CFR Part 50.
TVR 8.7.5.1, which requires continuous monitoring of the Waste Gas System, is performed by the instrumentation covered in TNC 8.3.6, Waste Gas System Oxygen Monitoring. The contingency measures in TNC 8.3.6 address loss of monitoring.
Auxiliary Feedwater System TRM 8.7.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.6-1 Revision 8 8.7 PLANT SYSTEMS 8.7.6 Auxiliary Feedwater System TECHNICAL NORMAL CONDITIONS TNC 8.7.6 The following Auxiliary Feedwater System features shall be FUNCTIONAL or in the required condition:
- a.
Auxiliary Feed Pump Turbine Inlet Steam Pressure Interlocks;
- b.
Auxiliary Feed Pump Suction Pressure Interlocks; and
- c.
CW 196, CW 197, FW 32, FW 91, and FW 106 in the closed position.
APPLICABILITY:
MODES 1, 2, and 3.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Auxiliary Feed Pump Turbine Inlet Steam Pressure Interlock Nonfunctional.
A.1 Restore Auxiliary Feed Pump Turbine Inlet Steam Pressure Interlock to FUNCTIONAL status.
7 days B. Contingency Measure and associated Restoration Time of Nonconformance A not met.
B.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately C. TNC 8.7.6 not met for reasons other than Nonconformance A.
C.1 Evaluate OPERABILITY of associated AFW train per Technical Specification 3.7.5.
Immediately
Auxiliary Feedwater System TRM 8.7.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.6-2 Revision 8 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.7.6.1 Not Used 8.7.6.2
NOTE---------------------------------
Not required to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after steam line pressure is > 275 psig.
Perform CHANNEL FUNCTIONAL TEST on the Auxiliary Feed Pump Turbine Inlet Steam Pressure Interlock.
31 days 8.7.6.3 Perform CHANNEL FUNCTIONAL TEST on the Auxiliary Feed Pump Suction Pressure Interlocks.
31 days 8.7.6.4 Not Used 8.7.6.5 Verify valves CW 196, CW 197, FW 32, FW 91, and FW 106 are in the closed position.
31 days 8.7.6.6 Perform CHANNEL CALIBRATION on the Auxiliary Feed Pump Turbine Inlet Steam Pressure Interlocks.
24 months 8.7.6.7 Perform CHANNEL CALIBRATION on the Auxiliary Feed Pump Low Suction Pressure Interlocks.
12 months 8.7.6.8 Perform CHANNEL CALIBRATION on the Auxiliary Feed Pump Low-Low Suction Pressure Interlocks.
24 months
Auxiliary Feedwater System TRM B 8.7.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.6-1 Revision 7 BASES 8.7.6 Auxiliary Feedwater System Verification of the turbine plant cooling water valves (CW 196 and CW 197), the startup feedwater pump suction valves (FW 32 and FW 91), and the startup feedwater pump discharge valve (FW 106) in the closed position is required to address the concerns associated with potential pipe failures in the auxiliary feedwater pump rooms, that could occur during operation of the startup feedwater pump.
The FUNCTIONALITY of the Auxiliary Feed Pump Turbine Inlet Steam Pressure Interlocks is required only for high energy line break concerns and does not affect Auxiliary Feedwater System OPERABILlTY. However, an additional feature is provided for the Train 2 interlocks. A separate relay prevents actuation of the Train 2 interlocks until after a 25 second time delay.
This feature provides protection for the specific scenario of a steam line break on OTSG 1, concurrent with a loss of offsite power and a single failure of AFP 1. Failure of this time delay relay (a non Tech Spec support feature) should be addressed under Nonconformance C (Ref. 1).
The Service Water System is the safety-related secondary source of the water and must be available for the associated Auxiliary Feedwater System train to be OPERABLE. The transfer is initiated upon detection of a low suction pressure at the suction of the auxiliary feedwater pumps by suction pressure interlock switches. These pressure switches, upon sensing low suction pressure, will automatically transfer the suction of the auxiliary feedwater pumps to the Service Water System. On a sustained low-low suction pressure, additional Auxiliary Feedwater Pump Suction Pressure Interlocks will operate to close the steam supply valves to protect the turbine driven auxiliary feedwater pumps from cavitation. Both the low and the low-low suction Auxiliary Feed Pump Suction Pressure Interlocks are non Tech Spec support features that are required for OPERABILITY of the associated auxiliary feedwater train.
REFERENCES
- 1.
UFSAR, Section 9.2.7.3
MDFP Lube Oil Interlocks TRM 8.7.7 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.7.7-1 Revision 0 8.7 PLANT SYSTEMS 8.7.7 Motor Driven Feedwater Pump (MDFP) Lube Oil Interlocks TECHNICAL NORMAL CONDITIONS TNC 8.7.7 The requirements of TVR 8.7.7.1 shall be performed.
APPLICABILITY:
MODES 1, 2, and 3, MODE 4 when steam generator is relied upon for heat removal.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. TNC 8.7.7.1 not met.
A.1 Evaluate OPERABILITY of MDFP train per Technical Specification 3.7.5.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.7.7.1 Verify proper operation of the Motor Driven Feedwater Pump lube oil interlocks.
24 months
MDFP Lube Oil Interlocks TRM B 8.7.7 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.7.7-1 Revision 0 BASES 8.7.7 None
A.C. Sources - Operating TRM 8.8.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.8.1-1 Revision 20 8.8 ELECTRICAL POWER SYSTEMS 8.8.1 AC Sources - Operating TECHNICAL NORMAL CONDITIONS TNC 8.8.1
- a. The requirements of TVR 8.8.1.1 and TVR 8.8.1.2 shall be performed.
AND
- b. The switchyard shall not be in a single point vulnerable configuration.
APPLICABILITY:
MODES 1, 2, 3, and 4.
CONTINGENCY MEASURES Nonconformance Contingency Measures Restoration Time A. TVR 8.8.1.1 or TVR 8.8.1.2 not met.
A.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
AND A.2 Evaluate EDG(s) for OPERABILITY requirements of Technical Specification 3.8.1.
Immediately Immediately B. Switchyard in a single point vulnerable configuration.
B.1 Enter Technical Specification 3.8.1 Condition for one inoperable offsite circuit.
Immediately
A.C. Sources - Operating TRM 8.8.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.8.1-2 Revision 20 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.8.1.1 For each EDG verify that the auto-connected loads do not exceed the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> rating of 2838 kw.
24 months 8.8.1.2 For each EDG, perform inspection in accordance with procedures prepared in conjunction with its manufacturers recommendations or industry practices.
NOTE-----------
Extension allowance per TRM 6.4 is not allowed.
30 months
A.C. Sources - Operating TRM B 8.8.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.8.1-1 Revision 20 BASES 8.8.1 AC Sources - Operating Technical Verification Requirement 8.8.1.1 ensures that the emergency diesel generators are capable of supplying all automatically connected loads.
NRC Log Number 5668, dated May 31, 2000 provides guidance relative to the operability of the offsite A.C. electrical power sources. Switchyard equipment can be removed from service or switchyard breakers can be opened that leaves the remaining switchyard equipment vulnerable to a single point failure that would result in a loss of offsite power. These configurations do not satisfy GDC 17 requirements. In these cases, the switchyard is considered to be in a Vulnerable Configuration that does not satisfy TNC 8.8.1.b. TS 3.8.1 Condition A must be entered and the appropriate actions taken as specified.
Whenever switchyard components are out of service, the resulting configuration must be evaluated to determine if a vulnerable switchyard configuration exists. The 345 kV system operating procedure provides additional details.
SBODG Availability TRM 8.8.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.8.2-1 Revision 7 8.8 ELECTRICAL POWER SYSTEMS 8.8.2 Station Blackout Diesel Generator (SBODG) Availability TECHNICAL NORMAL CONDITIONS TNC 8.8.2 The requirements of TVR 8.8.2.1 and TVR 8.8.2.2 shall be performed.
APPLICABILITY:
MODES 1, 2, 3, and 4, with an emergency diesel generator (EDG) removed from service for preventive maintenance activities of greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. SBODG Nonfunctional.
A.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.8.2.1 Verify the SBODG is capable of connection to the essential bus associated with an emergency diesel generator removed from service for preventive maintenance.
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> prior to removing an emergency diesel generator from service for preventive maintenance of greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter
SBODG Availability TRM 8.8.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.8.2-2 Revision 7 TVR VERIFICATION FREQUENCY 8.8.2.2 Verify performance of SBODG test DB-SC-04271 within the previous 30 days.
8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> prior to removing emergency diesel generator from service for preventive maintenance of greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
SBDG Availability TRM B 8.8.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.8.2-1 Revision 0 BASES 8.8.2 SBODG Availability The Contingency Measures provide verification that the Alternate A. C. (AAC) power source, the Station Blackout Diesel Generator, is functional and capable of being connected to the safety bus associated with the inoperable Emergency Diesel Generator. These actions are consistent with the NRC criteria for ensuring that the probability of a core damage accident given a Station Blackout event is not significantly increased due to the performance of Emergency Diesel Generator preventive maintenance of greater than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> during power operations.
These actions are applicable only when an Emergency Diesel Generator becomes inoperable for the performance of preventive maintenance. (Reference NRC Safety Evaluation for License Amendment 206, dated February 26, 1996)
Communications TRM 8.9.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.9.1-1 Revision 0 8.9 REFUELING OPERATIONS 8.9.1 Communications TECHNICAL NORMAL CONDITIONS TNC 8.9.1 Direct communications shall be maintained between the control room and personnel at the refueling station.
APPLICABILITY:
During movement of irradiated fuel assemblies in containment.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. Direct communications between the control room and personnel at the refueling station not maintained.
A.1 Suspend movement of irradiated fuel assemblies.
AND A.2 Suspend operations involving positive reactivity additions that could result in loss of required SDM or boron concentration.
Immediately Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.9.1.1 Verify direct communications between the control room and personnel at the refueling station.
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> prior to the start of movement of irradiated fuel assemblies in containment AND Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter
Communications TRM 8.9.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.9.1-1 Revision 0 BASES 8.9.1 Communications The requirements for communications capability ensures that refueling station personnel can be promptly informed of significant changes in the facility status or core reactivity condition during movement of irradiated fuel assemblies in containment.
Crane Travel - Fuel Handling Building TRM 8.9.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.9.2-1 Revision 18 8.9 REFUELING OPERATIONS 8.9.2 Crane Travel - Fuel Handling Building TECHNICAL NORMAL CONDITIONS TNC 8.9.2 Loads > 2430 pounds shall be prohibited from travel over fuel assemblies in the spent fuel pool.
APPLICABILITY:
With fuel assemblies in the spent fuel pool.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. TNC 8.9.2 not met.
A.1 Place the crane load in a safe condition.
Immediately TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.9.2.1 Verify the weight of each load, other than a fuel assembly, is 2430 pounds.
Prior to moving each load over fuel assemblies in the spent fuel pool
Crane Travel - Fuel Handling Building TRM 8.9.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.9.2-1 Revision 18 BASES 8.9.2 Crane Travel - Fuel Handling Building The restriction on movement of loads in excess of the nominal weight of a fuel assembly in a failed fuel container over other fuel assemblies in the spent fuel pool ensures that in the event this load is dropped (1) the activity release will not exceed the source term assumed in the design basis fuel handling accident for outside containment, and (2) any possible distortion of fuel in the storage racks will not result in a critical array.
The restriction is applicable to the movement of heavy loads over fuel assemblies in the spent fuel pool. The restriction does not apply to movement of heavy loads such as a Dry Shielded Canister top shield plug over fuel assemblies in the Cask Pit while using the single-failure-proof main hoist on the spent fuel cask crane as part of a single-failure-proof handling system where heavy load drops do not have to be postulated or evaluated (Ref.1).
REFERENCES
- 1. UFSAR, Section 9.1.5.2.2B
Spent Fuel Assembly Storage TRM 8.9.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.9.3-1 Revision 7 8.9 REFUELING OPERATIONS 8.9.3 Spent Fuel Assembly Storage TECHNICAL NORMAL CONDITIONS TNC 8.9.3 The following limits apply to spent fuel assembly storage:
- a.
The heat generation rate of each spent fuel assembly stored in the spent fuel pool shall be 80,209 watts, and the heat generation rate per heat transfer surface area of assembly cladding shall be
< 445 watts/ft2; and
- b.
The total decay heat load of stored spent fuel assemblies following a discharge of fuel assemblies to the spent fuel pool shall be
< 30.15 x 106 BTU/hr.
APPLICABILITY:
Whenever fuel assemblies are stored in the spent fuel pool.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. A fuel assembly exceeding the heat generation rate limit or heat generation rate per heat transfer surface area limit is stored in the spent fuel pool.
A.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately B. The total decay heat load of stored spent fuel assemblies following a discharge of fuel assemblies to the spent fuel pool exceeds the limit.
B.1 Initiate action to evaluate failure to meet TNC per TRM Section 7.3.
Immediately
Spent Fuel Assembly Storage TRM 8.9.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.9.3-2 Revision 7 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.9.3.1 Verify by administrative means that the fuel assembly heat generation rate and heat generation rate per heat transfer surface area are within limits.
Prior to storing the fuel assembly in the spent fuel pool 8.9.3.2 Verify by administrative means that the total decay heat load of stored spent fuel assemblies following a discharge of fuel assemblies to the spent fuel pool is within the limit.
Prior to discharging fuel assemblies to the spent fuel pool
Spent Fuel Assembly Storage TRM 8.9.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.9.3-1 Revision 0 BASES 8.9.3 Spent Fuel Assembly Storage The restriction on the heat generation rate and the heat generation rate per heat transfer surface area of assembly cladding of each stored spent fuel assembly is consistent with the thermal-hydraulic analyses.
The restrictions on the total decay heat load of stored spent fuel assemblies are consistent with the thermal-hydraulic analyses.
Fuel Handling Bridge TRM 8.9.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.9.4-1 Revision 0 8.9 REFUELING OPERATIONS 8.9.4 Fuel Handling Bridge TECHNICAL NORMAL CONDITIONS TNC 8.9.4 The control rod hoist and fuel assembly hoist of the fuel handling bridge shall be used for movement of control rods or fuel assemblies, and shall be FUNCTIONAL with:
- a. The control rod hoist having:
- 1. A capacity of 3000 pounds; and
- 2. An overload cutoff limit of 2650 pounds.
- b. The fuel assembly hoist having:
- 1. A capacity of 3000 pounds; and
- 2. An overload cutoff limit of 2700 pounds.
APPLICABILITY:
During movement of control rods or fuel assemblies within the reactor pressure vessel.
CONTINGENCY MEASURES NONCONFORMANCE CONTINGENCY MEASURES RESTORATION TIME A. One or more hoists Nonfunctional.
A.1 Suspend use of any nonfunctional hoist from operations involving the movement of control rods or fuel assemblies within the reactor pressure vessel.
Immediately
Fuel Handling Bridge TRM 8.9.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 8.9.4-2 Revision 0 TECHNICAL VERIFICATION REQUIREMENTS TVR VERIFICATION FREQUENCY 8.9.4.1 For each control rod hoist used for movement of control rods or fuel assemblies within the reactor pressure vessel, perform a hoist load test of 3000 pounds and verify an automatic overload cutoff when the control rod hoist load exceeds 2650 pounds.
Once within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> prior to start of movement of control rods or fuel assemblies within the reactor pressure vessel 8.9.4.2 For each fuel assembly hoist used for movement of control rods or fuel assemblies within the reactor pressure vessel, perform a hoist load test of 3000 pounds and verify an automatic overload cutoff when the fuel assembly hoist load exceeds 2700 pounds.
Once within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> prior to start of movement of control rods or fuel assemblies within the reactor pressure vessel
Fuel Handling Bridge TRM 8.9.4 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 B 8.9.4-1 Revision 0 BASES 8.9.4 Fuel Handling Bridge The FUNCTIONALITY requirements of the hoist bridges used for movement of fuel assemblies ensures that: 1) fuel handling bridges will be used for movement of control rods and fuel assemblies, 2) each hoist has sufficient load capacity to lift a fuel element, and 3) the core internals and pressure vessel are protected from excessive lifting force in the event they are inadvertently engaged during lifting operations.
Facility Staff TRM 10.2.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.2.1-1 Revision 11 10.0 ADMINISTRATIVE CONTROLS 10.2 ORGANIZATION 10.2.1 Facility Staff Each on duty shift shall be composed of at least the following minimum shift crew composition:
APPLICABLE MODES LICENSE CATEGORY 1, 2, 3, and 4 5 and 6 Senior Operating License 2
1(1)
Operating License 2
1 (1) Does not include the licensed Senior Operator or Senior Operator Limited to Fuel Handling.
Process Control Program Procedures TRM 10.4.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.4.1-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.4 PROCEDURES 10.4.1 Process Control Program Procedures Written procedures shall be established, implemented and maintained covering process control program activities.
Process Control Program (PCP) Changes TRM 10.5.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.5.1-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.5 PROGRAMS AND MAUAL 10.5.1 Process Control Program (PCP) Changes
- a. Changes to the PCP shall be documented, and records of reviews performed, shall be retained as required by the USAR, Chapter 17, "Quality Assurance Program".
This documentation shall contain:
- 1.
Sufficient information to support the change together with the appropriate analyses or evaluations justifying the change(s); and
- 2.
A determination that the change will maintain the overall conformance of the solidified waste product to existing requirements of Federal, State, or other applicable regulations.
- b. Changes to the PCP shall become effective after review and acceptance by the PORC and the approval of the plant manager.
In-Plant Radiation Monitoring TRM 10.5.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.5.2-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.5 PROGRAMS AND MANUALS 10.5.2 In-Plant Radiation Monitoring A program shall be provided which will ensure the capability to accurately determine the airborne iodine concentration in vital areas under accident conditions. This program shall include the following:
- 1. Training of personnel;
- 2. Procedures for monitoring; and
- 3. Provisions for maintenance of sampling and analysis equipment.
REPORTING REQUIREMENTS TRM 10.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS Technical Requirements Manual Section 10.6, Reporting Requirements has been developed to provide a central location for various Technical Specification reports. These reports are not controlled or revised under the change process for the Technical Requirements Manual. The documents contained in Section 10.6 are revised and issued as required by Technical Specification Section 5.6.
Annual Radiological Environmental Operating Report TRM 10.6.1 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6.1-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS 10.6.1 Annual Radiological Environmental Operating Report
Radioactive Effluent Release Report TRM 10.6.2 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6.2-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS 10.6.2 Radioactive Effluent Release Report
Core Operating Limits Report (COLR)
TRM 10.6.3 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6.3-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS 10.6.3 Core Operating Limits Report (COLR)
Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR)
TRM 10.6.4 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6.4-1 Revision 5 10.6.4 Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR)
Post Accident Monitoring Report TRM 10.6.5 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6.5-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS 10.6.5 Post Accident Monitoring Report
Steam Generator Tube Inspection Report TRM 10.6.6 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6.6-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS 10.6.6 Steam Generator Tube Inspection Report
Remote Shutdown System Report TRM 10.6.7 DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 10.6.7-1 Revision 5 10.0 ADMINISTRATIVE CONTROLS 10.6 REPORTING REQUIREMENTS 10.6.7 Remote Shutdown System Report
Station Emergency Ventilation System Boundary TRM Appendix A DAVIS-BESSE NUCLEAR POWER STATION UNIT NUMBER 1 A.1 Revision 0 Table A-1 (page 1 of 1)
Access Openings Required to be Closed to Ensure Shield Building Area Negative Pressure Boundary is Intact (as required by Technical Specification 3.7.12)
Air Tight Doors Door No.
Description Elevation (ft) 100 Access Door from the No. 1 ECCS Pump Room (Room 105) to Pipe Tunnel 101 545 104A Access Door from Stair AB-3 to the No.1 ECCS Pump Room (Room 105) 555 105 Access Door from Passge 110A to the area above the Decay Heat Coolers 555 107 Access Door from the No.2 ECCS Pump Room (Room 115) to the Miscellaneous Waste Monitor Tank and Pump Room (Room114) 555 108 Access Door from the No.2 ECCS Pump Room (Room 115) to the Detergent Waste Drain Tank and Pump Room (Room 125) 565 201-A Access Door from Corridor 209 to the No.1 Mechanical Penetration Room (Room 208) 565 204 Access Door from Passage 227 to the Makeup Pump Room (Room 225) 565 205 Access Door from Passage 227 to the No.2 Mechanical Penetration Room (Room 236) 565 307 Access Door from Corridor 304 to the No.3 Mechanical Penetration Room (Room 303) 585 308 Access Door from Corridor 304 to the No.4 Mechanical Penetration Room (Room 314) 585 Blowout Panels Total No.
Location Elevation (ft) 1 No. 2 Mechanical Penetration Room (Room 236) 565 6
No. 3 Mechanical Penetration Room (Room 303) 585 6
No. 4 Mechanical Penetration Room (Room 314) 585
The End