NUREG-0787, Safety Evaluation Report Related to the Operation of Waterford Steam Electric Station, Unit 3 (Redacted): Difference between revisions

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{{#Wiki_filter:NUREG-0787 Safety Evaluation Report related to the operation of Waterford Steam Electric Station, Unit No. 3 Docket No. 50-382 Louisiana Power & Light Company U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation July 1981
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7/9/31 TABLE OF CONTENTS Page_
1  INTRODUCTION AND GENERAL DISCUSSION                      1-1 1.1  Introduction . . . . . . . . .                      1-1 1.2  General Plant Description . . . . . . .              1-3 1.3  Comparison With Similar Facility Designs            1-4 1.4  Identification of Agents and Contractors            1-4 1.5  Summary of Principal Review Matters      . . . . 1-5 1.6  Modifications to Waterford 3 During the Course of NRC Review . . . . . . . . .                        1-6 1.7  Summary of Outstanding Issues .                      1-6 1.8  Confirmatory Issues .                                1-7 1.9  License Conditions                                  1-8 1.10 Generic Issues . . .                                1-9 1.11 Unique Plant Features                                1-9 1.12 References . .                                      1-12 2  SITE CHARACTERISTICS . . .                                2-1 2.1 Geography and Demography                              2-1 2.1.1  Site Description . . .                        2-1 2.1.2  Exc1usion Area Control                        2-1 2.1.3  Population Distribution                      2-5 2.1. 4 Cone 1 us ions . . . . . .                    2-6
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2.3 Meteorology . . . . . . . .                          2-13 2.3.l  Regional Climatology                          2-13 2.3.2  Local Meteorology . . . . . . . .            2-14 2.3.3  Meteorological Measurements Program . .      2-14 2.3.4  Short-Term (Accident) Diffusion Estimates    2-14 2.3.5  Long-Term (Routine) Diffusion Estimates . 2-15
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TABLE OF CONTENTS (Continued)
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2.5 Geology and Seismology .                                2-:1 2.5.1 Geologic Infonnation                              2-22 2.5.2 Seismology .      .                              2-26 2.5.2.1  Vibratory Ground Motion Summary        2-26 2.5.2.2  Tectonic Province . .                  2-26 2.5.2.3  Maximum Earthquake .      .            2-26 2.5.2.4  Safe Shutdown Earthquake                2-28 2.5.2.5  Operating Basis Earthquake              2-28 2.5.3 Surface Faulting .                .              2-29 2.5.4 Stability of Subsurface Materials and Foundations 2-29 2.5.4.1 Site Conditions . .              .      2-29 2.5.4.2 Groundwater Control, Excavation, and Backfill .    . . .                    2-33 2.5.4.3 Foundation Stability                    2-35 2.5.4.4 Conclusion                              2-38 2.5.5 Stability of Slopes                              2-38 2.5.6 Embankments and Dams                              2-38 2.6 References                                              2-39 3 DESIGN CRITERIA - STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3-1 3.1 General                                                3-1 3.1.1 Conformance With General Design Criteria          3-1 3.1.2 Conformance With Industry Codes and Standards    3-1 i;
 
TABLE OF CONTENTS (Continued)
Page 3.2 Classification of Structures, Systems, and Components        3-1 3.2.1 Seismic Classification . . . . . . .                  3-1 3.2.2 System Qua1ity Group Classification                  3- 2 3.3 Wind and Tornado Loadings . . .                              3-4 3.3.1 Wind Design Criteria . .                              3-4 3.3.2 Tornado Design Criteria                              3-4 3.4 Water Level (Flood) Design . .                              3-5 3.4.1 General Discussion . . . . . . . . .                  3-5 3.4.2 Water Level (Flood) Design Procedures                3-6 3.5 Missile Protection . . . . . . . . . . .                    3-6 3.5.1 Missile Selection and Description                    3-6
: 3. 5. L 1 Internally Generated Missiles (Outside Containment) . . . . . , . .              3-6 3.5. L 2 Internally Generated Missiles (Inside Containment)    . .    . . .              3-7 3.5.1.3 Turbine Missiles . . . . . .      . .        3-8 3.5.1.4 Missiles Generated by Natural Phenomena      3-8 3.5.2 Structures, Systems, and Components To Be Protected From Externally Generated Missiles . . . . . . . 3-9 3.5.3 Barrier Design Procedures . . . . . . . . . . .      3-10 3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping . . . . . . . . . . . . .      3-10 3.6.1 Plant Design for Protection Against Postulated Piping Failures in Fluid Systems Outside Containment 3-11 3.6.2 Determination of Break Locations and Dynamic Effects Associated With the Postulated Rupture of Piping    3-12
: 3. 7 Seismic Design . . . . . . . . . . . . . . . . . . .        3-13 3.7.1 Seismic Input . . . . . . . . . . .. . . . . .        3-13 3.7.2 Seismic System Analysis and Seismic Subsystem Analysis (Part 1) . . . . . . . . . . . . . .        3-13 3.7.3 Seismic Subsystem Analysis (Part 2) . . . . . .      3-14 iii
 
TABLE OF CONTENTS (Continued)
Page 3.7.3.1 Reactor Coolant System . . . . . . . . . . . 3-15 3.7.3.2 Reactor Internals, Core, and Control Element Orive Meehanism . . . . .  . . . . . . . . 3-15 3.7.3.3 Non-NSSS Seismic Category I Piping Systems      3-15 3.7.4 Seismic Instrumentation Program                        3-16 3.8 Design of Category I Structures                                3-16 3.8.1  Concrete Containment . .                              3-16 3.8.2  Steel Containment                                      3-17 3.8.3  Concrete and Structural Steel Internal Structures      3-17 3.8.4  Other Category I Structures                            3-18 3.8.5  Foundations . . . . . . .                              3-19 3.9 Mechanical Systems and Components . .                          3-20 3.9.1 Special Topics for Mechanical Components                3-20 3.9.2 Dynamic Testing and Analysis of Systems, Components, and Equipment . . . . . . . . . . . * . . . . . . . 3-21 3.9.2.1 Piping Preoperational and Startup Testing Program . . . . . . . . . . . . . . . 3-21 3.9.2.2 Dynamic Analyses of Reactor Coolant System . . 3-22 3.9.2.3 Reactor Internals, Flow-Induced Transients, Prototypical Testing . . . . . . . .          3-24 3.9.3 ASME Code Class 1, 2, and 3 Component Supports and Core Support Structures        . . . . . . . . . . 3-24 3.9.3.1 Loading Combinations, Design Transients, and Stress Limits . . . . . . . . . .        3-24 3.9.3.2 Pump and Valve Operability Assurance Program . . . . . . . . . . . . . .          3-25 3.9.3.3 Design and Installation of Pressure Relief Devices                                3-25 3.9.3.4 Component Supports                            3-26 3.9.4 Control Rod Drive System . .                            3-26 3.9.5 Reactor Pressure Vessel Internals                      3-26 3.9.6 Inservice Testing of Pumps and Valves                  3-27 3.10 Seismic and Dynamic Qualification of Seismic Category I Mechanical and Electrical Equipment . . . . .              3-29 3.11 Environmental Qualifications for Safety-Related Electrical Equipment                                          3-29 3.12 References . . . . . . . . . . . . . . . . . .                  30 iv
 
TABLE OF CONTENTS (Continued) 4 REACTOR    * * * *
* 4.1 Introduction        .                                      4-1 4.2 Fuel System Design                                        4-1 4.2.1 Description . .                                    4-1 4.2.2 Design Evaluation                                  4-2 4.2.2.1    Fuel Thermal Performance Analysis . 4-2 4.2.2.2    Fuel Rod Pressure Criteria            4-3 4.2.2.3    Cladding Collapse . . . . . .          4-3 4.2.2.4    Fretting Wear . . . . .                4-4
: 4. 2. 2. 5 Waterlogging . . . . . . . .          4-5 4.2.2.6    Pellet/Cladding Interaction .          4-5 4.2.2.7    Burnable Poison Rod Hydriding          4-6 4.2.2.8    Swelling and Rupture . . . .          4-6 4.2.2.9    Seismic and LOCA Loadings . . .        4-7 4.2.2.10  Fuel Rod Growth . . . . . . .          4-8 4.2.2.11  Fuel Rod Bowing. . . . . . .          4-8 4.2.2.12  Zircaloy Material Properties          4-9 4.2.3 Testing, Inspection, and Surveillance Plans . . . . 4-9 4.2.3.1    Testing and Inspection of New Fuel    4-9 4.2.3.2    Fue1 Surveillance . . . . . . .        4-9 4.2.3.3    Control Element Assembly Surveillance  4-10 4.2.3.4    Online Fuel Failure Monitoring        4-10 4.2.4 Fuel Design Conclusions                            4-11
: 4. 3 Nuciear Design . . .                                      4-11 4.3.1 Design Bases . . . .                                4-11 4.3.2 Design Description                                  4-11 4.3.2.1    Power Distribution .                  4-12 4.3.2.2    Reactivity Coefficient                4-13 4.3.2.3    Control    . . .                      4-13 4.3.2.4    Stability . . . .                      4-14 4.3.2.5    Vessel Irradiation      . .          4-14 4.3.2"6    Criticality of Fuel Assemblies        4-14
: 4. 3.3 Analytica 1 Methods . . .          . .      . 4-14 4.3.4 Summary of Evaluation Findings, NucJear Design      4-15 4.4 Therma 1-Hydrau lic Design .            .    .    .  . . 4-15 4.4.1 Thermal-Hydraulic Design Criteria and Design Bases  4-15 4.4.2 Thermal-Hydraulic Models . . . . . . . . . . . . . 4-19 V
 
TABLE OF CONTENTS (Continued)
Page 4.4.3 Thermal-Hydraulic Comparison                          4-20 4.4.4 Conclusion and Summary                                4-20 4.5 Reactor Materials . . . . . . . . .                          4-22
: 4. 5.1 Control Rod Drive Structural Materials . . .        4-22 4.5.2 Reactor Internals and Core Support Materials          4-23 4.6 Functional Design of Reactivity Control System              4-24 4.7 References . . . . . . . . . . . . . .                      4-27 5 REACTOR COOLANT SYSTEM AND CONNECTED SYSTEMS . . . .            5-1 5.1 Summary Description . . . . . . . . . . . . . .              5-1 5.2 Integrity of Reactor Coolant Pressure Boundary              5-2 5.2.1 Compliance With Codes and Code Cases .                5-2 5.2.1.1 Compliance With 10 CFR 50.55a                5-2 5.2.1.2 Applicable Code Cases                        5-3 5.2.2 Overpressurization Protection . . . .                5-4 5.2.2.i High Temperature Overpressure Protection    5-4 5.2.2.2 Low Temperature Overpressure Protection      5-4 5.2.3 Reactor Coolant Pressure Boundary Materials . . . 5-5 5.2.3.1 Material Specifications and Compatibility With Reactor Coolant . . . . . . . . . . 5-5 5.2.3.2 Fabrication and Processing of Ferritic Materials . . . . . . . . . . . . . . . . 5-6 5.2.3.3 Fabrication and Processing of Austenitic Stainless Steel . . . . . . . . . .        5-7 5.2.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing . . . . . . . . . . . .  . . 5-8 5.2.5 Reactor Coolant Pressure Boundary Leakage Detection  5-9 5.3 Reactor Vessel                                              5-10 5.3.1 Reactor Vessel Materials                              5-10 5.3.1.1 Compliance With Appendix G, 10 CFR Part 50  5-11 5.3.1.2 Compliance With Appendix H, 10 CFR Part 50  5-15 5.3.1.3 Conclusions on Compliance With Appendices G and H, 10 CFR Part 50 . . . . . . . . . . . 5-16 vi
 
TABLE OF CONTENTS (Continued)
Page 5.3.2 Pressure-Temperature Limits                          5-17 5.3.3 Reactor Vessel Integrity                              5-17 5.4 Component and Subsystem Design                              5-19 5.4.1 Reactor Coolant Pumps                                5-19 5.4.1.1 Pump Flywheel Integrity .                    5-19 5.4.2 Steam Generators . . .                                5-19 5.4.2.1 Steam Generator Materials . . . . .          5-19 5.4.2.2 Steam Generator Inservice Inspection        5-21 5.4.3 Shutdown Cooling (Residual Heat Removal) System      5-21 5.4.4 Pressurizer Relief Tank (Quench Tank)                5-25 5.5 References . . . . .                                        5-26 6 ENGINEERED SAFETY FEATURES .                                    6-1 6.1 Engineered Safety Features Materials                        6-1 6.1.1 Metallic Materials . . .                              6-1 6.1.2 Organic Materials . . .                              6-2 6.1.3 Post-Accident Chemistry. .                            6-2 6.2 Containment Systems . . . . .                                6-3 6.2.1 Containment Functional Design                        6-3 6.2.1.1 Containment Structures                      6-3 6.2.1.2 Subcompartment Analysis . . . . . .          6-4 6.2.1.3 Mass and Energy Release Analysis for Postulated Loss-of-Coolant Accident .      6-7 6.2.1.4 Mass and Energy Release Analysis for Postulated Secondary System Pipe Ruptures  6-8 6.2.1.5 Minimum Containment Pressure Analysis for Performance Capability Studies on the Emergency Core Cooling System              6-10 6.2. LG Summary and Conclusions . . . .              6-10 6.2.2  Containment Heat Removal Systems . , . .            6-11 6.2.3  Secondary Containment Functional Design              6-12 6.2.4  Containment Isolation System . . . . . .            6-14 6.2.5  Combustible Gas Control System . . . . . . . . . . . 6-17 6.2.6  Containment Leakage Test Program . . . . . . . . . . 6-18 6.2.7  Fracture Prevention of Containment Pressure Boundary 6-18 vii
 
TABLE OF CONTENTS (Continued)
Page 6.3 Emergency Core Cooling System                                  6-20 6.3.1  System Design  . . . .                                6-20 6.3.2  Evaluation . . . . . .                                6-22 6.3.3  Testing . . .  . . . . . . . . . .. . . . .. .        6-25 6.3.4  Conclusions on the Emergency Core Cooling Systems      6-26 6.4 Control Room Habitability . . . . . . . . . . . . . . . . . 6-26 6.5 Fission Product Removal and Control Systems . . . . . . .      6-27 6.5.1 Engineered-Safety-Feature Atmosphere Cleanup System . . 6-27 6.5.1.1  Control Room Air Conditioning System . .      6-27 6.5.1.2  Controlled Ventilation Area System . . .      6-28 6.5.1.3  Shield Building Ventilation System . . . . 6-28 6.5.1.4  Fuel Handling Building Ventilation System    6-29 6.5.1.5  System Evaluation . . . . . . . . . .        6-29 6.5.2 Containment Spray as a Fission Product Cleanup System . . . . . . . . . . . . . . . . . .            6-30 6.5.3 Fission Product Control System . . . . . .              6-31 6.6 Inservice Inspection of Class 2 and 3 Components              6-32 6.7 References. . . . . . . .                                      6-33 7 INSTRUMENTATION AND CONTROLS                                      7-1 7.1 Introduction . . . . .                                        7-1 7.1.1 General . . . . . . . . . .                            7-1 7.1.2 Specific Findings-Open Items                            7-1 7.1.3 Conclusions . . . .                                    7-3 7.2 Reactor Protective System . . . . .                            7-3 7.2.1  System Description . . . . . . . .                    7-3 7.2.2  Differences From Preliminary Design                    7-4 7.2.3  Core Protection Calculators . . . . . . . . .          7-5 7.2.4  Steam Generator and Pressurizer Water Level.          7-7 7.2.5  Independence of Redundant Power Supplies . .          7-8 7.2.5.1 Reactor Protection System Power Supplies      7-8 7.2.5.2 Logic Matrix Power Supplies                    7-8 7.2.6 Testing                                                7-9 7.2. 7 Bypasses                                              7-9 7.2.8 Conclusions                                            7-9 7.3  Engineered Safety Features Actuation System                  7-9 7.3.1 System Description .                                    7-9 viii
 
TABLE OF CONTENTS (Continued)
      - 3.2  Differences From Preliminary Design              7-10
: 7. 3.3  Diversity of Actuation Signals                  7-11 7.3.4  Emergency Feedwater System . .                  7-11 7.3.5  Resetting of the ESFAS Signals                  7-12 7.3.6  Transfer of Spare ESF Pump .                    7-12 7.3.7  Conclusions . . . . . . . . .                    7-12 4  Systems Required for Safe Shutdown                      7-13 7.4.1  General . . . . . . . . . .                      7-13 7.4.2  Shutdown Cooling System                          7-14 7.4.3  Emergency Shutdown From Outside the Control Room 7-14 7.4.4  Conclusions . . . . . . . . . .                  7-15 7.5 Safety-Related Display Instrumentation                    7-15
: 7. 5. 1 General . . . . . . . . . . . . . . . .          7-15 7.5.2  Post Accident Monitoring Instrumentation        7-16 7.5.3  Bypass and Inoperable Status Indication          7-16 7.5.4  Safety Parameter Display System . . . .          7-17 7.5.5  Conclusions        . . . . . . . . . . .        7-17 7.6 All Other Instrumentation Systems- Required For Safety    7-17
: 7. 6. 1 Genera 1 . . . . . . . . . . . . . . . . . . . 7-17 7.6.2  Safety Injection Tank Isolation Valve Interlocks 7-18 7.6.3  Containment Purge System . . . . . . . . . . 7-18 7.6.4  Reactor Coolant System Leak Detection System    7-19 7.6.5  Containment Vacuum Relief System . . . .        7-19 7.6.6  Low Temperature Overpressure Protection          7-19 7.6. 7  Conciusions . . . . . . . . . .                  7-19
: 7. 7 Control Systems Not Required For Safety . .              7-19
: 7. 7.1 General . . . . . . . . . . . . . .              7-19 7.7.2 Differences From Preliminary Design . .            7-20
: 7. 7.3 Megawatt Demand Setter System and Reactor Power Cutback System . . . . . . . . . . . .          , .......
7-?1 7.7.3.1 Megawatt Demand Setter System            7-21 7.7.3.2 Reactor Power Cutback System            7-21 7.7.3.3 Basis for Acceptability . . .            7-21 7.7.4 Loss of Power to Contral Systems . . .            7-22 7.7.5 Control System Failures Following a High Energy Line Break . . . . . . . . . . .                7-22
: 7. 7.6 Single Failure of Control System Study
: 7. 7. 7 Conclusions                                      7-22
: 7. :3 qeferences                                              7-23 ix
 
TABLE OF CONTENTS (Continued)
Paae 8  ELECTRIC POWER SYSTEMS                                    8-1 8.1 General Considerations                                8-1 8.2 Offsite Power System                                  8-1 8.2.1  General Description    . .  .                8-1 8.2.2  Circuit Description and Testability          8-3 8.2.3  Grid Stability Analysis . . . . . . .        8-3 8.2.4  Adequacy of Station Electric Distribution System Voltages    . .                        8-4 8.2.5 Conclusions      . .                          8-7 8.3 Onsite Emergency Power System . .                    8-7 8.3.1 Alternating Current Power Systems              8-7 8.3.1.1 120-Volt Uninterruptib1e Alternating Current System . . . . . . . . . 8-10 8.3.1.2 Criterion For Class lE Equipment      8-10 8.3.1.3 Conclusions . . . .                  8-12 8.3.2 Direct Current Power System                    8-12 8.3.2.1 Discussion                            8-12 8.3.2.2 Conclusion                            8-14 8.3.3 Fire Protection                                8-14 8.4 Other Electrical Features and Requirements For Safety 8-15 8.4.1  Containment Electrical Penetrations . .      8-15 8.4.2  Thermal Overload Protection Bypass . . . . . 8-16 8.4.3  Power Lockout to Motor-Operated Valves .      8-17 8.4.4  Physical Identification and Separation of Safety-Related Equipment .  . . . . . .      8-17 8.4.5  Nonsafety Loads on Emergency Power Sources. 8-18 8.4.6  Use of a Load Sequencer With Offsite Power    8-18 8.4.7  Third-of-a-Kind Class lE Equipment            8-19 8.4.8  Isolation Panel                              8-19 8.5 References                                                8-21 9  AUXILIARY SYSTEMS                                        9-1 9.1 Fuel Storage Facility                                9-1 9.1.1 New Fuel Storage .                            9-1 9.1.2 Spent Fuel Storage . .        .                9-2 9.1.3 Spent Fuel Pool Cooling and Cleanup System (Fuel Pool System) .                          9-4 9.1.4 Fuel Handling System                          9-6 X
 
TABLE OF CONTENTS (Continued)
: 9. 2 'r'iate: Systems . . . . . . . * * * * . . . . . . . . . . . . 9-8 9.2.l Station Service Water System . . . . . . . . . . . .      9-8 9.2.2 Reactor Auxiliaries Cooling Water System (Component)
Cooling Water System and Auxiliary Component Cooling Water System) . . . . . .                      9-8 9.2.3 Demineralized Water Makeup System . . .                  9-10 9.2.4 Potable and Sanitary Water Systems . . .                  9-11 9.2.5 Ultimate Heat Sink . . . . . . . . . . .                  9-11 9.2.6 Condensate Storage Facilities . . . . .                    9-12 9.2.7 Essential Services Chilled Water System                    9-13 9.3 Process Auxiliaries . . . . . .                                  9-14 9.3.l    Compressed Air System                                  9-14 9.3.2    Process Sampling System . . . . . .                    9-15 9.3.3    Equipment and Floor Drainage System                    9-16 9.3.4    Chemical and Volume Control System .                  9-17 9.4 Heating, Ventilation, and Air Conditioning (HVAC) Systems        9-18 9.4.1 Control Room Area Ventilation System (Control Room Air Conditioning System) . . . . . . . . . . .        9-18 9.4.2 Spent Fuel Pool Area Ventilation System (Fuel Handling Bui 1 ding Ventilation System) . . . . .      9-20 9.4.3 Auxiliary and Radwaste Area Ventilation System (Reactor Auxiliary Building Ventilation System)        9-22 9.4.4 Turbine Area Ventilation System (Turbine Building Ventilation System) . . . . . . . . . . . . .          9-25 9.4.5 Engineered Safety Features Ventilation System              9-25 9.5 Other Auxiliary Systems                                          9-25 9.5.1 Fire Protection                                            9-25 9.5.1.1 Introduction . . . . . . . . . . . . .        9-25 9.5.1.2 Fire Protection Systems Description and Evaluation      . . . . . . . . . . . . 9-26 9.5.1.3 Other Items Related to Fire Protection Programs . . . . . . . . . . . . . . . . 9-28 9.5.1.4 Plant Areas Containing Redundant Divisions    9-28 9.5.1.5 Emergency Lighting . . . . . . . . . . .      9-29 9.5.1.6 Fi re Protection For Specific Areas . . .      9-29 9.5.1.7 Administrative Controls and Fire Brigade      9-30 9.5.1.8 Conclusions .                                  9-30 3.5.2 Communication Systems . . . . .                          9-30
: 9. 5. 2.1 Intraplant Systems      . . . . . . . . . . 9-30 9.5.2.2 Interplant (Plant-to-Offsite) Communication Systems . .      . . . . . . . . . . . . . . 9-31 xi
 
TABLE OF CONTENTS (Continued) 9.5.3 Lighting System. . . . . . . . . . . . . . . .      9-32 9.5.4 Emergency Diesel Fuel Oil Storage and Transfer System . . . . . . . . . . . . . . . . .          9-33 9.5.4.1 Emergency Diesel Engine Auxiliary Support Systems (General) . . .                  9-33 9.5.4.2 Emergency Diesel Engine Fuel Oil Storage and Transfer System . .                  9-36 9.5.5  Emergency Diesel Engine Cooling Water System . 9-37 9.5.6  Emergency Diesel Engine Starting Systems          9-39 9.5.7  Emergency Diesel Engine Lubricating Oil System    9-40 9.5.8  Emergency Diesel Engine Combustion Air Inkake and Exhaust Systems                              9-41 9.6 References                                                9-43 10 STEAM AND POWER CONVERSION SYSTEM                              10-1 10.1 Summary Description . . . . .                            10-1 10.2 Turbine-Generator . . . . .                              10-1 10.2.1 Turbine-Generator Design                          10-1 10.2.2 Turbine Disc Integrity                            10-3 10.3 Main Steam Supply System                                  10-4 10.3.1 Main Steam Supply System (Up to and Including the Main Steam Isolation Valves) . . . . . .      10-4 10.3.2 Main Steam Supply System (Downstream of Main Steam Isolation Valves) . . . . . . .            10-5 10.3.3 Steam and Feedwater Systems Materials              10-5 10.3.4 Secondary Water Chemistry        . . . .          10-6 10.4 Other Features of the Steam and Power Conversion System  10-8 10.4.1  Main Condenser                                    10-8 10.4.2  Main Condenser Evacuation System                  10-9 10.4.3  Turbine Gland Sealing System                      10-10 10.4.4  Turbine Bypass System                            10-10 10.4.5  Circulating Water System . .                      10-11 10.4.6  Condensate Cleanup System                        10-ll 10.4. 7 Condensate and Feedwater System                  10-12 10.4.8  Steam Generator Slowdown System                  10-13 10.4.9  Auxiliary (Emergency) Feedwater System            10-13 10.4.9.1 EFS Standard Review . . . . .            10-13 10.4.9.2 EFS Review (TMI-2 Considerations)        10-19 10.4.9.3 Implementation of Recommendations        10-21 10.5 References                                                10-29 xii
 
TABLE OF CONTENTS (Continued)
Page
::.:::cACTlVE WASTE SYSTEM . .                                    11-1 Summary Description . . . . . . .                        11-1
::.2 System Description and Evaluation                            11-2 11.2.1 Liquid Waste Processing System                    11-2 11.2.1.1  Chemical and Volume Control System . 11-10 11.2.1.2  Boron Management . . . . . . . . , . 11-10 11.2.1.3  Waste Management System . . . . .      11-11 11.2.1.4  Steam Generator Slowdown System .      11-11 11.2.1.5  Industrial Waste System . . . . . . 11-12 11.2.1.6  Conformance With NRC Regulations and Staff Positions . . .        . . .. 11-12 11.2.2 Gaseous Waste Processing Systems . . . . . .      11-14 11.2.2.1  Gaseous Waste Management System.        11-14 11.2.2.2  Vent Gas Co11ection Header . . .      11-15 11.2.2.3  Containment Ventilation System .      11-15 11.2.2.4  Ventilation Releases From Other Buildings . . . . . . . . . . .  . 11-16 11.2.2.5  Main Condenser Evacuation System . 11-16 11.2.2.6  Turbine Gland Sealing System . . . 11-16 11.2.2.7  Atmospheric Steam Dump Valves .  . . . 11-16 11.2.2.8  Conformance With NRC Regulations and Staff Positions . . . . . . .          11-16 11.2.3 Solid Radioactive Waste Treatment System          11-17 11.2.3.1 Wet Solid Wastes  ..  . . . . . .      11-18 11.2.3.2 Ory Solid Wastes  . . . . . . . . . . 11-18 11.2.3.3 Conformance With  NRC Regulations and Staff Positions  . . . .              11-19 1.3 Process and Effluent Radiological Monitors                11-19
: l. 4 References . . . . . . . . . . .  . . . .              11-22 ADIATION PROTECTION . . . . .                                  12-1
:2.1 Ensuring That Occupational Radiation Exposures Are as Low as Reasonably Achievable .                              12-1 12.1.l  Policy Consideration . . .                      12-1 12.1.2 Design Considerations . .                        12-2
: 12. 1.3 Operational Considerations                      12-2
  *=
12.1.4  Decommissioning                                  12-3 qaaiation Sources . . . . . . . .                        12-3 xiii
 
TABLE OF CONTENTS (Continued)
Page 12.3 Radiation Protection Design Features                          12-4 12.3.1  Facility Design Features . .                        12-4 12.3.2  Shielding . . . . . . . . .                          12-5 12.3.3  Ventilation . . . . . . . . . . . . .                12-5 12.3.4  Area Radiation Monitoring and Airborne Radioactivity Monitoring Instrumentation                          12-5 12.4 Dose Assessment . . . . . . . . . . .                        12-6 12.5 Health Physics Program . . . . . . . .                        12-7 12.5.1  Program and Staff Organization                      12-7 12.5.2  Health Physics Facilities                            12-8 12.5.3  Health Physics Instrumentation                      l-8 12.5.4  Procedures                                          12-8 12.6 References . . . .                                            12-10 13 CONDUCT OF OPERATIONS                                              13-1 13.1 Organizational Structure and Qualifications                  13-1 13.2 Training . . . . . . . . . . . . . . . . .                    13-10 13.2.1 Corporate and Plant Staff Training Program            13-10 13.2.2 Licensed Operator Training Program                    13-11 13.3 Emergency Preparedness Evaluation                            13-12 13.3.1 Introduction . . . . . . .                            13-12 13.3.2 Evaiuation of the Emergency Plan                      13-12 13.2.2.l Assignment of Responsibility (Organization Contra l) . . . . . . . . . 13-12 13.3.2.2 Onsite Emergency Organization . . . . . 13-15 13.3.2.3 Emergency Response Support and Resources    13-16 13.3.2.4 Emergency Classification System            13-16 13.3.2.5 Notification Methods and Procedures        13-17 13.3.2.6 Emergency Communications . . . . .          13-18 13.3.2.7 Public Information .        . . . . .      13-18 13.3.2.8 Emergency Facilities and Equipment          13-19 13.3.2.9 Accident Assessment                        13-22 13.3.2.10 Protective Response        . . . . .      13-24 13.3.2.11 Radiological Exposure Control              13-25 13.3.2.12 Medical and Public Hea1th Support          13-25 13.3.2.13 Recovery and Reentry Planning and Post-Accident Ooerations . . . .          13-25 13.3.2. 14 Exercises and Drills . . . . . .          13-26 13.3.2.15 Radio1ogica1 Emergency Response Training  13-27 13.3.2.16 Responsibility for the Planning Effort:
Development, Periodic Review, and Distribution of Emergency Plans . . . . 13-27 xiv
 
TABLE OF CONTENTS (Continued)
Page 13.3.3 Conclusions                                          13-28 13.4 Review and Audit . .                                          13-28 13.5 Plant Procedures . .                                          13-30 13.5.1 Administrative Procedures    . . . .                13-30 13.5.2 Operating and Maintenance Procedures                  13-30 13.6 Physical Security Plan                                        13-30 13.7 References . .                                                13-32 14 INITIAL TEST PROGRAM                                              14-1 References . . . .                                                14-5 15 ACCIDENT ANALYSIS                                                  15-1 15.1 Gene,ral Discussion                                          15-1 15.1.1 Introduction . . . .                                  15-1 15.1.2 Analytical Techniques    .                            15-3 15.2 Normal Operation and Anticipated Transients                  15-5 15.2.1 Increase in Heat Removal by the Secondary System      15-5 15.2.2 Decrease in Heat Removal by the Secondary System      15-6 15.2.3 Decrease in Reactor Coolant Flow Rate . . . . .      15-7 15.2.3.1 Single Reactor Coolant Pump Shaft Seizure  15-7 15.2.3.2 Single Reactor Coolant Pump Sheared Shaft . 15-8 15.2.4 Reactivity and Power Distribution Anomalies .        15-8 15.2.4.l Uncontrolled CEA Withdrawal From a Subcritical or Low Power Condition . . . 15-8 15.2.4.2 Uncontrolled CEA Withdrawal at Power . . 15-8 15.2.4.3 Misoperation of Control Element Assembly . 15-9 15.2.4.4 Inadvertent Boron Dilution . . . . . . . 15-10 15.2.4.5 Inadvertent Loading of a Fuel Assembly Into the Improper Position . . . . . . 15-11 15.2.4.6 Ejection of the Control Element Assebly    15-11 15.2.5 Increase in Reactor Coolant System Inventory          15-11 15.2.6 Startup of an Inactive Loop                          15-12 15.2. 7 Conclusions                                          15-12 15.3 Limiting Accidents . . . . . .                                15-12 15.3.1 Steam Line Breaks                                    15-12 15.3.2 Feedwater System Pipe Breaks                          15-14 15.3.3 Loss-of-Coolant Accident                              15-14 xv
 
TABLE OF CONTENTS (Continued)
Page 15.3.4  Steam Generator Tube Rupture . . . . . . . . . . . 15-16 15.3.5  Inadvertent Opening of a Pressurizer Safety Valve  15-17 15.3.6  Anticipated Transients Without Scram              15-17 15.3.7  Conclusions . . . . . . . . .                      15-18 15.4 Radiological Consequences of Accidents                      15-19 15.4.1 Steam Line Break Accident . .                      15-19 15.4.2 Fuel Handling Accident . . . .                      15-26 15.4.3 Failure of a Small Line Carrying Primary Coolant Outside Containment . . . . .                      15-27 15.4.4 Waste System Failures . . . . .                    15-28 15.4.5 Control Rod Ejection Accident .                    15-28 15.4.6 Stearn Generator Tube Failure . .                  15-29 15.4.7 Loss-of-Coolant Accident (LOCA)                    15-30 15.4.8 Liquid Tank Failure Accident                        15-31 15.5 References . . . .                                          15-33 16 TECHNICAL SPECIFICATIONS                                        16-1 References . . . .                                              16-2 17 QUALITY ASSURANCE                                                17-1 17.1  General                                                    17-1 17.2  Organization                                              17-1 17.3  Quality Assurance Program                                  17-4 17.4  Conclusions . . . . . . . . . .                            17-6 17.5  Outstanding Quality Assurance Issue                        17-6 17.6  References . . . . . . . . . . . . .                      17-7 18 REPORT OF THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS          18-1 19 COMMON DEFENSE AND SECURITY                                      19-1 Reference                                                        19-2 20 FINANCIAL QUALIFICATIONS                                        20-1 20.1  Business of Applicant .                                    20-1 20.2  Estimated Operating Costs of Facility                      20-2 20.3  Estimated Costs to Decommission Facility                  20-2 20.4  Reasonable Assurance of Funds                              20-3 20.4.1 General . . . . . .                                20-3 20.4.2 Costs of Operation .                                20-4 20.4.3 Decommissioning Cost                                20-5 20.5 Conclusion                                                  20-6 20.6 References . . . . . . . .                                  20-7 xvi
 
TABLE OF CONTENTS (Continued)
Page 21 FINANCIAL PROTECTION AND INDEMNITY REQUIREMENTS    21-1 21.1 General . . . . . . .                        21-1
: 21. 2 Preoperational Storage of Nuclear Fuel      21-1 21.3 Operating Licenses                            21-1 21.4 References .                                  21-2 22 TMI-2 REQUIREMENTS . . .                          22-1 22.1 Introduction . . . .                          22-1 22.2 Discussion of Requirements                    22-2 23 CONCLUSIONS  . . . . . . . . . .                  23 = 1 xvii
 
TABLE OF CONTENTS (Continued)
Page APPENDICES A CHRONOLOGY OF RADIOLOGICAL REVIEW . . . . . . . . . . . .            A-1 B BIBLIOGRAPHY . . . . . . . . . . . . . . . . . . . . . .              B-1 C ACRS GENERAL CONCERNS . . . . . . . . . . . . . . . . . .            C-1 D LAWRENCE LIVERMORE LABORATORY  REPORT ON SITE SEISMICITY . . . . . 0-1 E EVALUATION OF THE APPLICANT 1 S PRELIMINARY CONTROL ROOM ASSESSMENT . E-1 F ABBREVIATIONS . . . . . . . . . . . . . . . . . . . . . . . . .      F-1 G GUIDELINES FOR DEMONSTRATION OF OPERABILITY OF PURGE ANO VENT VALVES . . . . . . . . . . . . . . . . . . . . . . . . . . . .        G-1 H PRINCIPAL CONTRIBUTORS . . . . . . . . . . . . . . . . . . . . .      H-1 xviii
 
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13.1 LP&L General Office Management and Support Structure          13-2 13.2 Waterford 3 Organization Structure . . . . . . .              13-6 13.3 Waterford 3 Project, Offsite Support Organization.            13-7 13.4 Waterford 3 Project, Offsite Support Organization (Continued)  13-8 17.1 Quality Assurance Organization . . . . . . . . . . . . . . . . 17-3 xix
 
LIST OF TABLES Page 2.1  Resident Population vs Distance . . . . . . . . . . . . . . . . . 2-5
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2.6  Summary of Subsurface Soil Conditions                            2-32 4.1  Reactor Design Comparison. . . . . .                              4-21 6.1  Emergency Core Cooling System Equipment at SONGS 2 & 3 and Waterford3 . . . . . . . . . . . . . . . . . . . . . .            6-21 11.1 Principal Parameters and Conditions Used in Calculating Releases of Radioactive Material in Liquid and Gaseous Effluents From Waterford 3 . . . . . . . . . . . .                  11-3 11.2 Calculated Annual Releases of Radioactive Materials in Liquid Effluents From Waterford3 . . . . . . . . . . . . . . . . .      11-6 11.3 Calculated Annual Releases of Radioactive Materials in Gaseous Effluents from Waterford 3 . . . . -. . . . . . . .              11-7 11.4 Calculated Annual Dose Commitments to a Maximally Exposed Individual Near Waterford3 . . . . . . . . . . . . . .            11-8 11.5 Comparison of Calculated Dose Conrnitments to a Maximally Exposed Individual From Effluents from Waterford3 to Annex to Appendix I Design Objectives . . . . . . . . . . . . . . . .      11-9 11.6 Design Parameters of Principal Components Considered in the Evaluation of Liquid and Gaseous Radioactive Waste Treatment Systems of Waterford3 . . .                                      11-13 11.7 Process and Effluent Monitors.                                    11-20 13.1 Acquisition of Vital Personnel                                    13-5 15.1 Chapter15 General Initial Conditions                              15-2 15.2 Topical Reports For the Codes Used in Safety Analyses            15-4 xx
 
LIST OF TABLES (Continued)
Page 15.3 Summary of Computer Accident Dose Consequences . . . . . . 15-20 15.4 Assumptions Used in the Radiological Consequences Analysis of the Steam Line Break Outside the Containment . . . . . . 15-21 15.5 Assumptions Used to Calculate Fuel Handling Accident Doses    15-22 15.6 Assumptions Used in Accidents Involving Small Line Breaksl5-23 Outside the Containment . . . . . . . . . . . . . . . . . . . 15-23 15.7 Assumptions and Bases For Steam Generator Tube Failure Doses  15-24 15.8 Assumptions Used in Loss-of-Coolant Dose Calculations . . . . 15-25 17.1 Regulatory Guidance Applicable to Qua1ity Assurance Program . 17-2
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SAFETY EVALUATION REPORT RELATED TO THE OPERATION OF WATERFORD STEAM ELECTRIC STATION UNIT NO. 3 1 INTRODUCTION AND GENERAL DISCUSSION
 
==1.1 INTRODUCTION==
 
This report is a safety evaluation report (SER) on the application for an operating license (OL) for the Waterford Steam Electric Station Unit 3 (Waterford 3) based upon an application filed by the Louisiana Power and Light Company (LP&L or the applicant). This report was prepared by the United States Nuclear Regulatory Commission staff (the NRC staff or the staff), and summarizes the resu1ts of the staff's radiological safety review of the facility.
The term NRC as used in this document refers to the staff's position. The NRC Licensing Project Manager for Waterford 3 is Mrs. Suzanne Black. Mrs. Black may be contacted by calling (301) 492-7119 or writing: Division of Licensing, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555. The NRC staff principal reviewers for this project are listed in Appendix H.
The application for a construction permit (CP) for the facility was filed with the United States Atomic Energy Commission (now the Nuclear Regulatory Commis sion) on December 31, 1970. Following staff review and a public hearing before the Atomic Safety and Licensing Board (ASLB), Construction Permit No. CPPR-103 was issued on November 14, J974. The application for an OL was filed with NRC in September 1978 and was docketed for review on December 18, 1978. The applicant has stated that construction of Waterford 3 will be complete and the plant ready for fuel loading by October 1982.
Before issuing an OL for a nuclear power plant, the NRC staff is required to review the effects of the plant on public health and safety. The safety review of Waterford 3 has been based on the Final Safety Analysis Report (FSAR) that accompanied the application for an OL and Amendments 1 through 19 thereto. All of this information is available to the public for review at the NRC Public Document Room at 1717 H Street, N.W., Washington, O.C., and at the University of New Orleans Library, Louisiana Collection, Lakefront, New Orleans, Louisiana. During the course of the review the staff has met a number of times with the applicant, the suppliers, and their consultants to discuss the design, construction, and proposed operation of Waterford 3. As a consequence, additional information was requested, which the applicant provided in Amendments 1 through 19 to the FSAR.
Following the Three Mile Island Unit 2 (TMI-2) accident, the Commission paused in its ljcensing activities to assess the impact of the accident. During this pause the recommendations of several groups established to investigate the lessons learned from TMI-2 became available. All available recommendations were correlated and assimilated into a 11 TMI Action Plan11 now published as NUREG-0660, entitled 11 NRC Action Plan Developed as a Result of the TMI-2 Accident." Additional guidance relating to implementation of the Action Plan is given in NUREG-0737, "Clarification of TM! Action Plan Requirements.11 These licensing requirements have been established to ensure incorporation of 1-1
 
the lessons learned from the TMI-2* accident to provide additional safety margins.
Sections 2 through 21 of this report address NRC review and evaluation of non-TMI-related issues that have been considered during the course of the staff 1 s review of the application for an OL for Waterford 3. Section 22 of this report contains the NRC review and evaluation of the applicant 1 s response to the TMI-2 requirements. In reviewing this report it should be kept in mind that TMI-related requirements are addressed for the most part in Section 22; non-TMI-related requirements are addressed in Sections 2 through 21. In ases where the non-TMI requirements have been completely superseded by TMI-related requirements, that section will only reference Section 22. The conclusions of this report are given in Section 23.
Appendix A is a chronology of NRC 1 s principal actions related to the review of the application. Appendix Bis a bibliography of the references used during the course of the review. Appendix C is a discussion of how various ACRS (Advisory Committee on Reactor Safeguards) generic concerns relate to the Waterford 3 application. Appendix D is a Lawrence Livermore Laboratory report on site seismicity. Appendix E is an evaluation of the applicant 1 s preliminary control room assessment. Appendix F is a list of abbreviations used in this report. Appendix G discusses the guidelines for demonstration of operability of purge and vent valves. Appendix His a list of principal contributors.
As part of NRC 1 s review of Waterford 3 for compliance with the Commission 1 s regulations, the staff requested the applicant to verify that Waterford 3 meets the pertinent regulatory requirements in 10 CFR Parts 20, 50, and 100.
The applicant 1 s response to this request, which was submitted on April 29, 1981, stated that Waterford 3 is in compliance with all applicable regulations and requirements. Subject to the applicant 1 s adoption of the additional requirements imposed by the staff in this Safety Evaluation Report, and the exemptions granted, the staff concurs that Waterford 3 is in compliance with these regulations and requirements.
In accordance with the provisions of the National Environmental Policy Act (NEPA) of 1969, Draft and Final Environmental Statements that set forth the considerations related to the proposed construction and operation of Waterford 3 were prepared by the staff and issued before NRC issued the CP (October 1972 and March 1973, respectively). After receiving the application for an OL, the staff issued a Draft Environmental Statement (DES) in April 1981 and will issue a Final Environmental Statement (FES) in August 1981.
The review and evaluation of Waterford 3 for an OL is only one stage in the continuing review by the staff of the design, construction, and operating features of the facility. The proposed design of the facility was reviewed as part of the CP review. Construction of the facility has been monitored in accordance with the inspection program of the staff. At this, the OL review stage, NRC staff has reviewed the final design to determine that the Commission 1 s safety requirements have been met. If an OL is granted, Waterford 3 must be operated in accordance with the terms of the OL and the Commission 1 s regu lations and will be subject to the continuing inspection program of the staff.
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1.2 GENERAL PLANT DESCRIPTION Waterford 3 employs a nuclear steam supply system (NSSS) consisting of a pressurized water reactor {PWR), a pressurizer, two steam generators, four coolant pumps, and the piping required to connect these components.
The reactor core will be composed of uranium dioxide pellets enclosed in Zircaloy tubes with welded end plugs. Water will serve as both the moderator and the coolant. The reactor coolant system (RCS) will consist of two separate loops, each provided with a steam generator and two pumps. An electrically heated pressurizer will establish and maintain the reactor coolant pressure and provide a surge chamber to accommodate reactor coolant volume changes during operation. Heat generated by the reactor will be transported by the reactor coolant to the steam generators where it will be transferred to the secondary (steam) system. The steam thereby produced will flow to the turbo generator where about one-third of the energy will be converted to approxi mately 1150 MWe of electrical energy. The remaining heat energy will be transferred in the steam condenser to a once-through circulating water system that draws water from and*discharges the heated water to the Mississippi River.
The major plant structures for Waterford 3 are the steel containment vessel and its surrounding concrete shield building, the auxiliary building, the fuel handling building, the cooling water intake structures, and the turbine building.
The containment vessel houses the nuclear steam supply system (NSSS). The auxiliary building houses most of the engineered safety features (ESFs), waste treatment facilities, emergency diesel generators, the control room, and other auxiliary systems. The fuel handling building contains the spent fuel storage pool and new fuel storage facilities. The intake structures contain pumps that provide river water for cooling the plant components. The circulating water system is connected to the turbine building by underground piping. The auxiliary component cooling water system (ACCWS) is connected to the circulating water system by underground piping from the wet cooling tower basins. The turbine building will house the condenser, the feedwater heaters and pumps, and the turbine auxiliaries. The turbine generator set will be an outdoor unit mounted on the top of the turbine building.
The reactor will be controlled by control rod movement and regulation of the concentration of a chemical neutron absorber (boric acid) in the reactor coolant. Eighty-three full-length and eight part-length control element assemblies (CEAs) wi11 each be moved vertically within the core by an individual control element drive shaft that penetrates the top head of the reactor vessel.
A reactor protection system (RPS) will automatically scram the reactor whenever a plant condition monitored by the system approaches preestablished limits. A protection system of similar quality will act to isolate the containment and initiate operation of ESFs should any or all of these actions be required.
The major plant auxiliary systems will be the chemical and volume control system (CVCS), the fuel handling system (FHS), and the waste management system
{WMS). The eves will be used to adjust the concentration of boric acid in the reactor coolant and to maintain the proper amount and purity of water in the RCS during reactor operation, heatup, and cooldown. The FHS will include the equipment and facilities used to transport and store new and used (spent) fuel while it is on the site, and wil1 include the reactor refueling cavity, which 1-3
 
will be flooded during refueling of the reactor, and the normally water-filled spent fuel storage pool. The WMS will be used to accumulate and process radioactive gases, liquids, and solids produced in the plant, and to control and monitor their release from the plant.
Auxiliary systems components, the shutdown cooling system heat exchangers, and the containment cooling heat exchangers will be cooled by the component cool ing water system (CCWS). The CCWS will transport heat energy to the ultimate heat sink. Processed liquid wastes will be released into the circulating water discharge piping.
The emergency core cooling system (ECCS) will supply cooling water to the reactor in the event of a loss of reactor coolant in excess of the amount that can be made up by the CVCS. In the event of a loss-of-coolant accident (LOCA),
cold water stored under nitrogen gas pressure in four safety injection tanks will be injected into the RCS when the system pressure drops below the pres sure of the nitrogen, three high-pressure and two low-pressure safety injection pumps (HPSI and LPSI) will also inject water into the RCS from a refueling water storage pool (RWSP). Water lost from the RCS will drain to a sump in the containment building; it will then be recirculated to the RCS by the Safety Injection Pumps.
A containment spray system (CSS) and a containment air cooler system (CACS) will act to reduce the containment pressure following a LOCA. Two containment spray pumps will initially pump water from the RWSP. During the recirculation phase of emergency core cooling (ECC), the containment spray pumps will pump water from the recirculation pump through the shutdown heat exchangers to the spray headers.
The switchyard will be supplied with electrical power from seven offsite transmission lines and will also be provided with independent and redundant onsite emergency power supplies capable of supplying the power needed to shut down the unit safely and to operate the ESFs in the event of an accident.
1.3 COMPARISON WITH SIMILAR FACILITY DESIGNS Many features of the design of Waterford 3 are similar to those the staff has evaluated and approved previously for other PWR plants now under construction or in operation (for example, San Onofre, Units 2 and 3, and Arkansas Nuclear One, Unit 2). To the extent .feasible and appropriate, NRC has relied on earlier reviews for those features that were shown to be substantially the same as those previously considered. Where this has been done, the appropriate sections of this report identify the other facilities involved. SERs for these other facilities have been published1 and are available for *public inspec tion at the Nuclear Regulatory Commission s Public Document Room at 1717 H Street, N.W., Washington, 0.C., and at the local Public Document Room at the University of New Orleans Library, Louisiana Collection, Lakefront, New Orleans, Louisiana.
1.4 IDENTIFICATION OF AGENTS AND CONTRACTORS Combustion Engineering Incorporated (Combustion or CE) is furnishing the NSSS for Waterford 3, including the first fuel loading, and Westinghouse Electric Corporation is furnishing the turbine generator set.
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Ebasco Services Incorporated (Ebasco) is providing engineering and construc tion management services, procurement services for all items not furnished by Combustion or Westinghouse, and administration of the Westinghouse and Combus tion contracts.
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==SUMMARY==
OF PRINCIPAL REVIEW MATTERS NRC technical review and evaluation of the information submitted by the appli cant considered, or will consider, the principal matters summarized below:
(1) The population density and land use characteristics of the site environs and the physical characteristics of the site (including seismology, meteorology, geology, and hydrology) to establish that these character istics have been determined adequately and have been given appropriate consideration in the plant design, and that the site characteristics are in accordance with the Commission's siting criteria in 10 CFR Part 100, taking into consideration the design of the facility, including the ESFs provided.
(2) The design, fabrication, construction and testing criteria, and expected performance characteristics of the plant structures, systems, and com ponents important to safety to determine that they are in accord with the Commission's General Design Criteria (GDC), Quality Assurance Criteria (QAC), Regulatory Guides, and other appropriate rules, codes, and standards, and that any departures from these:criteria, codes, and standards have been identified and justified.
(3) The expected response of the Waterford 3 facility to various anticipated operating transients and to a broad spectrum of postulated accidents.
Based on this evaluation, NRC determined that the potential consequences of a few highly unlikely postulated accidents (design-basis accidents, DBAs) would exceed those of all other accidents considered. The staff performed conservative analyses of these DBAs to determine that the calculated potential offsite radiation doses that might result, in the very unlikely event of their occurrence, would not exceed the Commission's guidelines for site acceptability given in 10 CFR Part 100.
(4) LP&L 1 s engineering and construction organization, plans for the conduct of plant operations (including the organizational structure and the general qualifications of operating and technical support personne1), the plans for industriai security, and the pianning for emergency actions to be taken in the unlikely event of an accident that might affect the general public, to determine that the applicant is technically qualified to safely operate the facility.
(5) The design of the systems provided for control of the radiological effluents from Waterford 3 to determine that these systems are capable of controlling the release of radioactive wastes from the facility within the limits of the Commission's regulations in 10 CFR Part 20, and that the equipment provided is capable of being operated by the applicant in such a manner as to reduce radioactive release to levels that are as low as is reasonably achievable (ALARA) within the context of the Commission's regulations in 10 CFR Part 50, and to meet the dose design objectives of Appendix I to Part 50.
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(6) LP&L's quality assurance program for the operation of the facility to assure that the program complies with the Commission's regulations in 10 CFR Part 50, and that the applicant will have proper controls over Waterford 3 operations so that there is reasonable assurance that the facility can be operated safely and reliably.
(7) The financial data and information supplied by LP&L as required by the Commission's regulations (Section 50.33(f) of 10 CFR Part 50, and Appendix C to Part 50) to determine that the applicant is financially qualified to operate the proposed facility.
1.6 MODIFICATIONS TO WATERFORD 3 DURING THE COURSE OF NRC REVIEW During the review, NRC staff met a number of times (see Appendix A to this report) with the applicant's representatives, contractors, and consultants to discuss various technical matters related to the facility. Also, the staff made a number of site visits to assess specific safety matters related to the station. The applicant made a number of changes to the facility design as a result of NRC review. The staff reviewed these design changes also. Special details concerning these changes are included in amendments to the FSAR and in appropriate subsections of this report.
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==SUMMARY==
OF OUTSTANDING ISSUES Section 18 is reserved for the report by ACRS to be issued following its review of the Waterford 3 application and this SER. The ACRS report is normally included in a supplement to the SER.
As a result of NRC review of the safety aspects of the Waterford 3 application, a number of items remain outstanding at the time of issuance of this report.
Since the staff has not completed its review and reached final positions in these areas, NRC considers these issues to be open. The review of these items will be completed before issuing an OL and will be reported in supplements to this report. The open items, with appropriate references to subsections of this report, are summarized below.
(1) Fire protection (7.4, 7.5, 7.7, 8.3.3, 9.5.1, 9.5.2, 9.5.3)
(2) Licensee qualifications (13.1, 13.2, 13.4)
(3) PSI/IS! (3.9.6, 5.2.4, 6.6)
(4) Appendices G & H (5.3.1, 5.3.2, 5.3.3)
(5) Emergency planning (13.3)
(6) Environmental qualifications (3.11)
(7) Seismic qualifications (3.10)
(8) Steam Voiding in reactor vessel analysis (15.3) 1-6
 
(9) Feedwater line break analysis (15.3.2)
(10) Loss of offsite power or tripping of the reactor coolant pumps during a main steam line break (15.3.1)
(11) Clarification of transient analyses with potential for fuel damage (15.2.1)
(12) Reactor coolant pump shaft break analysis (7.1, 7.2, 7.3, 7.5, 15.2.3.1)
(13) Pressure transient analysis in shield building annulus (6.2.3)
(14) Thermal-hydraulic design (4.4)
(15) Site Hazards (toxic gas, fire & explosive hazards) (2.2)
(16) Cold shutdown without leaving control room (5.4.3)
(17) Q-List (17)
(18) Turbine missiles (3.5.1.3, 3.5.3)
(19) Emergency feedwater control (7.3)
(20) I&E Bulletin 80-06 (7.3)
(21) Single failure of control system (7:7)
(22) Organic materials (6.1.2)
(23) Plant procedures (13.5)
(24) Indemnity requirements (21)
(25) TMI issues (Section 22)
Operational Safety (I.A.l tasks)
Organization and Management (I.B.1.2)
Operating Procedures (I.C tasks)
Control Room Review (I.D.1)
Containment System Design (II.E.4.2)
ICC Instrumentation (II.F.2)
Valve Position Indication (II.D.3) 1.8 CONFIRMATORY ISSUES At this point in the review there are a few items that have essentially been resolved to the staff's satisfaction, but for which certain confirmatory information has not yet been provided by the app1icant. In these instances, the applicant has committed to provide the confirmatory information in the near future. If staff review of the information does not confirm preliminary conclusions, that item will be treated as open and NRC staff will report on its resolution in a supplement to this report.
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The confirmatory items, with appropriate references to subsections of this report, are listed below.
(1) Testing the ultimate heat sink  (2.4)
(2) Piping analysis (3.9.1, 3.9.2)
(3) Containment isolation actuation signal (7.3)
(4) Performance of PWR relief and safety valves (22)
(5) Revised analysis of shield building (-5WG) (6.2.1)
(6) Reanalysis of Category I structure (3.7.3)
(7) Reevaluate foundation mat (3.8.5)
(8) Welding - justification of extrapolation (3.8.2)
(9)  Security plan (13.6)
(10) Sizing of primary safety valves (5.2.2)
(11) Shutdown initiation using safety grade equipment (5.4.3)
(12) Containment sump vortex test (6.3.3)
(13) Reactor coolant pump shaft seizure analysis (15.2.3.1)
(14) Diesel engine piping (9.5.4.2, 9.5.5, 9.5.6, 9.5.7)
(15) Boron dilution events (5.4.3, 15.2.4.4) 1.9 LICENSE CONDITIONS There are several issues for which a condition will be included in the operating license to ensure that NRC requirements are met during plant operation. Other license conditions will be defined at a later time. These items, with appro priate references to subsections of this report, are listed below.
(1) Shutdown cooling system flow sensors (5.4)
(2) Preoperational test of ECCS (6.3)
(3) LER required on spurious operation or malfunction of MOS or reactor power cutback system (7.3.3)
(4) Monitoring settlement (2.5.4.3)
(5) Fission gas release analysis for burnup in excess of 20 GWd/t (4.2.2.1)
(6) Fuel rod pressure approval only up to 39.1 GWd/t (4.2.2.2) 1-8
 
(7) Seismic and LOCA fuels analysis (4.2.2.9)
(8) Post-accident sampling (7.5.2, 22)
(9) Secondary water chemistry (10.3.4)
(10) Regulatory Guide 1.97 conformance (7.5.2)
(11) Control of heavy loads (9.1.4)
(12) Reevaluate essential verses non-essential systems (6.2.4) 1.10 GENERIC ISSUES ACRS periodically issues a report listing various generic matters applicable to light water reactors (LWRs). A discussion of these matters is provided in Appendix C to this report which includes references to sections of this report that more specifically discuss Waterford 3 concerns.
NRC continuously evaluates the safety requirements used in its review against new information as it becomes available. In some cases, the staff takes immediate action or interim measures to assure safety. In most cases, however, the initial assessment indicates that immediate licensing actions or changes in licensing criteria are not necessary. In any event, further study may be deemed appropriate to make judgments as t whether existing requirements should be modified. These issues being studied are sometimes called generic safety issues because they are related tq a particular class or type of nuclear facility. A discussion of NRC 1 s program to resolve these generic issues is presented in Appendix C to this report.
1.11 UNIQUE PLANT FEATURES (1) Ultimate Heat Sink The ultimate heat sink, which is entirely located within the nuclear island, consists of two independent, 100% capacity trains of mechanical draft, multiple cell dry and wet cooling towers and water stored in wet cooling tower independent basins. Four motors and other respective inde pendent distribution busses are sequenced with other diesel generator loads in the event off-site power is lost. Dry tower operation alone is sufficient to remove heat loads during most operating conditions; wet towers are needed to supplement dry tower operation during offnormal emergency conditions.
(2) Containment and Shield Building Design Waterford 3 possesses an advanced containment design which, in conjunction with a hold-up, dilution and multiple pass filtration system, significantly reduces off-site doses in the event of postulated accidents.
The design embodies a free standing steel containment vessel within a separate reinforced concrete shield building. There is an annulus between these two structures in which are supply and return ring ducts. To these ducts are connected two independent and safety grade trains of air handling 1-9
 
and filtration equipment. This system of air handling and filtration equipment is known as the Shield Building Ventilation System (SBVS).
The annulus is maintained at negative pressure relative to atmospheric pressure during normal operation and this pressure remains negative over the course of an accident. As a result, any leakage in the shield building structure causes atmospheric air to be drawn into the annulus rather than leakage of contaminated annulus air to the atmosphere.
Following an accident, there is an initial draw-down period of single pass filtration followed by a filtered recirculation mode during which there is a filtered and diluted release to the atmosphere.
(3) Condensate Storage Pool and Refueling Water Storage Pool The Reactor Auxiliary Building contains the Condensate Storage Pool and Refueling Water Storage Pool as an integral part of the building. This plant design feature precluded the need of providing separate, deep foundations supported by the Pleistocene sediments at the approximate elevation -45 to -50 MSL for these facilities. Additionally, this arrange ment eliminated the need to provide separate design features to protect the facilities against the effects of adverse atmospheric conditions, including winds, temperature, missiles, flooding and corrosive environment.
The selection of pools over tanks was based on established engineering criteria and analysis which took into account economic considerations as well as factors facilitating construction methods and schedules.
(4) Plant Computer The Waterford 3 Operational Man-Machine Interface Systems (OMMS) design is unique in that it has included since its inception, a firm and a flexible portion fully integrated in the design of the Main Control Board (MCB) and the operator's console. The firm portion is represented by the traditional hard-wired instrumentation, while the flexible portion com prises the functionally integrated computer-driven displays (color CRTs and plasma displays) and computer inputs (keyboards) available to the operator for the complete control of the versatile displays. The MCB includes four strategically located sets of computer (flexible) input/
output's, each comprising four 19-inch color CRT monitors, a plasma display and a keyboard, while the operator's console (desk) is equipped with three CRT monitors, a piasma display, and a keyboard. The supervisor i s office has two CRT monitors, a plasma display, and a keyboard.
Each of these stations operates independently and can display any infor mation available in the computer system, including duplication of another station's display. The six computer stations within the control room provide the operations staff with important, selectable, and expansible information at practically all necessary locations in the control room.
The central computer system consists of a "dual pair" 4 CPU configuration (two complete redundant systems with two CPUs each), with one pair active and the second pair in hot standby. The computers are System Engineering Laboratories (SEL) 32/55 (32 bit machines) with a high-speed flexible input/output system and a floating point processor. Each CPU has access 1-10
 
to 64K words of private memory and 64K words of shared memory. The SEL 32 architecture is designed around a synchronous time multiplexed SEL bus with a transfer rate of 26.67 million bytes per second.
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1.12 REFERENCES*
Code of Federal Regulations:
10 CFR Part 20 10 CFR Part 50 10 CFR Part 50, Section 50.33(f) 10 CFR Part 50, Appendix C Louisiana Power Light Co. Report:
FSAR for Waterford 3 US NRC Reports:
NUREG-0660 NUREG-0737 NUREG-0779
*See Appendix 8, Bibliography, for complete citations and availability statements.
 
2 SITE CHARACTERISTICS 2.1 GEOGRAPHY AND DEMOGRAPHY 2.1.1 Site Description Waterford 3 is located in St. Charles Parish, Louisiana between the towns of Killona and Taft. It is on the west bank of the Mississippi River, near River Mile 129.6 and about 24 mi west of the City of New Orleans. Its geographic location is shown in Figure 2.1. The Universal Transverse Mercator coordinates for the reactor are 3,320,700 m N and 744,000    m E, Zone 15. The corresponding geographical coordinates are latitude 29° 59 1 4211 N, and longitude 90° 28 1 16 11 W.
The flat terrain in the area is typical of the Mississippi River delta. The site area owned by the applicant is larger than 3000 acres, but the plant area occupies only about 100 acres. The plant area elevation is about 16 to 17 ft above mean sea level (MSL) (Gulf of Mexico). Between the Waterford 3 plant area and the river there is a levee and Louisiana State Highway 18 (LA 18),
both running parallel to the riverbank and traversing the site. Approximately 2200 ft W of the plant are Waterford 1 and 2, which are fossil-fueled power plants. The site is crossed on the south side by Missouri Pacific Railroad about 2300 ft from the plant area.
2.1.2 Exclusion Area Control The site has an exclusion area as required by 10 CFR Part 100. The applicant has designated the exclusion area to be the circular area having a radius of 914 m (about 3000 ft) centered on the reactor. This 648.5-acre area lies completely within the site area, except for a portion which extends over the Mississippi River. The applicant owns all the surface rights within the land portions of the exclusion area, and owns all the subsurface (mineral) rights except for a small triangular portion of about 2 acres at the extreme WSW edge of the exclusion area.
10 CFR §100.3(a) defines the exclusion area as the area where the reactor 1icensee 11 has the authority to determine all activities including exclusion or removal of personnel and property. 11 While the applicant does not own the sub surface mineral rights in the 2 acre trianguiar portion of the exclusion area in question, applicant's deed to the property under which subsurface mineral rights were reserved to others explicitly provides that the subsurface mineral right owners retain no surface rights of any kind. Pursuant to that deed, the subsurface mineral right owners have no right of ingress and egress to and from the triangular area, no right to drill on the surface thereof, no geophysical rights and no rights to lay or build pipelines, other lines, roads or canals.
The reservation of subsurface mineral rights in this area to the subsurface mineral right owners is limited to the right to their proportional share of mineral production from the area as a result of unitization and pooling and to drill directionally in the subsurface of the area without the use of the sur face of the area. In these circumstances then, the applicant has fu11 authority 2-1
 
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for controlling all activities on the surface of the triangular area in question, including the authority to prevent mineral exploration and extraction on the surface of this area and the authority to exclude or remove persons and property from this area. In view of this, we find that the applicant has the requisite authority over the entire exclusion area as defined in 10 CFR §100.3(a).
Nevertheless, it is theoretically possible to gain access to potential subsur face minerals in the above mentioned portion of the exclusion area using tech*
niques such as slant drilling from an adjoining property. The staff concludes, based upon the distance of the trianular area from the plant safety structures (about 2700 ft), as well as past review experience in other cases, that potential mineral extraction in this area would pose no threat to the safe operation of the Waterford 3 plant, neither from potential subsidence of plant safety-related structures nor from accidental fires r explosives associated with mineral extraction accidents.
The exclusion area is traversed by LA 18, which is about 140 m (460 ft) from the plant; a river levee about 183 m (600 ft) from the plant; the Missouri Pacific (formerly the Texas and Pacific) Railroad about 700 m (2300 ft) from the plant; and the Mississippi River about 305 m (1000 ft) from the plant.
The applicant has made arrangements with the St. Charles Parish Sheriff's Office and the Louisiana Department of Public Safety, Office of State Police, to control traffic on the portion of State Highway 18, traversing the exclusion area, in the event of emergency. Similarly, arrangements have been made for traffic control with the United States Coast Guard (river) and the Missouri Pacific Railroad Company (railroad). An agreement has been executed with the Board of Commissioners, Lafourche Basin Levee District to provide the applicant with the authority to restrict access to the Mississippi River Levee traversing the exclusion area.
There is no visitors' center or other recreational facilities at the Waterford 3 site; there are several activities not related to the plant within the exclusion area.
Two fossil-fueled power plants, Waterford Steam Electric Station, Units 1 and 2, are located about 2000 ft NW of the reactor. These plants are owned and operated by the applicant and employ a total of about 60 people.
There is a gas valve station at the ESE edge of the exclusion area. This station involves periodic monthly maintenance involving, typically, two persons.
Occasionally, people fish in the Mississippi River from the batture (the alluvial land lying between the low-water stage and the levee). The applicant has estimated that up to 10 people may be fishing within the exclusion area at a given time.
The applicant has indicated that portions of the exclusion area may continue to be used for agricultural purposes and that 50 to 60 farm workers may be in the exclusion area at times.
Based on the distances and nature of these activities, the NRC staff concludes that these activities that are not related to the operation of Waterford 3 2-4
 
will not interfere with normal operation of the nuclear facility. The applicant has the authority to control such activities and has described procedures to be followed for these activities in the event of an emergency.
2.1.3 Population Distribution The resident population in the vicinity of the Waterford 3 site is shown as a function of distance in the table below.
Table 2.1 Resident population vs. distance Distance (mi)
Year  0-1  0-2      0-3    0-4      0-5 1977  453  1,774    2,303  10,947  17,268 1981  453  1,860    2,606  11,656  18,546 2020  453  2,183    4,780  19,258  33,477 The largest community in the vicinity of the site is the Town of Norco, with an estimated 1977 population of 5236 located about 3 mi away from the plant, and on the opposite side of the Mississ1ppi River. The nearest community with a population over 1000 is the Town of Killona, located about 0.9 mi NW of the plant, with an estimated 1977 population of 1203.
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The applicant has chosen a low population zone (LPZ) radius or 2 mi. The estimated 1977 resident population within the LPZ was about 1800 persons and is projected to be about 2200 persons in the year 2020. One school, the Ki11ona Elementary School, which had a 1977 enrollment of 152 pupils is located within 2-5
 
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The applicant has selected the nearest population center (as defined in 10 CFR Part 100) to be the urbanized area of New Orleans, whose western boundary is about 12 mi from Waterford 3. The population center distance of 12 mi is approx imately the distance to the City of Kenner, a suburb of New Orleans, located in Jefferson Parish. Kenner had a 1975 population of 43,780 persons. The City of New Orleans is located in Orleans Parish and is about 24 mi from the Waterford 3 site. In 1970, the population of the New Orleans urbanized area was about 962,000.
According to the U.S. Department of Commerce, Bureau of the Census, the 1980 New Orleans standard metropolitan statistical area (SMSA) had a population of about 1,200,000. Based on the 1970 to 1980 growth rate for the area, the projected population is about 2,000,000 for the year 2030. Although communities west of New Orleans are expected to grow in conjunction with the growth of the New Orleans SMSA, none of the population centers within a distance of one and one-third times the LPZ radius is expected to exceed 25,000 persons. The projected popula tion for the year 2030, based on the growth rate of about 2.4% per year for St. Charles Parish between 1970 and 1980, is significantly less than 25,000 for any of the communities within 10 mi of Waterford 3. NRC staff concludes that the population center is located at a distance which is at least one and one-third times the LPZ radius, as required by 10 CFR Part 100.
The staff has made an independent estimate of the 1970 population within a 50-mi radius of the Waterford 3 site based on the Bureau of the Census data. The staff value of 1,532,917 is slightly lower than the 1,643,646 value listed by the applicant. The corresponding staff and applicant estimates for the year 2000 are 1,808,842 and 2,129,568, respectively. The staff's estimate is based on a growth rate of 18% between 1970 and 2000 as derived from the population projections of the Bureau of Economic Analysis Areas within a 50-mi radius.
The applicant's estimates correspond to a growth of about 30% between 1970 and 2000.
The emergency plan for Waterford 3 is curently undergoing staff review to deter mine if the applicant has provided reasonable assurance that adequate protective measures can and will be taken on behalf of the population in the event of a serious accident. A discussion of the staff findings is reported in Section 13.3, and the final findings will be reported in a supplement to this Safety Evaluation Report (SER).
2.1.4 Conclusions On the basis of NRC analysis of the onsite meteorological data from which the relative concentration factors (X/Q) were calculated (see Section 2.3 of this report), and the calculated potential radiological dose consequences of design basis accidents (see Section 15 of this report), the staff has concluded that the exclusion area and LPZ doses meet the guideline values of 10 CFR Part 100.
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2.3 METEOROLOGY 2.3.l Regional Climatology The climate of southeastern Louisiana is humid subtropical, influenced greatly by the Gulf of Mexico and many other water bodies. The predominant air mass type over the region during most of the year is maritime tropical originating over the Gulf of Mexico. In the winter, occasional southward movements of continental polar air from Canada bring colder and drier air into Louisiana.
It rains every month and a fairly definite rainy period occurs from mid-December to mid-March. Snow and freezing precipitation are of little importance in Louisiana. High wind speeds in the aiea are associated with hu;;icanes, thunderstorms, frontal passages, and extratropical cyclones. The highest 1-min average wind speed officially measured at New Orleans (USDC, 1972) was 44 m/sec (98 mph). During Hurricane Betsy (September 9, 1965) an extreme wind of 56 m/sec (125 mph) was estimated atop the Federal Building in New Orleans.
The extreme wind speed with a recurrence interval of 100 years has been computed to be 45 m/sec (100 mph) for the site area (Thom, 1968). The mean annual frequency of tornadoes per one degree square in the site area is about one.
The annual probability of a tornado striking the site is about 6 x 10-4 (Thom, 1963). High air pollution potential resulting from limited dispersion (atmo spheric stagnation) can be expected to occur with a greater frequency in the site area (10-15 days annually) than over most of the eastern United States (Holzworth, 1972). There has been no change in the regional climatology since 2-13
 
the CP was issued. The staff concludes that, pursuant to the requirements of 10 CFR Section 100.10, adequate consideration has been given to the regional climatology of the Waterford 3 site. The requirements in 10 CFR Part 50, Appendix A, GOC 2, to consider natural phenomena, and GDC 4, to consider tornado-generated missiles, have been met for meteorological parameters.
2.3.2 Local Meteorology The plant site is on the west bank of the Mississippi River upstream from New Orleans. The terrain in the vicinity of the plant is flat and has little or no influence on the meteoro1ogy. The predominant onsite wind direction is from the southeast with° a 2.3%° occurrence of calms. The average temperatures onsite range between 27 C (80 F) in July and 12° C (54° F) in January. The temperature rarely falls below freezing. Relative humidities are generally high throughout the year and heavy fog occurs frequently (about 32 days annually in New Orleans) in the vicinity of the site. Onsite temperature differences between 10 m (30 ft) and 40 m (130 ft) indicate stable atmospheric conditions 56% of the time, unstable conditions 19% of the time, and neutral stability 25% of the time.
The requirements to consider onsite meteorological conditions in 10 CFR Section 100.10 and the requirements in 10 CFR Part 50, Appendix A, GOC 2, to consider natural phenomena have been met for meteorological parameters.
2.3.3 Meteorological Measurements Program An onsite meteorological measurements program was operational at the Waterford 3 site between June 1971 and June 1975. The program was reactivated in February 1977 and operated until February 1978. A 40-m (130-ft) tower was installed approximately 610 m (2000 ft) east of the reactor building in a sugar cane field. Wind and temperature measuring instruments were located at the 10-m and 40-m (30-ft and 130-ft) levels on the tower. The applicant has submitted 4 years of data collected onsite (7/72-6/75 and 2/77-2/78) in joint frequency form similar to that suggested in RG 1.23 and hourly average data on magnetic tape. The onsite meteorological measurements system conforms to the guidance in RG 1.23 and provided adequate data to represent the onsite meteorological conditions as required in 10 CFR Section 100.10. The onsite data provide an acceptable basis for making conservative estimates of atmospheric diffusion for OBA and routine releases from the plant. The applicant*s program to address the meteorological requirements for emergency preparedness planning outlined in 10 CFR Section 50.47 and Appendix E to 10 CFR Part 50 are discussed in Section 13.3 of this report.
2.3.4 Short-Term (Accident) Diffusion Estimates The short-term (less than 30 days) accidental atmospheric releases from build ings and vents were evaluated by the staff according to the guidance provided in RG 1.145. Wind direction and speed measured onsite at the 10-m level and vertical temperature difference (T) between the 40-m and 10-m levels were used (see Section 2.3.3). A ground-level release with a building wake factor, cA, of 1234 m2 was assumed. The maximum sector 0.5 percentile relative concen tration (X/Q) for the 0- to 2-hr period was calculated to be 5.1 x 10-4 sec/m 3 in the NNW sector at the minimum site boundary distance of 914 m. The maximum 2-14
 
sector concentration at the outer boundary of the LPZ (3,219 m) was calculated to be 6.9 x 10-5 sec/m3 in the NNW sector for the 0- to 8-hr time period. The computed relative concentration at the outer boundary of the LPZ in the NNW sector was 4.5 x 10- 5 sec/m3 for the 8- to 24-hr time period, 1.8 x 10-5 sec/m3 for the 1- to 4-day period, and 4.9 x 10-6 for the 4- to 30-day period.
The applicant used a directionally independent methodology previously accepted by the staff for calculating short-term X/Q values and was, therefore, different than that suggested in RG 1.145 and used by the staff. The applicant's 0- to 2-hr X/Q value is 20% more conservative than the staff's, and the 0- to 8-hr X/Q is not significantly different. The staff's X/Q values for the 8- to 24-hr and 1- to 4-day time periods are about 6 times more conservative than the applicant's. The 4- to 30-day X/Q value computed by the applicant is about 3 times less conservative than the staff's. The staff's calculated short-term X/Q values were used in the accident analyses presented in Section 15 of this report.
2.3.5 Long-Term (Routine) Diffusion Estimates Long-term diffusion estimates were made by the applicant and the staff using the guidance given in RG 1.111, Rev. 1, for a constant mean wind direction model. A ground-level release was assumed for all releases. Open terrain recirculation factors were used in the computer model. The applicant used the July 1972 to June 1975 data; the staff used all the data submitted by the applicant (see Section 2.3.3 of this report). The staff's X/Q and D/Q (deposi tion rate) values are less than a factor of 2 more conservative than the applicant 1 s. This difference is attributable to the differences in modeling techniques, data, and terrain recirculation factors.
The staff's values were used in evaluating the applicant's proposed gaseous releases and compliance with 10 CFR Part 50, Appendix I design objectives discussed in Section 11.2 of this report.
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2.5 GEOLOGY AND SEISMOLOGY In the review of the Waterford Steam Electric Station Unit 3 Final Safety Analysis Report through Amendment 19 (June 19, 1981), NRC staff has considered pertinent information gathered since its initial geologic and seismologic review (Construction Permit Safety Evaluation Report) which was issued in December 1972. This pertinent information includes (1) data gained from both site and near-site investigations, (2) discussions with individuals at the State, Federal, and private levels who know of the region, and (3) data from a review of recently acquired literature.
As a result of its recent review and evaluation of the above geologic and seismologic information, the staff has determined that its 1972 Construction Permit Safety Evaluation Report conclusion regarding the safety of Waterford 3 from a geological and seismological standpoint remains valid. The NRC advisor for the Waterford 3 site, Lawrence Livermore Laboratory (LLL), has a1so completed its review of the FSAR. Its letter report is attached as Appendix D to this evaluation. Conclusions of both the NRC review and the LLL 1 s review can be summarized as follows:
(1)  Geologic and seismologic investigations and information presented by the applicant as required by 10 CFR Part 50, 10 CFR Part 100, and by Appendix A to 10 CFR Part 100 provide an adequate basis to establish that no capable faults exist in the plant site area which would cause earthquakes to be centered there.
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(2) No evidence has been found to indicate that a potential exists for surface faulting at the Waterford facility.
(3) The acceleration level and associated response spectrum proposed for the safe shutdown earthquake (SSE) are appropriate for the seismic design of the Waterford plant.
The applicant's presentation in FSAR Sections 2.5.1, 2,5.2, and 2.5.3 has satisfied the requirements of 10 CFR Part 50, 10 CFR Part 100, and Appendix A to Part 100 by (1) performing post-CP site and near-site geologic, seismological, and geophysical investigations, by (2) reviewing the pertinent site-related literature developed since issuance of the CP, and by (3) consulting with individuals who know about the local geology and seismology. This information is needed to assemble, evaluate, and adequately support the applicant's con clusions regarding the favorable geologic and seismic characteristics of the Waterford 3 site. In addition, the applicant is in conformance with applicable portions of the following documents:
(1) Standard Review Plan Sections 2.5.1, 2.5.2 and 2.5.3 (NUREG-75/087).
(2) Regulatory Guide 1.60, "Design Response Spectra for Seismic Design of Nuclear Power Plants."
(3) Regulatory Guide 1.70, "Standard Format and Content of Safety Analysis Repo.rts for Nuclear Power Plants," Revision 2.
(4) Regulatory Guide 1.132, "Site Investigations for Foundations of Nuclear Power Plants."
(5) Regulatory Guide 4.7, ''General Site Suitability Criteria for Nuclear Power Stations."
The newly acquired information reviewed for Waterford 3 is discussed in Sections 2.5.1, 2.5.2, and 2.5.3 below.
2.5.1 Geologic Information Since issuance of the Construction Permit Safety Evaluation Report in 1972, the applicant has conducted geologic investigations both onsite and offsite and has evaluated geophysical data obtained by others. These investigations and analyses have resulted in an increased understanding and confirmation of the surface and subsurface conditions of the Waterford site and vicinity. No new known information has been developed indicating that earlier conclusions reached by the staff regarding the suitability of the Waterford site should now be modified.
The principal newly developed geologic/geophysical information relative to the Waterford site and site vicinity (within 5 mi of Waterford 3) has been derived from the following sources:
(1) Mapping and photographing of the excavation for the plant structures.
(2) Acquisition and interpretation of remote-sensing imagery including Earth Resources Technology Satellite CERTS) Landsat, Skylab and side-looking radar.
(3) Well logs made in conjunction with hydrocarbon (oil/gas) exploration and development.
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(4) Structural contour maps of geologic horizons underlying the site and vicinity. These maps were prepared by the Geomap Company of Houston, Texas.
(5) A Corps of Engineers report by Kolb et al. (1975) which presents information regarding the geologic environment of the Waterford site area.
Geologic mapping of the plant excavation by the applicant, coupled with complete photographic coverage as well as analyses of remote sensing information including Skylab, ERTS (Landsat) and high-altitude photography, have confirmed the geologic integrity of the plant foundations area. As predicted by the applicant 1 s pre-CP investigations, the Waterford 3 excavations as inspected, mapped, and photographed show no evidence of either faulting or through-going deformation.
The only anomaly encountered was a NE-SW trending depression, located in the SE corner of the excavation. The applicant has demonstrated through various techniques, including mapping, photographing, closely spaced borings, and photolinear analysis, that this anomaly is of nontectonic origin and is most likely a filled stream channel incised into the uppermost Pleistocene (the Prairie Terrace) during Holocene time. The filled channel is shallow and terminates above plant foundation, which is at El -48 ft. Through site soil borings, several continuous horizons within the Prairie Terrace, which is at least 80,000 years old (Saucier, 1974), have been identified, further demonstra ting the absence of faulting in the uppermost Pleistocene. Contouring of the Pleistocene Prairie Terrace and the construction of geologic cross-sections in the vicinity of the depression have also confirmed the geologic integrity of the immediate plant area.
Although oil and gas exploration and development have continued in the near-site area following issuance of the CP, no new producing wells have been completed within approximately 4 mi of the Waterford 3 plant. Therefore, the potential geologic hazards (such as possible differential subsidence or displacement) which may be associated with the near-site development and production of hydrocarbons do not exist.
The geologic and geophysical information derived from the pre- and post-CP wells within 5 mi of Waterford 3 has been obtained and evaluated by the applicant.
These data, as interpreted by the applicant, confirm the earlier (CP) conclusions relative to the near site area in that growth faulting:
(1)  Does not cut the surficial deposits.
(2) Does not penetrate the Pliocene strata which are at least 5 million years oid.
Because of oil industry exploration, considerable subsurface information (seismic reflection/refraction surveys and hydrocarbon test wells) has been developed within the site area. This has resulted in the interpretation, by various groups, of a number of faults. Interest in the subsurface will undoubtedly continue, because of the economic incentive, and may result in the interpretation of additional fau1ts. The location, characteristics, and, in some cases, actual existence of these faults has been interpreted somewhat differently by different groups and different interpretations have been made at different times by the same group. Based upon NRC review of all available information, the staff concurs with the applicant that no capable faults are known to exist 2-23
 
in the plant area. The faults which have been identified within the near-site area since issuance of the Construction Permit Safety Evaluation Report are shown on FSAR Figure 361.7-1 and are identified as (1) Geomap Fault 1; (2) Geomap Fault 2, which is a fault zone consisting of three faults - Geomap Faults 2A, 2B and 2C; and (3) Fault 3. The other faults shown on the figure (Norco Fault and Faults Band C) were identified during the review of the PSAR. The post-CP faults and NRC 1 s bases for concluding their noncapability are summarized below:
(1) Geomap Company Faults--The Geomap Company of Houston, Texas (Jan. 1981) has interpreted two faults--one north of the Waterford 3 plant (Geomap Fault 1) and the other east of the plant (Geomap Fault 2). Geomap's analyses are based upon the company 1 s interpretation of geophysical data (well logs) as well as its knowledge of the structural geology                                  of the region. A des cription of the Geomap faults, the applicant 1 s analyses of Geomap 1 s bases for identification of the faults, and NRC's evaluation of the faults follows:
(a) Geomap Fault 1--The fault, as interpreted by the Geomap Company, is EW trending, is located 3 1/2 mi north of the Waterford plant, and is approximately 3 1/2 mi long with a two mi long branch fault extending to the northeast (Geomap, Jan. 1981).
The applicant, based upon its evaluation of well log numbers 96, 97, 107, 108, and other logs in the area, reinterpreted Geomap Fault 1 to be located southward at a different level and designated it as Fault 4. NRC agrees that there are bases for concluding that such a fault exists. Based upon staff interpretation of well logs, which show unfaulted Pliocene and older (Miocene) formations overlying its projection, the staff considers this fault (Fault 4) noncapable.
(b) Geomap Fault 2A--The Geomap Company has recently indicated* that it has reevaluated its basis for identifying Geomap Fault 2A and has determined that it no longer supports its previous interpretation. The staff under stands* that Geomap Fault 2A will not be shown on the next version of Geomap's structural contour map which is scheduled for publication before July 1981. As a result of Geomap's reevaluation and retraction, no further discussion relative to Geomap Fault 2A will be made.
(c) Geoma Fault 28--This fault (Geomap, January, 1981) is about 2-1/2 mi long, trenas northwesterly, and is about 4 mi E of the Waterford 3 plant.
The applicant accepts the general location of Geomap Fault 2B based on
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that the fault is the result of the vertical growth of the Good Hope salt dome. Based upon a combination of data including (i) structural contours of Pliocene horizons interpreted from the geophysical logs of hydrocarbon wells and (ii) published maps of Pleistocene aquifers derived from water wells (Hosman, 1972), the applicant has concluded that Geomap Fault 2B is not capable, having ceased movement prior to the Early Pliocene (about 5.0 million years ago), and therefore constitutes no potential site hazard.
*Personal Communication (telephone) from Geomap Company to U.S. Nuclear Regulatory Commission, April 27, 1981.
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The staff concurs with the applicant and accepts the general location of Geomap Fault 28. The staff also agrees with the applicant that Geomap Fault 28 appears to be the product of the development of the Good Hope salt dome which is about 5-1/2 mi E of the Waterford 3 site. Although NRC considers Geomap Fault 2B not capable, the staff concludes, after extensive evaluation of all available information, that the applicant 1 s bases for noncapability of the fault are not supportable because of a lack of available control points from which the map (Pleistocene aquifer and Pliocene structural contour) were constructed. The staff's bases for determination that the fault is not capable include (i) a nontectonic origin for the fault because of its association with salt dome growth* (Smith, 1980) and (ii) at least one well-documented unfaulted Pleistocene horizon overlying the surfaceward projection of Geomap Fault 28 (Kolb et al.,
1975).
(d) Geoma Fault 2C--At its closest approach to the Waterford 3 plant, which is a5out 4-1/2 mi to the west, Geomap Fault 2C (Geomap, January 1981) is about 5 mi long and trends NNE.
This fault, like Geomap Fault 2B, is accepted by the applicant as an identifiable subsurface fault associated with the growth of the Good Hope salt dome. As in the case of Geomap Fault 2B, the applicant has determined the noncapability of Geomap Fault 2C based upon contours developed on Pliocene horizons and Pleistocene aquifers.
NRC, like the applicant, accepts the general location of Geomap Fault 2C and, likewise, concurs with the applicant and associates the fault with the vertical growth of the Good Hope salt dome, located at a depth of at least 9,500 ft below the ground surface (Smith, 1980). The staff bases its determination that this fault is non-capable on (i) sufficient control on both Pliocene horizons (FSAR Figures 2.5-21 and 2.5-22) and Pleistocene horizons (Kolb et al., 1975) along the up-dip projection of the fault and (ii) association of the origin of the fault with the growth of a localized feature, the Good Hope salt dome.
(e) Fault 3--The applicant has identified a fault not shown on the Geomap structural contour maps (Geomap, January 1981). This NE trending fault, based upon the applicant 1 s interpretation (Figure 361.7-1 of the FSAR) is nearly 1-1/2 mi long and is about 4 mi N of the Waterford 3 plant.
Noncapability of the fault, in the applicant 1 s opinion, is demonstrated by capping of the fault by Pleistocene aquifers and undisturbed Miocene and Pliocene strata.
Based upon the staff 1 s interpretation of the geophysical logs of well Nos. 98, 99, and 107 (see FSAR Figure 2.5-18 for location) the staff accepts and recognizes the general location of Fault 3. The staff considers this fault not capable, since our interpretation of geophysical logs of nearby wells demonstrates that unfaulted Miocene and Lower Pliocene strata cap the surfaceward projection of the fault.
*Personal Communication (telephone) from Geomap Company to U.S. Nuclear Regulatory Commission, April 27, 1981.
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(2) Fault 4--See discussion under Item (1), Geomap Fault 1.
2.5.2 Seismology 2.5.2.1 Vibratory Ground Motion Summary In its review the staff has followed the tectonic province approach to determine the vibratory ground motion corresponding to the safe shutdown earthquake (SSE)
(Appendix A of 10 CFR Part 100). The conclusion of the CP review was that 0.10 g and 0.05 g are adequate values for the peak horizontal accelerations for the SSE and operating basis earthquake (OBE), respectively (Construction Permit Safety Evaulation Report, December 1972). Since the conclusion of the CP review no new information has become available to change the staff's original conclusions.
2.5.2.2 Tectonic Province During the CP review the staff's seismological consultant, National Oceanic and Atmospheric Administration (NOAA), evaulated the seismicity of the area around the proposed Waterford 3 site. NOAA recommended and the staff concurred that horizontal accelerations of 0.05 g and 0.10 g are adequate to represent ground motion for the OBE and SSE, respectively. Current staff practice uses the tectonic province approach outlined in Appendix A of 10 CFR Part 100 (November 1973), and locates the Waterford 3 site in the Gulf Coastal Plain Tectonic Province, characterized by thousands of feet of unmetamorphosed sediments of the Gulf Coast geosyncline. This is consistent with other SERs for sites in the Gulf Coastal region (Allens Creek; 1974; South Texas; 1975; Blue Hills; 1977; Yellow Creek, 1977; and Comanche Peak, 1981). King (1969) defines the Atlantic and Gulf Coastal Plains as platform deposits (Mesozoic age and younger) that were laid over the deformed basement (Paleozoic and older rocks of the Appalachian and Quachita foldbelts). The platform deposits thicken and slope seaward from the exposed parts of these foldbelts, with the basement descending beneath them. From New Jersey, south and then west to the Llano Uplift in central Texas, the landward border of the platform deposits (Coastal Plain) is drawn at the contact of the Cretaceous and (or) Tertiary deposits with the underlying and overlapping basement rock. The Waterford 3 site is located in the Gulf Coastal Plain Tectonic Province, which is the part of the Coastal Plain extending from west Florida westward and southward into Mexico.
The applicant has proposed tectonic provinces for the Gulf Coastal region based on unique crustal patterns, geologic history, and earthquake history. The staff has reviewed this, and although NRC established somewhat different boundaries, the applicant's analysis of the maximum earthquake for the Waterford 3 site, in accordance with Appendix A of 10 CFR Part 100, is equivalent to the staff's analysis.
2.5.2.3 Maximum Earthquake Within the Gulf Coastal Plain Tectonic Province, the staff recognizes that different regions of this large province exhibit vastly different levels of seismicity. In particular, to arrive at the appropriate choice of the SSE for the Waterford 3 site, the staff recognizes three areas of seismicity within or intersecting this province: (1) the Mississippi Ernbayment (New Madrid) Earth quake Zone, (2) the Ouachita-Wichita belt of seismicity, and (3) seismicity in the remainder of the Gulf Coastal Plain Tectonic Province.
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The Mississippi Embayment Earthquake Zone is located more than 330 mi N of the Wateford 3 site. This area is the source region of the largest earthquakes in the eastern United States--the 1811-1812 New Madrid earthquakes, MM intensity XI-XII (Nuttli, 1973). A reoccurrence of these earthquakes at the closest approach of the Mississippi Embayment Earthquake Zone to the Waterford 3 site (Memphis, Tennessee, more than 330 mi from the site) would produce MM intensity VI-VII at the site using Gupta and Nutt1i (1976), although the ground motion level would not be as great when compared with the largest earthquake within the remainder of the Gulf Coastal Plain Tectonic Province not associated with a tectonic structure, which is assumed to occur near the site. Thus, these earthquakes are located far enough from the site to be of little significance.
The boundaries of the E-W Ouachita-Wichita belt of seismicity are subject to interpretation by various investigators. Nutt1i and Brill (1981) show this E-W trending area overlapping the Nemaha Ridge Seismic Zone, while the appli cant's map of provinces of unique crustal patterns (Waterford 3 FSAR Figure 2.5-42) shows the front of the Ouachita Province. Both maps though, show the Ouachita-Wichita belt of seismicity and province to intersect and overlap the Gulf Coastal Plain Tectonic Province. While the boundaries are somewhat ambiguous, the largest historically recognized earthquake in the Ouachita-Wichita belt of seismicity is he October 22, 1882, MM intensity VII, earthquakes which occurred near Paris, Texas. This event is surrounded by some uncertainty with respect to the location and intensity. Estimates of its intensity, as reported in the literature, range from MMI=VII (Coffman and Von Hake, 1973), who placed the epicenter near Fort Smith, Arkansas, to a weak MMI=VIII (Docekal, 1970) who upon reevaluation of the data located the  epicenter near Paris, Texas.
Based on the available data it is the staff 1 s view that the earthquake occurred near Paris, Texas and that the maximum intensity was probably no higher than VII (Comanche Peak, CP review SER, 1974). Because this event has not been associated with known geologic structure, the staff assumes its occurrence t the closest approach of the Ouachita-Wichita belt of seismicity (more than 160 mi) to the Waterford 3 site. Assuming the occurrence of an MM intensity VII earthquake 160 mi away from the site and using the intensity-attenuation relationship of Gupta and Nuttli (1976) results in an MM intensity IV at the site.
Seismicity in the remainder of the Gulf Coastal Plain Tectonic Province is relatively uniform. The largest historical intensity earthquake that cannot be associated with known geologic structure is the MM intensity VI event centered near Donaldsonville, Louisiana that occurred on October 19, 1930. The largest historical magnitude earthquake that cannot be associated with known geologic structure is the mb = 4.8 event which occurred offshore in the Gulf of Mexico on November 5, 1963. Based on the lack of structural association, the staff assumes that an earthquake similar to that which occurred in Donaldsonville or the Gulf of Mexico, could occur near to or at the plant site. The January 8, 1891 Rusk, Texas earthquake is reported by some sources as MM intensity VII (Coffman and Von Hake, 1973). Although it apparently caused MM intensity VII damage over a small area, the earthquake was on1y reported at Rusk. Typically, an MM intensity VII earthquake is felt over a wide area. For example, the 1930 Donaldsonville, Louisiana, MM intensity VI earthquake was felt over an area of 18,500 mi2* It is hard to assess the damage from the Rusk earthquake, which was briefly described in the Dallas, Texas newspaper, because it was accompanied by violent weather conditions, making it difficlt to distinguish between earth-2-27
 
quake and storm damage. The intensity scale is not precise and must be carefully interpreted. Only chimney damage was reported. Nuttli and Brill (1981) inter pret earthquakes with relatively high epicentral intensity and small felt areas as being shallow events of very small magnitude occurring in the upper few kilometers of the crust. In light of the above considerations, the staff concludes that the Rusk event should be considered as a very shallow, small magnitude earthquake (mb = 3.8) (Nuttli and Brill, 1981).
2.5.2.4 Safe Shutdown Earthquake In determining the SSE, the staff has followed the tectonic province approach described in Appendix A of 10 CFR Part 100. The applicant 1 s proposed SSE acceleration level of 0.10 g is a conservative representation of the SSE and roughly corresponds to an MM intensity VI-VII occurring near the Waterford 3 site using the intensity-acceleration relationship of Trifunac and Brady (1975).
This acceleration value is used as the high frequency input to the response spectrum. Because Regulatory Guide 1.60 response spectra were not used, the applicant was requested to identify areas of exceedence of the design compared with Regulatory Guide 1.60. The result of this analysis (discussed in Section 3.7.1) showed that the spectra generally conform to RG 1.60.
Because the November 5, 1963 mb = 4.8 earthquake had no intensity or felt reports the staff*asked the applicant to compute the ground motion from an assumed similar earthquake close to the Waterford 3 site. As part of this analysis, the appli cant used the ground motion attenuation relationship of Nuttli and Herrmann (1978). Results show that at distances of 8 to 15 l, using a magnitude mb =
4.8, that peak horizontal accelerations are less than 0.10 g. The applicant has also used the procedure of Wong and Trifunac (1978) which generates a synthetic acceleration time history using magnitude (mb = 4.8), distance (8-15 km), and site conditions (deep soil). Response spectra (84th percentile) were produced from the synthetic time history and compared with the Waterford 3 SSE spectrum. Results of this analysis show that the SSE spectrum would not be exceeded if an mb = 4.8 earthquake occurred close to the site. The staff has also used various ground motion attenuation relationships compiled or developed by Tera-Livermore and the NRC staff for the Systematic Evaluation Program (SEP)
(Jackson, 1980) to estimate peak velocity and peak acceleration. Based on staff analysis and review and the applicant's analysis, NRC finds that the ground motion (both peaks and response spectrum) would not exceed the SSE response spectrum. The design response spectrum for the Waterford 3 site would thus accommodate the largest earthquakes not associated with known geologic struc tures (October 19, 1930, MM intensity VI; November 5, 1963 mb = 4.8) if events similar to these were to occur near the site.
2.5.2.5 Operating Basis Earthquake The applicant has proposed 0.05 g for the acceleration level corresponding to the OBE. The design vibratory ground acceleration for the OBE is taken to be one-half of the design vibratory ground acceleration for the SSE, consistent with Appendix A to 10 CFR 100. Considering the low seismicity of the Gulf Coastal Plain Tectonic Province, the staff finds that the proposed acceleration value for the OBE is adequately conservative for the Waterford 3 site.
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2.5.3 Surface Faulting Post-CP site and regional subsurface information reinforces the previous NRC staff finding that there is no known evidence either at the Waterford 3 site or within 5 mi of the plant site to indicate surface faulting or that the potential exists for such faulting. The new information consists of (1) the mapping and photographic coverage of the site excavation accomplished by the applicant, (2) deep hydrocarbon related regional drilling and geophysical logging, (3) a geologic report prepared by the Corps of Engineers (Kolb et al., 1975) addressing_the configuration of the uppermost Pleistocene sediments, and (4) a study of remote-sensing imagery including ERTS (Landsat), Skylab, radar, and color infrared which failed to identify possible structure-controlled lineaments.
2.5.4 Stability of Subsurface Materials and Foundations 2.5.4.1 Site Conditions (1) General Plant
 
== Description:==
The Waterford 3 plant is located on the right (W) bank of the Mississippi River in St. Charles Parish, about 25 mi W of New Orleans, Louisiana. The safety-related structures, systems, or compo nents (1isted in Table 3.2-1 of the FSAR) are supported on a single combined structural mat. The mat and the structures supported on the mat comprise the NPIS. There are no safety-related structures, systems, or components outside the NPIS.
The Mississippi River, located about 1,000 ft N of the NPIS, provides water for the circulating water system. The emergency shutdown water supply is contained in the component cooling water system which is located entirely within the NPIS.
The original grade in the plant area was about 13 ft above MSL (El +13).
Final plant grade is El +17.5 around the NPIS and El +14.5 around the turbine building. The land slopes gently down from the plant area to wetlands at about El zero at a distance of 1.5 to 2.5 mi from the site. Between the plant and the river there is a levee, located about 200 ft from the river bank. The top of the levee is at about El +31 (at Boring 71) and the sides slope at about 4:1 (horizonta1:vertica1) on the river side and about 5.5:1 on the inland side.
(2) General Design and Construction Concept: The NPIS that contains the safety-related structures, systems, and components is a reinforced concrete, boxlike structure that extends about 65 ft below final grade to El -47. The base mat is 12 ft thick, and 270 ft wide E-W by 380 ft long N-S.
The NPIS has been designed and constructed using the 11 compensated 11 or "floating" foundation concept. The app1ied vertical soil pressures at and below foundation 1eve1 have been contro11ed so that the in situ stresses remain essentially the same as the stresses existing before construction. In this way t the heave and reconsolidation of the foundation soils are controlled.
The in situ vertical stresses were controlled during construction by lowerinQ the groundwater level simultaneously with the excavating of soil. The lowering 2-29
 
of the groundwater level gave an increase in effective overburden pressure which compensated for the weight of soil removed. As structural loads were applied, the groundwater level was raised to reduce the effective overburden pressure and compensate for the structural loading. To equalize piezometric levels under the NPIS mat, a shell filter layer was placed under the mat on the bottom of the excavation.
The vertical effective stress at foundation level was about 3300 lb/ft2 before construction started. During concrete construction, this stress increased to 4500 lb/ft 2
* The overload was selected in order to provide the maximum amount of reconsolidation during construction but to avoid stressing the foundation soils beyond their preconsolidation pressure. After construction, the vertical effective stress was reduced to about 3100 1b/ft2* The static loading conditions and the vertical movements associated with these loads are discussed in Section 2.5.4.3 of this SER; the groundwater control, excavation, and backfill programs are discussed in Section 2.5.4.2 of this SER.
(3) Site Investigation: Between 1970 and 1972, soil testing borings, 50 to 500 ft deep, were made at 64 locations shown on Figure 2.5-48 of the FSAR. In seven of the borings, five inch diameter samples were obtained; in the other borings, three inch diameter samples were obtained. The soil exploration pro gram included undisturbed sampling with hydraulically pressed, thin walled tubes according to American Society for Testing and Materials (ASTM) method 0-1587 (ASTM-1587), and standard penetration tests (SPTs) with split-barrel sampling (ASTM D-1586). The soil boring logs provided in Appendix 2.58 of the FSAR show Penetrometer and Torvane readings on selected samples as well as visual classifications of the soils sampled.
The geophysical investigations consisted of five seismic refraction survey lines, as well as up-hole and cross-hole seismic wave velocity measurements.
An electrical induction survey was conducted in six borings.
(4) Properties of SLJbsurface Materials: The site is located in the southern portion of the Gulf Coastal Plain physiographic province. The subsurface sedimentary deposits are estimated to be more than 40,000 ft deep; the deposits significant to geotechnical engineering aspects of the plant are the Recent a11uvium that is about 53 ft deep, and the upper few hundred feet of the Pleistocene sands and clays that are about 1100 ft deep. The geology of the site is discussed in Section 2.5.1 of this SER; the growth fault phenomenon, which occurs in the site vicinity, is also discussed in Section 2.5.3 of this SER.
Descriptions of the subsurface soils together with a generalized subsurface profile are presented on FSAR Figures 2.5-49 through 2.5-52. A brief descrip tion of the most significant aspects of each stratum is presented in Table 2.6 of this SER.
The results of an extensive laboratory investigation of the subsurface soils are presented in Table 2.5A-l of the FSAR. Classification tests included determinations of moisture content, grain size distribution, Atterberg limits, unit weight, and specific gravity. The clay soils generally showed moisture contents closer to the plastic limit than the liquid limit; this is consistent with over-consolidation that was determined from geologic history and from the consolidation tests. The organic soils showed relative1y higher moisture contents and Atterberg limits, as would be expected for organic soils.
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The coefficients of permeability, determined from laboratory falling head permeability tests and from consolidation tests, were as follows:
Recent alluvium = 1.5 x 10- 6 cm/sec Stiff upper Pleistocene clays= 10- 8 cm/sec Silty sand at El -77 = 3 x 10- 5 cm/sec The strengths of the subsurface soils were determined from field and laboratory tests, as follows:
* Field Penetrometer tests--on most clay samples
* Field Torvane test--on most clay samples
* Laboratory unconfined compression tests--on undisturbed samples cut from both horizontal and veritical in situ orientations, and on selected remolded samples.
laboratory unconsolidated-undrained (UU) shear strength tests--on undisturbed clay samples, using direct shear and triaxfal test methods
* Laboratory consolidated-undrained triaxial tests with pore pressure measurements (C!O)--on undisturbed clay samples Laboratory consolidated-drained (CD) triaxial tests--on reconstituted samples of silty sand from El -77 to El -92.
For the clay soils, the unconfined compressive strength (qu) and cohesion (C = qu/2) values were averaged to obtain the design soil strength values shown on Table 2.6 of this SER and Figure 2.5-66 of the FSAR. The UU test results generally indicated higher strength values than than design values. Additionally, the tIU test results indicated much higher strength values than the design values.
The rn tests take into account the strength derived from in situ confining stresses; the UU and qu tests conservatively neglect these effects. Thus, the staff agrees that the design strength values developed from qu tests are conservative.
For the silty sand beiow El -77, the shear strength was conservatively assumed to be purely frictional, with an angle of internal friction equal to 41 degrees.
Considering the high density (based on SPT values in excess of 30 blows/ft) and the CD triaxial test results (FSAR Figure 2.5-73), the design shear strength for the si1ty sand is reasonable.
Appendix 2.SA of the FSAR shows the results of 87 conso7idation tests on undis turbed clay samples. Although there is scatter in the results, the staff concurs in the applicant 1 s assessment of the consolidation characteristics and the value adopted for design, based on the applicant 1 s consolidation and other laboratory test results and geologic studies. In particular, the overconsolidation ratios (OCRs) shown in Table 2.6 of this SER are acceptable design values.
The results of the geophysical studies showed compression wave (P-wave) velocities ranging from 2,000 to 4,000 ft/sec in the Recent material and 5,000 2-31
 
Table 2.6 Summary of subsurface soil conditions Elevation (ft above MSL)        General description          Significant characteristics Recent Alluvium
+13 to -40          Clay with silt and sand      C= 0.5 ksf; OCR= 2.0*;
pockets                      recent alluvium was removed from beneath seismic Category I foundations.
Ueeer Pleistocene
-40 to -77          Tan and gray cla)            C = 1.5 ksf; OCR= 3.4; (partly fissured              fairly uniform but with occasional silt and sand lenses.
-77 to -92          Tan silty sand                N = 30 to 50/5 in.**
Layer consistent throughout the site; Dewatering well tips located in this layer.
-92 to -108          Gray clay with silt lenses    C = 1.2 ksf; OCR= 1.4 Similar to the tan and gray clay at El -40 to -70
-108 to -116        Dark gray clay (organic)      C = 1.8 ksf, OCR= 1.7 Organic content 3% to 16%
-116 to -127        Gray and tan clay            C = 0.7 ksf; OCR= 2.0 with sand lenses
-127 to -317        Greenish gray clay            C = 2.0 ksf, OCR= 1.5 to 2.4 silty clay with sand          Organic content= 4% to 7%
lenses and layers            (El -197 to El -217).
Sand layer generally very dense with N= 16 to 50/5 in. (El -237 to El -245).
Lower Pliestocene
-317 to -500+        Gray silty sand              N = 38 to 50/4 in.
*C = cohesion (average); OCR= over-consolidation ratio (average)
**N = standard penetration test value, blows/ft (ASTM) D-1586 2-32
 
to 6,000 ft/sec in the upper Pleistocene clay. The shear wave (S-wave) velocity readings were 550 ft/sec in the Recent materials, 780 to 1,220 ft/sec in the upper Pleistocene deposits, and 1,600 to 1,650 ft/sec in the lower Pleistocene deposits (below El -317). The average shear modulus values at low strain levels were calculated for the Recent, upper Pleistocene, and lower Pleistocene materials to be 1,200 ksf, 3,900 ksf, and 10,000 ksf, respectively. The variations of shear modulus with strain level were determined from laboratory cyclic load tests on the upper Pleistocene material. The results for the upper Pleistocene materials show good correlation with published data as shown on FSAR Figure 2.5-78. For the lower Pleistocene material, laboratory tests were not performed and the variation of shear modulus with strain level was obtained from published data, as shown on FSAR Figure 2.5-79. Strain-dependent damping for the upper and lower Pleistocene materials was determined from published data, supported by some results from laboratory cyclic triaxial tests, as shown on FSAR Figures 2.5-78 and 2.5-79.
The elastic modulus (Young 1 s modulus) and Poisson 1 s ratio were calculated from the geophysical data and the results are provided on Table 2.5-14 of the FSAR.
The elastic modulus values were determined to be 3,600 ksf in the Recent material, 11,500 ksf in the upper Pleistocene material, and 29,000 ksf in the lower Pleistocene material. The calculated Poisson's ratio was between 0.45 and 0.49.
(5) Groundwater Conditions: A detailed groundwater monitoring program was a necessary part of the construction of the plant because of the need to carefully control effective stresses through ground water level control, as discussed in Section 2.5.4.1(2) of this SER. Piezometer readings before construction showed that the normal groundwater level in the Recent material is between El +4 and El +10, depending, to some extent, on the river level. However, the plant has been designed for a maximum flood level of El +30 ft that*could occur if the river level should be breached. There is no permanent dewatering system for the plant.
The site vicinity is underlain by three aquifers, located at El -77 to -92, El -200 to -312, and El -325 to -450. These are identified as the ft sand, the Gramercy aquifer and the Norco aquifer. The Gramercy is found within 1 mi SW of the plant but not directly beneath the plant. The other two aquifers are found directly beneath the site. The piezometric levels in the ft sand ranged from El +2 to El +10 during 1974; the piezometric levels in the Norco aquifer were about El -20 in 1965.
During construction, groundwater was controlled by pumping water into or out of strategically placed wells, as required to control in situ effective stresses.
Groundwater control during cnstruction is discussed below. Additional details of the groundwater conditions at the site are provided in Section 2.4.4 of this SER.
2.5.4.2 Groundwater Control, Excavation, and Backfill (1) Groundwater Control: Groundwater levels in the plant area were controlled during foundation construction (1972 to 1978) by pumping from 216 shallow wells and 34 deep wells around the perimeter of the plant area. The well tips were located at El -40+/- for sha11ow wells and El -95+/- for deep wells. In 2-33
 
January 1977 additional deep wells were installed around a 500 kV tower NW of the plant area and these wells were pumped to control differential settlement of the tower. At about the same time, 12 additional deep wells were installed around the foundation mat area and these wells were pumped to provide additiona1 groundwater control beneath the mat. Since the groundwater levels were to be raised in a controlled pattern as the structural loads were applied durinQ construction, 12 recharge wells were located near the edge of the foundation mat with tips in the shell filter material beneath the mat. Additional recharging of the groundwater level was achJeved by watering the backfill as necessary to maintain the desired piezometric levels. By the end of 1979, the groundwater levels had returned to normal levels. In December 1980, the groundwater levels ranged from about El +3 to El +12; these readings are considered to be in the normal range and compatible with preconstruction readings of El +4 to El +10. The history of piezometric levels is shown on Figure 2.5-113 of the FSAR.
(2) Excavation: The excavation for the NPIS extended to El -47, about 60 ft below original grade. The excavation was done as follows:
Stage I, grade to El -5, April to July, 1972; Stage II, El -5 to El -22, January to June, 1975; Stage III, El -22 to El -40, April to August, 1975; Stage IV, El -40 to El -48, October 1975 to March 1976; Turbine, grade to El -40, January to March 1977.
Recent material that extends to about El -40 in the plant areas was removed in Stages I, II, and III of the NPIS excavation phase, using cut slopes of 4:1 (horizontal:vertical). Groundwater levels were simultaneously lowered so as to maintain effective soil stresses within the design limits (see Section 2.5.4.3(1) of this SER).
The vertical cut into the upper Pleistocene material (from El -40 to E1 -47) was made in consecutive strips, starting with a 120-ft-wide strip across the center of the common mat, and following with alternating strips north and south of the center strip (see FSAR Figure 2.5-30). After each strip was excavated, the shell filter layer and the concrete mat were constructed as soon as possible so as to reload the foundation soils and minimize heave.
During construction, a design change was made for the foundation support of the nonseismic Category I turbine building. The initial proposal to support the turbine building on piles was changed and the turbine building is supported on compacted structural backfill. This change required the dewatering system to be extended beyond the south side of the NPIS during construction so that the Recent material could be removed. The effect of the design change on lateral loads acting on the subsurface walls of the NPIS is discussed in Section 2.5.4.3(5) of this SER.
The heave during excavation was measured at 0.4 to 0.8 ft on anchors located immediately beneath the NPIS mat (at El -50). This heave has been recompressed by the application of structural and backfill loads, as discussed in Section 2.5.4.3(2) of this SER.
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(3) Backfill: The backfill 'material below El +17 around the NPIS is clean sand, designated by the applicant as Class A material, that was pumped from the Mississippi River. The nonseismic Category I material used for final grading (Class B material) is a mixture of sand and shell material. The shell filter layer, 12 in. thick, under the NPIS mat is compacted clam shell material dredged from Lake Pontchartrain.
The properties of the Class A backfill material were evaluated by laboratory testing, as described in FSAR Section 2.5.4.5.3.3, that consisted of index property tests, static triaxial strength tests, cyclic property tests (strain dependent shear modulus and damping), and cyclic triaxial strength tests. The gradation tests showed that the Class A material is finer than 0.4 mm and has from 1 to 3% finer than 0.074 mm. The static and dynamic strength tests were performed on recompacted samples having a relative density of 85%. The static triaxia1 tests results showed an angle of internal friction ranging from 41.6 to 43.6 degrees; a conservative value of 40 degrees was used for design. By testing the samples along both active and passive stress paths, the relationship between the coefficient of earth pressure (K) and radial strain was developed as shown on FSAR Figure 2.5-87. The maximum passive coefficient, used in the determination of dynamic lateral loads on the NPIS, was found to be 5.0 at 2% strain. The strain-dependent shear modulus and damping were determined from cyclic triaxial tests at different strain levels and the results are shown on FSAR Figure 2.5-89. The results are consistent with published data.
The cyclic strengths and liquefaction potential of the backfill are discussed in Section 2.5.4.3(4) of this SER.
The placement of the Class A backfill and shell filter layer is described in FSAR Section 2.5.4.5.3.2. The Class A backfill compaction specifications required the backfill to be compacted to at least 75% relative density (ASTM D-2049) with a variation of no more than one standard deviation below 75%
relative density. The field test results show that the compaction criteria were met; the mean relative density obtained during construction was 94%, the standard deviation was 14.3% and only 5.2% of test results were below 75%
relative density. The compaction criteria for the shell filter layer were developed from test fills. The shell filter layer was compacted until negligible additional -densification could be obtained with further compaction. Because the purpose of the shell filter blanket is to equalize piezornetric levels beneath the NPIS mat, the permeability was checked during construction and found to be adequate (in the range of 10- 1 cm/sec). In order to prevent clogging of the sheil filter layer, a Marafi 140 filter cloth was placed over the Pleistocene silts and clays before the shell layer was placed.
2.5.4.3 Foundation Stability (1) Static Loadin Conditions: The plant has been designed to give a net reduction, by about 200 16/ft2 , of the applied soil loading at foundation level. Before construction began, the initial effective overburden pressure at foundation level was 3,300 lb/ft 2 ; after construction was complete the final effective static loading of the plant and backfill was 3,100 lb/ft2
* Thus there is no potential for a bearing capacity failure under stQtic loading conditions during operation of the plant. Bearing capacity limitations were considered in the development of construction procedures because the effective loading at foundation level during construction was increased to as high as 2-35
 
4,500 lb/ft 2* This limited maximum load was selected so that the foundation soils would not be loaded beyond the preconsolidation pressure of the soils with the lower overconsolidation ratios. The lowest design value of over consolidation ratio was 1.4 at El -92 to El -108 (see Table 2.6 of this SER),
which gives a calculated pre-consolidation loading of at least 4,620 lb/ft 2 at foundation level.
(2) Vertical Movements (Heave/Recom ression/Settlement): The heave points, anchored immediately beneath the NPI  mat, showed the following significant vertical movements:
* Maximum heave during excavating: north side 0.80 ft, other sides 0.45 to 0.55 ft.
Downward movement on reloading: north side 0.80 ft, other sides 0.93 to 1.00 ft.
* Net settlement at heave points: north side 0.00 ft, other sides 0.40 to 0.48 ft.
Measurements on settlement monuments located on the NPIS show that differential settlements between any monuments have been less than 2-1/2 in. Additionally, the heave point and settlement monument readings show that the vertical movements have attenuated (see FSAR Figure 2.5-113).
The long-term settlement of the NPIS mat is expected to be negligible because the net effective vertical soil pressures at and below foundation level are slightly lower after construction than before construction. However, the applicant has committed to monitor the settlement of the NPIS at least annually for a period of at least 3 years to verify that total and differential settle ments of the NPIS have, in fact, attenuated and that predicted long-term differential settlements will not exceed 2-1/2 in. at any of the monitoring points located within the NPIS. This will be a condition of the license.
(3) D namic loading Conditions: The applicant has analyzed the stability of foundat ions when earthquake loading is applied. Section 2.5.2.4 of the FSAR states that the maximum design earthquake is less than MM intensity VI. The SSE design acceleration is 0.10 g and the operating basis earthquake (OBE) design acceleration is 0.05 g. The staff's evaluation of the earthquake design basis is discussed in Section 2.5.2 of this SER.
The ultimate bearing capacity of the foundation soils, assuming an average cohesion of 1,750 lb/ft, no interna1 friction and saturated backfiii, was calculated by the applicant to be about 15,000 lb/ft2* Using the dynamic loading presented in Section 3.7.2.14 of the FSAR, the applicant calculates a factor of safety of 2.6 for bearing capacity under dynamic loading conditions.
The staff has checked, and found acceptable, the calculations of ultimate bearing capacity and the resulting margins of safety.
(4) Li uefaction Potential: The granular materials that could have a potential for earhquake-induced liquefaction are the granular backfill (located around the NPIS), the shell filter layer, the silty soils at about El -50 and the silty sands between El -77 and El -92 (located beneath the NPIS mat). The applicant analyzed the liquefaction potential of these soils by comparing 2-36
 
their shear strengths under cyc1ic loading conditions to the dynamic shear stresses induced in the soils by the vibratory motion associated with the SSE.
This comparison was made at various depths below ground surface to obtain factors of safety for liquefaction.
The shear strengths of the soils under cyclic loading conditions were determined at 10 equivalent uniform load cycles in cyclic triaxia1 tests, using 5% double amplitude strain as the failure criteria. Tests on the in situ sands were made on undisturbed samples at confining pressures equal to the in situ confining pressures. The backfill materials were compacted to 85%
relative density and tested at a confining pressure of 3 ksf. The cyclic strengths are shown on FSAR Figures 2.5-96 and 2.5-90 for the in situ and backfill materials, respectively.
The dynamic shear stresses induced in the soil by the vibratory motion associated with the SSE were calculated using the SHAKE computer program, with the synthetic time history of the SSE and a maximum horizontal ground surface acceleration of 0.10 g. The shear moduli values used in these calculations were computed from seismic survey results as discussed in Section 2.5.4.1(3) of this SER.
The influence of variations in soil properties was investigated by varying the shear modulus by+/- 25% in the dynamic shear stress calculations.
The applicant calculated factors of safety in excess of 1.5 for the liquefaction analyses. The applicant's analyses of liquefaction potential are adequately conservative and the staff concurs in the applicant's finding that there is a low potential for liquefaction of the backfill and the soil that supports the NPIS.
(5) Lateral Loads: For static loading conditions, the subsurface walls were designed for at-rest earth pressure (coefficient of earth pressure equal to 0.5) and hydrostatic loading with water levels taken at El +8 for normal conditions and El +30 for flood conditions. The static pressure diagram is shown on FSAR Figure 2.5-100. The effects of surcharge loading (e.g., of the turbine building foundations) have been included in the calculation of lateral loads on the NPIS walls below grade, as discussed in FSAR Section 2.5.4.14.
The seismic-induced dynamic earth pressures on subsurface walls were determined from their movement as calculated by dynamic analysis of the NPIS combined with calculated soil displacement values in the free field determined from the SHAKE computer program. The maximum displacement of the wall with respect to the soii during the earthquake at any depth was calculated from the sum of the maximum absolute wall movement (from the NPIS dynamic analysis) and the maximum absolute soil movement at the same depth (from the SHAKE analysis). The soil strain corresponding to the relative movement was assumed to occur over the horizontal length of the Rankine failure zone associated with each depth. The earth pressures or soil stresses at these strain values were then determined from the laboratory stress-strain test results. The calculated dynamic earth pressure diagram is shown on FSAR Figure 2.5-101. The maximum dynamic earth pressure coefficient was calculated to be 5.0 at the top of the fill at a relative wall-soil displacement of 0.2 ft. The maximum dynamic lateral earth pressure was calculated to be about 6.5 ksf, at about the midheight of the walls. The methods used to calculate lateral loads are acceptable and in accordance with state-of-the-art methods required by the Standard Review Plan.
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2.5.4.4 Conclusion Based on the applicant's design criteria and construction reports and on the results of the applicant's investigations, laboratory and field tests, and analyses, the staff has concluded that the foundation engineering aspects of 1 the NPIS are adequate to assure the safety of the Waterford 3 plant. The staff s evaluation has been made in accordance with the criteria outlined in Appendix A of 10 CFR Part 100; RG 1.70, Revision 2; and the current Standard Review Plan.
2.5.5 Stability of Slopes In the staff 1 s SER (Section 2.6) dated December 29, 1972, that was prepared in regard to the application for a CP, the staff reported on the river levee as follows (at Section 2.6):
The stability of the levee in the vicinity of the seismic Category I intake structure and essential service water pipelines that cross over the levee has not been adequately proven.... We will require, prior to issuance of a construction permit, that the applicant either (a) provide analyses that adequately demonstrate that the levee will be stable under safe shutdown earthquake conditions, or (b) provide an alternative Category I (seismic) essential service water system to assue a dependable supply of cooling water.
The applicant adopted the second alternative; the ultimate heat sink is contained entirely within the NPIS and thus no further staff review of the river levee was needed.
The staff concludes that, in the vicinity of the Waterford 3 plant, there are no slopes whose failure could adversely affect the plant. The staff's evaluation has been made in accordance with the criteria outlined in Appendix A of 10 CFR Part 100; RG 1.70, Revision 2; and the current Standard Review Plan.
2.5.6 Embankments and Dams There are no embankments or dams associated with the plant.
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==2.6 REFERENCES==
 
Books, papers, and journal articles:
Coffman, J. L. , and C. A. Von Hake, "Earthquake History of the United States,11 National Oceanic and Atmospheric Administration - U.S. Department of Commerce Publication 41-1, 1973.
Docekal, J., 11Earthquakes of the Stable Interior, With Emphasis on the Mid continent,11 Ph.D. Thesis, University of Nebraska, 1970.
((
                                                                                  ))
Gupta, 1. W., and 0. W. Nuttli, "Spatial Attenuation of Intensities for Central U.S. Earthquakes, 11 Seismol. Soc. Amer. Bu11. 66, pp. 227-248, 1976.
Holzworth, G. C., 11Mixing Heights, Wind Speeds, and Potential for Urban Air Pollution Throughout the Contiguous United States," AP-101, EPA, Office of Air Programs, North Carolina, January 1972.
((
                                                                                  ))
King, P. B., 11 The Tectonics of North America--a Discussion To Accompany the Tectonic Map of North America, Scale 1:5,000,000,11 U.S. Geol. Survey Prof.
Paper 628, Washington, D. C. 1969.
Kolb, C. R., F. L. Smith, and R. C. Silva, "Pleistocene Sediments of the New Orleans-Lake Pontchartrain Area,11 U.S. Waterways Expt. Sta. Tech. Rept.
S-75-6, Vicksburg, Miss., 1975.
Nuttli, 0. W., and R. B. Herrmann, "State-of-the-Art for Assessing Earthquake Hazards in the United States: Credible Earthquakes for the Central United States, 11Misc. Paper S-73-1, Report No. 12, U.S. Army Waterways Experiment Station, Vicksburg, Miss., 1978.
Saucier, R. T., 11 Quaternary Geology of the Lower Mississippi Valley: Arkansas Archeological Survey, 11 Research Series No. 6, Fayetteville, Ark., 1974.
Smith, D. A., "Sealing and Nonsealing Faults in Louisiana Gulf Coast Salt Basin,11 Amer. Assoc. Petrol. Geologists Bull. 64(2), 145-172, 1980.
Thom, H. C. S., 11 New Distribution of Extreme Winds in the United States,° Proceedings of the ASCE, Journal of the Structural Division, July 1968.
Thom, H. C. S., "Tornado Probabilities Monthly Weather Review,'1 U.S. Weather Bureau, Washington, D. C., October-December 1973, pp. 730-736, 1963.
Trifunac, M. D., and A. G. Brady, On the Correlation of Seismic Intensity Scales With Peaks of Recorded Strong Ground Motion,'' Seismal. Soc. Amer. Bull.
65, 1975.
2-39
 
U.S. Department of Commerce, 11 Local Climatological11 Data Annual Summary With Comparative Data for New Orleans, Louisiana, National Oceanic and Atmospheric Administration, Environmental Data Service, 1972.
Wong, H. L., and M. D. Trifunac, 11 Synthesizing Realistic Ground Motion Accelero grams,11 Los Angeles: University of Southern California, Department of Civil Engineering, 1978.
Code of Federal Regulations:
10 CFR  Part 50 10 CFR  Part 50, Appendix A (GDC 2) 10 CFR  Part 50, Appendix E 10 CFR  Part 50, Appendix I 10 CFR  Part 50 10 CFR  Section 50.34 10 CFR  Section 50.47 10 CFR  Part 100 10 CFR  Part 100, Appendix A 10 CFR  Section 100.3(a) 10 CFR  Section 100.10 General Design Criteria GDC 2 GOC 4 GDC 44 Louisiana Power & Light Company report:
FSAR for Waterford 3 through Amendment 19 Memorandum:
From R. E. Jackson, NRC, to D. Crutchfield, dated June 23, 1980 Regulatory Guides:
RG 1.23 RG 1. 27 RG 1. 59 RG 1. 60
* RG 1. 70 RG 1.102 RG 1.111, Revision 1 RG 1.132 RG 1.145 RG 4. 7 USNRC reports:
Construction permit Safety Evaluation Report for Waterford 3, December 1972.
2-40
 
11 Safetr Evaluation of the Allen Creek Nuclear Generating Station, Units 1 and 2,' Docket Nos. 50-466 and 50-467, 1974.
    "Safety Evaluation of the Comanche Peak Steam Electric Station Units 1 and 2,i'  Docket Nos. 50.445 and 50.446, 1974.
11 Safety Evaluation Report Related to Construction of the South Texas Project, Unit 1 and 2," Docket Nos. STN 50-498 and STN 50-499, 1975.
NUREG-75/087 NUREG-0131 NUREG-0347 2-41
 
3      DESIGN CRITERIA - STRUCTURE, COMPONENTS, EQUIPMENT AND SYSTEMS 3.1 GENERAL 3.1.1 Conformance With General Design Criteria In a {{letter dated|date=April 29, 1981|text=letter dated April 29, 1981}}, the applicant stated that Waterford 3 complies will all applicable NRC requirements and regulations. The staff reviewed the final design and the design criteria and concludes, subject to the applicant 1 s adoption of the additional requirements imposed by the staff and the exemptions granted as discussed in this Saftety Evaluation Report, that the facility has been designed to meet the requirements of the General Design Criteria.
3.1.2 Conformance With Industry Codes and Standards Our review of structures, systems and components relies extensively on the application of industry codes and standards that have been used as accepted industry practice. These codes and standards, as cited in this report and attached bibliography (Appendix B), have been previously reviewed and found acceptable by us; and have been incorporated into our Standard Review Plan (NUREG 75/087).
3.2 CLASSIFICATION OF STRUCTURES, SYSTEMS, AND COMPONENTS 3.2.1 Seismic Classification GDC 2, 11 Design Bases for Protection Against Natural Phenomena, 11 of 10 CFR Part 50, Appendix A, requires, in part, that nuclear power plant structures, systems, and components important to safety be designed to withstand the effects of earthquakes without loss of capability to perform their safety function.
These plant features are those necessary to assure (1) the integrity of the reactor coolant pressure boundary (RCPB), (2) the capability to shut down the reactor and maintain it in a safe shutdown condition, or (3) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to 10 CFR Part 100 guideline exposures. The earth quake for which these plant features are designed is defined as the safe shutdown earthquake (SSE) in 10 CFR Part 100, Appendix A. The SSE is based upon an evaluation of the maximum earthquake potential and is that earthquake which produces the maximum vibratory ground motion for which structures, systems, and components important to safety are designed to remain functional. Those plant features that are designed to remain functional if an SSE occurs are designated seismic Category I in Regulatory Guide 1.29. This Regulatory Guide, 11 Seismic Design Classification,' 1 is the principal document used in the staff review for identifying those plant features important to safety which, as a minimum, should be designed to seismic Category I requirements. NRC review of the seismic classi fication of structures, systems, and components (excluding electrical features) of Waterford Unit 3 was performed in accordance with the guidance in SRP Section 3.2.l, 11 Seismic Classification. 11 3- 1
 
The structures, systems, and components important to safety of Waterford 3 that are required to be designed to withstand the effects of an SSE and remain func tional have been identified in an acceptable manner in Table 3.2-1 of the FSAR.
Table 3.2-1, in part, identifies major components in fluid systems, mechanical systems, and associated structures designated as seismic Category I. In addi tion, piping and instrumentation diagrams in the FSAR identify the interconnect ing piping and valves and the boundary limits of each system classified as seismic Category I. NRC staff has reviewed Table 3.2-1 and the fluid system piping and instrumentation diagrams and concludes that the structures, systems, and components important to safety of Waterford 3 have been properly classified as seismic Category I items in conformance with RG 1.29, Revision 1.
All other structures, systems, and components that may be required for operation of the facility are not required to be designed to seismic Category I require ments, including those portions of Category I systems such as vent lines, fill lines, drain lines, and test lines on the downstream side of isolation valves and portions of these systems which are not required to perform a safety function.
The staff concludes that those structures, systems, and components important to safety of Waterford 3 are designed to withstand the effects of an SSE and remain functional are properly classified as seismic Category I items in accordance with Regulatory Guide 1.29 and that such design constitutes an acceptable basis for satisfying, in part, the requirements of GOC 2, and is, therefore, acceptable.
3.2.2 System Quality Group Classification GDC 1, "Quality Standards and Records," of 10 CFR Part 50, Appendix A requires that nuclear power plant systems and components important to safety be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety function to be performed. These fluid system, pressure retaining components are part of the RCPB and other fluid systems important to safety, where reliance is placed on these systems: (1) to prevent or mitigate the consequences of accidents and malfunctions originating within the RCPB, (2) to permit shutdown of the reactor and maintain it in a safe shutdown condi tion, and (3) to retain radioactive material. RG 1.26, 11 Quality Group Classi fication and Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants, 11 is the principal document used in the NRC review for identifying on a functional basis the components of those systems important to safety that are Quality Groups 8, C, and D. Section 50.55a of 10 CFR Part 50 identifies those American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vessel Code, Section III, Class 1 components that are part of the RCPB. Conformance of these RCPB components with Section 50.55a of 10 CFR Part 50 is discussed in Section 5.2.1.1 of this SER. These RCPB components are designated in RG 1.26 as Quality Group A. Certain other RCPB components which meet the exclusion requirements of footnote 2 of the rule are classified Quality Group Bin accordance with RG 1.26. Our review of the quality group classification for pressure-retaining components of fluid systems important to safety for Waterford 3 was performed in accordance with the guidance in SRP Section 3.2.2, "System Quality Group Classification. 11 The systems and components important to safety of Waterford 3 have been identified in an acceptable manner in Table 3.2-1 of the FSAR. Table 3.2-1, in part, identifies the major components in fluid systems such as, pressure 3-2
 
vessels, heat exchangers, storage tanks, pumps, piping, and valves; and mechanical systems, such as cranes, refueling platforms, and other miscellaneous handling equipment. In aduition, the piping and instrumentation diagrams in the FSAR identify the classification boundaries of the interconnecting piping and valves.
The applicant has utilized the American Nuclear Society (ANS) Safety Classes 1, 2, 3, and nonnuclear safety (NNS) as defined in ANS-18.2, 11 Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants, 11 in the classification of system components. Safety Classes 1, 2, 3, and NNS correspond to the Commission 1 s Quality Groups A, 8, C, and Din RG 1.26 and have been used by the applicant as an alternate classification system to the Commission's Quality Group classification system. A summary of the relationship of the NRC Quality Groups and ANS Safety Classes are as follows:
Waterford 3 NRC Quality Group            PWR Safety Class A                            1 B                            2 C                            3 D                          NNS The staff has reviewd the applicant's use of the ANS classification system in Table 3.2-1 and on the system piping and instrumentation diagrams and we con clude the pressure-retaining components of fluid systems important to safety have been properly classified as Safety Class 1, 2, 3, or NNS components and meet the guidance in RG 1.26, Revision 2.
Quality Group A (Safety Class 1), and Quality Group B (Safety Class 2) components of Waterford 3 have been constructed* in accordance with ASME Section III, Class 1 and Class 2 respectively, including third party inspection. Quality Group C (Safety Class 3) components have been constructed in accordance with ASME Section III, Class 3 requirements with the exception that the Code N-symbol stamp was not applied to these components and the third party inspection by an authorized inspection agency, as defined in the Code, was not implemented for these components. The applicant has stated that Class 3 components were pur chased only from suppliers who possessed the appropriate ASME Certificate of Authorization even though for the Waterford Class 3 components the Code N-symbol stamp was not applied and third party inspection not implemented. As an alternate to the Code third party inspection program, the applicant has provided an inspection program which is capable of being equivalent to that required by the Code if adequately implemented during construction. The staff reviewed the provisions of the program, the check points, and the required inspections and have concluded that it provides a level of inspection comparable to that of the Code.
*Constructed, as used herein, is an all-inclusive term compr1s1ng materials certification, design, fabrication, examination, testing, inspection, and certification required in the manufacture and installation of components.
3-3
 
The structures, systems, and components important to safety of Waterford 3 that are required to be designed to withstand the effects of an SSE and remain func tional have been identified in an acceptable manner in Table 3.2-1 of the FSAR.
Table 3.2-1, in part, identifies major components in fluid systems, mechanical systems, and associated structures designated as seismic Category I. In addi tion, piping and instrumentation diagrams in the FSAR identify the interconnect ing piping and valves and the boundary limits of each system classified as seismic Category I. NRC staff has reviewed Table 3.2-1 and the fluid system piping and instrumentation diagrams and concludes that the structures, systems, and components important to safety of Waterford 3 have been properly classified as seismic Category I items in conformance with RG 1.29, Revision 1.
All other structures, systems, and components that may be required for operation of the facility are not required to be designed to seismic Category I require ments, including those portions of Category I systems such as vent lines, fill lines, drain lines, and test lines on the downstream side of isolation valves and portions of these systems which are not required to perform a safety function.
The staff concludes that those structures, systems, and components important to safety of Waterford 3 are designed to withstand the effects of an SSE and remain functional are properly classified as seismic Category I items in accordance with Regulatory Guide 1.29 and that such design constitutes an acceptable basis for satisfying, in part, the requirements of GDC 2, and is, therefore, acceptable.
3.2.2 System Quality Group Classification GDC 1, 11 Quality Standards and Records, 11 of 10 CFR Part 50, Appendix A requires that nuc1ear power p1ant systems and components important to safety be designed, fabricated, erected, and tested to quality standards commensurate with the importance of the safety function to be performed. These fluid system, pressure retaining components are part of the RCPB and other fluid systems important to safety, where reliance is placed on these systems: (1) to prevent or mitigate the consequences of accidents and malfunctions originating within the RCPB, (2) to permit shutdown of the reactor and maintain it in a safe shutdown condi tion, and (3) to retain radioactive material. RG L26, 11 Quality Group Classi fication and Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants," is the principal document used in the NRC review for identifying on a functional basis the components of those systems important to safety that are Quality Groups B, C, and D. Section 50.55a of 10 CFR Part 50 identifies those American Society of Mechanical Engineers (ASME)
Boiler and Pressure Vessel Code, Section III, Class 1 components that are part of the RCPB. Conformance of these RCPB components with Section 50.55a of 10 CFR Part 50 is discussed in Section 5.2.1.1 of this SER. These RCPB components are designated in RG 1.26 as Quality Group A. Certain other RCPB components which meet the exclusion requirements of footnote 2 of the rule are classified Quality Group B in accordance with RG 1.26. Our review of the quality group classification for pressure-retaining components of fluid systems important to safety for Waterford 3 was performed in accordance with the guidance in SRP Section 3.2.2, 11 System Quality Group Classification. 11 The systems and components important to safety of Waterford 3 have been identified in an acceptable manner in Table 3.2-1 of the FSAR. Table 3.2-1, in part, identifies the major components in fluid systems such as, pressure 3-2
 
r*
                                                                                  /
The Office of Inspection and Enforcement (IE) has verified that the applicant has adequately implemented this alternate inspection program. Therefore, the applicant's inspection program for components classified Quality Group C (Safety Class 3) and constructed to ASME Section III is acceptable.
The staff concludes that construction of the components in fluid systems important to safety in conformance with the ASME Code, the Commission 1 s regula tions, and the guidance provided in RG 1.26 and ANS-18.2, provides assurance that component quality is commensurate with the importance of the safety func tion of these systems and constitutes an acceptable basis for satisfying the requirements of GDC 1 and is, therefore, acceptable.
3.3 WIND AND TORNADO LOADINGS 3.3.l Wind Design Criteria All Category I structures exposed to wind forces were designed to withstand the effects of the design wind. The design wind specified has a velocity of 200 mph based on a recurrence of 100 years.
The procedures that were used to transform the wind velocity into pressure loadings on structures and the associated vertical distribution of wind pressures and gust factors are in accordance with ASCE Paper 3269. This document is acceptable to the staff.
The procedures that were utilized to determine the loadings .on seismic Category I structures induced by the design wind specified for the plant are acceptable since these procedures provide a conservative basis for engineering design to assure that the structure will withstand such environmental forces.
The use of these procedures provides reasonable assurance that in the event of design basis winds, the structural integrity of the plant seismic Category I structures will not be impaired and, in consequence, seismic Category I systems and components located within these structures are adequately protected and will perform their intended safety functions, if needed. Conformance with these procedures is an acceptable basis for satisfying, in part, the requirements of GDC 2.
3.3.2 Tornado Design Criteria All Category I structures exposed to tornado forces and needed for the safe shutdown of the plant were designed to resist a tornado of 300 mph tangential wind velocity and a 60 mph translational wind velocity. The simuitaneous atmospheric pressure drop was assumed to be 3 psi in 3 seconds. Tornado missiles are also considered in the design as discussed in Section 3.5 of this report.
The procedures that were used to transform the tornado wind velocity into pressure loadings are similar to those used for the design wind loadings as discussed in Section 3.3.1 of this report. The tornado missile effects were determined using procedures to be discussed in Section 3.5 of this report.
The total effect of the design tornado on Category I structures is determined by appropriate combinations of the individual effects of the tornado wind 3-4
 
pressure, pressure drop, and tornado associated missiles. Structures are arranged on the plant site and protected in such a manner that collapse of structures not designed for the tornado will not affect other safety-related structures.
The procedures utilized to determine the loadings on structures induced by the design basis tornado specified for the plant are acceptable since the procedures provide a conservative basis for engineering design to assure that the structures withstand such environmental forces.
The use of these procedures provides reasonable assurance that in the event of a design basis tornado, the structural integrity of the plant structures that have to be designed for tornados will not be impaired and, in consequence, safety related systems and components located within these structures will be adequately protected and may be expected to perform necessary safety functions as required.
Conformance with these procedures is an acceptable basis for satisfying, in part, the requirements of GDC 2.
3.4 WATER LEVEL (FLOOD) DESIGN 3.4.1 General Discussion In order to assure conformance with the requirements of GDC 2, 11 Design Bases for Protection Against Natural Phenomena,1 with respect to protection against 1
flooding, the staff reviewed the overall plant flood protection design including all systems and components whose failure as a result of flooding could prevent safe shutdown of the plant or result in uncontrolled release of significant radioactivity. The applicant has provided protection from inundation and static and dynamic effects for safety-related structures, systems, and components by the "Incorporated Barrier" method as defined in RG 1.102, 11 Flood Protection for Nuclear Power Plants, 11 as described below.
The probable maximum water level (PMF plus windwave runup) at Waterford 3 is El +27.6 ft MSL (refer to Section 2.4.3 of this SER for further discussion).
Plant grade varies between El +17.5 ft MSL and +14.5 ft MSL. All safety-related systems and components that must be protected against flooding have been identi fied and are located within the seismic Category I NPIS which includes the reactor building, reactor auxiliary building, and fuel handling building. The NPIS is a concrete box structure which is designed to be watertight to El
+30.0 ft MSL. All exterior doors and penetrations in the structure below El
+30.0 ft MSL which might allow water to penetrate to areas which house safety related equipment are watertight. All construction joints in the NPIS founda tion mat are provided with waterstops. The exterior walls subjected to floods are waterproofed to plant grade and are provided with waterstops at construction joints below grade elevation to El +30.0 ft MSL. Additional flood protection includes administrative procedures (required by technical specifications) which require that all watertight doors below El +30.0 ft MSL will be locked closed in the event of a flood warning. Within the NPIS, protection against flooding from failures in fluid piping systems as identified in the guidelines of Branch Technical Position ASB 3-1, "Protection Against Postulated Piping Failures in Fluid Systems Outside Containment, is provided by equipment location and 11 drainage as described under Section 9.3.3 of this SER.
3-5
 
The Office of Inspection and Enforcement (IE) has verified that the applicant has adequately implemented this alternate inspection program. Therefore, the applicant's inspection program for components classified Quality Group C (Safety Class 3) and constructed to ASME Section III is acceptable.
The staff concludes that construction of the components in fluid systems important to safety in conformance with the ASME Code, the Comrnission 1 s regula tions, and the guidance provided in RG 1.26 and ANS-18.2, provides assurance that component quality is commensurate with the importance of the safety func tion of these systems and constitutes an acceptable basis for satisfying the requirements of GDC 1 and is, therefore, acceptable.
3.3 WIND AND TORNADO LOADINGS 3.3.l Wind Design Criteria All Category I structures exposed to wind forces were designed to withstand the effects of the design wind. The design wind specified has a velocity of 200 mph based on a recurrence of 100 years.
The procedures that were used to transform the wind velocity into pressure loadings on structures and the associated vertical distribution of wind pressures and gust factors are in accordance with ASCE Paper 3269. This document is acceptable to the staff.
The procedures that were utilized to determine the loadings on seismic Category I structures induced by the design wina specified for the plant are acceptable since these procedures provide a conservative basis for engineering design to assure that the structure will withstand such environmental forces.
The use of these procedures provides reasonable assurance that in the event of design basis winds, the structural integrity of the plant seismic Category I structures will not be impaired and, in consequence, seismic Category I systems and components located within these structures are adequately protected and will perform their intended safety functions, if needed. Conformance with these procedures is an acceptable basis for satisfying, in part, the requirements of GDC 2.
3.3.2 Tornado Design Criteria All Category I structures exposed to tornado forces and needed for the safe shutdown of the plant were designed to resist a tornado of 300 mph tangential wind velocity and a 60 mph translational wind velocity. The simultaneous atmospheric pressure drop was assumed to be 3 psi in 3 seconds. Tornado missiles are also considered in the design as discussed in Section 3.5 of this report.
The procedures that were used to transform the tornado wind velocity into pressure loadings are similar to those used for the design wind loadings as discussed in Section 3.3.l of this report. The tornado missile effects were determined using procedures to be discussed in Section 3.5 of this report.
The total effect of the design tornado on Category I structures is determined by appropriate combinations of the individual effects of the tornado wind 3-4
 
pressure, pressure drop and tornado associated missiles. Structures are arranged on the plant site and protected in such a manner that collapse of structures not designed for the tornado will not affect other safety-related structures.
The procedures utilized to determine the loadings on structures induced by the design basis tornado specified for the plant are acceptable since the procedures provide a conservative basis for engineering design to assure that the structures withstand such environmental forces.
The use of these procedures provides reasonable assurance that in the event of a design basis tornado, the structural integrity of the plant structures that have to be designed for tornados will not be impaired and, in consequence, safety related systems and components located within these structures will be adequately protected and may be expected to perform necessary safety functions as required.
Conformance with these procedures is an acceptable basis for satisfying, in part, the requirements of GDC 2.
3.4 WATER LEVEL (FLOOD) DESIGN 3.4.1 General Discussion In order to assure conformance with the requirements of GDC 2, 11 0esign Bases for Protection Against Natural Phenomena, 11 with respect to protection against flooding, the staff reviewed the overall plant flood protection design including all systems and components whose failure as a result of flooding could prevent safe shutdown of the plant or result in uncontrolled release of significant radioactivity. The applicant has provided protection from inundation and static and dynamic effects for safety-related structures, systems, and components by the 11 Incorporated Barrier111 method as defined in RG 1.102, 11 Flood Protection for Nuclear Power Plants, 1 as described below.
The probable maximum water level (PMF plus windwave runup) at Waterford 3 is El +27.6 ft MSL (refer to Section 2.4.3 of this SER for further discussion).
Plant grade varies between El +17.5 ft MSL and +14.5 ft MSL. All safety-related systems and components that must be protected against flooding have been identi fied and are located within the seismic Category I NPIS which includes the reactor building, reactor auxiliary building, and fuel handling building. The NPIS is a concrete box structure which is designed to be watertight to El
+30.0 ft MSL. All exterior doors and penetrations in the structure below El
+30. 0 ft MSL which might allow water to penetrate to areas which house safety related equipment are watertight. All construction joints in the NPIS founda tion mat are provided with waterstops. The exterior walls subjected to floods are waterproofed to plant grade and are provided with waterstops at construction joints below grade elevation to El +30.0 ft MSL. Additional flood protection includes administrative procedures (required by technical specifications) which require that all watertight doors below El +30.0 ft MSL will be locked closed in the event of a flood warning. Within the NPIS > protection against flooding from failures in fluid piping systems as identified in the guidelines of Branch Technical Position ASS 3-1, 11 Protection  Against Postulated Piping Failures in Fluid Systems Outside Containment, 11 is provided by equipment location and drainage as described under Section 9.3.3 of this SER.
3-5
 
Based on NRC review of the design criteria and bases, and safety classifica-tion of safety-related systems, structures, and components necessary for a safe plant shutdown during and following flood conditions, the staff concludes that the design of the facility for flood protection conforms to the requirements of GDC 2 with respect to protection against natural phenomena and conforms to the guidelines of RG 1.102 concerning flood protection and is, therefore, acceptable.
3.4.2 Water Level (Flood) Design Procedures
((
                                                                                    ))
The procedures (CERC Shore Protection Manual, 1973) utilized to determine the loadings on seismic Category I structures induced by the design flood or highest groundwater level specified for the plant are acceptable since these procedures provide a conservative basis for engineering design to assure that the structures will withstand such environmental forces.
The use of these procedures provides reasonable assurance that in the event of floods or high groundwater, the structural integrity of the plant seismic Category I structures will not be impaired and, in consequence, seismic Category I systems and components located within these structures will be adequately protected and may be expected to perform necessary safety functions, as required. Conformance with these design procedures is an acceptable basis for satisfying, in part, the requirements of GDC 2.
3.5 MISSILE PROTECTION 3.5.1 Missile Selection and Description 3.5.1.1 Internally Generated Missiles (Outside Containment)
Protection against postulated internally generated missiles outside contain-ment associated with plant operation, such as missiles generated by rotating or pressurized equipment as identified in the requirements of GDC 4, "Environ mental and Missile Design Bases, 11 is provided by any one or a combination of compartmentalization, barriers, separation, and equipment design. The primary means utilized by the applicant to provide protection to safety-related equipment from damage resulting from internally generated missiles is through the use of the physical arrangement of the plant. Safety-related systems are physically separated from nonsafety-related systems, and redundant components of safety related systems are physically separated so that a potential missile could not damage both trains of the safety-related system. Stored fuel is protected from damage by internal missiles which could result in radioactive release as identified in the guidelines of RG 1.13, 11 Sµent Fuel Storage Facility Design Basis," by the fuel pool walls and by locating new and spent fuel in an area with no high energy piping system or rotating machinery in the vicinity.
The applicant has provided an evaluation of potential missile sources to deter mine whether a single failure could result in their becoming potential missiles.
This evaluation indicated that only resistance temperature detectors (thermo wel1s) in high energy systems are credible missiles. The analysis verified 3-6
 
that plant features such as walls and separation would prevent these missiles from causing adverse effects to safety-related systems and components. The staff concurs with the applicant's assumptions and evaluation for potential missiles outside containment. Protection of safety-related equipment and stored fuel from the effects of turbine missiles is discussed in Section 3.5.1.3 of this SER.
The staff reviewed the adequacy of the applicant's design to maintain the capability for a safe plant shutdown in the event of internally generated missiles outside containment. Based on the above, the staff concludes that through the use of compartmentalization, barriers, separation, and equipment design, the design is in conformance with the requirements of GDC 4 with respect to missile protection and meets the guidelines of RG 1.13 as it relates to protection of spent fuel from missiles and is, therefore, acceptable.
3.5.1.2 Internally Generated Missiles (Inside Containment)
Protection against postulated internally generated missiles inside containment associated with plant operation such as missiles generated by rotating or pres surized equipment as identified in the requirements of GDC 4, "Environmental and Missile Design Bases" is provided by any one or a combination of barriers, separation, and equipment design. The primary means of providing protection to safety-related equipment within the reactor building from damage resulting from internally generated missiles is provided by shield walls.
The applicant has provided an evaluation of potential missile sources inside containment. The only credible potential missile sources identified are from high energy systems as follows:
(1) Reactor vessel (a)  closure head nut (b)  closure head nut and stud (c)  instrumentation assembly (d)  instrumentation from flange up (e)  instrument flange stud (2) Steam generator (a) primary manway stud and nut (b) secondary handhole stud and nut (c) secondary manway stud and nut (3) Pressurizer (a)  safety valve with flange (b)  safety valve flange bolt (c)  lower temperature element (d)  manway stud and nut (4) control rod drive assembly (magnetic jack)
(5) Main coolant piping temperature nozzle with resistance temperature detector 3-7
 
(6) Surge and spray piping thermowells with resistance temperature detector (7) Reactor coolant pump thermowell with resistance temperature detector Kinetic energy, impact section, and penetration depth was determined for each of the above potential missiles. The applicant 1 s analysis verified that struc tures, shields, or barriers provide protection for safety-related equipment from the above primary missiles and any secondary missiles generated by their impact. The staff concurs with the applicant's assumptions and evaluation for potential missiles inside containment.
In addition, the applicant has anclyzed the potential for missile sources as a result of failures in the reactor coolant pump flywheel in accordance with the guidelines of Regulatory Guide 1.14, "Reactor Coolant Pump Flywheel Integrity.''
The applicant's analysis evaluated the materials integrity of the flywheel under assumed overspeed conditions of the pump as a result of pipe break at the pump discharge. This analysis verified that failure of the flywheel does not occur and thus it  is not a potential missile source. The staff concurs with the applicant 1 s analysis.
The NRC staff has reviewed the adequacy of the applicant's design to maintain the capability for a safe plant shutdown in the event of internally generated missiles inside containment. Based on the above, the staff concludes that through the use of barriers, separation, and equipment design, the design is in conformance with the requirements of GDC 4 with respect to missile protection and the guidelines of RG 1.14 concerning reactor coolant pump flywheel integrity and is, therefore, acceptable.
3.5.1.3 Turbine Missiles According to GDC 4 of Appendix A to 10 CFR Part 50, nuclear power plant structures, systems, and components important to safety shall be appropriately protected against dynamic effects including the effects of turbine missiles.
The turbine-generator train at Waterford 3 has a non-peninsular orientation relative to the reactor building. This configuration places the main steam and feedwater lines, control room, diesel generators, and ECCS, as well as the containment building within the low trajectory turbine missile strike zones.
The applicant has performed an analysis to evaluate the probability of damage from postulated turbine missiles to safety-related components. Based on the historical missile-producing turbine failure rate, approximately 10- 4 per year, the applicant 1 s analysis yields a probability of unacceptable damage to safety related components because of turbine missiles which exceeds current NRC guidelines, as stated in RG 1.115 and SRP Sections 3.5.1.3 and 2.2.3.
The applicants has been requested to supply additional data to show that Waterford 3 will meet GOC 4, as it applies to turbine missiles. This will remain an open item until the requested information is evaluated and accepted by the NRC staff.
3.5.1.4 Missiles Generated by Natural Phenomena GOC 2, 11 Design Bases for Protection Against Natural Phenomena, 11 requires that structures, systems, and components essential to safety be designed to withstand 3-8
 
the effects of natural phenomena; GDC 4, 11 Environmental and Missile Design Bases, 11 requires that these same plant features be protected against missiles. The missiles generated by natural phenomena of concern are those resulting from tornadoes. The applicant has identified a spectrum of missiles for a tornado zone 1 site as identified in RG 1. 76, "Design Basis Tornado for Nuclear Power Plants. 11 The spectrum includes the weight, velocity, kinetic energy, impact area and height, penetration depth, and minimum available concrete thickness providing protection. The missile spectrum for Waterford 3 was reviewed and approved at the CP stage prior to issuance of the SRP. The staff has reevaluated this spectrum and concludes that it is representative of missiles at the site and is, therefore, acceptable. Discussion of the protection afforded safety related equipment from the identified tornado missiles is provided in Section 3.5.2 of this SER. Discussion of the adequacy of barriers and structures designed to withstand the effects of the identified tornado missiles is provided in Section 3.5.3 of this SER. Based on NRC review of the tornado missile spectrum, the staff concludes that it was properly selected and meets the require ments of GOC 2 and 4 with respect to protection against missiles generated by natural phenomena and missiles and the guidelines of RG 1.76 with respect to identification of missiles generated by natural phenomena and is, therefore, acceptable.
3.5.2 Structures Systems, and Components to be Protected from Externally Generated Aissiles GDC 4, 11 Environmental and Missile Design Bases, 11 requires that all structures, systems, and components essential to the safety of the plant be protected from the effects of externally generated missiles. The tornado missile spectrum is rHc:c11ssed ;n Cer+;nn Ul..t \,,II    Ill ..J lw\.flVII oJ* V*  1 4 o-F th;c: 5i::D I:; ...
* I  II IW  11-1,. The ::ipplic::int hac: irlontified .::ill Ill ...,._ 1 1 _, ,.,, I ._, *--* -* * * -
* safety-related structures, systems, and components requiring protection from externally generated missiles. All safety-related structures are designed to withstand postulated tornado-generated missiles without damage to safety-related equipment. All safety-related systems and components as well as stored fuel are located within tornado missile-protected structures or are provided with tornado missile barriers with the exception of a portion of the emergency feed water system piping and portions of the wet and dry cooling towers which comprise the ultimate heat sink (UHS). The staff has evaluated these exceptions and found them to be acceptable as described in SER Sections 10.4.9 and 9.2.5, respectively.
Thus, the requirements of GOC 4 with respect to missile protection and the speci fic guidance of Regulatory Guides 1.13, "Spent Fuel Storage Facility Design Basis, 11 1.27, "Ultimate Heat Sink for Nuclear Power Plants, 11 and 1.117, "Tornado Design Classification11 concerning tornado missile protection for safety-related structures, systems and components, including stored fuel and the UHS are met.
Based on the above, the staff concludes that the applicant 1 s list of safety related structures, systems, and components to be protected from externally generated missiles and the provisions in the plant design providing this protection are in accordance with the requirements of GDC 4 with respect to missile and environmental effects and the guidelines of RGs 1.13, 1.27, and 1.117 concerning protection of safety-related plant features from tornado missiles and is, therefore, acceptable.
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3.5.3 Barrier Design Procedures The plant Category I structures, systems, and components are shielded from, or designed for, various postulated missiles. Missiles considered in the design of structures include tornado-generated missiles and various containment internal missiles, such as those associated with a loss-of-coolant accident (LOCA). The tornado missiles considered in this evaluation are presented in Table 3.5-10 of the FSAR. The Category I structures have not been designed to act as barriers for potential turbine missiles.
Information has been provided indicating that the procedures that were used in the design of the structures, shields, and barriers to resist the effect of missiles, other than turbine missiles, are adequate. The analysis of structures, shields, and barriers to determine the effects of missile impact was accomplished in two steps. In the first step, the potential damage that could be done by the missile in the immediate vicinity of impact was investigated. This was accomplished by estimating the depth of penetration of the missile into the impacted structure. Furthermore, secondary missiles are prevented by fixing the target thickness well above that determined for penetration. In the second step of the analysis, the overall structural response of the target when impacted by a missile is determined using established methods of impactive analysis.
The equivalent loads of missile impact, whether the missile is environmentally generated or accidentally generated within the plant, are combined with other applicable loads as is discussed in Section 3.8 of this SER. All Category I structures are designed without venting provisions.
The procedures that were utilized to determine the effects and loadings on seis mic Category I structures, missile shjelds, and barriers induced by design basis missiles selected for the plant are acceptable since these procedures provide a conservative basis for engineering design to assure that the structures or barriers are adequately resistent to and will withstand the effect of such forces.
However, these barriers will not provide adequate resistance to the impact of turbine missiles.
The use of these procedures provides reasonable assurance that in the event of design basis missiles (with the exception of turbine missiles) striking seismic Category I structures or other missile shields and barriers, the structural integrity of the structures, shields, and barriers will not be impaired or degraded to an extent that will result in a loss of required protection. Seismic Category I systems and components protected by these structures are, therefore, adequately protected against the effects of missiles and will perform their intended safety function, if needed. Conformance with these procedures is an acceptable basis for satisfying, in part, the requirements of GDC 2 and 4.
3.6 PROTECTION AGAINST DYNAMIC EFFECTS ASSOCIATED WITH THE POSTULATED RUPTURE OF PIPING The review performed under this section pertains to the applicant's program for protecting safety-related components and structures against the effects of postulated pipe breaks both inside and outside containment. The effect that breaks or cracks in high and moderate energy fluid systems would have on adjacent safety-related components or structures has been analyzed with respect to jet impingement, pipe whip, and environmental effects. Several means are used to assure the protection of these safety-related items. They include physical separation, enclosure within suitably designed structures, the use of pipe whip restraints, and the use of equipment shields.
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3.6.1 Plant Design for Protection Against Postulated Piping Failures in Fluid Systems Outside Containment GDC 4, 11 Environmental and Missile Design Bases, 11 requires that systems and components important to safety be appropriately protected against dynamic effects, including the effects of missiles, pipe whipping, and discharging fluids, that may result from equipment failures. In order to meet this requirement with regard to protection against pipe breaks outside containment, the applicant has designed the plant in accordance with the criteria of BTP ASB 3-1, "Protection Against Postulated Piping Failures in Fluid Systems Out side Containment.11 These criteria concern failures in high and moderate energy fluid systems. The applicant has identified all high and moderate energy piping systems in accordance with these guidelines and has also identified those systems requiring protection from postulated piping failures.
The plant design accommodated the effects of postulated pipe breaks and cracks, including pipe whip, jet impingement, and environmental effects. The means used to protect essential (safety-related) systems and components include physical separation, enclosure within suitably designed structures, pipe whip restraints and equipment shields. In order to be consistent with BTP ASB 3-1, the applicant used separation as the primary means of protection, and where separation was not feasible, one of the other acceptable methods of protection was used.
The plant design includes the ability to sustain a high energy pipe break accident coincident with a single active failure and retain the capability for safe cold shutdown. For postulated pipe failures, the resulting effect will not preclude the habitability of the control room and will not cause the loss of function of power supplies or controls and instrumentation needed to complete a safety action as indicated in BTP ASB 3-1.
The applicant has also analyzed the effects of moderate energy line breaks outside containment on safety-related systems. The moderate energy systems are also designed to meet the criteria set forth in BTP ASB 3-1. The staff has evaluated the applicant 1 s analysis and concludes that it adequately demon strates that a postulated crack in a moderate energy line will not cause a loss of function of any safety-related system.
The main steam and feedwater lines outside the containment (reactor building) between the reactor building wall and the turbine building are seismic Category I and are routed over the reactor auxiliary building roof. The main steam and feedwater isolation valves are located in separate penetration compartments which are open to the outside environment. The compartments are therefore, fully vented, and a subcompartment pressure anaiysis as a resuit of a postu lated crack equivalent to the flow area of a single-ended pipe rupture in any one of these lines was not required. NRC staff also examined the area in order to determine what essential equipment was located there and whether it was environmentally qualified. Environmental qualification of essential equipment identified, including the main steam and feedwater isolation valves, emergency feedwater system flow control/isolation valves, atmospheric dump valves, and emergency feedwater turbine steam supply valves, is discussed in Section 3.11 of this SER. The need for qualification of the above equipment to the environ ment resulting from postulated main steam/feedwater line cracks is not required because the redundant components are located in the separate penetration compart ments. The applicant provided a pressure analysis for the other subcompartments 3-11
 
outside containment which contain high energy p1p1ng. The results of this analysis indicated that safe shutdown of the plant is not affected by the postulated break in these high energy lines.
Based on NRC review, as described above, the staff concludes that the applicant has adequately designed and protected areas and systems required for safe plant shutdown following postulated events, including the combination of pipe fai1ure and single active failure. The plant design meets the criteria set forth in BTP ASB 3-1 as far as protection of safety-related systems and components from postulated piping system failures and, therefore, meets the requirements of GOC 4 regarding protection against pipe breaks. Therefore, NRC staff concludes that the plant design for protection against postulated piping failures in fluid systems outside containment is acceptable.
3.6.2 Determination of Break Locations and Dynamic Effects Associated With the Postulated Rupture of Piping The NRC staff used the criteria of SRP Section 3.6.2 to review the locations chosen by the applicant for postulating piping failure. NRC also reviewed the size and orientation of these postulated failures including the methodology used by the applicant in calculating the resultant pipe whip and jet impingement loads and its effect on nearby safety-related components.
In addition, the staff has reviewed the applicant's information with respect to high energy piping system stresses; heating, ventilating, and* air conditioning (HVAC) jet impingement analysis, welded attachments to pipe, and details of its dynamic analysis for pipe breaks. The applicant has also committed to an augmented inservice inspection program for high energy piping within the break exclusion area.
Main steam and feedwater piping within the break exclusion region (from the outer containment wall to the isolation valves) will receive augmented inservice inspection. The remaining high energy piping penetrating the containment are 4 in. nominal pipe size or smaller and are exempt from inservice examination (IWC-1200).
The inservice examination of the main steam and feedwater piping during each inspection interval will consist of 100% volumetric examination of all circumferential and longitudinal welds within the break exclusion region.
Upon review of FSAR Section 3.6.2, staff findings are as follows:
The applicant has proposed methodologies for determining the location, type, and effects of postulated pipe breaks in high energy piping systems and postu lated pipe cracks in moderate energy piping systems. The applicant has used the effects resulting from these postulated pipe failures to evaluate the design of systems, components, and structures necessary to safely shut the plant down and to mitigate the effects of these postulated piping failures. The applicant has stated that pipe whip restraints, jet impingement barriers, and other such devices will be used to mitigate the effects of these postulated piping failures.
The staff has reviewed these methodologies and has concluded that they provide for a spectrum of postulated pipe breaks and pipe cracks which includes the most likely locations for piping failures, and that the types of breaks and 3-12
 
their effects are conservatively assumed. NRC finds that the methods used to design the pipe whip restraints provide adequate assurance that they will function properly in the event of a postulated piping failure. The staff further concludes that the use of the applicant's proposed pipe failure criteria in designing the systems, components, and structures necessary to safely shut the plant down and to mitigate the consequences of these postulated piping failures provides reasonable assurance of his ability to perform their safety function following a failure in high or moderate energy piping systems. The applicant 1 s methodologies comply with SRP Section 3.6.2 and satisfy the applicable portions of GDC 4 and are acceptable.
3.7 SEISMIC DESIGN
: 3. 7.1 Seismic Input The input seismic design response spectra (QBE and SSE) applied in the design of seismic Category I structures, systems, and components, in general, comply with the recommendations of Regulatory Guide 1.60, 11 Design Response Spectra for Nuclear Power Plants. 11 The specific percentage of critical damping values used in the seismic analysis of Category I structures, systems, and components are in conformance with Regulatory Guide 1.61, 11 Damping Values for Seismic Analysis of Nuclear Power Plants. 11 The synthetic time history used for seismic design of Category I plant structures, systems, and components is adjusted in amplitude and frequency content to obtain response spectra that envelope the response spectra specified for the site.
In general, the Regulatory Guide 1.60 spectral curves fall below the Waterford 3 synthetic time history spectral curves. The portions of Regulatory Guide 1.60 spectral curves exceeding the Waterford 3 synthetic time history spectral curves are limited to a narrow frequency range. We have required that the applicant provide data in a tabular form for this frequency range in question and deter mine that this small variance is not significant to the structural safety of the Category I structures. The applicant has provided this comparison which verifies that a negligible difference exists between the two curves for the frequency range in question. Also, the applicant utilized lower damping values in the Waterford 3 design than the damping values identified in Regulatory Guide 1.61. This is considered a conservative measure in the design of the Category I structures.
Conformance with the intent of Regulatory Guides 1.60 and 1.61 requirements, as explained above, provides reasonable assurance that for an earthquake whose intensity is 0.05 g for the QBE, and 0.1 g for the SSE, the seismic inputs to Category I structures, systems, and components are adequateiy defined to assure a conservative basis for the design of such structures, systems, and components to withstand the consequent seismic loadings.
: 3. 7.2 Seismic System Analysis, and 3.7.3 Seismic Subsystem Analysis (Part 1)
The scope of review of the seismic system and subsystem analysis for the plant included the seismic analysis methods for all Category I structures, systems, and components. It included review of procedures for modeling, seismic soil structure interaction, development of floor response spectra, inclusion of 3-13
 
torsional effects, evaluation of Category I structure overturning, and deter mination of composite damping. The review has included design criteria and procedures for evaluation of interaction of non-Category I structures and piping with Category I structures and piping and effects of parameter variations on floor response spectra. The review has also included criteria and seismic analysis procedures for reactor internals and Category I buried piping outside the containment.
The system and subsystem analyses were performed by the applicant on an elastic basis. Modal response spectrum multidegree of freedom and time history methods form the bases for the analyses of all major Category I structures, systems, and components. When the modal response spectrum method was used, governing response parameters were combined by the square root of the sum of the squares rule. However, the absolute sum of the modal responses were used for modes with closely spaced frequencies. To account for the three components of earth quake motion, the applicant considered for each element the two responses related to one horizontal and one vertical earthquake component combined using the absolute sum method. However, the square root of the sum of the squares of the maximum co-directional responses was used for three randomly selected elements in accounting for three components of the earthquake motion for both the time history and response spectrum methods to verify the equivalency of the two methods for this design. Floor spectra inputs used for design and test verifi cations of structures, systems, and components were generated from the time history method, taking into account variation of parameters by peak widening.
A vertical seismic system dynamic analysis is employed for all structures, systems, and components. Torsional effects and stability against overturning are considered.
The applicant has investigated the effects that additional modes and lumped masses have on the structural response of Category I structures and concluded that the effects are negligible. Also, the applicant complies with our criteria for system/subsystem decoupling as identified in SRP Section 3.7.3.
The lumped soil spring approach is used to evaluate soil-structure interaction and structure-to-structure interaction effects upon seismic responses.
The applicant has agreed to perform additional dynamic analyses of the Category I structures to determine the effects of the appropriate ties between the various cantilever stick model representing the Category I structures supported on the common mat foundation, the effects of the inclusion of the torsional soil springs, and the effects of considering actual and accidental eccentricities for all mass points. The staff will confirm the acceptability of these dynamic analyses before issuance of an OL.
The staff concludes that the seismic system and subsystem analysis procedures and criteria utilized by the applicant provide an acceptable basis for the seismic design pending the resolution of the above mentioned confirmatory item.
3.7.3 Seismic Subsystem Analysis (Part 2)
The scope of our review under SRP Section 3.7.3 included:
(1) The applicant's seismic analysis of the RCS; (2) The applicant's seismic analysis of reactor internals, core, and control element drive mechanism, and 3-14
 
(3)  The applicant's seismic analysis of non-NSSS seismic Category I piping systems.
This review is divided into the three aspects described above.
3.7.3.1 Reactor Coolant System The reactor vessel, pumps, steam generators and their supports, and the interconnecting piping system were evaluated as a coupled system. The model includes 30 mass points with 79 dynamic degrees of freedom. The mathematical model provides a three-dimensional representation of the dynamic response of the coupled components to seismic excitations in both the horizontal and vertical directions. The analysis was conducted using methods of dynamic analyses employing time-history and modal response spectra techniques.
The pressurizer and surge line from the hot leg to the pressurizer were evaluated as decoupled subsystems. The analysis was conducted using a moda1 response spectra technique.
In both types of analyses, the applicant has appropriately considered the combination of modal responses by the square root of the sum of the squares rule. The absolute sum of the modal responses are used for modes with closely spaced frequencies. The applicant has also considered combination of the three spatial components of earthquake motion by the square root of the sum of squares, and evaluation of multiple-supported components with distinct inputs applied at each support.
The staff concludes that the seismic analysis procedures described by the applicant for RCSs are acceptable.
: 3. 7.3.2 Reactor Internals, Core, and Control Element Drive Mechanism The applicant describes mathematical models and analysis techniques for reactor internals, core, and control element drive mechanism which are analogous to those described for the RCSs. The input response spectra used are based on the acceleration of the reactor vessel supports. Also, the adequacy of the control element drive mechanism when subjected to seismic loadings is verified by a combination of test and analysis.
The staff concludes that the seismic evaluation techniques and procedures described by the applicant for reactor internals, core, and control element drive mechanism are acceptable.
: 3. 7.3.3 Non-NSSS Seismic Category I Piping Systems All seismic Category I piping systems 1/2-in. nominal size or larger are seis mically analyzed. Code Class 1 piping systems are ana1yzed by the modal response spectra method. In the analysis of complex systems where closely spaced modal frequencies (difference is less than 10% of the lower frequency) are encountered, the response of the closely spaced modes are combined by the summation of the absolute values and then combined with the responses of the remaining significant modes by the square root of the sum of the squares method. The approach used by the applicant for modal combination provides an equivalent level of safety to that provided in Regulatory Guide 1.92.
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Class 2 and 3 piping systems are analyzed by one of three methods:
(1)  the same modal response spectra method as used for Class 1 piping systems, (2)  an equivalent static load method, or (3)  a chart method.
The applicant has indicated the analysis method used for each p1p1ng system and has provided technical justification for use of the equivalent static load and chart methods. The staff has reviewed the applicant 1 s procedure and concludes that the seismic evaluation methods and procedures described by the applicant for non-NSSS seismic Category I piping systems are acceptable.
Standard Review Plan Section 3.7.3, 11 Seismic Subsystem Analysis, 11 requires five OBEs with a minimum of 10 cycles each to be used in the fatigue evaluation.
The Waterford 3 plant utilizes 200 full load cycles with an amplitude equal to the maximum response produced during the entire duration of an OBE. Thus, the approach is conservative and is acceptable.
The staff has reviewed the methods used by the applicant for its seismic subsystem analyses. The seismic subsystem analyses for the Waterford 3 plant comply with SRP Section 3.7.3 and constitute an acceptable basis for complying with the applicable portions of GDC 2.
3.7.4 Seismic Instrumentation Program The type, number, location and utilization of strong motion accelerographs to record seismic events and to provide data on the frequency, amplitude, and phase relationship to the seismic response of the containment structure comply with Regulatory Guide 1.12. Supporting instrumentation is being installed on Category I structures, systems, and components in order to provide data for the verification of the seismic responses determined analytically for such Category I items.
The installation of the specified seismic instrumentation in the reactor con tainment structure and at other Category I structures, systems, and components constitutes an acceptable program to record data on seismic ground motion as well as data on the frequency and amplitude relationship of the response of major structures and systems. A prompt readout of pertinent data at the con trol room can be expected to yield suf.ficient information to guide the opera tor on a timely basis for the purpose of evaluating the seismic response in the event of an earthquake. Data obtained from such installed seismic instru mentation will be sufficient to determine that the seismic analysis assumptions and the analytical model used for the design of the plant are adequate and that allowable stresses are not exceeded under conditions where continuity of opera tion is intended. Provision of such seismic instrumentation complies with Regulatory Guide 1.12.
3.8 DESIGN OF CATEGORY I STRUCTURES 3.8.1 Concrete Containment Not applicable to this facility.
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3.8.2 Steel Containment The containment consists of a free-standing steel shell located within a separate reinforced concrete shield reactor building. The containment was designed, fabricated, constructed, and tested as a Class MC Vessel in accordance with subsection NE of the ASME Boiler and Pressure Vessel Code, Section III. Loads include an appropriate combination of dead and live loads; thermal loads; seismic and LOCA including pressure and jet forces.
The analysis of the containment was based on the elastic thin shell theory. The allowable stress and strain limits are in accordance with those delineated in the applicable sections of subsection NE of the ASME Code, Section III, for the various loading conditions.
The applicant identified the use of the Welding Research Council Bulletin No. 107 for the evaluation of local stresses of the cylindrical steel shell due to external loads. It was found that a substantial extrapolation of the data pro vided by the above reference was done without providing justifications. The applicant has agreed to investigate this design procedure and provide the requested justifications. The staff will review these justifications and confirm their acceptability before issuance of an OL.
The criteria that were used in the analysis, design, and construction of the steel containment structure for anticipated loadings and postulated conditions that may be imposed upon the structure during its service lifetime are in conformance with established criteria, codes, standards, and guides acceptable to the NRC staff, pending the resolution of the above mentioned confirmatory item.
The use of these criteria as defined by applicable codes, standards, and guides; the loads and loading combination; the design and analysis procedures; the structural acceptance criteria; the materials, quality control programs, and special construction techniques; and the testing and inservice surveillance requirements provide reasonable assurance that, in the event of earthquakes and various postulated accidents occurring within and outside the containment, the structure will withstand the specified conditions without impairment of structural integrity or safety functions. A seismic Category I concrete shield building protects the steel containment from the effects of wind, tornadoes, and various postulated accidents occurring outside the shield building. Con formance with these criteria constitutes an acceptable basis for satisfying, in part, the requirements of GDC 2, 4, 16, and 50, pending the resolution of the confirmatory item.
3.8.3 Concrete and Structural Steel Internal Structures The containment interior structures consist of walls, compartments, and floors.
The major code used in the design of concrete internal structures is ACI 318-63 Code, "Building Code Requirements for Reinforced Concrete. 11 For design of rein forcing steel splices, ACl 318-71 Code is used. For steel internal structures the AISC Specification, "Specification for the Design, Fabrication, and Erection of Structural Steel for Building, 11 is used.
The containment concrete and steel internal structures were designed to resist various combinations of dead and live loads, accident-induced loads, including pressure and jet loads, and seismic loads. The load combinations used to cover 3-17
 
those cases likely to occur and include all loads which may act simultaneously.
The design and analysis procedures that were used for the internal structures are the same as those used on previously licensed applications and, in general, are in accordance with procedures delineated in the ACI 318-63 Codes and in the AISC Specification for Concrete and Steel Structures, respectively.
The containment internal structures were designed and proportioned to remain within limits established by the NRC staff under the various load combina tions. These limits are, in general, based on the ACI 318-63 Code and on the AISC Specification for Concrete and Steel Structures, respectively, modified as appropriate for load combinations that are considered extreme.
The materials of construction, their fabrication, construction, and installation are in accordance with the ACI 318-63 Code and AISC Specification for Concrete and Steel Structures, respectively.
The criteria that were used in the design, analysis, and construction of the containment internal structures to account for anticipated loadings and postu lated conditions that may be imposed upon the structures during their service lifetime are in conformance with established criteria, and with codes, standards, and specifications acceptable to the NRC staff.
In their reply to an NRC {{letter dated|date=April 21, 1980|text=letter dated April 21, 1980}}, the applicant stated that there are no seismic Category I masonry walls at Waterford 3. The staff requested the applicant to identify any masonry walls within any Category I structures and consider the effects of their failure during the postulated seismic events on any safety systems -and components or state if the structural designs of these masonry walls account for the seismic environmental loads and meet the Branch Technical Position on the subject. The applicant stated that it complies with the second option. This position is acceptable to the staff.
The use of these criteria as defined by applicable codes, standards, and speci fications; the loads and loading combinations; the design and analysis proce dures; the structural acceptance criteria; the materials, quality control programs, and special construction techniques; and the testing and inservice surveillance requirements provide reasonable assurance that, in the event of earthquakes and various postulated accidents occurring within the containment, the interior structures will withstand the specified design conditions without impairment of structural integrity or the performance of required safety func tions. Conformance with these criteria constitutes an acceptable basis for satisfying, in part, the requirements of GDC 2 and 4.
3.8.4 Other Category I Structures Category I structures other than containment and its interior structures are all of structural steel and concrete. The structural components consist of slabs, walls, beams, and columns. The major code used in the design of concrete Category I structures is the ACI 318-63 Code, "Building Code Requirements for Reinforced Concrete." For design of reinforcing steel splices, ACI 318-71 Code was used. For steel Category I structures, the AISC Code, "Specification for the Design, Fabrication and Erection of Structural Steel for Buildings," is used.
The concrete and steel Category I structures were designed to resist various combinations of dead loads; live loads; environmental loads including winds, 3-18
 
tornadoes, QBE and SSE, and loads generated by postulated ruptures of high energy pipes such as reaction and jet impingement forces, compartment pressures, and impact effects of whipping pipes.
The design and analysis procedures that were used for these Category I structures are the same as those approved on previously licensed applications and, in general, are in accordance with procedures delineated in the ACI 318-63 Code and in the AISC Specification for Concrete and Steel Structures, respectively.
The various Category I structures are designed and proportioned to remain within limits established by the staff under the ACI 318-63 Code and in the AISC Speci fication for Concrete and Steel Structures, respectively, modified as appropriate for load combinations that are considered extreme.
The criteria that were used in the analysis, design, and construction of all the plant Category I structures to account for anticipated loadings and postu lated conditions that may be imposed upon each structure during its service lifetime are in conformance with established criteria, codes, standards, and specifications acceptable to the staff.
The applicant has considered the safety implications related to masonry walls.
The resolution of the safety concerns related to masonry wall design has been documented in Section 3.8.3 of this report.
The use of these criteria as defined by applicable codes, standards, and speci fications; the loads and loading combinations, the design and analysis procedures; the structural acceptance criteria; the materials, quality control, and special construction techniques; and the testing and inservice surveillance requirements provide reasonable assurance that, in the event of winds, tornadoes, earthquakes, and various postulated accidents occurring within the structures, the structures will withstand the specified design conditions without impairment of structural integrity or the performance of required safety functions.
Conformance with these criteria, codes, specifications, and standards constitutes an acceptable basis for satisfying, in part, the requirements of GOC 2 and 4.
3.8.5 Foundations Foundations of Category I structures are described in Section 3.8.5 of the Final Safety Analysis Report (FSAR). Primarily, the foundation is a reinforced con crete mat. The major code used in the design of the concrete mat foundation is ACI 318-63 Code. For design of reinforcing steel splices, AC! 318-71 Code was used. The concrete foundation has been designed to resist various combina tions of dead loads; live loads; environmental loads including winds, tornadoes, QBE and SSE, and loads generated by postulated ruptures of high energy pipes.
The design procedures that were used for this Category I foundation mat are the same as those approved on previously licensed applications and, in general, are in accordance with procedures delineated in the ACI 318-63 Code. The founda tion mat was analyzed as a rectangular flat slab resting on an elastic foundation.
This Category I foundation mat was designed and proportioned to remain within limits established by the staff under the various load combinations. These 3-19
 
limits are, in general, based on the AC! 318-63 Code modified as appropriate for load combinations that are considered extreme. The materials of construction and installation are in accordance with the ACI 318-63 Code.
The applicant has agreed to reevaluate the foundation mat for changes in the value of the subgrade modulus. This reevaluation will verify the location of the critical sections in the foundation mat, when used as in a rigid block, and will permit the evaluation of special reinforcement identified for these sections. The staff will confirm the acceptability of this analysis before issuing an DL.
The criteria that were used in the analysis, design, and construction of all the plant Category I foundations to account for anticipated loadings and postu lated conditions that may be imposed upon the foundation mat during its service lifetime are in conformance with established criteria, codes, standards, and specifications acceptable to the NRC staff, pending the resolution of the confirmatory item.
The use of these criteria as defined by applicable codes, standards, and specifications; the loads and loadings combinations; the design and analysis procedures; the structural acceptance criteria; the materials, quality control, and special construction techniques; and the testing and inservice surveillance requirements provide reasonable assurance that, in the event of winds, tornadoes, earthquakes, and various postulated events, Category I founda tions will withstand the specified design conditions without impairment to struc tural integrity and stability or the performance of required safety functions.
Conformance with these criteria, codes, specifications, and standards constitutes an acceptable basis for satisfying, in part, the requirements of GDC 2 and 4.
3.9 MECHANICAL SYSTEMS AND COMPONENTS The staff reviewed structural integrity and operability of various safety-related mechanical components and supports, and other components such as CRO mechanisms, reactor internals, ventilation ducting, cable trays, and any safety-related piping designed to industry standards other than the ASME Boiler and Pressure Vessel Code. The staff reviewed such issues as load combinations, allowable stresses, methods of analysis, summary results, seismic qualification, preopera tional testing, and inservice testing of pumps and valves. The staff used SRP Sections 3.9.1 through 3.9.6 as criteria for its reviews. In order to find the plant acceptable the staff must conclude that there is adequate assurance of a mechanical component performing its safety-related function under the required combinations of normal operating conditions, system operating transients, postulated pipe breaks, and seismic events.
3.9.1 Special Topics for Mechanical Components The staff review of FSAR Section 3.9.l included the design transients, computer programs, experimental stress analyses, and elastic-plastic analysis methods that were used in the analysis of seismic Category I ASME Code and non-Code items.
Additionally, the NRC staff has contracted with Oak Ridge National Laboratory (ORNL) to perform an independent stress analysis of a sample piping system in 3-20
 
the Waterford 3 plant. This analysis will verify that the sample piping system meets the applicable ASME Code requirements, and will also provide a check on the applicant's ability to correctly model and analyze its piping systems.
The staff will report the results of this independent piping analysis in a supplement to this SER.
NRC has reviewed the list of design transients specified for use in the fatigue analysis of ASME Class 1 components and have found them to be acceptab1e.
Computer programs were used in the analysis of specific components. A list of the computer programs that were used in the dynamic and static analyses to deter mine the structural and functional integrity of these components is included in the FSAR along with a brief description of each program. Verification of the computer programs, as required by 10 CFR Part 50, Appendix B, is described for each computer program.
The applicant describes the analysis methods under asymmetric LOCA loadings in Appendix 3.9E of the FSAR. The asymmetric LOCA is presented in Section 3.9.2 of this SER.
The methods used in defining the applicable transients and the computer codes and analytical methods used in the analyses provide assurance that the calcula tions of stresses, strains, and displacements for seismic Category I ASME Code 1, 2, and 3 components and supports are acceptable.
The methods of analysis that the applicant has employed in the design of all seismic Category I ASME Code Class 1, 2 and 3 components, component supports, reactor internals, and other non-Code items are in conformance with SRP Section 3.9.1 and satisfy the applicable portions of GDC 2, 4, 14, and 15, and therefore are acceptable.
3.9.2 Dynamic Testing and Analysis of Systems, Components, and Equipment The staff review of FSAR Section 3.9.2 included the methodologies, testing procedures, and dynamic analyses employed by the applicant to assure the structural integrity and operability of piping systems, mechanical equipment, and reactor internals and their supports under vibratory loadings. This review is divided into three parts, each of which is discussed briefly below.
3.9.2.1 Piping Preoperational and Startup Testing Program Piping vibration, thermal expansion, and dynamic effects testing will be conducted during the Waterford 3 plant's preoperational and startup testing pro gram. The purpose of these tests is to assure that the piping vibrations are within acceptable limits and that the piping system can expand thermally in a manner consistent with the design intent.
The applicant describes its program and acceptance criteria for preoperational vibration, thermal expansion and dynamic testing of piping. SRP Section 3.9.2 requires an applicant to monitor its piping systems during preoperationa1 and startup testing for excessive vibration. The vibration may result from plant transients or may be associated with steady-state plant operation. This steady state vibration, whether flow induced or caused by nearby vibrating equipment, 3-21
 
may be responsible for an excessive number of stress cycles in the pipe during the 40-yr plant life. The applicant is required to evaluate pipe vibration and determine whether the deflection is substantial enough to cause fatigue degradation.
The applicant has used for its vibration acceptance criteria, pipe deflections that would result in a steady-state stress amplitude less than or equal to 50%
of the alternating stress amplitude at 106 cycles as shown in the ASME Code.
For transient vibration, limits similar to steady-state vibration are used.
However, if displacements result in stress amplitudes exceeding 50% of the alternating stress amplitude at 106 cycles, then the cumulative usage factor is computed. The vibration is accepted if the cumulative usage factor is less than 0.1. NRC will require the applicant to provide a summary of results of this program upon its completion.
Based upon staff review of FSAR Section 3.9.2, findings are as follows:
The vibration, thermal expansion, and dynamic effects test program which will be conducted during startup and initial operation on specified high and moderate energy piping, and all associated systems, restraints, and supports is an acceptable program for the following reasons. The tests provide adequate assurance that the piping and piping restraints of the system have been designed to withstand vibrational dynamic effects caused by valve closures, pump trips, and other operating modes associated with the design basis flow conditions.
In addition, the tests provide assurance that adequate clearances and free movement of snubbers exist for unrestrained thermal movement of piping and supports during normal system heatup and cooldown operations. The planned tests will develop loads similar to those experienced during reactor operation.
This test program complies with SRP Section 3.9.2 and constitutes an acceptable basis for fulfilling the applicable requirements of GDC 14 and 15.
3.9.2.2 Dynamic Analyses of Reactor Coolant System The staff asked the applicant to expand this section to address asymmetric LOCA loads. The applicant responded to the asymmetric LOCA load question in a letter from L. V. Maurin to A. Schwencer dated March 23, 1981 which includes considera tion of asymmetric loads on reactor primary coolant system components.
The applicant has performed detailed structural analyses as described in Amendment 16 to the FSAR. The primary loop break locations for these analyses were postulated in accordance with CENPD-168, 11 Design Basis Pipe Breaks. 11 The critical break location for the design of the reactor pressure vessel supports is a 2258.06 cm2 (350 in. 2) reactor pressure vessel (RPV) nozzle inlet break with a break opening time of 6 msec. The time varying forcing functions result ing from this break were calculated. The loads considered were subcooled blow down loads, cavity pressure loads, strain energy release loads, and jet impinge ment and thrust loads. Simultaneous effects of all these LOCA load components were applied to the reactor vessel and internals and a nonlinear time history dynamic analysis of a three-dimensional mathematical model of the RCS was performed to demonstrate the adequacy of the reactor vessel supports. The calculated loads on the vessel supports are found to be acceptable even though support pad design load in the vertical direction is exceeded slightly. The 3-22
 
basis for acceptance is the fact that the support loads resulting from this low probability event are well below the ultimate capacity of the pressure vessel support.
Maximum reactor vessel motions were imposed upon a flexibility analysis model of the RCS in order to compute the load on the steam generator supports as a result of the vessel motion. The reactor coolant pumps have not been specifi cally analyzed except as part of the primary reactor coolant piping analysis.
The asymmetric pressure histories obtained for the breaks postulated in Section 6.2.1.2 of the FSAR have been used to determine the asymmetric loads across the steam generator and reactor coolant pumps. The staff finds that these components have been demonstrated to meet the applicable acceptance criteria under the asymmetric pressure loads resulting from the design basis breaks postulated in the FSAR. The structural adequacy of the reactor coolant pump supports and the steam generator upper and lower supports have been demon strated to not exceed more than 70% of the design allowable, thus providing adequate design margin.
The asymmetric LOCA analysis performed by the applicant for the RPV is found to be acceptable since the vessel meets the applicable FSAR acceptance criteria for the vessel.
The adequacy of reactor coolant piping under LOCA conditions has been demonstrated by reference to CENPD-168. The Waterford 3 RCS design falls witrin the bounds of the primary coolant system designs of CENPD-168 which the staff has previously accepted. An elastic plastic analysis of one of the two RCS attached ECCS piping systems which are identical, has been performed on the basis of bounding Waterford 3 specific vessel motions derived from the worst-case LOCA which are assumed to adequately represent the ECCS nozzle motions. The analyzed line and its existing supports are capable of withstanding loads resulting from asymmetric LOCA loads.
Currently, a LOCA analysis is being performed by the applicant for the assessment of reactor internals and control element drive mechanism (CEDM). Since the Waterford 3 reactor internals and CEDM are identical to those of San Onofre Units 2 and 3 which have been reviewed and approved by the staff, we find that the asymmetric loads resulting from the bounding 2258.06 cm2 (350 in.2 ) reactor vessel inlet break are expected to be similar and that the above components will meet the applicable FSAR acceptance criteria. Based on the results of the plant unique analysis not exceeding the loads used in the reactor internals and CEDM assessment, the staff finds acceptable the applicant's methodology and work completed to date.
The dynamic system analysis as performed by the applicant provides an acceptable basis for confirming the structural design adequacy of the reactor internals and unbroken piping loops to withstand the combined dynamic loads of postulated LOCA and the SSE. The analysis provides adequate assurance that the combined stresses and strains in the components of the RCS and reactor internals do not exceed the allowable stress and strains limits for the materials of construction, and that the resulting deflections or displacements at any structural elements of the reactor internals will not distort the reactor internals geometry to the extent that core cooling may be impaired. The methods used for component analysis have been found to be compatible with those used for the systems 3-23
 
analysis. The proposed combinations of component and system analyses are, therefore, acceptable. The assurance of structural integrity of the reactor internals under LOCA and SSE conditions for the most adverse postulated loading event provides added confidence that the design will withstand a spectrum of lesser pipe breaks and seismic loading events. Accomplishment of the dynamic system analysis constitutes an acceptable basis for satisfying the applicable requirements of GDC 2 and 4.
3.9.2.3 Reactor Internals, Flow-Induced Transients, Prototypical Testing The applicant cites the Maine Yankee and Fort Calhoun designs as valid prototype designs for Waterford 3. The applicant designates Waterford 3 as a non-prototype Category I design.
The applicant is proceeding to implement a preoperational vibration monitoring program for Waterford 3 which is consistent with the recommendations of Regula tory Guide 1.20, Revision 1, 11 Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing," as it relates to non-prototype Category I units.
The preoperational vibration program planned for the reactor internals provides an acceptable basis for verifying the design adequacy of these internals under test loading conditions comparable to those that will be experienced during operation. The combination of tests, predictive analysis, and post-test inspec tion provides adequate assurance that the reactor internals will, during their service lifetime, withstand the flow-induced vibrations of reactor operation
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V IUIU tion tests is in conformance with the provisions of Regulatory Guide 1.20 and constitutes an acceptable basis for demonstrating design adequacy of the reactor internals, and satisfies the applicable requirements of GDC 1 and 4.
3.9.3 ASME Code Class l, 2 1 and 3 Component Supports and Core Support Structures Staff review of FSAR Section 3.9.3 includes the structural integrity and operability of pressure-retaining components, their supports, and core structures which are designed in accordance with the ASME Boiler and Pressure Vessel Code, Section III, or earlier industry standards. The review is divided into four parts, each of which is discussed briefly below.
3.9.3.1 Loading Combinations, Design Transients, and Stress Limits The applicant describes loading combinations, design transients, and stress limits which are consistent with Regulatory Guide 1.48, 11 Design Limits and Loading Combinations for Seismic Category I Fluid Systems Components 11 with the exception of valves for which the loading combinations of Regulatory Guide 1.48 were not in effect at the time of the purchase of the valves. The staff reviewed the loading combinations and allowable limits used by the applicant for all components, including valves, and find that they provide a level of safety equivalent to that provided in Regulatory Guide 1.48 and, thus, are acceptable.
Staff findings are as follows:
The specified design and service loading combinations as applied to ASME Code Class 1, 2, and 3 pressure retaining components in systems designed to meet 3-24
 
seismic Category I standards provide assurance that, in the event of an earthquake or other service loadings caused by postulated events or system operating transients, the resulting combined stresses of system components will not exceed allowable stress and strain limits for the materials of construction.
Limiting the stresses under such loading combinations provides a conservative basis for the design of system components to withstand the most adverse combination of loading events without loss of structural integrity. The design and load combinations and associated stress and deformation limits specified for ASME Code Class 1, 2, and 3 components comply with SRP Section 3.9.3 and satisfy the applicable portions of GDC 1, 2 and 4.
3.9.3.2 Pump and Valve Operability Assurance Program The applicant describes its pump and valve operability assurance program in 3.9.2.2 of the FSAR. The staff has reviewed the design basis events that were considered in evaluating the operability of active pumps and valves. Staff review has also included the stress limitations, acceleration limits, and testing methods used to verify operability for pumps and valves.
NRC findings are as follows:
The component operability assurance program for ASME Code Class l, 2, and 3 active valves and pumps provides adequate assurance of the capability of such active components (1) to withstand the imposed design and service loads without loss of structural integrity, and (2) to perform necessary active11 functions 11 (e.g., valve closure or opening, pump operation) during postulated events and conditions expected when plant shutdown is required. The specified component operability assurance test program complies with SRP Section 3.9.3 and satisfies the applicable portions of GDC 1, 2, and 4.
3.9.3.3 Design and Installation of Pressure Relief Devices This section concerns the methods used by the applicant in designing its ASME Class 1, 2, and 3 safety and relief valves, their attached piping, and their supports. The staff has1 specifically reviewed the applicant's compliance with Regulatory Guide 1.67, Installation of Overpressure Protection Devices." NRC 1
has reviewed the applicant 1 s methodologies for closed or quasi-closed and open discharge systems.
Findings are as follows:
The methodology used in the design and installation of ASME Class 1, 2, and j safety and relief valves provides adequate assurance that, under discharging conditions, the resulting stresses will not exceed allowable stress and strain limits for the materials of construction. Limiting the stresses under the loading combinations associated with the actuation of these pressure relief devices provides a conservative basis for the design and installation of the devices to withstand these loads without the loss of structural integrity of impairment of the overpressure protection function. The methodologies used for the design and installation of ASME Class 1, 2, and 3 overpressure relief devices constitute an acceptable basis for meeting the applicable requirements of GDC 1, 2, 4, 14, and 15 and are consistent with those guidelines specified in Regulatory Guide 1.67 and SRP Section 3.9.3.
3-25
 
3.9.3.4 Component Supports The applicant describes the design of ASME Class 1, 2, and 3 component supports in 3.9.3.4 of the FSAR. Some supports for ASME Code components have been designed in accordance with Subsection NF of the ASME Code, Section III. The remaining supports for ASME Code components were designed to remain elastic under maximum loads.
NRC has reviewed the applicant's design procedures for the buckling of component supports and finds the applicant's design procedures and stress limits accep table because they meet the criteria given below.
Findings are as follows:
The specified design and service loading combinations used for the design of ASME Code Class 1, 2, and 3 components supports in systems classified as seismic Category I provide assurance that, in the event of an earthquake or other service loadings resulting from postulated events or system operating transients, the resulting combined stresses imposed on system components will not exceed allowable stress and strain limits for the materials of construction. Limiting the stresses under such loading combinations provides a conservative basis for the design of component supports to withstand the most adverse combinations of loading events without loss of structural integrity or component operability. The design and service load combinations and associated stress and deformation limits speci fied for ASME Code Class 1, 2, and 3 component supports comply with SRP Section 3.9.3 and satisfy the applicable portions of GDC 1, 2 and 4.
3.9.4 Control Rod Drive System Staff review under SRP Section 3.9.4 covered the design, analysis, and testing of the magnetic jack CRD mechanism. NRC reviewed the analyses and tests per formed to assur the structural integrity and operability of the mechanism during normal operation and under accident conditions. The staff also reviewed the life cycle testing performed to demonstrate the reliability of the CRD mechanism over its 40-yr life.
Findings are as follows:
The design procedures and the testing program conducted in verification of the mechanical operability and life cycle capabilities of the CRD system are in conformance with SRP Section 3.9.4. The use of these criteria provide assur ance that the svstem will function reliablv when reauired and will form an
;ptable bsi; fr satisfying the mechanical relibility requirements of GDC 27.
3.9.5 Reactor Pressure Vessel Internals NRC review of FSAR Section 3.9.5 included the load combinations, design stress intensity limits, and other procedures used in the design of the Waterford 3 pressure vessel internals. The applicant has stated that the limits of stress intensities to which the reactor internals are designed are those given in Subsection NG and Appendix F of Section III of the ASME Code. The description of the configuration and general arrangement of the reactor internal structures, 3-26
 
components, assemblies, and systems has been reviewed and the staff has noted that with minor exceptions they are identical to the reactor internals in the Maine Yankee NSSS. The staff has reviewed the information concerning details of the vessel internals, deflection limits, and compliance with the design rules of Subsection NG of Section III of the ASME Code.
Findings are as follows:
The specified transients, design and service loadings, and combination of loads as applied to the design of the Waterford 3 RPV internals provide assurance that in the event of an earthquake or of a system transient during normal plant operation, the resulting deflections and associated stresses imposed on the reactor internals will not exceed allowable stresses and deformation limits for the materials of construction. Limiting the stresses and deformations under such loading combinations provides an acceptable basis for the design of these reactor internals to withstand the most adverse combinations of loading events that have been postulated to occur during the service lifetime without loss of structural integrity or impairment of function. The design procedures used by the applicant in the design of the Waterford 3 reactor internals comply with SRP Section 3.9.5 and constitute an acceptable basis for satisfying the appli cable requirements of GDC 1, 2, 4, and 10.
3.9.6 Inservice Testing of Pumps and Valves In Sections 3.9.2 and 3.9.3 of this SER the staff discussed the design and seismic qualifications of safety-related pumps and valves in the Waterford 3 plant. The design of these pumps and valves is intended to demonstrate that they will be able to perform their safety function (open, close, start, etc.,)
at any time during the plant life. However, to provide added assurance of the reliability of these components, the applicant is required to periodically test all of its safety-related pumps and valves. These tests are performed generally in accordance with the rules of Section XI of the ASME Code. These tests verify that these pumps and valves operate successfully when required. Additionally, periodic measurements are made of various parameters which are compared to base line measurements in order to detect long-term degradation of the pump or valve performance. NRC review of FSAR Section 3.9.6 covers the applicant's program for preservice and inservice testing of pumps and valves. The staff gives parti cular attention to those areas of the test program for which the applicant requests relief from the requirements of Section XI of the ASME Code.
The applicant states: 11 The complete inservice inspection program, including testing procedures and requests for relief, is scheduled to be complete approximately one year prior to fuel loading date."
NRC staff will report on the overall results of its review of the program in a supplement to this SER.
One generic area of concern during recent NRC reviews has been periodic leak testing of pressure isolation valves.
There are several safety systems connected to the coolant pressure boundary that have design pressure below the rated pressure. There are also some systems that are rated at full reactor pressure on the discharge side of pumps but have 3-27
 
pump suction below RCS pressure. In order to protect these systems from RCS pressure, two or more isolation valves are placed in series to form the interface between the high pressure RCS and the low pressure systems. The leak tight integrity of these valves must be ensured by periodic leak testing to prevent exceeding the design pressure of the low pressure systems thus causing an inter system LOCA. Periodic leak testing of pressure isolation valves shall be per formed after all disturbances to the valve are completed. The pressure isolation valves to be tested (Table 5.2-11 of the FSAR) will be listed in the technical specifications.
The applicant has agreed in his response to Question 211.67 to categorize the pressure isolation valves for the HPSI, LPSI, and the shut down cooling system as Category A or AC. These categorizations meet NRC requirements and the staff finds them acceptable. Pressure isolation valves are required to be Category A or AC and to meet the appropriate valve leak rate test requirements of IWV-3420 of Section XI of the ASME Code except as discussed below. The allowable leakage rate shall not exceed 1.0 gal/min for each valve as stated in the technical specifications.
The applicant has committed to test all pressure isolation valves to the 1.0-gal/min leak rate criteria.
Valves in systems rated at less than 50% of the RCS design pressure shall be leak tested or verified closed each time the valve is disturbed as a result of flow in the line or valve actuation. This will ensure the effectiveness of the valves as isolation barriers. Consistent with the above, the staff has determined that leak testing of checK valves SI-114, 124, 134 and 144 will be required at each disturbance in addition to that frequency committed to by the applicant. This requirement will appear in the technical specifications.
The staff finds this acceptable for the following reasons: (1) full closure of these valves is verified in the control room by direct monitoring position indicators, (2) inadvertent opening of these valves is prevented through inter locks which require the plant to be below shutdown cooling system operating pressure prior to opening, and (3) gross leakages due to valve failure would be detected by increasing levels in the containment sump. Therefore, full closure of these valves is assured after opening, inadvertent opening is pre vented and gross RCS leakages can be readily detected.
Limiting conditions for operation (LCO) will be added to the technical specifications which will require corrective action, i.e., shutdown or system isolation when the leakage iimits are not met. Also surveillance requirements, which will state the acceptable leak rate testing frequency, will be provided in the technical specifications.
The NRC staff concludes that LP&L's commitments to periodic leak testing of pressure isolation valves between the RCS and low pressure systems will provide reasonable assurance that the design pressure of the low pressure systems will not be exceeded, and thus reduce the probability of an occurrence of an intersystem LOCA. This meets, in part, the requirements of GOC 55 of 10 CFR Part 50.
3-28
 
3.10 SEISMIC AND DYNAMIC QUALIFICATION OF SEISMIC CATEGORY I MECHANICAL AND ELECTRICAL EQUIPMENT On March 16, 1981, the staff issued a request for information to the applicant which asked for information concerning their equipment qualification for seismic and hydrodynamic loads. The applicant has committed to responding to this request for information by July 30, 1981. After reviewing the July 30, 1981 submittal, a subsequent request for additional information will be issued which will require response within one week (or at least two weeks before the site visit). Based on these schedules, the Seismic Qualification Review Team (SQRT) plans to conduct a plant site review of the applicant 1 s qualification documentation tentatively scheduled for early September 1981. The staff will report on the results of the review in a supplement to this report.
3.11 ENVIRONMENTAL QUALIFICATIONS FOR SAFETY-RELATED ELECTRICAL EQUIPMENT In December 1979, the staff issued guidance for the environmental qualifica tion of safety-related electrical equipment (NUREG-0588, "Interim Staff Posi tion on Environmental Qualification of Safety-Related Electrical Equipment 11 ).
By {{letter dated|date=November 12, 1980|text=letter dated November 12, 1980}}, the staff requested that LP&L review the environmental qualification documentation for each item of safety-related electrical equipment that could be exposed to a harsh environment so as to identify the degree which the associated environmental qualification program complies with the staff's position as described in NUREG-0588. Further, where there are deviations, the staff requested that the applicant provide the basis for concluding that the associated environmental qualification program demonstrates that each item in question is environmentally qualified for its service conditions.
The Commission Memorandum and Order (CLI-80-21, dated May 23, 1980) directs the staff to complete its review of environmental qualification including the publication of SERs for all operating reactors. In addition, this order directs that by no later than June 30, 1982, all electrical equipment in operating reactors subject to this review be in compliance with NUREG-0588 or the Guidelines for Evaluating Environmental Qualification of Class IE Electrical Equipment in Operating Reactors.
By {{letter dated|date=April 14, 1981|text=letter dated April 14, 1981}}, the licensee stated his intention to provide its NUREG-0588 submittal (for harsh environments) to the staff on or before October 1, 1981. Accordingly, the staff will conduct its review and complete the Environmental Qualification Safety Evaluation Report following receipt of the applicant 1 s submittal 3-29
 
3.12 REFERENCES*
American Concrete Institute:
ACI 318-63 Code ACI 318-71 Code American Institute of Steel Construction:
AISC Specification for Concrete and Steel Structures ASC Specification for the Design, Fabrication, and Erection of Structural Steel Buildings American Nuclear Society:
ANS-18.2 American Society of Civil Engineers ASCE Paper 3269 American Society of Mechanical Engineers:
ASME Boiler and Pressure Vessel Code Branch Technical Position:
BTP ASB 3-1 Coastal Engineering Research Center (U.S. Army)
CERC Shore Protection Manual, 1973 Code of Federal Reaulations:
10 CFR Part 50, Appendix 8 10 CFR Part 50, Section 50.55a 10 CFR Part 50, Part 100 10 CFR Part 50, Part 100, Appendix A CLI-80-21 Combustion Engineering Report:
CENP0-168 Louisiana Power & Light Report:
FSAR for Waterford 3 General Design Criteria:
GDC 1 GOC 4 GOC 10 GDC 14 GDC 15 GDC 16 GOC 27 GDC 50 Guidelines for Evaluating Environmental Equipment in Operating Reactors:
Qualification of Class IE Electrical
*See Appendix 8, Bibliography, for complete citations and availability statements.
3-30
 
Letters:
Letter  from  LP&L to NRC dated August 22, 1980*
Letter  from NRC to LP&L dated November 12, 1980*
Letter  from L. V. Maurin, to A. Schwencer, NRC, dated March 23, 1981*
Letter  LP&L  to NRC dated April 14, 1981*
Regulatory Guides:
RG 1.12 RG 1.13 RG 1.14 RG 1.20 RG 1.26 RG 1.27 RG 1.29 RG 1.48 RG 1.60 RG 1.61 RG 1. 67 RG 1.76 RG 1.102 RG 1.115 RG 1.117 Louisiana Power & Light Report:
FSAR for Waterford 3 USNRC Report:
NUREG-0588 NUREG-75/087 Welding Research Council Bulletin No. 107
*See Appendix A Chronology of Radiological Review, for complete citation and availability statement.
3-31
 
4 REACTOR
 
==4.1 INTRODUCTION==
 
Criterion 10 of the General Design Criteria requires that the reactor core and associated systems be designed to assure that specified acceptable fuel design limits are not exceeded during any condition of normal operation, including the effects of anticipated operational occurrences. The staff reviewed the informa tion provided in the Final Safety Analysis Report in support of the Waterford 3 reactor design. The staff evaluation is contained below.
The unit's nuclear steam supply system is supplied by Combustion Engineering and is designed to operate at a maximum core thermal output of 3560 megawatts, with sufficient margin to allow for transient operation and instrument error, without causing damage to the core and without exceeding the pressure settings of the safety valves in the coolant system.
The reactor will be cooled and moderated by light water at a pressure of 2250 pounds per square inch, absolute. The reactor coolant will contain soluble boron for neutron absorption. The concentration of the boron will be varied, as required, to control relatively slow reactivity changes, including the effects of fuel burnup. Additional boron, in the form of burnable poison rods, will be employed to establish the desired initial reactivity. Part-length control element assemblies may be used for axial power shaping, and full-length control element assemblies will be used for reactor shutdown.
The design of the Waterford 3 reactor is similar to that of the Arkansas Nuclear One, Unit 2 facility, Docket No. 50-368. The staff approved the latter plant for operation. Both of these facilities utilize the 16 x 16 fuel assembly.
4.2 FUEL SYSTEM DESIGN The objectives of the fuel system safety review are to provide assurance that (1) the fuel system is not damaged as a result of normal operation and anticipated operational occurrences, (2) fuel system damage is never so severe as to prevent control rod insertion when it is required, (3) the number of fuel rod failures is not underestimated for postulated accidents, and (4) coolability is always maintained. The staff has reviewed the information provided in the FSAR in support of the Waterford 3 reactor design to determine if these objectives have been met. The NRC evaluation is described below.
4.2.1 Description The Waterford 3 reactor core design is similar to that described in NRC SER's for the San Onofre Nuclear Generating Station, Units 2 and 3 (SONGS-2 & 3) and Arkansas Nuclear One, Unit 2 (AN0-2) facilities (NUREG-0712 and and 0308, respectively). The major difference between the core mechanical design of Waterford 3 and SONGS-2 & 3 is in the construction of the fuel rod spacer grids.
4-1
 
The Waterford 3 core is composed of 217 fuel assemblies of a 16 x 16 fuel rod array design. Each fuel assembly wi11 have 10 Zircaloy-4 fuel rod spacer grids and 1 Inconel-625 bottom spacer grid. The Waterford 3 core will employ a total of 91 control element assemblies (CEAs), of which 8 will contain only a part-length poison column.
4.2.2 Design Evaluation Evaluation of the CE 16 x 16 fuel mechanical design is based upon engineering analyses, tests, and in-reactor operating experience. In addition, the perform ance of the design will be subject to continuing surveillance of operating reactors by CE and licensees having CE NSSS facilities. These programs con tinually provide confirmatory and current design performance information.
4.2.2.1 Fuel Thermal Performance Analysis One of the major thermal analysis considerations reviewed by the staff is related to fuel densification. In its evaluation of the thermal performance of the reactor fuel, the staff assumes that densification of the uranium oxide fuel pellets may occur during irradiation in LWRs. Briefly stated, in-reactor densification (shrinkage) of oxide fuel pellets (1) may reduce gap conductance, and hence increase fuel temperatures, because of a decrease in pellet diameter; (2) may increase the linear heat generation rate because of the decrease in pellet length; and (3) may result in gaps in the fuel column as a result of pellet length decreases (these gaps produce local power spikes and sites for cladding creep collapse).
CE has conducted an extensive study of fuel densification and has developed a conservative time-dependent description of the densification process as described in the  CE topical report CENPD-118, 11 Densification of Combustion Engineering Fuel11
* NRC review of the densification model along with other general information on fuel densification is given in NUREG-0085.
The densification kinetics expression, along with data on fuel swelling, thermal expansion, fission gas release, fuel relocation, thermal conductivities, cladding creep, and other properties, have been combined in a detailed fuel performance evaluation model called FATES, which is presented in the CE topical report CENPD-139, 11 Fuel Evaluation Model". This model is used to calculate fuel temperature and stored energy, changes in linear thermal output, and augmentation (power spikes) factors. The staff has reviewed CENPD-139 and concluded that the fuel performance evaluation model was a generically accept able method of describing the fuel behavior, as discussed in the NRC safety evaluation that is bound into CENPD-139, and the staff concludes that this model is applicable to the Waterford 3 fuel.
However, the staff has recently questioned (NUREG-0418) the validity of fission gas release calculations in most fuel performance codes including FATES for burnups greater than 20 gigawatt days per metric ton (GWd/t). CE was informed of this concern, and NUREG-0418 provided a method of correcting gas release calculations for burnups greater than 20 GWd/t. Since there is no question of the adequacy of FATES for burnups below 20 GWd/t, the Waterford 3 calculations wi11 be acceptable for operation early in 1ife until the peak local burnup reaches 20 GWd/t. For burnups in excess of that value, FATES calculations 4-2
 
(and other affected analyses) will have to be redone using the correction method mentioned above or such modified methods that might be submitted by LP&L or CE and approved by NRC.
In Amendment Number 7 to the FSAR, LP&L has deferred resolution of the enhanced fission gas release issue. The staff will, accordingly, condition the Waterford 3 OL (in a like manner as done previously for AN0-2 and SONGS-2) to require resolu tion of this issue prior to the cycle in which the Waterford 3 core achieves a peak pellet exposure of 20 GWd/t.
4.2.2.2 Fuel Rod Pressure Criteria The staff requested that the Waterford 3 FSAR be revised to explicitly limit end-of-life (EOL) fuel rod pressures to values less than nominal primary coolant system pressure. Subsequently, LP&L has responded that such a design limit was not needed as a formal criterion because no adverse effect had been identi fied which has, as its threshold, the occurrence of a net internal pressure on the cladding.
NRC does not agree that this is an acceptable conclusion without explicit justification. From the staff's precedent-setting review (Letter, May 19, 1978) of another NSSS-vendor's safety analysis of operation with net positive fuel rod pressures, NRC recognizes the potential for (1) increased stored energy due to pellet-to-cladding gap opening during normal operation and (2) fuel rod ballooning during postulated accidents involving departure from nucleate boiling (DNB). The CE fuel performance code FATES has not been approved for use with net positive fuel rod pressures, and the effects (such as DNB propagation) of ballooning in postulated accidents, except LOCA, have not been analyzed for Waterford 3. Therefore, we believe that NRC's prior requests for an explicit FSAR limit that prohibits operation with fuel rod pressures that exceed primary coolant system pressure are justified.
Nevertheless, LP&L has submitted the results of a fuel rod pressure calculation that was performed with FATES as modified by the NRC burnup enhancement factor.
In this calculation the tolerances were biased to maximize the internal pressure.
The results were that the maximum peak internal rod pressure at 39.1 GWd/t rod average burnup will be less than nominal primary system pressure.
Therefore, the staff concludes that the LP&L fuel design satisfies NRC's rod pressure criterion. However, this analysis and staff approval are limited to a 39.1 GWd/t rod-average burnup. This burnup corresponds to an exposure that is beyond the presently intended three-batch fuel management scheme which will result in batch-average burnups of about 30 GWd/t with associated peak rod-average burnups of less than 39.1 GWd/t.
4.2.2.3 Cladding Collapse CE has written a computer code that calculates time-to-collapse of Zircaloy cladding in a PWR environment. This code is described in the CE report CENPD-187, 11 CEPAN Method of Analyzing Creep Collapse of Oval Cladding). 11 NRC has reviewed this code and found it acceptable as described in the staff safety evaluation, which is bound into (CENPD-187-A). The applicant has submitted time to-cladding-collapse calculations using the CEPAN code and conservative inputs 4-3
 
such as the worst-case combination of manufacturing tolerances, m1n1mum fill gas pressure, no fission gas release, and conservative flux and temperature histories. The results of this analysis showed that the minimum time-to-collapse is in excess of the design three-cycle lifetime of the fuel. NRC concludes, therefore, that the fuel rod cladding will not collapse and is acceptable in this regard.
4.2.2.4 Fretting Wear Mechanical tests to demonstrate the effects of flow-induced vibration and con sequent fatigue, fretting, and corrosion have been performed on 4 x 4 test assemblies and on full-sized 14 x 14, 15 x 15, and 16 x 16 fuel assemblies.
In general, these tests adequately demonstrate that the effects of flow-induced vibration on the fuel rod are acceptable. However, a wear tendency that was not originally observed in the above-described flow tests has been found (for example, see Letters, Dec. 23, 1977; Feb. 14, 1978; Feb. 17, 1978) in irradiated fuel assemblies taken from operating reactors. These inspections detected unexpected degradation of guide tubes that are under control element assemblies.
Coolant turbulence was responsible for inducing vibratory motions in the normally fully withdrawn CEAs and, when these vibrating control rods were in contact with the inner surface of the guide tubes, a wearing of the guide tube wall has taken place. Significant wear has been found to be limited to the relatively soft Zircaloy-4 guide tube because the Inconel-625 cladding on the control rods provides a relatively hard wear surface. The extent of the observed wear has appeared to be plant dependent, but has in some cases extended completely through the tube wall.
As a solution to this problem, LP&L will use two permanent and one temporary hardware modifications in the Waterford 3 core. First, permanent flow channel extensions will be placed on the lowermost portion of the 87 upper guide tube structures that accommodate 5-element CEAs. These extensions will extend to the bottom of the fuel alignment plate and thereby minimize flow turbulence near the control rods by isolating the interior of the control rod shroud from much of the flow exiting the fuel assembly. This design alteration leads to a configuration similar to that in the older CE NSSS plants that use 14 x 14 fuel assembly designs. Also, nearly identical modifications were made to other CE NSSS plants that use the 16 x 16 fuel assembly design (that is, AN0-2 and SONGS-2 & 3).
The second permanent modification consists of placing flow bypass inserts in the lowermost portion of the cores's four upper guide structures that accommodate four-element CEAs. The function of these inserts is the same as that of the flow channe1 extensions, namely to divert a portion of the fuel assembly flow directly to the outlet plenum, thus away from control rods and the CEA shroud cavities.
The third modification is the attachment of sleeve inserts to the interior of the uppermost portions of fuel assembly guide tubes. These sleeve inserts are chrome-plated, stainless-steel inserts that are mechanically attached to guide tubes that are to reside under CEA banks. The function of the sleeve inserts is not to eliminate CEA vibratory motion, but rather to protect the guide tubes by providing relatively fretting resistant barriers.
The staff concludes that the three hardware modifications described above are potentially effective methods of mitigating guide tube wear. With regard to 4-4
 
the first modification, NRC has previously approved the addition of flow channel extensions in AN0-2 and SONGS-2 & 3. The Waterford 3 flow channel extensions are conceptually and dimensionally similar to those previously approved.
The staff regards the second modification as an innovative design change that is similar in concept to the other modification inasmuch as its use should result in less flow-induced control rod vibration due to the additional shielding and flow diversion. NRC has previously approved the addition of flow bypass inserts in SONGS-2 & 3. Should the performance of this modified design not be as satis factory as anticipated, the overall effect on core performance should be insigni ficant because of the limited application of this modified design and its employ ment only in core periphery locations. Confidence in the potential effectiveness of both of these designs has been demonstrated in two separate 250-hr out-of-pile flow tests of full-sized 16 x 16 fuel assemblies.
Finally, the staff has previously concluded on other plants that the use of sleeve inserts is an acceptable means of mitigating guide tube wear and does not produce undesirable changes in the fuel assembly structural properties.
In addition, confirmatory CEA scram testing has not revealed any significant occurrences where the use of sleeve inserts produced unacceptable scram times.
NRC's previous approvals for use of sleeve inserts in CE plants were for Calvert Cliffs-1 & 2, Millstone-2, AN0-2, St. Lucie-1, and SONGS-2 & 3.
Should LP&L desire to discontinue the use of sleeve inserts for future cycles of Waterford 3, the justification should include guide tube wear measurements taken on previously rodded, unsleeved fuel assemblies that were discharged from SONGS, AN0-2, or a similar plant.
4.2.2.5 Waterlogging The staff has reviewed the safety aspects of waterlogging fuel rod failures.
NRC's survey (NUREG-0303) of available information included (1) the results of tests in the capsule driver core at the special power excursion reactor test (SPERT) facility and the Japanese nuclear safety research reactor (NSRR), and (2) observations of waterlogging failures in test and commercial reactors.
This survey indicated that the rupture of waterlogged fuel rods should not result in failure propagation or significant fuel assembly damage that would affect coolability of the fuel rod assembly. The Waterford 3 applicant has addressed the potential and consequences of operating with waterlogged fuel rods. The staff has 1
found the eva1uation, as presented in the FSAR, to be in agreement with NRC s independent evaiuation and, thus, to be acceptable.
4.2.2.6 Pellet/Cladding Interaction The CE 16 x 16 fuel rod design used in Waterford 3 incorporates features that, when compared with the older 14 x 14 design, reduce cladding strain from pellet/
cladding interaction (PCI). Based on the available experimental and commercial reactor data, these design features should result in a reduction or delay of pellet/cladding interaction failures to later in the fuel design life. Although the failure thresholds are probably lower at high burnup than at low burnup, the fuel duty is also less severe. There are presently no licensing requirements that deal with small-strain PCI failures.
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The effects of PCI have not been restricted solely to fuel rods, but have also been observed (CE report CEN-50) in burnable poison rods. In burnable poison rods, PCI has predominantly resulted in excessive axial growth of the rod, rather than perforation of the cladding wall. To reduce the potential for poison rod growth, CE has made several pertinent design modifications. These revisions consist of chamferred or tumbled pellets, reduced pellet length, increased rod prepressurization, and reduced plenum spring preload. The staff has reviewed these revisions and agree that they should significantly reduce PCI in poison rods.
4.2.2.7 Burnable Poison Rod Hydriding In the past, some CE burnable poison rods have experienced failures because of primary hydriding (CE report CEN-77) Subsequently, CE made changes to the poison rod design and manufacturing processes. The revisions included reduced pellet moisture limit and revised manufacturing processes aimed at reducing moisture ingress to the poison rod. NRC has approved (NUREG-0308) such modifications and agrees that they will reduce the potential for primary hydriding of burnable poison rods. No further failures of this kind have been reported.
: 4. 2. 2.8 Swelling and Rupture The NRC staff has been generically evaluating three materials models that are used in ECCS evaluations. Those models predict cladding rupture temperature, cladding burst strain, and fuel assembly flow blockage. The staff has (1) discussed the NRC evaluation with vendors and other industry representatives (Memorandum, Nov. 20, 1979) (2) published NUREG-0630; 11 Cladding Swelling and Rupture Models for LOCA Analysis, 11 and (3) required licensees to confirm that their operating reactors would continue to be in conformance with 10 CFR 50.46 if the NUREG-0630 models were substituted for the present materials models in their ECCS evaluations and certain other compensatory model changes were allowed (Letter, Nov. 9, 1979; Nov. 26, 1979).
Until NRC has completed its generic review and implemented new acceptance criteria for cladding models, the staff will require that the ECCS analyses in the FSAR be accompanied by supplemental calculations to be performed with the materials models of NUREG-0630. For these supplemental calculations only, the staff will accept other compensatory model changes that may not yet be approved by the NRC, but are consistent with the changes allowed for the confirmatory operating reactor calculations mentioned above.
By {{letter dated|date=June 12, 1981|text=letter dated June 12, 1981}}, LP&L responded to our request by subrogating and justifying the applicability of a previously submitted supplemental ECCS calculation. That calculation was submitted (i.e., response to NRC Question 231.34) on the SONGS-2 and 3 docket in satisfaction of the same request on the San Onofre OL application.
The San Onofre supplemental calculation utilized the heat-transfer portion of the proposed CE alternate ECCS evaluation model (CE letter, September 18, 1978) for the calculation of steam heat-transfer coefficients for locations at or above the maximum blockage plane. Other portions of the calculation used the approved CE ECCS evaluation model except for the substitution of input parameters that bounded those which would be predicted from the cladding rupture temperature, cladding burst strain, and flow blockage models of NUREG-0630. The calculation 4-6
 
was then performed for the limiting (with respect to peak cladding temperature) primary system break. The results demonstrated that the combination of limiting values of the NUREG-0630 materials models and the alternate evaluation models heat transfer model resulted in reduced peak cladding temperature (PRT) and peak locai oxidation (PLO) compared with those documented in the SONGS-2 and 3 FSAR.
The Waterford 3 and SONGS-2 and 3 facilities are all 3410 MWt plants with NSSS and fuel designs nearly identical. The only difference among the facilities that could influence ECCS performance is the larger Waterford containment, and hence a lower ECCS containment backpressure for Waterford. However, this dif ference is compensated by the lower peak linear heat rating for Waterford com pared with San Onofre (i.e., 13.4 versus 13.9 kW/ft). Consequently, the behavior of the PCT and PLO transients are similar to Waterford and San Onofre. Also, both facility FSARs predict cladding rupture at approximately the same temperature and time in the early reflood period with the PCT achieved during late reflood after the reflooding rate drops below one inch per second.
The staff agrees with LP&l as to the applicability of the San Onofre supplemental calculation to the Waterford OL application. We, therefore, conclude that the applicant has provided adequate supplemental ECCS calculations that indicate continued compliance with 10 CFR Section 50.46.
4.2.2.9 Seismic and LOCA Loadings An important aspect of the behavior of the reactor core during a LOCA is the calculation of the combined loads on the fuel because of blowdown forces and the SSE. ihe applicant has referenced the topical report CENPD-178, 11 Structural Analysis of Fuel Assemblies for Combined Seismic and Loss-of-Coolant Accident Loading, 11 which addresses this matter. As a result of the preliminary review (NUREG-0308) the staff concluded that CENP0-178 did not contain an adequate model for analyzing lateral loads on the fuel assembly nor did CENP0-178 present sufficient information on spacer grid tests.
Subsequently, LP&L provided a preliminary analysis (Letter, May 11, 1981) of the fuel assembly response to seismic-and-LOCA loads using the best available methodology. In this analysis, the fuel assembly spacer grid design is assumed to be that of the high impact design (HI0)-1 grid design, rather than that of the design which is presently specified in the Waterford 3 FSAR. The new HID-1 grid has a higher elastic limit strength to improve lateral resistance to seismic and LOCA loading conditions, and was approved for the SONGS-2 & 3 cores. Struc turally, substitution of the HID-1 grid design is an improvement.
The results from the preliminary seismic-and-LOCA loading analysis (Letter, May 11, 1981) show acceptable fuel assembly response. In addition, NRC has also examined (Interoffice correspondence, May 5, 1981) effects of model refine ments that will be incorporated into the generic methods that will be used for the final structural analysis. It is anticipated that the final analysis will predict that some fuel assemblies will have deformed grids; however, grid deformation is expected to be limited to fuel assemblies that are located on the core periphery. If deformed grids are predicted, an ECCS analysis with deformed grids will be submitted for NRC review along with the final structural analysis. In light of the low nuclear peaking in core peripheral assemblies, 4-7
 
the staff expects that this analysis will show that the ability of the Water-ford 3 core to meet the ECCS acceptance criteria of 10 CFR 50.46 is maintained.
On the basis of the NRC review, the staff expects that the final seismic-and-LOCA loading analysis will demonstrate compliance with the Standard Review Plan requirements. The applicant has agreed to perform this final analysis and submit the results to NRC in February 1982, and the Waterford 3 OL will be so conditioned.
Therefore, according to the plan of action (NUREG-0609) governing this issue, NRC finds the issue to be resolved for Waterford 3 because (1) a satisfactory analysis has been provided with the best available methodology and (2) a commit ment has been made to submit a reanalysis with approved generic methods.
4.2.2.10  Fuel Rod Growth The Waterford 3 FSAR references a CE topical report, CENP0-198, 11 Zircaloy Growth In-Reactor Dimensional Changes in Zircaloy-4 Fuel Assemblies, 11 in support of a discussion on the dimensional stability of Zircaloy. The staff has reviewed this topical report and its supplements (CENPD-198, Supplements 1 and 2), but NRC approval (Letter, August 21, 1979) was limited to an axially averaged fast neutron fluence of 4 x 10 2 1 n/cm2 , which corresponds to a maximum assembly exposure of 22.5 GWd/t. This is an exposure (1) above which CE has not reported data on its core components and (2) below the design exposures planned for Waterford 3.
Assurance of the acceptability of the Waterford 3 fuel design beyond an expo sure of 22.5 GWd/t will be available from the visual fuel assembly inspection program, which will be performed on six fuel assemblies during each of the first three outages. Thus any trend toward unanticipated growth or mechanical interference wiil be evident during inspection. In addition, during the first three refueling outages of AN0-2 (a plant whose fuel design was also based on the CENPD-198 methods), the length of the fuel assembly and peripheral fuel rods will be precisely measured in six assemblies (two from each fuel region) that have been extensively precharacterized (FSAR, Arkansas Power and Light Co., May 25, 1977). Thus, NRC staff will be able to compare the measured values with those calculated as the burnup progresses. If a nonconservative gap closure is observed, remedial action can be taken before safety is affected.
4.2.2.11 Fuel Rod Bowing Because fuel rod bowing in PWRs affects neutronic and thermal-hydraulic safety margins, LP&L is required to analyze the anticipated impact of rod bowing in Waterford 3. The consideration of both fuel and poison rod bowing in the 16 x 16 design was previously documented in the topicai report CENP0-225, "Fuel and Poison Rod Bowing 11 and the Waterford 3 FSAR references this report.
However, CENPD-225 will not be approved before November 1981. For interim acceptance of methods by which rod bowing analyses can be made, the staff has issued two reports (Memorandum, Dec. 8, 1976; Feb. 16, 1977) in which it has (1) given approval of a burnup-dependent approach to rod bowing, (2) presented a formulation to be used in extrapolating bow magnitudes to new designs (i.e.,
16 x 16), and (3) described a factor that increases the cold rod bow magnitudes (which are determined from cold-measured gap closures in spent fuel pools) to account for hot rod bow magnitudes that occur in-reactor during hot-operating conditions.
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In response to our questions, LP&L provided revised DNBR penalties due to fuel rod bowing. These penalties were derived with the staff-approved interim methods described above and are therefore based on acceptable bow magnitude predictions.
The thermal-hydraulic penalties will be described in Section 4.4 of the SER.
However, the mechanical input to this analysis (that is, the burnup-dependent rate of bowing) is acceptable. Hence, fuel rod bowing has been satisfactorily addressed.
4.2.2.12 Zircaloy Material Properties In the FSAR the use of unirradiated and irradiated values for Zircaloy-4 yield strength, ultimate strength, and uniform tensile strain was discussed. Because the referenced source (that is, CE Standard Safety Analysis Report, PSAR) did not (1) provide these property correlations as functions of service temperature and neutron fluence and (2) address annealed material that is used in the Waterford 3 core, NRC staff requested that LP&L provide the missing correlations and identify the calculations and the conservative manner in which the irradiated properties are used.
In response to NRC's request, LP&L stated that irradiated values are actually not used in design calculations for Zircaloy yield and ultimate strengths.
This method is conservative since irradiation would increase the allowable stresses. On the other hand, irradiation is included in non-beginning of life (BOL) calculations involving uniform tensile strain, since the allowable value would be conservatively reduced by irradiation. Furthermore, LP&L stated that the FSAR will be amended to correct the discussion on irradiated Zircaloy properties.
The staff has concluded that the Zircaloy property correlations submitted in response to NRC request appear reasonable; consequently, on the basis that the FSAR will be amended to correct the present discussion on irradiated Zircaloy properties, the staff concludes that LP&L has adequately adressed these concerns.
4.2.3 Testing, Inspection, and Surveillance Plans 4.2.3.l Testing and Inspection of New Fuel Testing and inspection plans for the new core components include verification of cladding integrity, fuel system dimensions, fuel enrichment, burnable poison concentration, and absorber composition. Details of the Waterford 3 testing and inspection programs are documented, referenced, and summarized in the FSAR.
Onsite inspection of new fuel and control assemblies after they have been deiivered to the plant is also described. These testing and inspection programs, which are similar to those for the previously approved SONGS-2 & 3 facilities, are comprehensive and thorough and, therefore, acceptable.
4.2.3.2 Fuel Surveillance CE has instituted a fuel surveillance program for the 16 x 16 fueled reactor core. This program is being conducted in AN0-2 and involves the irradiation of six standard 16 x 16 fuel assemblies--two in each fuel loading region. Each assembly includes a minimum of 50 precharacterized, removable rods. Interim examination of all remaining test assemblies will be conducted during the first three refueling outages.
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The staff concluded that the design-oriented surveillance program originally proposed by CE will adequately demonstrate the performance of the 16 x 16 fuel assembly if that program is supplemented with a more comprehensive, but less detailed, surveillance program at Waterford 3.
According to the SRP, a minimum acceptable supplemental program should include a qualitative visual examination of some discharged fuel assemblies after each refueling. Such a program should be sufficient to identify gross problems of structural integrity, fuel rod failure, fuel rod bowing, spacer grid strap damage, insufficient fuel rod shoulder gap spacing, or crud deposition. There should also be a commitment in the program to notify NRC and perform additional surveillance if unusual behavior is noticed in the visual examination or if the plant radiation process monitor indicates gross fuel failures.
In response to our request, LP&L has provided a supplemental surveillance program for Waterford 3. The program will consist of viewing the tops and sides of six fuel assemblies with an underwater TV camera or a periscope during each refueling outage. The inspections will concentrate on detecting gross fuel anomalies as discussed above. Furthermore, LP&L has agreed to (a) pursuing a more thorough investigation and (b) notifying NRC in the event that major abnormalities should be observed or detected by plant instrumentation.
Consequently, fuel surveillance has been satisfactorily addressed.
4.2.3.3 Control Element Assembly Surveillance Surveillance of a different kind is needed for the B 4C-filled control rods.
Although CE has previously had successful operating experience with this type of design, the staff believes that it is unwise to allow rods containing a water soluble poison to remain in the reactor coolant for their iifetime (years) with out ever checking their integrity or reactivity worth. Therefore, at NRC's request, the applicant submitted a control element assembly surveillance program for Waterford 3 that is similar to the program NRC approved for the SONGS-2 & 3 reactors. Although this program involves no additional testing, the staff finds that the planned CEA symmetry test described in Section 4.2.4.4 of the FSAR is adequate for detecting reactivity anomalies that would result from the loss of poison material. These low-power physics tests will be conducted prior to plant startup and at the beginning of each refueling cycle. The staff concludes that the above tests satisfy CEA testing and surveillance requirements.
4.2.3.4 Online Fuel Failure Monitoring In Section 9.3.4.2.2(n) of the FSAR, LP&L has described the process radiation monitor. A detector is located in the purification filter bypass line and provides a continuous signal to a ratemeter that is located in the main control room. The analyzer utilizes gamma-ray spectrometry to monitor gross gamma and specific fission product (i.e., high yield isotopes) gamma activity in the reactor coolant. The monitor is sensitive enough to detect the activity asso ciated wth less than 1% failed fuel and has sufficient range that it will not saturate. The applicant has stated that increasing trends in fission product activity will be interpreted as indications of fuel failures.
The staff concludes that the applicant's online fuel failure monitoring system and the intended use of the system are acceptable.
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4.2.4  Fuel Design Conclusions The staff concludes that the Waterford 3 plant has been designed so that (1) the fuel system will not be damaged as a result of normal operation and anticipated operational occurrences, (2) fuel damage during postulated accidents will not be so severe as to prevent control rod insertion when it is required, (3) the number of fuel rod failures will not be underestimated for postulated accidents, and (4) core coolability will always be maintained, even after severe postulated accidents. The applicant has provided sufficient evidence that these design objectives have been met based on operating experience, prototype testing, and analytical predictions. The applicant has also provided for testing and inspec tion of new fuel to ensure that it is within design tolerances. The staff con cludes that the applicant has met all the requirements of the applicable regulations, current regulatory positions, and good engineering practice.
All applicable requirements related to the reactor fuel are described in Sec tion 4.2, "Fuel System Design/' of the SRP. The applicable regulations and Regulatory Guides are: 10 CFR 50.46; 10 CFR 50 Appendix A (GDC 10); 10 CFR 50 Appendix K; Regulatory Guides 1.3; 1.4; 1.25; 1.77, and 1.126. Some of these requirements are satisfied in Chapter 15 of the FSAR rather than in Section 4.2.
4.3 NUCLEAR DESIGN The Waterford 3 power plant has a reactor core consisting of 217 fuel assemblies and 91 control element assemblies (CEAs). The core has a design heat output of 3390 thermal megawatts and is similar to the San Onofre 2 and 3 reactors.
The NRC reactor design review was based on information contained in the Final Safety Analysis Report (FSAR), amendments thereto, and the referenced topical reports. The review was conducted in accordance with the guidelines provided by the Standard Review Plan, Section 4.3.
4.3.1 Design Bases Design bases are presented which comply with the applicable General Design Criteria. Acceptable fuel design limits are specified (GDC 10), a negative prompt feedback coefficient is specified (GDC 11), and tendency toward diver gent operation (power oscillation) is not permitted (GDC 12). Design bases are presented requiring a control and monitoring system (GDC 13) that automati cally initiates a rapid reactivity insertion to prevent exceeding fuel design limits in normal operation or anticipated transients (GOC 20). The control system is required to be designed so that a single malfunction or single operator error will cause no violation of fuel design limits (GDC 25). A reactor coolant boration system is provided which is capable of bringing the reactor to cold shutdown conditions (GDC 26), and the control system is required to control reactivity changes during accident conditions when combined with the engineered safety features (GDC 27). Reactivity accident conditions are required to be limited so that no damage to the reactor coolant system boundary occurs (GDC 28).
The staff finds the design basis presented in the FSAR to be acceptable.
4.3.2 Design Description The FSAR contains the description of the first cycle fuel loading which consists of three different enrichments and has a first cycle length of approximately 4-11
 
one year. Fuel enrichment and burnable poison distributions are shown. Assembly enrichments, core burnup, critical solution boron concentrations and worths, and plutonium buildup are also presented. Values presented for the delayed neutron fraction and prompt neutron lifetime at beginning and end of cycle are consistent with those normally used and are acceptable.
4.3.2.1 Power Distribution The design bases affecting power distribution are:
(1) The peaking factor in the core will not be greater than 2.28 during normal operation at full power in order to meet the initial conditions assumed in the LOCA analysis.
(2) Under normal conditions (including maximum overpower) the peak fuel power will not produce fuel centerline melting.
(3) The core will not operate during normal operation or anticipated operational occurrences, with a power distribution that will cause the departure from nucleate boiling ratio to fall below 1.19 (using the CE-1 DNBR correlation).
The applicant will employ a reactor monitoring system, designated the core operating limit supervisory system (COLSS), to continuously monitor important reactor characteristics and establish margins to operating limits. This system, which consists of software executed on the plant computer, will utilize the output of the incore detector system to synthesize the core average axial power distribution. Rod positions taken from the control rod position indication system, together with precalculated radial peaking factors, will be used to construct axially dependent, radial power distributions. By using this infor mation, together with measured primary coolant flow, pressure, and temperature, the COLSS will establish the margin to the operating limits on maximum linear heat generation rate and minimum DNB ratio. The system will also monitor azimuthal flux tilt and total power level and wi11 generate an alarm if any of these limits is exceeded. The margins to all of these limits except azimuthal tilt are continuously displayed to the operators; the tilt can be displayed at the request of the operator. The operator will monitor these margins and take corrective action if the limits are approached. These actions include improv ing the power distribution by moving full-length or part-length rods, reducing power, or changing thermal-hydraulic conditions, that is, coolant inlet temperature and primary system pressure.
A description of the COLSS algorithms and an uncertainty analysis of the calcu lations performed by the COLSS are presented in CE topical report CENPD-169-P, 11 COLSS--Assessment of the Accuracy of PWR Operating Limits as Determined by the Core Operating Limit Supervisory Systems." The staff has reviewed this report and concludes that the methods employed in the COLSS to determine power distributions are acceptable. The axial power distribution synthesis methods are the same as those used at existing CE plants for periodic processing of incore detector data. Similarly, the use of precalculated information to determine radial peaking factors is consistent with the approach now used to establish monitoring limits on existing reactors.
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4.3.2.2 Reactivity Coefficients The reactivity coefficients are expressions of the effect on core reactivity of changes in such core conditions as power, fuel and moderator temperature, moderator density, and boron concentration. These coefficients vary with fuel burnup and power level. The applicant has presented calculated values of the coefficients in the FSAR and has also evaluated the accuracy of these calcula tions. The staff has reviewed the calculated values of reactivity coefficients and has concluded that they adequately represent the full range of expected values. Having reviewed the reactivity coefficients used in the transient and accident analyses, the staff concludes that they conservatively bound the expected values, including uncertainties. Further, moderator and power Doppler coefficients along with boron worth are measured as part of the startup physics testing to assure that actual values are within those used in these analyses.
4.3.2.3 Control To allow for changes of reactivity due to reactor heatup, changes in operating conditions, fuel burnup, and fission product buildup, a significant amount of excess reactivity will be built into the core. The applicant has provided sufficient information relating to core reactivity balance for the first core and has shown that means are incorporated into the design to control excess reactivity at all times.
Control of both excess reactivity and power level will be achieved with movable CEAs and through the variation of boron concentration in the reactor coolant.
In addition, the chemical and volume control system (CVCS) will be capable of shutting down the reactor by adding soluble boron poison and maintaining the reactor at least 5% subcritical when refueling. The combination of control systems satisfies the requirement of GDC 26.
The plant will be operated at steady-state full power with only one bank of the full-length CEAs slightly inserted. Limited insertion of the full-length control rods will permit compensating for fast reactivity changes (e.g., that required for power level changes and for the effects of minor variations in moderator temperature and boron concentrations) without impairing shutdown capability.
Rod insertion will be controlled by the power-dependent insertion limits that will be given in the technical specifications. These limits will (1) ensure that there is sufficient negative reactivity available to permit the rapid shut down of the reactor with ample margin and (2) ensure that the worth of a control rod that might be ejected in the uniikeiy event of an ejected rod accident will be no worse than that assumed in the accident analysis.
Soluble boron poison will be used to compensate for slow reactivity changes including those associated with fuel burnup, changes in xenon and samarium concentration, buildup for long-life fission products, burnable poison rod depletion, and the large moderator temperature change from cold shutdown to hot standby. The soluble boron poison system wi11 provide the capability to take the reactor at ieast 10% subcritical in the cold shutdown condition.
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The staff has reviewed the calculated rod worths and the uncertainties in these worths, based upon appropriate comparison of calculations with experiments.
On the basis of NRC review, the staff has concluded that the applicant 1 s assessment of reactivity control is suitably conservative, and that adequate negative reactivity worth has been provided by the control system to assure shutdown capability, assuming that the most reactive CEA is stuck in the fully withdrawn position. The staff has concluded that the CEA and soluble boron worths are acceptable for use in the accident analysis.
4.3.2.4 Stability The stability of the reactor to xenon-induced power distribution oscillations and the control of such transients have been discussed by the applicant. Because of the negative power coefficient, the reactor is inherently stable to oscilla tions in total reactor power.
The core may be unstable to axial oscillations during the first cycle. The applicant has provided sufficient information to show that axial oscillations will be detected and controlled before any safety limits are reached, thus preventing any fuel damage. The applicant also concluded that the core will be stable to both radial and azimuthal xenon oscillations throughout core life based on analysis. This conclusion is verified by measurements on an operat ing reactor, Maine Yankee, in which the predicted damping factor agreed well with the measured value. The staff concurs with this conclusion.
4.3.2.5 Vessel Irradiation Maximum fast neutron fluxes greater than 1 MeV incident on the vessel and shroud inside diameters are presented. For reactor operation at the full power rating and an 80% capacity factor, the calculated vessel fluence greater than 1 MeV at the vessel wall does not exceed 3.68 x 10 19 n/cm2 over the 40-yr design life of the vessel. The calculated exposure includes a 10% uncertainty factor.
The staff concludes that the vessel fluence is acceptable because it is less than the 10 2 0 n/cm2 criteria given in the SRP.
4.3.2.6 Criticality of Fuel Assemblies Criticality of fuel assemblies outside the reactor is precluded by adequate design of fuel transfer and storage facilities. The applicant has presented information on calculational techniques and assumptions in Section 9.1 of the FSAR that were used to assure that criticality is avoided. The staff has reviewed this information and the criteria to be employed and finds them to be acceptable.
4.3.3 Analytical Methods The applicant has described the computer programs and calculational techniques used to calculate the nuclear characteristics of the reactor design and has pro vided examples to demonstrate the ability of these methods to predict experi mental results. The staff concludes that the information presented adequately demonstrates the ability of these analytical methods to calculate the reactor physics characteristics of the Waterford 3 core.
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4.3.4 Summary of Evaluation Findings, Nuclear Design To allow for changes of reactivity due to reactor heatup, changes in operating conditions, fuel burnup, and fission product buildup, a significant amount of excess reactivity is designed into the core. The applicant has provided sub stantial information relating to core reactivity balances for the first cycle and has shown that means have been incorporated into the design to control excess reactivity at all times. The applicant has shown that sufficient con trol rod worth is available to shut down the reactor with at least a 1.0% k/k subcritical margin in the hot condition at any time during the cycle with the most reactive control rod stuck in the fully withdrawn position.
On the basis of NRC review, the staff concludes that the applicant 1 s assessment of reactivity control requirements over the first core cycle is suitably conser vative, and that negative worth has been provided by the control system to assure shutdown capability. Reactivity control requirements will be reviewed for additional cycles as this information becomes available. The staff also con cludes that nuclear design bases, features, and limits have been established in conformance with the requirements of GDC 10, 11, 12, 13, 20, 25, 26, 27, and 28.
The applicant has described the computer programs and calculational techniques used to predict the nuclear characteristics of the reactor design and has pro vided examples to demonstrate the ability of these methods to predict experi mental results. The staff concludes that the information presented adequately demonstrates the ability of these analyses to accurately predict reactivity and physics characteristics of the Waterford 3 plant.
4.4 THERMAL-HYDRAULIC DESIGN 4.4.l Thermal-Hydraulic Design Criteria and Design Bases The principal thermal-hydraulic design basis for the Waterford 3 core is to prevent thermal-hydraulic induced fuel damage during normal steady-state operation and anticipated operational transients. The prevention of departure from nucleate boiling (DNB) and of hydrodynamic instability will ensure that this design basis is satisfied.
The margin to DNB at any point in the core is expressed in terms of the DNB ratio. The DNB ratio is defined as the ratio of the heat flux required to produce DNB at the calculated local conditions to the actual local heat flux.
The thermal-hydraulic design basis in the Waterford 3 FSAR Section 4.4.1.1 for the DNB ratio is as follows:
The minimum DNBR (departure from nucleate boiling ratio) shall be such as to provide at least a 95% probability with 95% confidence that departure from nucleate boiling (DNB) does not occur on a fuel rod having that minimum DNBR during steady-state operation and anticipated operational occurrences.
The hydrodynamic stability design basis in the Waterford 3 FSAR Section 4.4.1.2 is as follows:
Operating conditions shall not lead to flow instability during steady state operation and during anticipated operational occurrences.
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The correlation used to determine the DNBR is the CE-1 critical heat flux correlation. The CE-1 correlation is described in the CE Topical Report CENPD-162-P-A, "Critical Heat Flux Correlation for CE Fuel Assemblies With Standard Spacer Grids, Part 1 Uniform Axial Power Distribution. 11 The report also describes the Combustion Engineering test program. The tests were con ducted with 4 x 4 and 5 x 5 electrically heated rod bundles representative of 14 x 14 and 16 x 16 CE fuel assemblies. Based on these tests, CE originally proposed a minimum DNB ratio of 1.13. The staff review of the uniform axial heat flux test data concluded that the design limit DNBR based on the test data for 16 x 16 fuel should be 1.19.
The DNB program was extended by CE to include axially nonuniform heat flux data.
The CE-1 critical heat flux correlation was modified to include the Tong F-Factor to account for the nonuniform heat flux. The test results and the modified form of the CE-1 correlation are documented in CENPD-207.
The staff has reviewed the CE-1 correlation, the uniform and non-uniform axial heat flux test programs and the proposed DNBR limit of 1.19. Originally Combus tion Engineering used 731 data points from test bundles simulating 14 x 14 and 16 x 16 fuel assemblies. Based on these data points CE proposed DNBR limit of 1.13 for the CE-1 correlation. The staff has independently evaluated the CE-1 correlation using the COBRA IV computer code. Our statistical analysis of the measured to predicted critical heat flux (CHF) ratios has shown that the data from the tests simulating 16 x 16 fuel assemblies and the rest of the data do not belong to the same population. Thus, it is inappropriate to mix these data.
The test bundle that is more representative of a 16x16 fuel assembly has a DNBR limit of 1.19. Therefore, the staff has determined that the 1.19 DNBR limit for th CE 1 correlation is acceptable for those fuel assemblies having a grid spacing of 14.3 inches and using the CE standard grid design. However, in Amendment 18 to the FSAR, Waterford changed the grid design. Waterford is now using a High Impact Design-I (HID-1) grid rather than a CE standard grid.
Since the CE 1 CHF correlation was based on test data having grid spacings of 14.3 inches, 17.4 inches, and 18.25 inches and using CE standard grids, the staff requested that the applicant justify using the CE-1 correlation for the new Waterford fuel design. The applicant responded that the 15.7 inch grid spacing was bounded by the 14.3 inch and 17.4 inch data. Lacking test data on the Waterford 3 bundle geometry, the staff is not convinced by the above argument but agrees that the effects on CHF of the fuel design change, if any, should be small.
Combustion Engineering has recently submitted, on another docket (CEN-165-(s)-P),
information which is relevant to this evaluation. We will complete our review of this information by August 15, 1981, advise the applicant of the new DNBR limit (1.19 or otherwise) and report on the resolution of this issue in a supplement to this SER.
A significant parameter that influences the thermal-hydraulic design is rod-to-rod bowing within fuel assemblies. Presently, the staff1 1 is reviewing the Cf Topical Report, CENPD-225, 1 1 Fuel and Poison Rod Bowing, which describes the methodology for evaluating the effects of rod-to-rod bowing on DNB. Until NRC completes its review of CENPD-225, the staff will impose a DNBR penalty which was calculated using the staff 1 s interim criteria for evaluating the effects of rod bow on DNBR. Credit has been given for thermal margin due to a 4-16
 
multiplier of 1.05 on the hot enthalpy rise factor used to account for pitch reduction due to manufacturing tolerances. The resultant reduction in DNBR because of rod bow is given by:
Burnup              DNBR Penalty (MWD/MTU)                (%)
0                      0 2,400                      0 5,000                    3.0 10,000                    7.1 15,000                  10.3 20,000                  12.9 25,000                  15.3 30,000                  17.4 35,000                  19.4 40,000                  21.2 The applicant has stated that the thermal margin reduction shown above will be put in the basis of the Core Protection Calculator (CPC) system. They will be verified to be in the Core Operating Limits Supervisory System (COLSS) and the CPC system at least once per 31 days. Therefore, the appropriate provisions will be incorporated into the Technical Specifications. The applicant should a1so insert into the basis of the Technical Specifications any generic or plant specific margin that may be used to offset the reduction in DNBR due to rod bowing, and reference the source and staff approval of each generic margin.
With these requirements satisfied by the applicant the staff concludes that they have adequately accommodated the reductions listed above.
In steady-state, two-phase, heated flow in parallel channels, the potential for hydrodynamic instability exists. The applicant provided the following information to support the contention that the Waterford 3 core is thermal hydraulically stable. 11 Flow instabilities which have been observed occur almost exclusively in closed channel systems operating at low pressures relative to PWR pressures. 11 Dynamic flow tests performed on 4 x 4 fuel arrays and full-size fuel assemblies have shown that no adverse effects are expected on the perform ance of the fuel assembly due to flow-induced vibrations. Since crossflow resistance is extremely small among subchannels of the CE 16 x 16 fuel assembly, it would have a stabilizing effect. This has been confirmed by Veziroglu and Lee who found that crossflow between parallel heated channels enhances flow stability. Kao, Morgan, and Parker conducted flow stability experiments at pressures up to 2,200 psia with closed parallel heated channels. They found that at pressures above 1,200 psia for flow and power levels encountered in oower reactors, no flow oscillations could be induced.
The staff is presently conducting a generic study of the hydraulic stability characteristics of pressurized water reactors. Limitations to the thermal hydraulic design resulting from the staff study will be compensated for by appropriate operating restrictions; however, no operating restrictions are anticipated.
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In the interim, the staff concludes that past operating experience, flow stabil ity experiments, and the inherent thermal-hydraulic characteristics of CE PWRs provide a basis for accepting the Waterford 3 stability evaluation for issuance of an OL.
Crud depositions in the core and an associated change in core pressure drop and flow have been observed in some PWRs. In response to a staff question, the applicant stated that the effects of possible crud buildups have been accounted for in the Waterford 3 design in the form of an increase in the pressure drops used in the determination of design hydraulic loads. In addi tion, the core flow will be continuously monitored by the COLS$ using pump casing differentials and pump speed as input. Any reduction in the core flow due to crud deposits will be accounted for in the COLSS thermal margin assessment.
Based on this information the staff concludes that the applicant has adequately addressed NRC concerns relative to uniform or preferential crud deposits in the core. NRC will require that the technical specifications include the requirements that the actual reactor coolant system total flow rate be greater than or equal to the value indicated by the core protection calculator system (CPCS).
The applicant has provided a description of the loose parts monitoring system (LPMS) which will be used by Waterford 3. The design will include two sensors at each selected natural collection region. The system will be capable of detecting loose parts having an impact energy greater than or equal to 0.05 ft-lb.
The applicant has stated that the system will be designed to remain functional for a seismic event up to and including the OBE and will be qualified to operate in the normal service environment inside containment. Alarm settings will be established based on baseline data taken during startup testing at selected nominal power levels. The staff has evaluated the Waterford 3 LPMS by comparing it with the equipment and procedures used on other comparable plants, taking into account pertinent differences, and the criteria of Regulatory Guide 1.133.
Based on these comparisons, the staff concludes that the Waterford 3 LPMS is an acceptable system.
With regard to the CPCS, the staff requested that the applicant provide the following:
(1) A definition of software algorithm and data changes from previously approved CPC systems, giving the reason for changes and a definition of the change.
(2) A description of the conduct and results of Phase I and II implementation testing. The description will include test cases, test results, errors found in testing, and corrective action.
(3) The Software Functional Specifications upon which the Waterford 3 CPCSs are based.
(4) The data base constants used in the CPCS algorithms and the assumptions and methodology used in the data base design.
(5) Evaluation of the CPCS response to design basis transient events by com parison to safety analyses and to other versions of the CPCS software which have been previously evaluated by the staff.
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The applicant committed to suply items 1 and 2 by June, 1982 and orally committed to supply items 3, 4, and 5 by March, 1982. In order to provide reasonable time for the staff to complete its review of the CPCs by the fuel load date of October, 1982, the staff needs all of the requested information by at least March, 1982. CE has stated that June, 1982 is the earliest possible date for items (1) and (2) since the testing required to obtain this information would not be complete. The applicant is being urged to expedite the development of the CPC software in order to avoid possible startup delays due to inadequate review time or in event that software changes are required as a result of the review.
4.4.2 Thermal-Hydraulic Models The thermal-hydraulic design was performed using the TORC computer code. The TORC code, as described in CENP0-161, is used to analyze a specific three dimensional power distribution superimposed on an explicit core inlet flow dis tribution. This type of calculation is performed in three stages. The first stage is to calculate the coolant conditions on a corewide basis. In the second stage, the hot assembly is analyzed using input parameters obtained from the Stage 1 calculations. Finally, the third stage is to calculate the local condi tions and minimum DNBR by performing a subchannel analysis.
The design calculations for the Waterford 3 reactor were performed using the simplified TORC model discussed in CENPD-206-P. This method uses one limiting core radial power distribution for all the analyses; the hot assembly power is raised or lowered in order to obtain the proper maximum radial power factor; and all the assemblies except the hot assembly use the average mass velocity.
Since the hot assembly can occur anywhere in the reactor core, a reduction in the amount of inlet flow to the hot assembly may be required. The percent reduction for mass velocity is determined by comparison of results with the detailed procedure discussed above.
The staff has reviewed CENPD-161 and CENPD-206 and determined that the TORC computer code is an acceptable method for performing steady-state calculations of the reactor core thermal-hydraulic performance. The applications should be limited to conditions of single-phase flow or homogeneous two-phase flow. If the code is used for the analysis of flow blockage conditions, the blockage must be assumed to occur in the high power fuel assembly.
The Waterford 3 thermal-hydraulic design calculations were performed for fuel assemblies having one Inconel and eleven Zircaloy grids per fuel assembly.
The new fuel assemblies being used by Waterford have one Inconel and ten Zircaloy grids per assembly. The staff asked the applicant how this new design would affect diversion crossflow in the thermal-hydraulic analysis. The applicant responded that the HID-1 design would increase crossflow and turbulent mixing.
They also stated that the loss coefficients for the standard grids were used in the TORC analyses of the new fuel design. This would result in a more conser vative DNB analyses. The staff has reviewed this information and concludes that the applicant must either quantitatively demonstrate, by appropriate calcu lations, that the present DNB analyses are conservative or perform a new set of analyses using the loss coefficients and grid spacing which represent the existing fuel design.
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4.4.3 Thermal-Hydraulic Comparison The thermal-hydraulic design parameters for the Waterford 3 core are listed in Table 4.1. A comparison of these parameters with those of the AN0-2 initial design parameters is also included. The major differences are an increase in heat output, flow rate, and active heat transfer area for the Waterford 3 design.
However, the power density and coolant enthalpy rise across the two cores are comparable. The use of a different CHF correlation precludes a direct comparison of the initial design parameters. However, AN0-2 Cycle 2 uses modified thermal design procedures which are comparable to those of the Waterford 3 initial design.
The staff concludes that the Waterford 3 thermal-hydraulic design is comparable to that for AN0-2, which has previously been reviewed and found acceptable by the staff. Howevr, Regulatory Guide 1. 70, Standard Format and Content of Safety Analysis Reports, states that in Chapter 4 of the SAR:
11 * *
* the applicant should provide an evaluation and supporting information to establish the capability of the reactor to perform its safety functions throughout its design lifetime under all normal operation modes... 11 In our review of the AN0-2 Cycle 2 design the staff concluded that design methodology changes, including revisions to the CPC software, were necessary in order to achieve sufficient thermal margin for normal operation at full power during Cycle 2. Since all of the design methodology changes for AN0-2 Cycle 2 have not been included in the Waterford 3 CPC software, the staff requested the applicant to convincingly demonstrate that CPC software changes will not be required to provide sufficient thermal margin for operation in future cycles.
The applicant responded that the FSAR was submitted in support of the operating license for the first cycle.
Since the safety analyses did not consider future cycle power distributions and did not use the correct fuel design, the staff requires that the applicant perform new safety analyses which account for the above discrepancies. These analyses must be completed prior to the issuance of an OL.
4.4.4 Conclusion and Summary The thermal-hydraulic design of the core for the Waterford 3 plant has been reviewed. The scope of NRC review included the design basis and the steady state analysis of the core thermal-hydraulic performance. The review concen trated on the difference between the proposed design and those designs that have been previously reviewed and found acceptable by the staff. All such differences were satisfactorily justified by the applicant. The applicant 1 s thermal-hydraulic analyses were performed using analytical methods and corre lations which have been previously approved by the staff.
The staff also reviewed the applicant 1 s vibration and loose parts monitoring system (LPMS). The LPMS was evaluated by comparing it with systems from comparable plants, taking into account pertinent differences and the criteria of Regulatory Guide 1.133.
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Table 4.1 Reactor design comparison Thermal and hydraulic                                        AN0-2 design parameters (nominal)                    Waterford 3  (SER)
I. Performance characteristics:
Reactor core heat output (MWt)          3,390        2,815 System pressure (lb/in2 , absolute)      2,250        2,250 Minimum DNB ratio (full power)          2.07*        2.26**
Minimum DNB ratio                        1.19*        1.30**
II. Coolant flow:
Total flow rate (gal/min)                396,000      322,000 Average mass velocity along fuel rods (ft/sec)                          16.3          16.4 Average mass velocity (106 lb/hr/ft2 )  2.61          2.6 III. Coolant temperature, °F:
Nominal reactor inlet                    553          553.5 Nominal reactor outlet                  611          612.0 Nominal hot channel outlet              642          652 IV. Heat transfer, 100% power:
Active heat transfer surface area (ft2 )                            62,000        51,000 Average heat flux (Btu/hr/ft2 )          182,400      182,200 Maximum heat flux (Btu/hr/ft2 )          428,000      425,800 Average linear heat rate (kW/ft, based on heat deposited in fuel only)                                  5.34          5.34
*CE-1
**\v-3 4-21
 
Based on staff review and the design commitments provided by the applicant, the staff concludes that the thermal-hydraulic design of the Waterford 3 initial core conforms to the requirements of GDC 10, 10 CFR Part 50, the guidelines of Regulatory Guide 1.68, and SRP Section 4.4. NRC also concludes that the LPMS is designed for compliance with Regulatory Guide 1.133, and is therefore acceptable.
However, the applicant has stated that the safety analyses provided support only the first cycle of operation. Therefore, we cannot conclude, based on the analyses provided, that the reactor core is designed with appropriate margin to assure that specified acceptable fuel design limits are not exceeded for any condition of normal operation as is required by GDC 10, 10 CFR Part 50.
Specifically, the staff requires further analyses to support this conclusion for the Waterford fuel design with due consideration of power distributions now planned for future operating cycles (i.e. beyond the first cycle).
Prior to issuance of an OL, the staff will require resolution of the open issues which follow:
: 1. the applicability of the CE-1 CHF correlation and the proposed limit value to the Waterford-3 fuel design.
: 2. for the CPC system, the five information items previously enumerated, must be submitted by March, 1982, and,
: 3. the applicant must perform safety analyses which account for the new fuel design and power distributions in the future cycles.
These items will be addressed in a supplement to this report.
Finally, in Section 4.4.3.4 the applicant stated that operation at power with two or three pumps or one pump operating or while in natural circulation is not allowed. The staff will include in the technical specifications provisions to ensure that these types of operation are prohibited.
4.5 REACTOR MATERIALS 4.5.1 Control Rod Drive Structural Materials The staff concludes that the materials used for the construction of the control rod drive structure materials are acceptable and meet, in part, the requirements of GDC 1, 14, and 26 of Appendix A; and Section 50.55a of 10 CFR Part 50.
The applicant has met the requirements of GDC 1, 14, and 26 and Section 50.55a of 10 CFR Part 50 by assuring that the design, fabrication, and testing of the materials used in the control rod drive structural materials meet high quality standards, adequate for structural integrity.
The mechanical properties of structural materials selected by the applicant for the control rod system components of Waterford 3 that are exposed to the reactor coolant satisfy the stringent procurement specification requirements applied by the designer and conform with NRC 1 s position as stated in SRP Section 4.5.1 that the yield strength of cold worked austenitic stainless steel should not exceed 90,000 lb/in 2
* 4-22
 
The controls imposed upon the austenitic stainless steel of the mechanisms conform to the recommendations of Regulatory Guides 1.31, 11 Control of Ferrite Content in Stainless Steel Weld Metal , 11 and Regulatory Guide 1.44, 11 Control of the Use of Sensitized Stainless Steel.11 Fabrication and heat treatment practices performed in accordance with these recommendations provide added assurance that stress corrosion cracking (SCC) will not occur during the design life of the component. The compatibility of all materials used in the control rod system, in contact with the reactor coolant, satisfies the criteria of Articles NB-2160 and NB-3120 of Section III of the ASME Code. With one minor exception, both martensitic and precipitation-hardening stainless steels have been given tempering or aging treatments in accordance with NRC positions as stated in SRP Section 4.5.1.
Cleaning and cleanliness control have been performed to provide adequate con tamination control of components during fabrication, shipment, and storage.
The controls imposed upon the austenitic stainless steel of the system satisfy the requirements of the material specification. Most of the austenitic stainless steel materials are furnished in solution heat treated condition.
Sensitization is avoided by not permitting heat treatment in the temperature range of 800 to 1500° F. Fabrication and heat treatment practices performed as stated above provide added assurance that SCC will not occur during the design life of the components.
Conformance with the codes, standards, and Regulatory Guides indicated above, conformance with NRC positions on the allowable maximum yield strength of cold worked austenitic stainless steel, and generally the tempering or aging tempera tures of martensitic and precipitation-hardened stainless steel, constitute an acceptable basis for meeting the requirements of GDC 1, 14, and 26 of Appendix A, and Section 50.55a of 10 CFR Part 50.
4.5.2 Reactor Internals and Core Support Materials The staff concludes that the materials used for the construction of the reactor internals and core support are acceptable and meet, in part, the requirements of GDC 1 of Appendix A and Section 50.55a of 10 CFR Part 50.
The applicant has met the requirements of GDC 1 and Section 50.55a of 10 CFR Part 50 by assuring that the design, fabrication, and testing of the materials used in the reactor internals and core support structure are of high quality and adequate to maintain structural integrity. The controls imposed upon compo nents constructed of austenitic stainless steel satisfy the intent of the recommendations of Regulatory Guides 1.31 and 1.44.
The materials used for the construction of components of the reactor internals and core support structure have been identified by specification and found to be in accordance with the requirements of NG-2000 of Section III and Parts A, B, and C of Section II (or equivalent specification) of the ASME Code. As proven by extension tests and satisfactory performance the specified materials are compatible with the expected environment and corrosion is expected to be negligible.
The controls imposed on the reactor coolant chemistry provide reasonable assurance that the reactor internals and core support structure will be adequately protected 4-23
 
during operation from conditions that could lead to stress corrosion of the materials and loss of component integrity.
The material selection, fabrication practices, examination and testing procedures, and control practice performed in accordance with these recommendations provide reasonable assurance that the materials used for the reactor internals and core support structure will be in a metallurgical condition to preclude service deterioration. Conformance with requirements of the ASME Code and the recommen dations of the Regulatory Guides constitutes an acceptable basis for meeting the requirements of GDC 1 and Section 50.55a of 10 CFR Part 50.
4.6 FUNCTIONAL DESIGN OF REACTIVITY CONTROL SYSTEMS The functional design of the reactivity control systems for the facility have been reviewed to confirm that they meet the various reactivity control condi tions for all modes of operation. These are:
(1)  The capability to operate in the unrodded, critical, full-power mode throughout plant life; (2)  The capability to vary power level from full power to hot shutdown and assure control of power distributions within acceptable limits at any power level; (3)  The capability to shut down the reactor in a manner sufficient to mitigate the effects of postulated events discussed in Section 15 of this SER.
The reactivity control systems for the facility are the control element assembly drive system (CEADS), the safety injection system (SIS), and the eves.
The CEAOS contains magnetic jack control element drive mechanisms (CEDMs).
When electrical power is removed from the coils of the CEDM, the armature springs automatically cause the driving and holding latches to be withdrawn from the CEDM drive shaft, allowing insertion of the control element assemblies (CEAs) and the part-length CEAs by gravity. There are 83 full-length CEAs and 8 part length CEAs. The regulating CEA groups (full- and part-length) may be used to compensate for changes in reactivity associated with power level changes and power distribution, variations in moderator temperature, or changes in boron concentration. Refer to Sections 3.9.4 and 4.3.2.3 of this SER for further dis cussion of this feature. No reactivity credit toward shutdown margin is taken for the part-length CEA. The part-length CEAs contain a strong neutron absorber in the top 10% of their active length which on reactor trip offsets any positive reactivity insertion due to the shift in axial flux distribution between full and zero power. They also help control power distribution and suppress xenon-induced power oscillations.
The SIS is automatically actuated to inject borated water into the RCS upon receipt of a safety injection actuation signal (SIAS). The SIS pumps take suc tion from the refueling water storage pool (RWSP). The SIS is discussed further in Section 6.3 of this SER.
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The CVCS is designed to control slow or long-term reactivity changes such as that caused by fuel burnup or by variation in the xenon concentration result ing from changes in reactor power level. The eves is used to control reactivity by adjusting the dissolved boron concentration in the moderator. The boron concentration is controlled to obtain optimum CEA positioning, to compensate for reactivity changes associated with variations in coolant temperature, core burnup, xenon concentration, and to provide shutdown margin for maintenance and refueling operations or emergencies. A portion of the CVCS (the charging pumps, the boric acid pump discharge, and the boric acid makeup tanks) injects a high concentration boron solution into the RCS to help ensure plant shutdown in the event of an SIAS. The boric acid concentration in the RCS is controlled by the charging and letdown portions of the eves.
The CVCS can be used to maintain reactivity within the required bounds by means of the automatic makeup system which replaces minor coolant leakage without significantly changing the boron concentration in the RCS. Dilution of the RCS boron concentration is required to compensate for the reactivity losses occurring as a result of fuel and burnable poison depletion. This is accom plished by manual operation of the eves. The eves is discussed further in Section 9.3.3 of this SER.
The concentration of boron in the RCS is changed manually under the following operating conditions:
(1)    Startup--boron concentration decreased to compensate for moderator temper ature and power increase; (2)    Load follow--boron concentration increased or decreased to compensate for xenon transients following load changes; (3)    Fuel burnup--boron concentration decreased to compensate for burnup; and (4)    Cold shutdown--boron concentration increased to compensate for increased moderator density due to cooldown.
Soluble poison concentration is used to control slow operating reactivity changes. If necessary, CEA movement can also be used to accommodate such changes, but assembly insertion is used mainly to mitigate anticipated operational occurrences (the analysis assumes a single malfunction such as a stuck rod).
In either case, fuel design limits are not exceeded. The soluble poison control is capable of maintaining the core subcritical under conditions of cold shutdown which conforms to the requirements of GDC 26; 11 Reactivity Control System Redundancy and Capability."
Full-length CEAs are the primary shutdown mechanism for normal operation, accidents, and transients. They are inserted automatically in accident and transient conditions. Concentrated boric acid solution is injected by the SIS in the event of a LOCA, steam line break, loss of normal feedwater flow, steam generator tube rupture, or CEA ejection, thereby complying with GDC 20, 11 Protection System Functions,    which requires that automatic protective 11 systems be provided (1) to assure that specified acceptable fuel design limits are not exceeded and (2) to sense accident conditions and to initiate operation of systems and components important to safety.
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The ability of the full-length CEA to be fully inserted and the part-length CEA which are inserted in the core to have their position changed is tested every 31 days during power operation. At every refueling shutdown, each CEA is stepped over its entire range of movement, and drop tests are performed to demonstrate the ability of the assemblies to meet required drop times. The CEA design is such that a single failure will not result in loss of the protec tion system nor will a loss of redundancy occur as a result of removal of a channel or component from service. This is discussed further in Section 7.2 of this SER. The foregoing periodic testing, reliability, and redundancy conform to the requirements of GOC 21, 11 Protection System Reliability and Testability.11 Failure of electrical power to any control element drive mechanism will result in insertion of that assembly. Analysis of accidental withdrawal of a CEA was found to have acceptable results as discussed in Section 15 of this SER. This conforms to the requirements of GOC 23, 11 Protection System Failure Modes, 11 and GDC 25, 11 Protect ion System Requirements for Reactivity Control Malfunctions. 11 The reactivity control systems, including the addition of concentrated boric acid solution by the SIS, are capable of controlling all anticipated opera tional changes, transients, and accidents, except possibly the small-break LOCAs. For further information on the performance of the charging and berating portion of the eves with respect to small-break LOCAs, refer to Sections 6.3 and 15.3.3 of this SER. All accidents are calculated with the assumption that the most reactive CEA is stuck and cannot be inserted, which complies with the requirements of GDC 27, 11 Combined Reactivity Control Systems Capability.11 Compliance with the requirements of GOC 28, "Reactivity Limits, 11 is discussed in Section 4.3 and 15 of this SER.
Based on NRC review, the staff concludes that the reactivity control system functional design meets the requirements of GDC 21, 23, 25, 26, and 27 with respect to its reliability and testability, fail-safe design, malfunction protection design, redundancy and capability, and combined systems capability and is, therefore, acceptable.
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4.7  References*
American Society of Mechanical Engineers:
Boiler and Pressure Vessel ASME Code, Section II, Part A, 8, and C ASME Code, Section III, NB-2160 ASME Code, Section III, NB-3120 ASME Code, Section III, NB-2000 Code of Federal Regulations:
10 CFR Part 50 10 CFR Part 50, Appendix A 10 CFR Part 50, Appendix K 10 CFR Part 50, Section 50.55a 10 CFR Part 50. Section 50.46 Combustion Engineering Reports:
CEN-50 CEN-77(M)-P CENPD-118 CENPD-139-A CENPD-161 CENPD-162-P-A CENPD-169-P CENPD-178 CENPD-187-A CENPD-198 CENPD-198 (Supplement 1)
CENPD-198 (Supplement 2)
CENPD-206-P CENPD-207 CENPD-225 General Design Criteria:
GDC 1 GDC 10 GDC 11 GDC 12 GDC 13 GDC 14 GDC 20 GDC 21 GOC 23 GDC 25 GDC 26 GDC 27 GDC 28 Interoff correspondence from R. W. Macek, EG&G, to C. F. Obenchain, dated May 5, 1981
*See Appendix B, Bibliography, for complete citations and availability statements.
4-27
 
Letters:
Letter from A. E. Sherer, CE, to V. Stello, NRC, dated December 23, 1977 Letter from W. P. Johnson, MYAPCo, to V. Stello, NRC, Dated February 14, 1978 Letter from A. E. Lunduall, BG&E Co., to V. Stello, NRC dated February 17, 1978 Letter from J. F. Stolz, NRC to T. M. Anderson, W, dated May 19, 1978 Letter from R. L. Baer, NRC to A. E. Scherer, CE: dated August 21, 1979 Letter from D. G. Eisenhut, NRC, to All Operating Light Water Reactors, dated November 9, 1979 Letter from L. V. Maurin, LP&L, to R. L. Tedesco, NRC, dated May 11, 1981 Louisiana Power & Light Report:
FSAR Arkansas Nuclear One, Unit 2 Memoranda:
Memorandum from D. F. Ross and D. G. Eisenhut, NRC, to D. B. Vassallo and K. R. Goller, dated December 8, 1976 Memorandum from D. F. Rosee and D. G. Eisenhut, NRC, to D. B. Vassallo and K. R. Goller, dated February 16, 1977 Memorandum from R. P. Denise, NRC, to R. J. Mattson, dated November 20, 1979 Memorandum from H. R. Denton, NRC, to Commissioners, Dated November 26, 1979 Regulatory Guides:
RG 1.3 RG 1.4 RG 1.25 RG 1.31 RG 1.44 RG 1.68 RG 1.77 RG 1.126 RG 1.133 USNRC reports:
NUREG-75/087 NUREG-0885 NUREG-0303 NUREG-0308 NUREG-0308, Supplement 2 NUREG-0418 NUREG-0609 NUREG-0630 NUREG-0712 4-28
 
5 REACTOR COOLANT SYSTEM ANO CONNECTED SYSTEM 5.1
 
==SUMMARY==
DESCRIPTION The reactor in Waterford 3 is a pressurized water reactor (PWR) with two coolant loops. The reactor coolant system (RCS) circulates water in a closed cycle, removing heat from the reactor core and internals and transferring it to a secondary (steam generating) system. In a pressurized water reactor, the steam generators provide the interface between the reactor coolant (primary) system and the main steam (secondary) system. The steam generators are vertical U-tube heat exchangers in which heat is transferred from the reactor coolant to the main steam system. Reactor coolant is prevented from mixing with the secondary system by the steam generator tubes and the steam generator tube sheet, making the RCS a closed system thus forming a barrier to the release of radioactive materials from the core of the reactor to the containment building.
Major components of the reactor coolant system are the reactor vessel; two parallel heat transfer loops, each containing one steam generator and two reactor coolant pumps; a pressurizer connected to one of the reactor vessel outlet pipes; and associated piping. All components are located inside the containment building.
Effluent discharges from the pressurizer safety valves are condensed and cooled in the quench tank.
System pressure is controlled by the pressurizer, where steam and water are maintained in thermal equilibrium. Steam is formed by energizing immersion heaters in the pressurizer, or is condensed by the pressurizer spray to limit pressure variation caused by contraction or expansion of the reactor coolant.
The average temperature of the reactor coolant varies with power level and the fluid expands or contracts, changing the pressurizer water level.
The charging pumps and letdown control valves in the chemical and volume control system (CVCS) are used to maintain the programmed pressurizer water level. A continuous but variable letdown purification flow is maintained to keep the RCS chemistry within prescribed limits. Two charging nozzles and a letdown nozzle are provided on the reactor coolant piping for this operation. The charaina flow is also used to alter the boron concentration or correct the chemical content of the reactor coolant.
Other reactor coolant loop penetrations are the pressurizer surge line in one reactor vessel outlet pipe; the four safety injection inlet nozzles, one in each reactor vessel inlet pipe; one outlet nozzle to the shutdown cooling system in one reactor vessel outlet pipe; two pressurizer spray nozzles; vent and drain connections; and sample connections and instrument connections.
Overpressure protection for the reactor coolant pressure boundary is provided by two spring-loaded ASME Code safety valves connected to the top of the pressur izer. These valves discharge to the quench tank, where the steam is released under water to be condensed and cooled. If the steam discharge exceeds the 5-1
 
capacity of the quench tank, it is relieved to the containment atmosphere through a rupture disc.
Overpressure protection for the secondary side of the steam generators is provided by 18 spring-loaded ASME Code safety valves located in the main steam system upstream of the steam line isolation valves.
5.2 INTEGRITY OF REACTOR COOLANT PRESSURE BOUNDARY 5.2.1 Compliance With Codes and Code Cases 5.2.1.1 Compliance With 10 CFR Part 50, Section 50.55a The components of the RCPB as defined by the rules of 10 CFR Part 50, Section 50.55a, 11 Codes and Standards" have been properly classified in Table 5.2-1 of the FSAR as ASME Section III, Class 1 components for Waterford 3.
These components are designated Safety Class 1 (quality group A) in conformance with Regulatory Guide 1.26, 11 Quality Group Classifications and Standards for Water-, Steam-, and Radio-Waste-Containing Components of Nuclear Power Plants. 11 The ASME Section III Code editions and addenda used in the construction of these quality group A components are those that were required at the time of procure ment of the components or are, where appropriate, later editions or addenda to the Code to assure compliance with 10 CFR Part 50, Section 50.55a except for the following components identified in Table 5.2-1 of the FSAR. These components for Waterford 3 are: (1) reactor pressure vessel, (2) steam generators (primary side), (3) pressurizer, (4) reactor coolant pumps (5) reactor coolant system piping, and (6) valves (supplied by CE).
In addition to the quality group A components of the RCPB, certain components which meet the exclusion requirements of footnote 2 of the rule are classified Safety Class 2 (quality group B) in accordance with the guidance provided in Position C.l of Regulatory Guide 1.26 and are constructed as ASME Section III, Class 2, components.
The reactor pressure vessel, steam generators (primary side), and pressurizer are constructed to ASME Section III, Class 1, 1971 edition, "Rules for Construc tion of Nuclear Power Plant Components, 11 through the Summer 1971 addenda; in order to be in compliance with subsection (c)(2) of Section 50.55a these compo nents should be constructed to ASME Section III, 1971 edition, through the Summer 1972 addendum. The staff reviewed the differences in these Code addenda as applicable to these components and has identified no major differences, except with respect to fracture toughness testing requirements for materials which were extensively revised in the Summer i972 addendum to the Code. Staff bases for accepting these components with respect to fracture toughness testing requirements for materials are discussed in Section 5.3.1 of this SER.
The reactor coolant system piping is constructed to ASME Section III, Class l, 1971 edition, through the Winter 1971 addendum; in order to be in compliance with subsection (d)(2) of Section 50.55a this piping should be constructed to ASME Section III, 1971 edition, through the Summer 1973 addendum. The staff reviewed the differences in these Code addenda as applicable to the RCS piping and has identified no major differences except with respect to fracture toughness testing requirements for materials which were extensively revised in the Summer 5-2
 
1972 addenda to the Code. The bases for staff acceptance of the RCS p1p1ng with respect to fracture toughness testing requirements for materials are discussed in Section 5.3.1 of this SER.
The reactor coolant pumps are constructed to ASME Section III, Class 1, 1971 edition, through the Winter 1971 addendum; in order to be in compliance with subsection (e)(2) of Section 50.55a these components should be constructed to ASME Section III, 1971 edition, through the Winter 1972 addendum. The staff reviewed the differences in these Code addenda as applicable to the RCPs and has identified no major differences except with respect to fracture toughness testing requirements for materials which were extensively revised in the Summer 1972 addendum to the Code. Staff bases for acceptance of the RCPs with respect to fracture toughness testing requirements for materials are discussed in Section 5.3.1 of this SER.
Valves of the RCPB supplied by CE are constructed to ASME Section III, Class 1, 1971 edition, through the Summer 1972 addendum; in order to be in compliance with subsection (f)(2) of Section 50.55a these components should be constructed to ASME Section III, Class l, 1971 edition, through the Winter 1972 addendum.
The staff reviewed the differences in these Code addenda as applicable to valves of the RCPB and has identified no major differences except with respect to fracture toughness testing requirements for materials which were extensively revised in the Summer 1972 addendum to the Code. NRC bases for acceptance of the valves of the RCPB supplied by CE with respect to fracture toughness testing requirements for materials are discussed in Section 5.3.1 of this SER.
Except for the fracture toughness testing requirements for materials as applicable to the components of the RCPB identified above, the staff concludes that updating these components to meet the requirements of subsections (c)(2), (d)(3), (e)(2) and (f)(2) of 10 CFR Part 50, Section 50.55a, would not be compensated by an increase in the level of safety. Therefore, the staff finds that the ASME Code used in the construction of: (1) reactor pressure vessels, (2) steam generators (primary side), (3) pressurizer, (4) reactor coolant pumps, (5) reactor coolant system piping, and (6) valves (supplied by CE) is acceptable and provides adequate assurance of component quality.
The staff concludes that construction of the components of the RCPB in conformance with the appropriate ASME Code editions and addenda and the Commission's regula tions provides assurance that component quality is commensurate with the impor tance of the safety function of the RCPB and constitutes an acceptable basis for satisfying the requirements of GDC 1 and is, therefore, acceptable.
5.2.1.2 Applicable Code Cases The applicant has identified specific Code cases of ASME in Table 5.2-2 of the FSAR whose requirements have been applied in the construction of pressure retaining ASME Section III, Class 1, components within the RCPB (quality group A).
The staff has reviewed the Code cases in Table 5.2-2. The basis for acceptance in NRC review has been the Code cases found to be acceptable in Regulatory Guide l.8L "Code Case Acceptability-ASME Section III, Design and Fabrication,n and Regulatory Guide 1.85, 11 Code Case Acceptability-ASME Section III, Materials," and the Code cases previously found to be acceptable by the staff for plants similar to Water ford 3, before publication of the Regulatory Guides. The staff concludes that compliance with the requirements of these Code cases will result in a component 5-3
 
quality level commensurate with the importance of the safety function of the RCPB and constitutes an acceptable basis for satisfying the requirements of GDC 1 and is, therefore, acceptable.
5.2.2 Overpressurization Protection Overpressure protection of the primary coolant system is designed to accommodate both low and high temperature operation. High temperature overpressure protec tion is designed to limit transient pressures to below 110% of design pressure.
Low temperature overpressure protection is designed to prevent the RCS from exceeding 10 CFR Part 50, Appendix G, 11 Fracture Toughness, 11 limits.
5.2.2.1 High Temperature Overpressure Protection The high temperature overpressure protection system is designed to maintain secondary and primary operating pressures within 110% of design by means of 2 primary safety valves, 12 secondary safety valves, and the reactor protection system. The secondary safety valves are sized to pass a steam flow equivalent to a power level of 3,580 MWt, which is greater than the proposed licensed power level of 3,410 MWt. The reactor is designed to trip at an RCS pressure of 2,400 psia while the primary pressurizer safety valves are designed to lift at a pressure of 2,500 psia, which is system design pressure.
The design basis event for sizing the primary safety valves is loss of load with a delayed reactor trip. In the analysis provided, no credit is taken for letdown, charging, pressurizer spray, secondary bypass, or feedwater flow after turbine trip. At the onset of the transient, the RCS and main steam supply system (MSSS) are at the maximum rated output plus a 2% uncertainty. The moderator and Doppler coefficients used for the analysis maximize the pressure and power excursion.
Under the assumptions of this analysis, a low steam generator level trip set point would be reached at about the same time the high pressurizer trip setpoint is reached. The peak primary and secondary system pressures are limited to 110% of design pressures during the loss-of-load transient. SRP Section 5.2.2 states that the high pressure reactor trip or second safety grade scram signal, whichever occurs later, should be used for sizing the primary system safety valves. The staff requires the applicant to confirm that this criterion is met in sizing Waterford 3 safety valves. The staff will report the resolution of this item in a supplement to this SER.
Testing and inspection of the primary safety valves is governed by ASME Sec tion XI, Subsection IWV. The secondary safety valves are tested to verify set points during hot functional testing. Periodic inservice testing of the secondary valves will be defined in the technical specifications.
5.2.2.2 Low Temperature Overpressure Protection Overpressure protection of the RCS during low temperature conditions is provided by relief valves SI-486 and SI-487 located in the shutdown cooling system (SOCS) suction lines. An SOCS relief valve is a spring-loaded (bellows) liquid relief valve with a capacity of 3,004 gal/min at 430 psia with 10% accumulation. The most limiting transients calculated were an inadvertent safety injection actua tion (mass input) and an reactor coolant pump start when a positive steam 5-4
 
generator to reactor vessel AT exists (energy input). Calculations show that this relief system can mitigate these transients and prevent violation of 10 CFR Part 50, Appendix G.
System design criteria required by the staff include no credit for operator action for 10 min; the mitigating system must meet single active failure criteria; the system must be testable; the system must be able to withstand an operating basis earthquake (QBE); and the system must be capable of functioning following loss of offsite power. The applicant has met all the design criteria for NRC 1 s position on water solid overpressure protection.
In response to staff request, the applicant, in Amendment 17 to the FSAR, committed to provide the following:
(1) A technical specification shall be imposed to ensured the RCS is on the SOCS with all suction line valves open whenever the RCS temperature is below an appropriate temperature.
(2) A technical specification to prohibit actuation of a reactor coolant pump if the associated steam generator to RCS AT is greater than 100 ° F.
(3) The setpoint for automatic isolation of the SOCS will be raised to 700 psig or a pressure determined appropriate for Waterford 3.
(4) A technical specification to test the SOCS safety relief valves at intervals not to exceed 30 months shall be imposed.
The applicant stated that the relief valves (SI-486 and SI-487) for overpressure protection of the RCS during low temperature conditions have been designed to 1971 edition of ASME Code Section III, Winter 1973 addendum and each relief valve was sized for transients due to simultaneous, inadvertent operation of three HPSI pumps and three charging pumps and pressurizer backup heater in operation. Since SIAS starts only two HPSI pumps, this resulted in a 20%
design margin for each relief valve. The staff finds the relief capacity for these relief valves sufficient to bound single phase discharge uncertainty and is therefore acceptable. Based on the above, the staff concludes that the design of the low temperature overpressure protection system is acceptable.
5.2.3 Reactor Coolant Pressure Boundary Materials 5.2.3.1 Material Specifications and Compatibility With Reactor Coolant The materials used for construction of components of the RCPB have been identified by specification and found to be in conformance with the require ments of Section III of the ASME Code.
The RCPB materials of construction that will be exposed to the reactor coolant have been identified and all of the materials are compatible with the expected environment, as proven by extensive testing and satisfactory performance.
General corrosion except for carbon and low-alloy steel will be negligible.
For these materials, conservative corrosion allowances have been provided for all exposed surfaces of carbon and low-alloy steel in accordance with the requirements of the ASME Code, Section III. Mostly reflective metallic insula tion is used in the RCPB. The nonmetallic insulation materials that are used 5-5
 
are consistent with the recommendations of Regulatory Guide 1.36,  11 Nonmetallic Thermal Insulation for Austenitic Stainless Steels.fl Further protection against corrosion problems will be provided by control of the chemical environment. The composition of the reactor coolant will be controlled, and the proposed maximum contaminant levels, as well as the proposed pH, hydrogen overpressure, and boric acid concentrations, have been shown by tests and service experience to be adequate to protect against corrosion and stress corrosion problems.
The controls imposed on reactor coolant chemistry are in conformance with the recommendations of Regulatory Guide 1.44, Control of Sensitized Stainless Steel/'
11 and provide reasonable assurance that the RCPB components will be adequately protected during operation from contaminating conditions that could lead to stress corrosion of the materials and loss of structural integrity of a component.
The instrumentation and sampling provisions for monitoring reactor coolant water chemistry provide adequate capability to detect significant changes on a timely basis. The use of materials of proven performance and conformance with the recommendations of the Regulatory Guides constitutes an acceptable basis for satisfying the requirements of GDC 1, 30, 4, and 14.
5.2.3.2 Fabrication and Processing of Ferritic Materials Fracture toughness of the components of ferritic materials in the RCPB is covered in Section 5.3.1 of this SER.
Welding of all components of ferritic steels in the RCPB was performed in accordance with the provisions of the ASME Code, Sections III and IX. This compliance with the Code provides reasonable assurance that cracking of compo nents made from ferritic steels will not occur during fabrication.
The controls imposed on preheat temperature during welding of low-alloy steels satisfy the recommendations of Regulatory Guide 1.50, 11 Control of Preheat Temperature for Welding of Low-Alloy Steel.fl The controls imposed during weld cladding low-alloy steel components with austenitic stainless steel conform with the major recommendations of Regulatory Guide 1.43, Control of Stainless 11 Steel Weld Cladding Low-Alloy Steel Components. 11 The controls consists of limited use of SA-508, Class 2, forging material and avoidance of high-heat-input weld cladding processes. Therefore, the purpose of the Regulatory Guide, namely, to limit the occurrence of underclad cracking, was achieved. Conformance with the recommendation of the two Regulatory Guides, as described above, provides additional assurance that cracking of components made from low-alloy steels, including underclad cracking, will not occur during fabrication, and that the possibility of subsequent cracking due to residual stress being retained in the weldment will be minimized.
Performance qualifications for personnel welding components of ferritic steels under conditions of limited accessibility were conducted and maintained in accordance with the applicable requirements of Sections III and IX of the ASME Code. A requalification was required when any of the essential variables of Section IX were changed or when authorized personnel had reason to question the ability of the welder to perform satisfactorily. Only the most highly 5-6
 
skilled personnel were assigned, production welding was monitored for comp1iance with procedure parameters, welding qualification requirements were certified, and weld quality was verified by nondestructive examination. In effect, the purpose of Regu 1 atory Guide 1. 71, 11 We 1 der Qua 1 ification for Areas of Limited Accessibility, 11 namely, production of sound welds, was achieved. The fabrica tion practices and examination procedures performed as stated above provide reasonable assurance that welds of ferritic steel components in the RCPB will be satisfactory in locations of restricted accessibility.
Conformance with the applicable provisions of the ASME Code and conformance with the recommendations of the Regulatory Guides, during welding of ferritic steel components of the RCPB, constitute an acceptable basis for meeting the requirements of GOC 1, 30, and 14.
5.2.3.3 Fabrication and Processing of Austenitic Stainless Steel Within the RCPB, no components of austenitic stainless steel have a yield strength exceeding 90,000 psi, in accordance with the NRC position as stated in Section 5.2.3 of the SRP.
The welding controls imposed upon components constructed of austenitic stainless steel and used in the RCPB satisfy the requirements of the ASME Code, Sections III and IX.
For NSSS components, welder qualification for welding austenitic stainless steel components under conditions of limited accessibility was the same as for welding ferritic steel components under these conditions, as described above. For field welding austenitic stainless steel piping joints in areas of limited accessibility, the major recommendations of Regulatory Guide 1. 71, 11 Welder Qualification for Areas of Limited Accessibility,' 1 were followed. This included radiographic examination of test weldments. Therefore, the purpose of Regulatory Guide 1.71 was achieved for both the NSSS components and the field welded piping joints.
Conformance with the major recommendations of Regulatory Guide 1.71 provides reasonable assurance that the welds of components of austenitic stainless steel in the RCPB at areas of limited accessibility will be satisfactory.
In order to preclude microfissuring in austenitic stainless steel welds in the RCPB, the major recommendations of the Interim Position then in effect for Regulatory Guide 1.31, 11 Control of Ferrite Content in Stainless Steel Weld Metal, 11 were followed for the NSSS components, and all of the recommendations of the Interim Position were met for components other than NSSS components. All weld filler meta1 was controlled to produce welds having at least 5% delta ferrite.
Subsequent to July 1978, the recommendations of Regulatory Guide 1.31, Revision 3, were followed primarily on erection work. Conformance with the major recommenda tions of the Interim Position for Regulatory Guide 1.31 (in effect during welding of the major RCPB components), including the requirement for 5% minimum delta ferrite content of production welds, provides reasonable assurance that no deleterious hot cracking will be present during the fabrication and assembly of austenitic stainless steel components.
The controls during fabrication, shipment, and storage of NSSS components of austenitic stainless steel to avoid sec by avoiding surface contaminants and sensitization were consistent with the recommendations of Regulatory Guide 1.44, 5-7
 
"Control of the Use of Sensitized Stainless Steel. The controls for austenitic 11 stainless steel components other than NSSS components followed the major recom mendations of Regulatory Guide 1.44, including steps to avoid contaminants during welding; procurement of solution annealed pipe, fittings, plate, forgings, and castings; obtaining 5% minimum delta ferrite in casting; and controlling welding heat to avoid sensitization during welding. Conformance with all of the above recommendations provides reasonable assurance that the austenitic stainless steel components of the RCPB will be free of contaminants and sensitization.
The quality of water used for final cleaning of flushing of finished surfaces during installation, and other requirements to prevent surface contamination, are in accordance with the recommendations of Regulatory Guide 1.37, "Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants.11 Materials selection, fabrication practices, examination procedures, cleaning procedures, and protection procedures performed in accordance with the applicable provisions of the ASME Code and in accordance with the recommendations of the RGs described in the preceding paragraphs provide reasonable assurance that the austenitic stainless steel in the RCPB will be free from cracking (micro fissures) and will be in a metallurgical condition (including freedom from sur face contaminants) which precludes susceptability to SCC in service. Conformance with the Code requirements and conformance with the RG recommendations constitute an acceptable basis for meeting the requirements of GOC 1, 14, and 30.
5.2.4 Reactor Coolant Pressure Boundary Inservice Inspection and Testing GOC 32, "Inspection of Reactor Coolant Pressure Boundary,u Appendix A of 10 CFR Part 50, requires, in part, that components which are part of the RCPB be designed to permit periodic inspection and testing of important areas and features to assess their structural and leaktight integrity.
To ensure that no deleterious defects develop during service, selected welds and weld heat-affected zones (HAZs) will be inspected before plant startup and periodically throughout the life of the plant. The applicant has stated that its inservice inspection (ISI) program will comply with the rules published in 10 CFR 50, Section 50.55a. The design of the RCS incorporates provisions for access for ISI in accordance with Section XI of the ASME Boiler and Pressure Vessel Code. The ISI program will consist of a preservice inspection plan and an ISI plan. The conduct of periodic inspections and leakage and hydrostatic testina of oressure-retaininq components of the RCPB in accordance with the requirements of Section XI of the* ASME Code provides reasonable assurance that evidence of structural degradation or loss of leaktight-integrity occurring during service will be detected in time to permit corrective action before the safety function of a component is compromised. Compliance with the ISis required by this Code constitutes an acceptable basis for satisfying in part the require ments of GDC 32.
Section 50.SSa(g), 10 CFR Part 50, defines the detailed requirements for the preservice and ISI programs for light-water-cooled nuclear power facility components. Based upon a CP date of November 14, 1974, this section of the CR requires that a preservice inspection program be developed and implemented using at least the edition and addenda of Section XI of the ASME Code in effect 5-8
 
6 months before this date. Also, the initial ISI program must comply with the requirements of Section XI of the ASME Code in effect no more than 12 months before the date of issuance of the OL, subject to the limitations and modifications listed in Section 50.55a(b) of 10 CFR Part 50.
NRC has not received a preservice inspection program from the applicant. Before the staff review and evaluation can be completed, a preservice inspection program must be submitted in accordance with the guidelines in Q 121.2 in the FSAR.
We will report on the resolution of this issue in a supplement to this SER.
5.2.5 Reactor Coolant Pressure Boundary Leakage Detection A limited amount of leakage is to be expected from components forming the RCPB.
Means are provided for detecting and identifying this leakage as practical in accordance with the requirements of GDC 30, "Quality of Reactor Coolant Pressure Boundary." Leakage is classified into two types--identified and unidentified.
Components such as valve stem packing, pump shaft seals, and flanges are not completely leak tight. Since this leakage is expected, it is considered identi fied leakage and is monitored, limited, and separated from other leakage (unidentified) by directing it to closed systems as identified in the guide lines of Position C.l of Regulatory Guide 1.45, 11 Reactor Coolant Pressure Boundary Leakage Detection Systems."
Sources, disposition, and indication of identified leakage are:
(1) Reactor coolant pump (RCP) seal leakage to the volume control tank is monitored in the main control room and alarms for high pressure, high flow, and high temperature in the controlled bleedoff lines are provided.
(2) Pressurizer safety valve and RCP bleed-off safety valve leakage to the quench tank is monitored in the main control room by temperature indicators and alarms on the pressurizer safety valve discharge line and the level and temperature indicator and alarm on the quench tank.
(3) Reactor vessel head closure leakage and RCP flange closure leakage are monitored for pressure increase which is alarmed in the control room.
Unidentified leakage, which includes steam generator tube or tube sheet and intersystem leakage, is monitored by several devices as identified in the guide lines of Positions C.2, C.3, and C.4 of Regulatory Guide 1.45. Steam generator tube ieakage is monitored by the condenser air vacuum pump exhaust radiation monitors, steam generator radiation monitors, or routine steam generator water samples. The method of detection of intersystem leakage depends on the particular interfacing system. Leakage of reactor coolant through the safety injection tank (SIT) check valves is detected by monitoring the tank water level and pres sure. These parameters are alarmed in the control room. Leakage of reactor coolant to the shutdown cooling system is detected via the shutdown cooling (SOC) relief valve discharge to the containment leak measuring tank. The resulting flow is recorded and alarmed in the control room. Leakage from the RCPB to the safety injection system is detected by pressure transmitters on the 1ow pressure side of the system check valves and is indicated and alarmed in the control room. Leakage past the hot leg injection check valves is detected by pressure transmitters and is indicated and alarmed in the control room.
5-9
 
Leakage from the SITs past the normally closed isolation valves is detected by low tank water level which is indicated and alarmed in the control room. Leakage of reactor coolant through the letdown heat exchanger and RCP seal heat exchanger and thermal barrier can be detected by any combination of the component cooling water system radiation detectors and the component cooling water surge tank level switches. High component cooling water radiation and high surge tank level are alarmed in the control room. In the event that leakage is alarmed and confirmed in a flowpath with no indicators, the staff will require that the technical specifications include that a water inventory material balance be begun within 1 hr to determine the extent of the leakage.
Indication of unidentified leakage from the RCPB into the containment is pro vided by two sources. The first is containment atmosphere radiation monitor indicators and alarms. The second is containment sump flow with its associated alarms. The containment atmosphere radiation monitor operates continuously to detect particulate, iodine, and gaseous radiation in the containment atmosphere.
The sensitivity of the containment atmosphere radiation monitor is such that leaks of 1 gal/min or less are detectab1e in less than 1 hr. The radiation monitors are seismic Category I, testable and may be calibrated as identified in the guidelines of Positions C.6, C.7, and C.8 of Regulatory Guide 1.45. If a break were to occur in the primary system, the resulting coolant flow would pass to the containment atmosphere providing airborne contamination or fall to the floor. Equipment and floor drains are routed to a measurement tank and from there to a containment sump. The measurement tank is equipped with a level transmitter. The level corresponds to the flow of water into the tank. An increase in flow of 1 gal/min above normal flow rates is alarmed in the control room. The sump flow measuring system is testable and can be calibrated as required. The sensitivity of these measuring systems meet the guidelines of Position C.5 of Regulatory Guide 1.45. Additional sources of indication of unidentified leakage include containment pressure, temperature, and humidity indicators, pressurizer level indicators, and LPSI header pressure.
Based on the above, the staff concludes that the RCPB leakage detection systems are diverse and provide reasonable assurance that primary system leakage (both identified and unidentified) will be detected and meets the requirements of GDC 30 with respect to provisions for RCPB leak detection and identification, and the guidelines of Regulatory Guide 1.45 with respect to RCPB leakage detection system design and are, therefore, acceptable.
5.3 REACTOR VESSEL 5.3.1 Reactor Vessel Materials GDC 31, 11 Fracture Prevention of Reactor Coolant Pressure Boundary, 11 Appendix A, 10 CFR Part 50, requires, in part, that the RCPB be designed with sufficient margin to ensure that, when stressed under operating, maintenance, and test conditions, the boundary behaves in a nonbrittle manner and the probability of rapidly propagating fracture is minimized. GOC 32, "Inspection of Reactor Coolant Pressure Boundary," Appendix A, 10 CFR Part 50, requires, in part, that the RCPB be designed to permit an appropriate material surveillance program for the reactor pressure vessel.
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The fracture toughness requirements for the ferritic materials of the RCPB are defined in Appendix G, Fracture Toughness Requirements, and Appendix H, 11                              11 "Reactor Vessel Material Surveillance Requirements," of 10 CFR Part 50.
The staff has reviewed the materials selection, toughness requirements, and extent of materials testing conducted by the applicant to provide assurance that the ferritic materials used for pressure-retaining components of the RCPB possess adequate toughness under operating, maintenance, testing and anticipated transient conditions.
The Waterford 3 reactor vessel, steam generators (primary side), and pressurizer were designed to the specifications of the 1971 edition of the ASME Boiler and Pressure Vessel Code (hereinafter, the Code 11 Section III, Rules for Construc 11        ),            11 tion of Nuclear Power Plant Components," including addenda through Summer 1971.
The RCPB piping, pumps, and valves were designed to the specifications of the 1971 edition of the Code, Section III, including addenda through Winter 1971.
Based on the November 1974 CP date, Section 50.55a, Codes and Standards, 11                    11 10 CFR Part 50 requires that the ASME Code editions and addenda applied to the pressure vessels be no earlier than those of the Summer 1972 addendum of the 1971 edition. Section 50.55a also requires that the ASME Code edition and addenda applied to the piping, pumps and valves that are part of the RCPB shall be no earlier than those of the Winter 1972 addendum of the 1971 edition.
The design and construction of the RCPB components of Waterford 3 are, therefore, not in compliance with the requirements of Section 50.55a, 10 CFR Part 50.
However, the staff will evaluate the applicant's RCPB materials to Appendix G of 10 CFR Part 50 which will ensure that material properties are equivalent or superior to those specified in Section 50.55a, 10 CFR Part 50.
5.3.1.1 Compliance With Appendix G, 10 CFR Part 50 Staff evaluation of the Waterford 3 FSAR to determine the degree of compliance with the fracture toughness requirements of Appendix G, 10 CFR Part 50, indicates that the applicant meets all the requirements of this appendix except for the specific requirements of paragraphs III.B.l, III.8.3, III.C.l, IV.A.l, IV.A.3 and IV.B. NRC evaluation of the areas of noncompliance follows.
Paragraph III.B.1 requires that the location and orientation of Charpy V-notch (CVN) impact test specimens comply with the requirements of paragraph NB-2322 of the ASHE Code. This paragraph of the Code specifies that the CVN impact test specimens for all plate and forging materials used for pressure-retaining parts of vessels, pumps, and valves sha11 be oriented in a direction normal (transverse) to the principal rolling or working direction. The Waterford 3 impact test qualification program does not conform to this requirement because longitudinally oriented CVN specimens were tested instead of transversely oriented CVN specimens. Evaluation of the Waterford 3 FSAR's conformance to the present requirements of paragraph III.B.l will be presented later in this SER section under the discussion of compliance to paragraph IV.A.I.
Paragraph III.8.3 requires that calibration of temperature instruments and CVN impact test machines comply with the requirements of paragraph NB-2360 of the ASME Code. Paragraph NB-2360 requires the calibration of temperature instruments 5-11
 
and impact machines every 3 months and 6 months, respectively. This requirement has been met in the impact testing of Waterford 3 RCPB piping, but not for the impact testing of the reactor vessel, steam generator, pressurizer, and RCP materials. The applicant has stated that these machines were calibrated in accordance with paragraph NB-4600. However, time intervals for calibration are not specified in paragraph NA-4600. The applicant must provide the time interval for calibration of the testing machines to demonstrate compliance with paragraph III.8.3.
Paragraph III.C.1 requires that CVN impact tests be conducted over a temperature range sufficient to define the CVN test curves for all reactor vessel be1tline material. Ferritic steel plates, weld metal, and heat-affected zones are the material located in the Waterford 3 reactor vessel beltline. The Waterford 3 FSAR report includes CVN impact test data for all plates, for one weld, and for one HAZ in the reactor vessel beltline.
In addition to CVN impact data, the applicant has indicated that the vessel beltline welds were fabricated using the submerged arc weld process with Linde 0091 flux and MIL B-4 wire and also the shielded metal arc weld process with E8018 electrodes.
Even though only one HAZ in the reactor vessel beltline has been CVN impact tested, the staff concludes, based on the weld processing identified by the applicant and other information and data reviewed by the staff, that the fracture toughness of post-weld heat treated ferritic HAZs in the Waterford 3 reactor vessel beltline region is equivalent or greater than that of the beltline plates.
Based on the conclusion that the base metal plates will be more limiting than the HAZ, an exemption from paragraph III.C.l requirements to CVN impact test Waterford 3 reactor vessel beltline HAZs is warranted.
Since only one weld in the reactor vessel beltline has been qualified by CVN impact testing, the applicant must provide additional information which will define the CVN impact curve for all other beltline welds.
Paragraph IV.A.1 requires that a reference temperature, RTNDT' be determined for each ferritic material of the RCPB and that this reference temperature be used as a basis for providing adequate margins of safety for reactor operation.
The value of RTNDT is defined in paragraph NB 2330 of the ASME Code as the higher of either (1) the nil ductility temperature, as determined by the drop weight test, or (2) a temperature of 60° F less than the temperature at which 50 ft-lb energy and 35 mils lateral expansion is achieved, as determined by the CVN impact test. CVN impact test specimens from plates and forgings are to be oriented in a direction normal (transverse) to the principal rolling or working direction.
The applicant has met the requirements of paragraph IV.A.1 for all ferritic RCPB materials except the following.
(1) SA-105 base metal used in RCPB applications in valve bonnets, pump covers (lower flange of drive mount), and surge nozzle forging; (2) SA-182 Type 403 and ASTM A-276 Type 440 material used in RCPB applications in lower control element drive mechanism housings and upper control element drive mechanism housings, respectively; 5-12
 
(3) All base metals used in the reactor vessel, the primary side of the steam generator, the pressurizer, and RCPB piping; (4) Weld metal outside the beltline region; and (5) HAZs outside the beltline region.
The applicant has not determined the RTNOT for SA-182 Type 403, ASTM A-276 Type 440 and SA-105 materials.
Either the applicant must supply the RTNDT for each of these materials or must demonstrate that the component is not limiting for operation per Appendix G of the ASME Code, 11 Protection Against Non-Ductile Failure."
All base metal used in the reactor vessel, the primary side of the steam generator, the pressurizer, and RCPB piping were CVN impact tested with specimens oriented in the longitudinal direction rather than the transverse direction. To compensate for the effect of directionality, the applicant has estimated the temperature at which 50 ft-lb energy and 35 mils lateral expan sion would be achieved if transversely oriented specimens had been tested.
If the minimum absorbed energy of three longitudinally oriented CVN impact specimens was less than 30 ft-lb, the temperature at which 50 ft-lb and 35 mils would occur for transversely oriented specimens was estimate from lower bound CVN impact test data from Waterford 3 and 25 heats of material from SONGS-2 which had been fabricated to the same material specification as the material from Waterford 3. The applicant may use this approach provided the applicant demonstrates that the materials from Waterford 3 are metallurgically equivalent to the materials from SONGS-2.
The applicant has used three other methods for estimating the RTNOT from longitudinally oriented CVN impact tests. However, the applicant has not sub mitted any data to demonstrate that the three other methods for estimating the RTNOT from longitudinally oriented CVN impact tests are conservative. The applicant must provide CVN impact data from sufficient number of heats to demonstrate that correlations used in these three other methods are conservative.
The applicant has determined the nil ductility temperature from drop weight test data for all ferritic RCPB base metals except for those in the steam generator and the piping. For all primary side ferritic steam generator materials and all RCPB piping greater than 2-1/2 in. thick the applicant must submit drop weight test data or supply technical justification to demonstrate that the CVN impact data submitted in the FSAR is sufficientiy conservative to determine the RTNDT without the drop weight test data.
The applicant has not determined the RTNOT for any RCPB weld HAZ outside the beltline region. The applicant can satisfy the intent of paragraph IV.A.1 for HAZs by demonstrating that weld processing will not reduce the fracture toughness of the HAZs below that of the adjacent base metal or weld metal.
Paragraph IV.A.3 requires, in part, that material for bolting and other fasteners meet the fracture toughness requirements of paragraph NB-2333 of the ASME Code.
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10 CFR Part 50, paragraph 50.55a requires pressure vessel bolting to be fabricated to the ASME Code editions and addenda no earlier than the Summer 1972 addendum but no later than the Summer 1978 addendum. For bolting, the Code requires CVN testing of three specimens at a temperature no higher than the preload temperature or the lowest service temperature, whichever is less. All three specimens shall meet the ASME Code requirements of:
(1) 25 mils lateral expansion for bolting over 1 in. through 4 in. in nominal diameter; and (2) 25 mils lateral expansion and 45 ft-lb absorbed energy for bolting over 4 in. in nominal diameter.
RCPB bolting and fasteners meet these requirements except for RCP casing studs and nuts, reactor vessel bolting (heat no. 18551), and pressurizer manway nuts.
The RCP casing studs and reactor vessel bolting (heat no. 18551) were fabricated from SA-540 B-23; pressurizer manway nuts from SA-193 B-7, and RCP nuts from SA-194 8-7.
In addition, the mils lateral expansion data for the 1.656 in. in diameter steam generator and pressurizer manway studs were not reported. These studs were fabricated to SA-540 Grade B24 requirements.
The applicant has estimated a minimum preload temperature of 60° F and lowest service temperature of approximately 160 ° F. The bolting materials that did not meet the ASME Code requirements for Charpy V-notch impact testing, were tested at temperatures of 0 ° F and 10° F. Since the materials were tested at temperatures below the temperature required by the ASME Code, compliance with ASME Code CVN impact requirements was demonstrated by extrapolating the bolting material 1 s CVN impact data from 0 ° F and 10° F to 60° F.
The applicant has submitted in FSAR Figures 121.3-1 and 121.3-2 curves of mils lateral expansion vs. temperature and energy absorption vs. temperature from several heats at SA-540 Grade B23 material. These CVN curves may be considered a conservative representation of the effect of temperature upon CVN impact properties for Waterford 3 SA-540 Grade B23 material provided the material identified in FSAR Figures 121.3-1 and 121.3-2 have been processed to a metallurgical condition equivalent to the material used in Waterford 3. The applicant must provide heat treatment data to demonstrate the materials identi fied in FSAR Figures 121.3-1 and 121.3-2 are metallurgically equivalent to the material in Waterford 3.
The steam generator and pressurizer manway studs which did not have the mils lateral expansion reported, had absorbed energy values of 54 - 57 ft-lb at a test temperature of 10° F. A review of CVN impact data for reactor vessel closure head bolting in FSAR Table 5.3-11 indicates material with 54 - 57 ft-lb will have greater than 25 mils lateral at 60° F. Therefore, the steam generator and pressurizer manway studs CVN impact data are equivalent to the Code requirements.
Material specification requirements of SA-193 Grade 87 and SA-194 Grade 87 are significantly different than the requirements for SA-540 Grade B23. Therefore, 5-14
 
the generic CVN curves for SA-540 Grade B23 cannot be used to establish maximum temperature limits for SA-193 Grade B7 and SA-194 Grade B7 material. The appli cant must demonstrate that RCPB bolting fabricated from SA-193 Grade B7 and SA-194 Grade B7 meets the CVN requirements of paragraph NB-2333 of the ASME Code. Lower bound curves may be used to demonstrate that the CVN impact values of SA-194 Grade B7 RCP casing nuts and SA-193 Grade B7 pressurizer manway nuts at test temperatures of 0 ° F and 10 ° F, respectively, satisfy ASME Code impact requirements at 60 ° F.
Paragraph IV.B requires reactor vessel beltline materials to have a minimum CVN upper-shelf energy of 75 ft-lb in accordance with paragraph NB-2322.2 of the ASME Code. This paragraph requires beltline base material to be tested with specimens oriented in the transverse and longitudinal directions. The applicant has determined the upper shelf for all reactor vessel beltline base metal with specimen oriented longitudinally. The beltline base material is SA-533 Grade B Class 1. The lowest CVN upper-shelf energy absorption value identified in FSAR Table 5.2-6 is 138 ft-lb.
According to Idaho National Engineering Laboratories (INEL) Report EGG-FM-5313, "Review of the Estimation of the Transverse Charpy V-Notch Shelf Value From the Longitudinal Value, 11 the transverse CVN upper-shelf energy absorption may be conservatively estimated as 65% of the longitudinal CVN upper-shelf    energy 1
absorption. The staff has reviewed this report and considers INEL s conclusion acceptable. Sixty-five percent of the lowest CVN upper-shelf energy absorption value (138 ft-lb) is 89 ft-lb, which exceeds the minimum requirements of para graph IV.B. Therefore, an exemption to paragraph IV.B that requires the deter mination of the transverse upper-shelf energy for base metal, is justified.
The applicant has submitted CVN upper-shelf energy absorption data for one belt line weld. Until the applicant provides CVN impact test data to define the CVN impact curve for all beltline welds, compliance with paragraph IV.B will be an open item.
The fracture toughness of the HAZs in the reactor vessel beltline were discussed in paragraph III.C.l. Since the fracture toughness was considered equivalent or greater than that of the adjacent base metal or weld metal, no CVN impact curves for reactor vessel beltline HAZs will be required.
5.3.1.2 Compliance With Appendix H, 10 CFR Part 50 The materials surveillance program at Waterford 3 will be used to monitor changes in the fracture toughness properties of ferritic materials in the reactor vessel beltline region, resulting from exposure to neutron irradiation and the thermal environment as required by GDC 32. Under the Waterford 3 surveillance program, fracture toughness data must be obtained from material specimens that are repre sentative of the limiting base, weld, and HAZ materials in the beltline region.
These data will permit the determination of the conditions under which the vessel can be operated with adequate margins of safety against fracture throughout its service life.
The fracture toughness properties of reactor vessel beltline materials must be monitored throughout the service life of Waterford 3 by a materials surveillance program that meets the requirements of Appendix Hof 10 CFR Part 50.
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The staff has evaluated the applicant 1 s information for degree of compliance to these requirements. Based on this evaluation, the staff concludes that the applicant has met all the requirements of Appendix H, 10 CFR Part 50 with the exception of paragraph II.B.
Paragraph II.B, Appendix H to 10 CFR, Part 50, requires that reactor vessels constructed of ferritic materials, with a peak neutron fluence (E > 1 MeV) at the end of the design life of the vessel exceeding 10 17 n/cm2 , shall have their beltline regions monitored by a surveillance program complying with the specifi cations of ASTM Standard E 185-73 except as modified by Appendix H. ASTM Standard E 185 requires that material placed in the surveillance capsules represent the material that may limit operation of the reactor during its lifetime. The selection of the base metal, HAZ, and the weld metal surveillance specimens is based on consideration of the fracture toughness properties of all of the beltline materials (RTNDT and upper-shelf CVN energy) in the unirradiated condition, the chemical composition and the neutron fluence to establish the limiting materials. The applicant 1 s selection of the lower shell plate (M1004-2) as the limiting base metal and the selection of the HAZ (Ml004-2) as the limiting HAZ is acceptable. The applicant has provided the chemical composition of all the beltline welds but only provided CVN impact data for one weld seam in the beltline. Until the applicant provides CVN impact data for each weld in the reactor vessel beltline region, the applicant's compliance with the surveillance requirements of paragraph II.B cannot be adequately assessed.
5.3.1.3 Conclusion on Compliance With Appendices G and H, 10 CFR Part 50 Based on staff evaluation of compliance with Appendices G and H, 10 CFR Part 50, the applicant has met all the fracture toughness requirements of these Appendices except for the following: paragraphs III.B.1, III.8.3, III.C.l, IV.A.l, IV.A.3, and IV.B of Appendix G and paragraphs II.B of Appendix H.
The applicant has submitted information to resolve these open items. Our preliminary review of this information indicates it is unlikely there will be any significant open issues. We will complete our review and prepare a supplement to the SER which will resolve all open issues and recommend exemptions when they are warranted.
Appendix G, Section III of the ASME Code, will be used, together with the fracture toughness test results required by Appendices G and H, 10 CFR Part 50, to calculate the pressure-temperature limitations for the Waterford 3 reactor vessel.
The fracture toughness tests required by the ASME Code and by Appendix G of 10 CFR Part 50 provide reasonable assurance that adequate safety margins against the possibility of nonductile behavior or rapidly propagating fracture can be established for all pressure-retaining components of the RCPB. The use of Appendix G, Section III of the ASME Code, as a guide in establishing safe operating procedures, and use of the results of the fracture toughness tests performed in accordance with the ASME Code and NRC regulations, will provide adequate safety margins during operating, testing, maintenance, and anticipated transient conditions. Compliance with these Code provisions and NRC regulations constitutes an acceptable basis for satisfying the requirements of GDC 31.
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The materials surveillance program, required by Appendix H, 10 CFR Part 50, will provide information on material properties and the effects of irradiation on material properties so that changes in the fracture toughness of the material in the Waterford 3 reactor vessel beltline caused by exposure to neutron radia tion can be properly assessed, and adequate safety margins against the possibility of vessel failure can be provided.
Compliance with Appendix H, 10 CFR Part 50 assures that the surveillance program constitutes an acceptable basis for monitoring radiation-induced changes in the fracture toughness of the reactor vessel material and satisfies the require ments of GDC 32.
5.3.2 Pressure-Temperature Limits Appendix G, 11 Fracture Toughness Requirements, 11 and Appendix H "Reactor Vessel Material Surveillance Program Requirements, 11 10 CFR Part 50, describe the condi tions that require pressure-temperature limits and provide the general bases for these limits. These appendices specifically require that pressure-temperature limits must provide safety margins at least as great as those recommended in the ASME Code, Section III, Appendix G, 11 Protection Against Non-Ductile Failure. 11 Appendix G, 10 CFR 50, requires additional safety margins whenever the reactor core is critical, except for low-level physics tests.
The following pressure-temperature limits imposed on the RCPB during operation and tests are reviewed to ensure that they provide adequate safety margins against nonductile behavior or rapidly propagating failure of ferritic components, as required by GDC 31:
(1) Preservice hydrostatic tests, (2) Inservice leak and hydrostatic tests, (3) Heatup and cooldown operations, and (4) Core operation.
The review of the proposed pressure-temperature limits for Waterford 3 cannot be completed until the reference temperature values, RTNDT' are determined for all ferritic RCPB materials as discussed in the staff 1 s evaluation of Appendix G in SER Section 5.3.1.
The pressure-temperature limits to be imposed on the RCS for all operating and testing conditions, to ensure adequate safety margins against nonductile or rapidly propagating failure, must conform to established criteria, codes, and standards to be acceptable to the staff. The use of operating limits based on these criteria, as defined by applicable regulations, codes, and standards, will provide reasonable assurance that non-ductile or rapidly propagating failure will not occur, and will constitute an acceptable basis for satisfying the applicable requirements of GDC 31.
5.3.3 Reactor Vessel Integrity The staff has reviewed the FSAR sections related to the reactor vessel integrity of Waterford 3. Although most areas are reviewed separately in accordance with other review plans, reactor vessel integrity is of such importance that a special summary review of all factors relating to reactor vessel integrity is warranted.
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The staff has reviewed the information supplied by the applicant to ensure that it is complete and that no inconsistencies exist that would reduce the certainty of reactor vessel integrity. The areas reviewed are:
(1) Design (SER 5.3.1),
(2) Materials of construction (SER 5.3.1),
(3) Fabrication methods (SER 5.3.1), and (4) Operating conditions (SER 5.3.2).
The staff has reviewed the above factors contributing to the structural integrity of the Waterford 3 reactor vessel and concludes that the applicant has fully complied with the required regulations, codes, and standards except for the following:
* Paragraph III.8.1 Appendix G: The applicant has not supplied suffi cient fracture toughness data to demonstrate that CVN impact data from longitudinally oriented specimens may be used for calculation of the RTNDT in lieu of CVN impact data from transversely oriented specimens.
Paragraph III.B.3 Appendix G: The applicant has not provided suffi cient information to demonstrate that the CVN impact test machines and temperature instruments have been correctly calibrated.
Paragraph III.C.1 Appendix G: The applicant has not provided sufficient data to define the CVN test curves for reactor vessel beltline welds.
Paragraph IV.A.l Appendix G: The applicant has not provided suffi cient data to determine the reference temperature, RTNOT' for base metals, weld metals and HAZs in the reactor vessel.
* Paragraph IV.A.3 Appendix G: The applicant has not provided suffi cient data to determine whether RCPB bolting and fasteners have sufficient fracture toughness.
* Paragraph IV.B. Appendix G: The applicant has not determined that CVN upper shelf for transversely oriented reactor vessel beltline base metals, HAZs, and weld metals. An exemption for reactor vessel beltline base metals and HAZs has been justified in the evaluation of Appendix G.
Paragraph II.B. Appendix H: The applicant has not supplied suffi cient data to demonstrate that the weld specimens in the surveillance capsule represent the most limiting weld in the beltline region.
Until the applicant has supplied the information necessary to complete NRC evaluation of compliance with Appendices G and H, 10 CFR Part 50, the staff cannot reach a conclusion concerning the structural integrity of the reactor vessel for Waterford 3.
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5.4 COMPONENT AND SUBSYSTEM DESIGN 5.4.1 Reactor Coolant Pumps 5.4.1.1 Pump Flywheel Integrity GDC 4, "Environmental and Missile Design Bases/' of Appendix A, 10 CFR Part 50, requires, in part, that nuclear power plant structures, systems, and components important to safety be protected against the effects of missiles that might result from equipment failures. Because reactor coolant pump (PCP) flywheels have large masses and rotate at speeds of approximately 1,200 rpm during normal operation, a loss of flywheel integrity could result in high energy missiles and excessive vibration of the RCP assembly. The safety consequences could be significant because of possible damage to the reactor coolant system, the containment, or the engineered safety features.
Adequate margins of safety and protection against the potential for damage from flywheel missiles can be achieved by the use of suitable material, adequate design, and inspection. The flywheels have been fabricated from SA-543 Grade B, Class 1 steel. This steel is of a quality suitable for improved fracture tough ness. The flywheel material has been manufactured by a process that will minimize flaws and improve fracture toughness, and has been cut, machined, finished, and inspected in accordance with Section III of the ASME Code and Regulatory Guide 1.14.
The applicant has indicated that each pump flywheel will be inspected according to the recommendations of paragraph C.4.b of Regulatory Guide 1.14.
The RCP has been designed for a speed 125% that of the normal synchronous speed of the motor (approximately 1,500 rpm). However, the minimum speed for failure is estimated to be much higher than 125% of operating speed for flywheels of the design used at Waterford 3. The applicant has stated that the minimum fracture toughness of the flywheel material at normal operating temperature is equivalent o a dynamic stress intensity factor (Kid) equal to or greater than 100 ksi in The staff concludes that the RCP flywheels in Waterford 3 possess a margin of safety against flywheel missiles equivalent to that recommended in Regulatory Guide 1.14. Compliance with Regulatory Guide 1.14 will provide a basis acceptabie to the staff for satisfying the requirements of GDC 4.
5.4.2 Steam Generators 5.4.2.l Steam Generator Materials The staff concludes that the materials specified for the steam generator are acceptable and meet the requirements of GOC 1, 14, 15, and 31 of Appendix A, and Appendix B of 10 CFR Part 50. This conclusion is based on the following considerations:
The applicant has met the requirements of GDC 1 with respect to codes and standards by assuring that the materials for use in Class 1 and Class 2 components will be fabricated and inspected in conformance 5-19
 
with codes, standards, and specifications acceptable to the staff.
Welding qualification, fabrication, and inspection during manufacture and assembly of the steam generator will be done in conformance with the requirements of Sections III and IX of the ASME Code.
The requirements of GDC 14 and 15 have been met to assure that the RCPB and associated auxiliary systems have been designed, fabricated, erected, and tested so as to have an extremely low probability of abnormal leakage, of rapidly propagating failure, and of gross rupture during normal operation and anticipated operational occurrences.
The primary side of the steam generator is designed and fabricated to comply with Class 1 criteria of the ASME Code as required by the staff. The secondary side of the pressure boundary of the steam generator will be designed, manufactured, and tested to Class 1 criteria although the required classification is ASME Code Class 2.
The crevice between the tube sheet and the inserted tube will be minimal because the tube will be expanded to full depth of insertion of the tube in the tube sheet. The tube expansion and subsequent positive contact pressure between the tube and the tube sheet will preclude a buildup of impurities from forming in the crevice region and reduce the probability of crevice boiling.
* The tube support structure will be manufactured to the egg crate design. This design eliminates the narrow annular gap at the tube supports, because the support may contact the tube at only four lines on the tube circumference and provides almost complete washing of the tube surface with steam generator water.
The requirements of G0C 31 have been met with respect to the fracture toughness of the ferritic materials since the pressure boundary materials of ASME Class 1 components of the steam generator will comply with the fracture toughness requirements and tests of subarticle NB-2300 of Section III of the ASME Code. The materials of the ASME Class 2 components of the steam generator will comply with the fracture toughness requirements of subarticle NC-2300 of Section III of the ASME Code.
The requirements of Appendix 8 of 10 CFR Part 50 have been met since the onsite cleaning and cleanliness control during fabrication conform to the recommendations of Regulatory Guide 1.37, 11 Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants. 11 Reasonable assurance of the satisfactory performance of steam generator tubing and other steam generator materials is provided by (1) the design provisions and manufacturing requirements of the ASME Code, (2) secondary water monitoring and control, and (3) the limiting of condenser inleakage. The controls described above combined with conformance with applicable codes, standards, staff positions >
and Regulatory Guides constitute an acceptable basis for meeting in part the requirements for G0C 1, 14, 15, and 31 of Appendix A, and Appendix B of 10 CFR Part 50.
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5.4.2.2 Steam Generator Inservice Inspection GDC 32, 11 Inspection of Reactor Coolant Pressure Boundary, 11 Appendix A of 10 CFR Part 50, requires, in part, that components which are part of the RCPB or other components important to safety be designed to permit periodic inspection and testing of critical areas for structural and leaktight integrity.
The components in the steam generator are classified as ASME Boiler and Pressure Vessel Code Class 1 and 2 depending on their location in either the primary or secondary coolant systems, respectively. The Waterford 3 steam generators have been designed to permit inservice inspection of the Class 1 and 2 components, including individual tubes. The design aspects that provide access for inspec tion and the proposed inspection program should follow the recommendations of Regulatory Guide 1.83, 11 Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes, 11 Revision 1, NUREG-0212, "Standard Technical Specifications for Combustion Engineering Pressurized Water Reactors," Revision 1, and comply with the requirements of Section XI of the ASHE Code, with respect to the inspection methods to be used, provisions for a baseline inspection, selection and sampling of tubes, inspection intervals, and actions to be taken in the event defects are identified.
In Amendment 1 to the FSAR, dated January 1979, the applicant has stated its intent to conform to Regulatory Guide 1.83 and Section XI of the ASME Code.
Furthermore, staff review also indicates that the steam generator tube inspec tion program for Waterford 3 is in compliance with NUREG-0212. Compliance with Regulatory Guide 1.83, NUREG-0212, and Section XI of the ASME Code constitutes an acceptable basis for meeting the applicable requirements of GDC 32 concerning periodic inspection and testing of steam generator components. We consider this issue to be resolved.
5.4.3 Shutdown Cooling (Residual Heat Removal) System The shutdown cooling system (SOCS) is used in conjunction with the main steam and main or auxiliary feedwater systems to reduce RCS temperatures from normal operating temperatures to the refueling temperature.
Initially, heat is rejected from the steam generators to the condenser or atmos phere. When the RCS temperature and pressure have been reduced to approximately 350° F and 377 psig, the SOCS is put into operation to reduce the reactor coolant temperature to the refueling temperature and to maintain this temperature during refueling.
When the SOCS is in operation, the system takes suction from the hot legs via a system of parallel lines and valves forming redundant trains. From the discharge of the two pumps, a portion of the coolant is diverted to the SOC heat exchangers which are cooled by component cooling water. The diverted flow is then mixed with the main SOCS flow stream and discharged into four reactor cold legs. No single failure of an active component will result in a loss of core cooling capability or prevent the initiation of shutdown cooling.
Besides the cooldown and cold shutdown functions, the SDCS has several other functions. These are:
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(1) Shutdown--connected to CVCS to provide filtration and ion exchange of reactor coolant and to provide monitoring of boron level.
(2) Refueling--used to transfer water from the refueling water storage pool (RWSP) to the refueling pool and back to the RWSP at the end of refueling.
(3) Emergency Core Cooling--the LPSI pumps that drive the SOCS are aligned during power operation and hot shutdown for low pressure coolant injection into the RCS as an integral part of the ECCS.
(4)  Containment  Spray--during normal operation the containment spray pumps are aligned  to discharge through the shutdown cooling heat exchangers.
This is the  required alignment for emergency operation following a LOCA.
During SOC,  the heat exchangers are isolated from the CSS.
SOCS leak detection is discussed in Section 5.2.5 of the SER. If onsite electric power is available and offsite electric power is unavailable, the SOCS i.s capable of cooling the RCS given a single active failure. Each of the two SOCS trains may be isolated independently from the other while allowing the nonisolated 100% capacity train to perform its safety function, which is in compliance with GOC 34.
The SOCS is housed in a structure that is designed to withstand tornadoes, floods, and seismic phenomena in accordance with GOC 2. Flood protection is discussed in Section 3.4 of this report.
The SOCS is designed to meet the environmental requirements for normal operation and for operation during or following LOCA where required. Missile protection and the protection against dynamic effects of pipe whip and discharging fluid are discussed in Sections 3.5 and 3.6 of this report.
The SOCS is designed to comply with Regulatory Guides 1. 29, 11 Seismic Design Classification, 11 Regulatory Guide 1.26, "Qua 1 ity Group Classification and Standards for Water-, Steam-, and Radioactive-Waste-Containing Components of Nuclear Power Plants," and Regulatory Guide 1.46, "Protection Against Pipe Whip Inside Containment."
Since no components of the SOCS are shared with other units, the SOCS satisfies GDC 5.
The staff has reviewed the containment isolation capability of the SOCS and finds that adequate containment isolation capability exists and that the SOCS design meets GOC 55, 56, and 57. The staff has reviewed the CCWS to assure that sufficient cooling capability is available to the SOC heat exchangers.
The cooling capability was found acceptable, as discussed in Section 9.2 of this report.
The SOCS is designed to provide adequate isolation between the SOCS and the safety injection tanks or the reactor coolant system when the RCS is above the design pressure of the SOCS as follows:
(1) There are two parallel paths with two isolation valves per path inside containment on the suction line to the SOCS pumps. Each valve is inter locked with a separate and independent pressurizer pressure signal. Valve 5-22
 
opening is prevented until the RCS pressure falls to a value of 377 psig.
The interlock also provides automatic closure of the SOCS suction line isolation valves when pressurizer pressure increases to 500 psig. The staff is considering an increase in this setpoint to 700 psig, so that the low temperature overpressure protection (LTOP) system is not isolated when required to function. The staff 1 s recommendations in this area are presented in Section 5.2.2 of this report.
(2) Safety injection tank (SIT) pressure will be lowered to 377 psig by the operator when RCS pressure reaches 650 psig. An interlock with pressurizer pressure will prevent the SIT isolation valves from being closed if RCS pressure is greater than 500 psig.
(3) There are two check valves and an open (closed when not on SOC; open on SIS) motor-operated isolation valve on each line from SOCS discharge to the four cold legs to protect the system from RCS pressure.
Overpressure protection of the SOCS is provided by relief valves in the suction line and valves in the LPSI pump discharge headers to provide protection from pressure changes due to temperature changes of trapped water.
Preoperational tests are conducted to verify proper operation of the SOCS.
The preoperational tests include verification of adequate SOC flow and verifica tion of the operability of all associated valves. In addition, a preoperational hot functional performance test is made on the installed SOC heat exchangers.
Flow tests comply with Regulatory Guide 1.68, "Initial Test Programs for Water Cooled Reactor Power Plants. 11 Preoperational hydrostatic tests will be performed per Section III of the ASME Boiler and Pressure Code, and inservice hydrostatic testing will be performed per Section XI of the ASME Code.
During the course of the NRC review, the staff requested information from the applicant to demonstrate how the requirements of BTP RSB 5-1, "Design Require ments of the Residual Heat Removal System," have been met. Specifically, the applicant was asked to demonstrate that the plant could be brought to the point of SOCS initiation in less than 30 hr using only seismic Category I equipment, assuming the most limiting single failure, and with only onsite or only offsite power available.
The applicant 1 s response <identified the systems that would be used to meet these requirements. Cooldown to shutdown entry conditions employ the emergency feed water system, the atmospheric dump valves (ADVs), the CVCS, the main steam safety valves, the RCP seal cooling system, and the auxiliary systems supporting the above systems and components. The initial plant cooldown is accomplished by heat rejection to the atmosphere by the steam generator ADVs. ,Two safety-grade ADVs, one per steam generator, are provided. Seismic nitrogen accumulators are provided to power the valves. The valves can also be operated manually.
Should a single failure occur making one ADV inoperable, the other valve was assumed to release steam from both steam generators. When the plant reaches the appropriate temperature and pressure, the SOCS is aligned, and the cooldown proceeds by rejecting heat to the SOCS heat exchangers.
The current design of the SOCS does not provide essential power to the LPSI pump flow sensors, therefore they would not be available following a loss of 5-23
 
offsite power. These flow sensors provide valuable information regarding the performance of the SOCS and should be operational assuming a loss of offsite power. Therefore, before fuel loading, the staff requires that these flow indicators be powered from an emergency power source. In response to this staff request, the applicant, in Amendment 17 to the FSAR, committed to upgrade these flow instruments to Category 2 criteria of Regulatory Guide 1.97 before fuel loading. This is acceptable. In addition, to provide protection for the SOCS pumps, alarms will be initiated by the plant computer on low discharge flow or pressure. This will ensure that problems with the pump suction or discharge paths will be detected before the to pump is damaged. The staff finds these provisions acceptable.
In performing an analysis of the consequences of a moderate energy line break in the shutdown cooling mode the applicant indicated that operator action was required within 10 minutes of the alarm signaling the event. The staff questioned whether all necessary actions could be initiated within the the 10-minute period indicated by the applicant. The applicant must demonstrate either that more time is available before corrective action is necessary or show that all necessary steps can be taken within the 10-minute period provided in the analysis. In response to this staff concern, the applicant has confirmed in Amendment 18 to the FSAR that the results of the analysis are with no credit for operator action for at least 20 minutes after the alarm signals the event.
This is acceptable.
The applicant's planned natural circulation test does not include prov1s1ons for demonstrating adequate boron mixing when forced circulation is not present.
Rather, the applicant has referenced the boron mixing tests which will be per formed at SONGS-2. Because of the similarity in design of the reactor coolant system, the staff finds this commitment acceptable. However, subsequent to the SONGS tests, but prior to fuel loading at Waterford, the staff will require that the applicant submit a review of the SONGS tests and demonstrate the acceptability and applicability of the results to the Waterford 3 plant.
Additionally, the staff has required that action be taken to preclude voiding in the upper head during natural circulation cooldown, as was observed recently at an operating reactor. The applicant in Amendment 18 of the FSAR, has committed to modify plant operating procedures to prevent this occurrence, and to include additional training for operators in the proper techniques for natural circulation cooldown and depressurization. The staff finds these commitments acceptable.
The original design of the SOCS required the manual operation of a number of valves to initiate SOC. Upon staff request, the applicant in Amendment 17 to the FSAR confirmed that the system has been modified so that all valves normally utilized to enter shutdown cooling are provided with motor operators, and are controllable from the control room. The only exception is that the current plant design requires that an operator leave the control room to restore power to the SIT isolation valves. The staff will require that this function can be performed from the control room, or that other methods be available so that the plant can be placed into shutdown cooling, with no need for an operator to leave the control room.
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The applicant 1 s analysis to demonstrate compliance with BTP RSB 5-1 was reviewed.
It was found to rely on the use of nonseismic equipment (steam cross tie) in the event of a single failure of an atmospheric relief valve. This allowed a more rapid cooldown on two steam generators through the use of the nonseismic crossover piping. Without credit for the crossover piping, cooldown on one steam generator will take longer than 36 hr. This is acceptable provided sufficient water supplies are available to maintain feedwater to the steam generators. If other than condensate-grade emergency feedwater supplies are identified (for example, river water), justification that this water will not foul or otherwise unacceptably affect the steam generators must be provided.
Prior to fuel loading, the applicant must provide an acceptable cooldown analysis that demonstrates compliance with the above position.
5.4.4 Pressurizer Relief Tank (Quench Tank)
The nonsafety-related (quality group 0, nonseismic Category I) quench tank is designed to receive and condense normal discharges from the primary system (pressurizer) safety valves without a release to the containment atmosphere.
This is accomplished by discharging the pressurizer steam under water in the quench tank through a sparger. The water level is maintained manually. Level, temperature, and pressure indication and alarms are provided in the control room to alert the operator to the quench tank conditions and the need for makeup.
A nitrogen blanket is also provided in the tank to permit expansion of the entering steam and to control the tank atmosphere. Overpressure protection is provided by a rupture disc which opens to the containment. The quench tank is sized to receive and condense the steam from the maximum expected step load event. The rupture disc relief capacity is greater than the combined relief capacities of the primary safety valves. The quench tank is located inside the reactor containment which provides protection against natural phenomena.
Failure of the quench tank does not affect the integrity of the RCPB nor does it affect the capability to safely shut down the plant as it is located down stream of the pressurizer safety valves and thus the requirements of GOC 2, 11 Design Bases for Protection Against Natural Phenomena, 11 and the guidelines of Regulatory Guide 1.26, "Quality Classifications and Standards for Water-, Steam-,
and Radioactive-Waste-Containing Components for Nuclear Power Plants, 11 and Position C.2 of Regulatory Guide 1.29, 11 Seismic Design Classification, 11 are met.
Based on staff review, the quench tank meets the requirements of GDC 2 with respect to the need for protection against natural phenomena and meets the guidance of Regulatory Guides 1.26 and 1.29 concerning its seismic and quality group classification and is, therefore, acceptable.
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==5.5  REFERENCES==
American Society of Mechanical Engineers Boiler and Pressure Vessel Code ASME Code, Section III ASME Code, Section III, Appendix G ASME Code, Section III, Class 1 ASME Code, Section III, Class 1, 1971 edition Addenda:
Summer 1971 Winter 1971 Summer 1972 Winter 1972 Summer 1973 Winter 1973 Summer 1978 ASME Code, Section IX ASME Code, Section XI Branch Technical Position:
BTP RSB 5-1 Code of Federal Regulations:
10 CFR Part 50 10  CFR Part 50, Appendix B 10  CFR Part 50, Appendix G 10  CFR Part 50, Appendix H 10 CFR Part 50, Section 50.55a 10 CFR Part 50, Section 50.55a(b) 10  CFR Part 50, Section 50.55a(g)
General Design Criteria:
GDC  1 GOC  2 GDC  4 GDC  5 GDC  14 GDC  15 GDC  30 GDC  31 GDC  32 GDC  34 GDC  55 GDC  56 GDC  57 Idaho National Engineering Laboratories report:
INEL Report EGG-FM-5313
*See Appendix B, Bibliograpny, for complete citations and availability statements.
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Louisiana  Power & Light report:
FSAR  for Waterford 3 FSAR  for Waterford 3, Amendment 1 FSAR  for Waterford 3, Amendment 17 FSAR  for Waterford 3, Amendment 18 Regulatory Guides RG 1.14 RG 1. 26 RG 1. 29 RG 1. 36 RG 1.37 RG 1. 43 RG 1. 44 RG 1.45 RG 1.46 RG 1. 50 RG 1. 68 RG 1. 71 RG 1.83 RG 1. 84 RG 1.85 RG 1.97 USNRC report NUREG 75/087 5-27
 
6 ENGINEERED SAFETY FEATURES 6.1 ENGINEERED SAFETY FEATURES MATERIALS 6.1.1 Metallic Materials The materials selected for the Engineered Safety Features satisfy Appendix I of Section III of the ASME Code, and Parts A, B, and C of Section II of Code, and the staff position that the yield strength of cold-worked stainless steels shall be less than 90,000 psi. Fracture toughness of the ferritic materials meets the requirements of the Code.
The controls on the pH and chemistry of the reactor containment sprays and the Emergency Core Cooling water following a postulated loss-of-coolant or design basis accident, are adequate to reduce the probability of stress corrosion cracking of the austenitic stainless steel components and welds of the Engineered Safety Features systems in containment throughout the duration of the postulated accident to completion of cleanup.
The controls on the use and fabrication of the austenitic stainless steel in the systems satisfy the requirements of Regulatory Guide 1. 31, 11 Contro1 of Ferrite Content of Stainless Steel Weld Meta1,i 1 and Regulatory Guide 1.44, "Control of Use of Sensitized Stainless Steel. 11 If the regulatory positions in the guides were not followed, the actions taken by the applicant have previously been approved by the staff as acceptable alternatives for other plants. Fabrication and heat treatment practices performed in accordance with these requirements provide added assurance that the probability of stress cor rosion cracking will be reduced during the postulated accident time interval.
The external nonmetallic insulation to be used on austenitic stainless steel components conforms with the recommendations of Regulatory Guide 1.36 "Nonmetallic Thermal Insulation for Austenitic Stainless Steels. 11 The use of materials of proven performance in service and the conformance with the recommendations of the stated regulatory guides and codes constitutes and acceptable basis for satisfying the requirements of NRC General Design Criteria 4, 11 Environmental Design 11 with respect to the compatibility of materials and compo nents with the environmental conditions associated with normal operation, main tenance, testing, and postulated accidents.
The materials of construction exposed to the containment sprays are compatible with the expected environment as proven by extensive testing and satisfactory performance. General corrosion of all materials except carbon and 1ow alloy steel is expected to be negligible. For these materials, conservative corrosion allowances have been provided in accordance with the requirements of Section III of the ASME Code.
The selection and use of the materials further satisfies the requirements of GDC 14, "Reactor Coolant Pressure Boundary," as it relates to a design having 6-1
 
an extremely low probability of abnormal leakage, of rapidly propagating failure and of gross rupture.
Conformance with the codes and regulatory guides and with the staff positions mentioned above, constitute and acceptable basis for meeting in part the require ments of General Design Criteria 1, 4, 14, 31, 35, and 41; Appendix B to 10 CFR Part 50, and 10 CFR Section 50.55a, in which the systems are to be designed, fabricated, and erected so that the systems can perform their function as required.
6.1.2 Organic Materials The FSAR states that the total amount of unqualified coating is expected to be insignificant in terms of an increased combustible gas generation rate or an increased amount of debris which could reach the Safety Injection System con tainment sump. However, upon our request, the applicant is currently conducting a review of the total amount of unqualified protective coatings and organic materials used inside containment. The staff will provide an evaluation in a supplement to this SER concerning the acceptability of these unqualified materials when the requested information is provided by the applicant.
6.1.3 Post-Accident Chemistry This review is related to 1) to providing proper water chemistry in the contain ment spray during the injection phase following a Design Basis Accident and in assuring that appropriate methods are available to raise or maintain the pH of the mixed solution in the containment sump during the recirculation phase of the containment spray, ECCS water, and chemical additives for reactivity control for iodine fission product removal (SRP 6.5.2) and 2) to reduce the likelihood of stress corrosion cracking of austenitic stainless steel after the accident.
(SRP 6.1.1, BTP-MTEB 6-1)
The licensee will use borated water (concentration >1720 ppm B) from the refueling water storage tank during the injection phase of containment spray.
The borated water from the containment spray drains to the Safety Injection System containment sump which contains open baskets of Trisodium phosphate dodecahydrate (TSP). The borated water dissolves the TSP to raise the pH to
>7.0. A total weight of 2771.6 kgms of TSP is stored in fifteen open baskets.
Mixing is achieved as the solution is continuously recirculated from the sump to the containment spray nozzles.
THe staff evaluated the pH of the containment sump water (mixture of refueling water storage tank and safety injection tank borated water) following dissolution and mixture with the TSP in the containment sump. The staff also verified by independent calculations that sufficient TSP is available to raise the contain ment sump water pH above the minimum 7.0 level. The staff also evaluated the design of the containment sump to assure that the mixing of the borated water with the TSP will not result in volumes that accumulate pH solutions <7.0.
Additionally, the staff evaluated the proposed Technical Specifications and found surveillance requirements for verifying that sufficient TSP is contained in the storage baskets and for verifying the dissolution rate of a representative TSP sample in borated water from the refueling water storage tank.
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On the basis of the above evaluation, the staff concludes that the post-accident chemistry system meets the requirements of SRP 6.5.2 and GDC 41 and SRP 6.1.1 BTP MTEB 6-1 and GDC 14 and is, therefore acceptable.
6.2 CONTAINMENT SYSTEMS The containment systems for Waterford 3 include dual containment structures, containment heat removal systems, a containment isolation system, secondary containment treatment systems (shield building ventilation system and controlled ventilation area system), and a containment combustible gas control system.
The primary and secondary containment structures and their associated systems all function to prevent or control the release of radioactive fission products which might be released following a postulated LOCA, secondary system pipe rupture, or any other accident releasing radioactive material into the contain ment atmosphere.
6.2.1 Containment Functional Design 6.2.1.1 Containment Structures The Waterford 3 containment consists of a primary containment vessel and a shield building and the controlled ventilation areas of the reactor auxiliary building (RAB). The primary containment vessel is a 1.9-in.-thick cylindrical steel pressure vessel with hemispherical dome and ellipsoidal bottom, which houses the RPV, the reactor coolant piping, the pressurizer, the quench tank, the RCPs, the steam generators, and the safety injection tanks. The primary steel shell is an independent free-standing structure with a net free volume of approximately 2,680,000 ft3
* The primary containment vessel is completely enclosed by the reinforced concrete shield building with a 4-ft annular region between the structures (see Section 6.2.3).
(1) Maximum Pressure and Temperature Analyses: The applicant has performed analyses on a spectrum of postulated [OCAs and secondary system line breaks to verify the primary containment functional design; i.e., to ensure that the con tainment design pressure is not exceeded by any of these postulated accidents and to ensure the containment pressure is reduced to 50% of the peak calculated pressure within 24 hr for the design basis accident (OBA) LOCA. Analyses were also performed to establish the peak and long-term containment temperature and pressure to which safety-related equipment located in containment must be environmentally qualified. The accidents analyzed were chosen to be representa tive of pipe breaks varying in size from double-ended guillotine and slot breaks to smaller sizes. For LOCAs, breaks in the hot leg and cold leg (both pump discharge and pump suction) were considered. Main steam line break (MSLB) analyses at five different power levels were performed, each of which identified the maximum break size allowing a pure steam blowdown. All of the applicant's peak calculated pressures were determined to be below the containment design pressure of 44 psig, and the applicant 1 s OBA LOCA analysis demonstrated the containment pressure was reduced to 50% of the peak within 24 hr.
The staff has reviewed the applicant 1 s analyses including the description of the modified CONTEMPT-LT/26 computer code used to perform the analyses and the input assumptions concerning heat removal mechanisms, mass and energy releases (see Sections 6.2.1.3 and 6.2.1.4), and initial conditions, and found them to be acceptable.
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Additionally, the staff has performed confirmatory analyses on the applicant's OBA LOCA and two MSLB cases utilizing the computer code CONTEMPT-LT/28. Each of the confirmatory analyses was performed with the applicant's assumptions and initial conditions, which were reviewed for adequate conservatisms, including the assumption of the most severe single active failure. This failure for the OBA LOCA case was the failure of one diesel generator. In the case of the MSLB analyses, the most severe single active failure was the failure of one-half of the containment heat removal systems. All the peak values of NRC's confirma tory analyses are lower than the applicant's values. In addition, the staff's confirmatory OBA LOCA pressure response showed a decrease to less than 50% of the calculated peak at 24 hr.
Based on these confirmatory analysis results and review of the applicant's applysis, the staff finds as acceptable the applicant's calculations of the pressures and temperatures produced by the OBA LOCA and secondary system pipe ruptures and concludes  that the containment functional design basis is adequate.
The applicant 1 s calculated peak temperature of 413.5&deg; F for the 102% power MSLB is also acceptable along with the calculated containment pressures for use in the postaccident environmental qualification of equipment important to safety and located inside containment (see Section 3.11).
(2) Protection Against Damage from External Pressure: The applicant has pro vided analyses to demonstrate that the primary containment and shield building are adequately protected against damage from external pressure conditions resulting from the worst postulated accident. The limiting situation was found to exist if inadvertent operation of all the containment heat removal systems is postulated. In this case the primary containment pressure is quickly reduced until redundant vacuum relief valves connecting the primary containment to the shield building annulus open. Each vacuum relief valve is designed to be capable of maintaining the differential external pressure across the steel shell below the design value of 0.65 psid.
The applicant 1 s external pressure analysis of the primary containment and shield building has assumed (1) that both trains of the containment heat removal system operate inadvertently; (2) that only one vacuum relief valve is operable; and (3) that the passive heat sinks (which would be heat sources in this case) are ignored. The staff has reviewed the applicant 1 s analysis, including the initial conditions, and concludes that the analysis is acceptable and that it demons trates the adequacy of protection of the primary containment and shield building from postulated external pressure conditions.
(3) Containment Instrumentation: The applicant has provided postaccident moni toring 1nstrumentat1on to monitor containment atmosphere pressure and temperature and sump water temperature. The staff has reviewed the range, accuracy, and response time of this instrumentation and finds them acceptable.
6.2.1.2 Subcompartment Analysis Subcompartments within containment must be designed to withstand the differen tial pressures which would result from postulated pipe ruptures within a sub compartment. Subcompartments in which high-energy line ruptures are postulated include the reactor cavity, the pressurizer compartment, and a steam generator compartment. A spectrum of breaks for each subcompartment is presented by the applicant. The CEFLASH-4A computer code was used to calculate the mass and 6-4
 
energy release rates from postulated RCS pipe ruptures. The Henry Fauske Moody critical flow models were used with a discharge coefficient of 1.0 and no momentum flux for flows within the RCS. In NRC 1 s SER for the Combustion Engineering Standard Safety Analysis Report (CESSAR), dated December 1975, the staff has determined that this method of calculation is acceptable.
The CEFLASH-4A computer program was also used to calculate the mass and energy release rates from the postulated feedwater break at the steam generator inlet nozzle. Based on the capability of CEFLASH-4A, which has been demonstrated in the mass/energy calculation for ECCS analysis and for subcompartment analysis of primary coolant breaks, the staff concludes that CEFLASH-4A, along with the conservative assumptions used, are acceptable for the calculation of feedwater line break mass/energy release to the steam generator subcompartment.
Therefore, the staff concludes that the mass and energy release data for subcompartment analysis are acceptable.
The applicant has performed differential pressure analyses using the above mass and energy release data on all three of the subcompartments. Each is reviewed below.
(1) Reactor Cavity Analysis: The Waterford 3 reactor cavity is a cylin-drical annular volume bounded above by a missile shield and just below the vessel supports by a neutron shield. The volume is divided into six nodes with each hot and cold leg wholly contained in one nodal volume. Although a more realistic nodalization would place nodal boundaries at the nozzle center lines, the applicant 1 s scheme allows the complete blowdown to be emptied into a single volume, thus making the analysis very conservative with respect to peak differential pressure calculations. Added conservatism in the applicant's model is the restriction of flow to the lower section of the reactor cavity by the neutron shield.
The applicant has chosen to use the reactor cavity nodalization sensitivity study of Carolina Power & Light on its Shearon Harris plant (Docket 50-400, 401, 402, 403) as a basis for verification of the Waterford 3 reactor cavity nodalization scheme. The staff has reviewed the Shearon Harris nodalization sensitivity studies on both the reactor cavity and steam generator subcompart ments and found them to be acceptable and applicable to Waterford 3. The staff 1 s acceptance of the Shearon Harris nodalization sensitivity studies is documented in a letter to Carolina Power & Light, dated April 14, 1978 (Letter, April 14, 1978).
The applicant considered several RCS pipe breaks and determined that the 350-in. 2 discharge leg break was the most limiting case. The analysis was carried out with the RELAP-3 Mod 68 computer code, which uses a Moody-choked flow multiplier of 0.6, and a vent flow calculation based on a homogeneous mixture in thermal equilibrium, with the assumption of 100% water entrainment.
Initial conditions essentially represent a dry air model. Further initial conditions that tend to maximize the calculated pressures are a 0.95 multi plier on all flow areas and a 0.9 multiplier on all volumes to account for additions or modifications within the cavity. The staff has reviewed the applicant 1 s assumptions and finds them acceptable.
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In addition to reviewing the applicant 1 s analysis, NRC staff performed a confirmatory a11alysis using the COMPARE-MOD IA computer code. Two initial analyses were performed with COMPARE, one in which the applicant 1 s exact nodal model was incorporated, and a second analysis in which the cavity nodes were shifted so that nodal boundaries rested on the nozzle vertical centerlines and the blowdown issued into the two volumes adjacent to the break nozzle. Both analyses showed the peak differential pressure to be well below the reactor cavity wall design value. Thus, the applicant's model and differential pres sure results are acceptable and demonstrate the adequacy of the design basis of the reactor cavity to withstand the differential pressures which would result from postulated pipe ruptures within the reactor cavity.
(2) Steam Generator Subcompartment Analysis: The applicant considered a number of RCS pipe breaks and feedwater line breaks for resultant load impact on the steam generator subcompartment (SGS) walls. Staff review of these break sizes and mass and energy releases confirms that the proper break size of 592 in. 2 was chosen.
The nodalization consisted of 23 volumes surrounding the steam generator and excluded the reactor cavity volume. The basis for acceptability of nodaliza tion was again the Shearon Harris steam generator subcompartment sensitivity study.
NRC staff has reviewed the applicant's nodalization scheme and performed a confirmatory calculation using the same nodal model as the applicant. The results of this confirmatory calculation are lower than the results of the applicant's calculation (performed with RELAP-3 Mod 68) which in turn are lower than the design values.
Based on the confirmatory results and the review of the conservatisms in the analysis including the vent flow behavior, the staff finds that the steam generator subcompartment analysis is acceptable and concludes that the design basis of SGS walls is adequate for the differential pressures from any postu lated pipe rupture within the SGS.
(3) Pressurizer Subcompartment Analysis: The three types of pipe breaks considered for the pressurizer subcompartment were surge line, safety relief line, and spray line breaks. The most limiting case was the double-ended guillotine surge line break of 161 in2
* Based on the staff's review of these breaks the staff finds the applicant's choice acceptable for use in the subcompartment analysis.
All initial conditions were reviewed and found acceptable. The applicant's calculation, using RELAP-4 Mod 5, included the homogenous equilibrium flow model. This was reviewed and found acceptable for this type of subcompartment.
NRC has performed confirmatory analyses and the results showed peak differen tial pressures across the pressurizer subcompartment walls greater than those which the applicant computed, but still below the design value.
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Staff review indicated, however, that asymmetric flow out of the vents in the pressurizer support skirt was possible. Hence, another calculation using a model with more nodes was performed and showed that the resulting flow does not cause uneven loading on the pressurizer walls, and that the resulting differential pressures were still below the design value.
Based on the staff's confirmatory analysis and review of all initial conditions and assumptions, the staff finds that the pressurizer subcompartment analysis is acceptable and demonstrates the adequacy of the design basis of the pres surizer subcompartment for differential pressures resulting from postulated pipe ruptures within the pressurizer subcompartment.
6.2.1.3 Mass and Energy Release Analysis for Postulated Loss-of-Coolant Accidents The applicant has provided the mass and energy release data for a spectrum of LOCA break sizes and locations in the RCS. The break locations include the cold leg piping at the suction and discharge sides of the primary coolant pump and the hot leg (see Table 6.2-1 in the Waterford 3 FSAR). The mass and energy release data maximize the energy release to the containment and establish the maximum pressure for the containment functional design. For the same break location, the larger the break area the higher the peak containment pressure results. Moreover, for the largest break area (double-ended break), the worst break location is identified as the cold leg pump suction side. The applicant 1 s spectrum of LOCA breaks includes a postulated double-ended pipe rupture at the pump suction, which results in the highest containment pressure; therefore the staff concludes that the spectrum of pipe breaks considered is acceptable.
The mass and energy release to the containment from a LOCA is considered in terms of blowdown, reflood, post-reflood, and long-term phases. The blowdown phase starts at the initiation of the postulated pipe break. During the blow down phase the primary coolant is being rapidly injected into containment.
The blowdown phase ends when essentially all of the coolant has been injected into containment. The reflood phase occurs as the core is being recovered (or flooded) with safety injection system (SIS) water. The reflood phase ends when the water level in the core region reaches a height that is sufficient to quench the core. The post-reflood phase occurs when the steam generator secondary energy remaining at the end of reflood is removed, along with wall heat sources and decay heat, to boil off a portion of the two-phase flow mixture passing through the primary system. The post-reflood phase ends when the steam generator secondary temperature has essentially reached equilibrium with the primary side temperature, and there is no longer a significant driving potential for secondary to primary system heat transfer. During the long-term phase, SIS water boils at the containment pressure. Energy sources during this phase include decay heat generation and residual thick metal and steam generator cooldown.
For hot leg breaks, the broken piping provides a direct path for fluid entry into containment without passing through the steam generators. Therefore, the secondary systems wil1 remove energy at a much slower rate than that for cold leg breaks.
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The CEFLASH-4 computer code was used by the applicant to determine the mass and energy addition rates to containment during the blowdown phase of the accident. The staff has found this code to be acceptable for blowdown calcu lations. This finding is based on the staff 1 s evaluation of a Combustion Engineering topical report (CENPD-26), and was transmitted to CE by {{letter dated|date=June 13, 1975|text=letter dated June 13, 1975}}.
The applicant calculated the mass and energy release to containment during the reflood phase of the accident using the FLOOD-MOD 2 computer code which was previously found acceptable by the staff in the Safety Evaluation Report for CESSAR, dated December 1975. The applicant has included consideration of a possible additional energy release to the containment during the post reflood phase of the large-break accident. The post reflood phase begins after the core has been recovered with water. During this phase, decay heat generation will produce boiling in the core, and a two-phase mixture of steam and water will exist in the core. The calculations performed by the applicant assumed that this two-phase mixture rises above the core and enters the steam generator.
By this process, the remainder of the available steam generator energy is removed by boiling of the water entrained in the two-phase mixture and carried into the containment as steam. In calculating the rate of energy removed from the steam generators, the applicant has used the maximum steam flow based on the hydraulic resistance of the system and steam generator heat transfer. In the SER for CESSAR the staff has reviewed this calculational method and concluded that the energy release to the containment resulting from LOCAs had been calcu lated in a conservative manner.
Based on NRC review of the applicant's selected pipe break spectrum and calcu lational method, the staff concludes that the data for mass and energy release resulting from a LOCA are acceptable for the containment functional design analysis.
6.2.1.4 Mass and Energy Release Analysis for Postulated Secondary System Pipe Ruptures The applicant has analyzed the peak containment pressure and temperature for a spectrum of postulated MSLBs at various power levels and for various single active failures. For each case, the break area is varied until the most con servative break size (that is, the largest break that results in a pure steam blowdown) is determined. The applicant has provided the mass and energy release data for the MSLB cases which result in the highest peak containment pressure and temperature. Main feedwater line breaks are not analyzed since such breaks result in a biowdown less limiting than the MSLB, because of the lower fluid enthalpy.
The applicant has calculated the MSLB mass and energy release using the SGN-III computer code. This code is described in Appendix 6B to CESSAR and was found acceptable by the staff in the SER for CESSAR ) dated December 1975. The code calculates heat transfer from the primary system to the steam generator secon dary side, steam-water separation within each steam generator, entrained liquid 6-8
 
carryover out the break, and the break flow. The CESSAR model, however, does not include the additional mass/energy release that would result from the stored fluid in the balance-of-plant secondary piping systems but this mass/energy release has been determined in the Waterford 3 FSAR from single-failure analyses by the applicant.
Analyses have been performed by the applicant to show that the containment design pressure is not exceeded considering the following single active failures coincident with the MSLB: (1) loss of one containment cooling train; (2) main steam isolation valve (MSIV) failure to close; (3) main feedwater isolation valve (MFIV) failure to close. The most limiting single active failure has been determined to be the loss of one containment cooling train. The assump tions for each case are given below.
For the loss of one containment cooling train, the MSIVs and MFIVs are postu lated to close. The 1500 ft3 of steam in the steam line between the break (at the steam generator nozzle) and the nearest MSIV is assumed to expand into the containment, but the 9000 ft 3 of steam in the steam line between the MSIVs and the turbine stop valves is isolated along with the intact steam generator.
The 284 ft3 of feedwater between the ruptured steam generator and its MFIV flashes into the steam generator and is released to the containment. One con tainment spray train and two containment fan coolers are assumed to operate.
For the MSIV failure, the MFIVs and both containment cooling trains are postu lated to function. The 1500 ft3 of steam in the steam line between the break and the nearest MSIV, and the 9000 ft3 of steam in the steam line between the MSIVs and the turbine stop valves, expand into the containment. The MSIV nearest the intact steam generator closes. The 284 ft3 of feedwater upstream of the affected steam generator flashes into the steam generator and is released to the containment. Two containment spray trains and four containment fan coolers are assumed to operate.
For the MFIV failure, the MSIVs and both containment cooling trains are postu lated to function. The 1500 ft3 of steam in the steam line expands into the containment. The MFIV nearest to the ruptured steam generator is postulated to fail. The MFIV, however, is backed up by feedwater regulating valves which close in 5 sec after receipt of a main steam isolation signal. The 530 ft 3 of feedwater between the MFIV and the backup regulating valve flashes along with the 284 ft3 of feedwater between the MFIV and the ruptured steam generator.
Two containment spray trains and foui containment fan coolers are assumed to operate.
Offsite power is assumed to be available for the analysis. Availability of offsite power allows the continuation of reactor coolant pump and feedwater pump flow. Maintaining reactor coolant and feedwater flow maximizes the rate of primary to secondary heat transfer which maximizes the rate of mass/energy release. A single active failure of the emergency feedwater system was not explicitly analyzed since the additional water inventory involved is less than the additional inventory associated with the MFIV failure analysis.
NRC staff has reviewed the applicant's single-failure analysis along with other assumptions and has concluded that they are conservative for the purpose of containment analysis.
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Based on NRC review, the applicant 1 s mass and energy release data for postulated secondary system pipe ruptures are acceptable.
6.2.1.5 Minimum Containment Pressure Analysis for Performance Capability Studies on the Emergency Core Cooling System Appendix K to 10 CFR Part 50 of the Commission 1 s regulations requires that the containment pressure used for evaluating cooling effectiveness during reactor core reflood and spray cooling shall not exceed a pressure calculated conser vatively for this purpose. The calculation includes the effect of operation of all installed containment pressure reducing systems and processes. The corresponding reflood rate in the core will then be reduced because lessened containment pressure reduces the resistance to steam flow in the reactor coolant loops and increases the boiloff rate from the core.
Energy is removed from the containment atmosphere by several means. Steam con densation on the containment walls and internal structures serves as a passive energy removal mechanism and the containment cooling system (CCS) and containment spray system (CSS) serve as active heat removal systems. When the steam conden sation and heat removal rates exceed the rates of steam and heat addition from the primary system, the containment pressure will decrease from its maximum value.
The emergency core cooling system (ECCS) minimum containment pressure calcula tions for Waterford 3 were performed using the CE ECCS evaluation model. The CEFLASH-4A computer program is used to determine the mass and energy released to the containment during the blowdown phase of a postulated LOCA, and the COMPERC-II computer program is used to determine both the mass and energy released to the containment during the reflood phase and the minimum containment pressure response to be used in the evaluation of the effectiveness of the ECCS.
The staff reviewed the model and published a Status Report on October 16, 1974, which was amended on November 13, 1974. In NRC 1 s SER for CESSAR, dated December 1975, the staff concluded that the CE containment pressure model was acceptable for ECCS evaluation.
NRC staff has also reviewed the applicant 1 s plant-dependent input parameters used in the minimum containment pressure analysis consisting of initial con tainment conditions, containment volume, passive heat sinks, heat transfer to passive heat sinks, containment active heat removal, and containment purge system operation, and found them all to be acceptably conservative. The applicant 1 s selection of the 0.6 double-ended slot at the pump discharge (DES/PD) break as the most severe LOCA for the mass and energy reieased to the containment for the minimum containment pressure analysis is consistent with the applicant 1 s analyses which showed this LOCA as producing the highest peak clad temperature.
In conclusion, the staff finds acceptable the applicant 1 s minimum containment pressure analysis for performance capability studies on the ECCS.
6.2.1.6 Summary and Conclusions Having evaluated the containment functional capability with respect to GDC 16 and 50  of Appendix A to 10 CFR Part 50, the staff finds acceptable the appli cant 1 s analyses of the dynamic pressure loads which would act on the containment 6-10
 
vessel and subcompartment structures, and finds the results to be within the functional design basis of the containment vessel and subcompartment structures.
The minimum containn1ent pressure analysis for performance capability studies on the emergency core cooling system required by Appendix K to 10 CFR Part 50 is also acceptable.
6.2.2 Containment Heat Removal Systems The function of the containment heat removal systems is to remove heat from the containment atmosphere and maintain containment pressure and temperature at acceptably low levels following a LOCA or secondary system pipe rupture.
The containment heat removal systems are the containment cooling system (CCS) and the containment spray system (CSS).
The CCS consists of four fan coolers and a ducted air distribution system with associated instrumentation and controls. The CCS is divided into two redun dant loops with each loop containing two fan coolers. Each loop has the cooling capacity, in conjunction with the CSS, required to maintain the peak pressure at less than design pressure for the full spectrum of postulated pipe breaks and to reduce the containment pressure following a LOCA to 50% of its peak value within 24 hr (see Section 6.2.1). All four fan coolers are automatically acti vated or placed in their emergency operating mode by a safety injection actuation signal (SIAS) following a LOCA or main steam line break (MSLB). The fan cooler system is in full operation within 23 sec after receipt of an SIAS, assuming loss of offsite power. Even with the assumed loss of the nonsafety-related portion of the CCS ductwork, the applicant has shown that the fan coolers will ensure adequate mixing in association with the CSS. Cooling water is provided to each redundant CCS loop by one of the redundant loops of the CCWS.
The CSS consists of two independent 100% capacity loops each containing a spray pump, a shutdown heat exchanger, piping, valves, spray headers, spray nozzles, and associated instrumentation and controls. Each of the two containment spray pumps is rated at 1810 gal/min at a head of 485 ft. Containment spray is automa tically initiated by a containment spray actuation signal (CSAS). Upon receipt of a CSAS the containment spray pumps are started and borated water from the RWSP flows into the containment spray headers. Full spray flow from the nozzles is established within 47 sec after receipt of a CSAS, assuming loss of offsite power. When low level is reached in the RWSP, a recirculation actuation signal (RAS) will automatically realign the spray pump suction to the SIS sump. The operator must then close the RWSP isolation valves to complete the transition from the injection mode to the recirculation mode. During the recirculation mode, the spray water is cooled by the shutdown heat exchangers. Cooling water to the shutdown heat exchangers is provided by the CCWS.
Both containment heat removal systems invoke the proviions of Regulatory Guides 1.26, 11 Quality Group Classifications and Standards for Water-, Steam-,
and Radioactive-Waste-Containin Components of Nuclear Power Plants, 11 and 1.29, 11 Seismic Design Classification,' and meet or invoke the design, quality assurance, redundancy, power source, and instrumentation and control requirements of ESFs.
The applicant has also provided failure modes and effects analyses (FMEAs) and other information demonstrating the ability of the CCS and CSS to function follow ing postulated single active failures. The heat removal capacity of the fan coolers has been verified by manufacturers' tests on prototype fan cooler cooling coils and by independent tests of cooling coil performance. Performance testing 6-11
 
of the CSS spray nozzles has verified that they will perform satisfactorily during postulated accidents.
The staff has reviewed the applicant 1 s net positive suction head (NPSH) calcu lations and find satisfactory the NPSH available for the CSS pumps during flow from either the RWSP or the SIS sump. The applicant has complied with the provi sions of Regulatory Guide 1.1, 11 Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal Systems, 11 with one exception. Regulatory Guides 1.1 states that containment heat removal systems should be designed so that adequate NPSH is provided to system pumps assuming maximum expected tempe ratures of pumped fluids and no increase in containment pressure from that present before postulated LOCAs. Instead, the applicant has calculated NPSH available using a saturated sump model (that is, the containment atmosphere is conservatively assumed to be at the saturation pressure corresponding to the containment sump temperature). NRC has found the saturated sump model to be conservative (SRP 6.2.2.II.2) and, therefore, acceptable.
Regulatory Guide 1.82, 11 Sumps for Emergency Core Coo 1 ing and Containment Spray System, 11 provides guidelines that should be met by reactor building sumps which are designed to be sources of water for the ECCS and the CSS following a LOCA.
The guidelines address redundancy, location, and arrangement of sumps as well as provisions to screen out debris and to ensure adequate pump performance.
One guideline states that the size of openings in the fine inner screen should be based on the minimum restrictions found in systems served by the sump. The applicant has met this guideline by selecting a fine screen mesh size of 0.078 in. to avoid particle blockages in the reactor core fuel assembly spacer grids.
The applicant 1 s sump design also conforms to the rest of Regulatory Guide 1.82, with the following three exceptions. First, Regulatory Guide 1.82 states that at least two redundant, physica1ly separated reactor building sumps should be provided. Instead, the applicant has a single sump with a screen to provide a b?rr;er between the two intakes to ensure that postulated damage to the sump structure will not adversely affect both suction lines. S2cond, Regulatory Guide 1.82 states that a solid top deck over the sump is preferable. Instead, the applicant has provided a horizontal screen 5 ft above the sump intake.
(Credit has been taken by the applicant only for the vertical screens in calcu lating the coolant velocity through the screens.) Finally, Regulatory Guide 1.82 states that a vertically mounted outer trash rack should be provided to prevent large debris from reaching the fine inner screen. Instead, the applicant has provided a horizontal grate installed 7 ft above the sump intake. The contain ment lavout and the arranqement of the qratinq are such that the probability of large debris entering the sump area and damaging the screens is minimized.
The staff has reviewed the above three deviations from the provisions of Regulatory Guide 1.82 and find the applicant's proposed SIS sump design acceptable.
The staff concludes that the CCS and the CSS satisfy explicitly the requirements of GDC 38, 29, 40, and 50 and the provisions of Regulatory Guides 1.1 and 1.82 either explicitly or on an acceptable alternative basis as described above and, therefore, are acceptable.
6.2.3  Secondary Containment Functional Design The secondary containment or shield building is a seismic Category I structure completely enclosing the primary containment vessel. The reinforced concrete 6-12
 
shield building provides biological shielding and environmental protection of the containment vessel. In addition, the 4-ft-wide annular space between the shield building and the steel containment vessel permits collection and con trolled release of primary containment outleakage by the shield building venti lation system (SBVS) following an accident.
The SBVS is an engineered safety feature designed to maintain a negative pressure greater than 0.25-in. water gauge in the annulus following a LOCA. The SBVS also provides dilution, mixing, high-efficiency removal of fission products by filtration of particulates and adsorption of iodine, and holdup time by recircu lation of potential primary containment outleakage into the shield building annulus. The SBVS consists of two independent 100% capacity units and meets or invokes all the design, quality assurance, redundancy, power source, instru mentation and control (I&C), and single active failure requirements of an engi neered safety feature. Each redundant unit is designed to seismic Category I and Safety Class 2 requirements and includes one full capacity exhaust fan (10,000 ft3 /min), a filter train (including a demister, electric heating coil, medium efficiency prefilter, pre-HEPA (high-efficiency particulate air) filter, charcoal adsorber, and after-HEPA filter), ductwork, valves, and Class IE instru mentation and controls. During normal operation, the shield building annulus is maintained at a negative pressure greater than 5.0 in. water gauge by the nonsafety and nonseismic annulus negative pressure system. In the event of a LOCA, an SIAS trips and isolates the annulus negative pressure system and actuates both units of the SBVS.
The applicant has provided an analysis of the shield building annulus pressure transient following a postulated LOCA. The analysis assumes loss of offsite power, the failure of one SBVS unit, and a 30-sec delay for the remaining SBVS fan to reach rated speed. The results show that the annulus is maintained at a negative pressure greater than 0.25-in. water gauge relative to the outside atmosphere throughout the transient thus ensuring no primary containment out leakage escapes unfiltered directly through the shield building. However, 1 final acceptance of the applicant 1 s analysis is subject to completion of NRC s confirmatory analysis which requires receipt of additional requested information from the applicant. The need for a confirmatory analysis is based on the appli cant 1 s slight deviation from what NRC considers to be adequately conservative model assumptions.
Waterford 3 also has a controlled ventilation area system (CVAS) which is designed to provide filtration of exhaust air from several areas of the RAB that could receive leakage from the primary containment, bypassing the shield building annulus (bypass leakage). The CVAS is Safety Class 3, seismic Category I, and meets or invokes all the design, quality assurance, redundancy, power source, I&C, and single active failure requirements of an engineered safety feature.
The CVAS includes two independent, 100% capacity units. Each redundant unit consists of an exhaust fan (3000 ft3 /min), a filter train identical to those of SBVS, ducting, valves, and I&C. In the event of a LOCA, an SIAS energizes the CVAS fans and repositions valves in the ductwork to isolate the normal reactor auxiliary building (RAB) ventilation system from the controlied areas of the RAB while allowing the CVAS to draw all exhaust air from these areas. Assuming loss of offsite power and a single active failure which incapa citates one CVAS unit, the applicant has demonstrated that the controlled venti lation areas in the RAB will be evacuated to a negative pressure greater than 0.25 in. water gauge relative to surrounding areas within approximateiy 45 sec.
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Therefore, all bypass leakage into CVAS areas will be treated to remove airborne fission products starting 45 sec after the beginning of a LOCA.
The staff has reviewed the information contained in the FSAR concerning bypass leakage paths and finds it incomplete. Based upon the review, the staff has identifi ed additional containment penetrations which are potential bypass leakage paths. Subject to further review of these potential bypass leakage paths with the applicant, these paths will be included as necessary in the tabulation of bypass l eakage paths during the development of the Technical Specifications for the operation of the plant.
The applicant has provided guard pipes for all high-energy pipes penetrating the shield building annulus, specifically designed to prevent release of mass and energy into the annulus should a postulated pipe break occur. Thus, no demonstration of the ability of the annulus to withstand the effects of a high energy pipe rupture occurring inside the annulus is required.
With the exception of the need for additional analysis of the post-LOCA shield building annulus pressure transient and agreement on the identification of all bypass leakage paths, the staff concludes that the secondary containment systems including the SBVS and CVAS are designed to meet the requirements of GOC 41, 42, and 43 and comply with the guidance provided in BTP CSB 6-3, 11 Determination of Bypass Leakage Paths in Dual Containment Plants, 11 and are, therefore, accept able. The review results of the post-LOCA shield building annulus pressure transient analysis will be provided in a supplement to the SER, and the proper identification of all bypass leakage paths will be resolved as part of the Technical Specification review.
6.2.4 Containment Isolation System The function of the containment isolation system (CIS) is to isolate fluid systems that pass through the primary containment vessel to confine any radio activity that may be released following a LOCA or an MSLB inside containment.
The CIS includes the portions of all fluid systems penetrating the primary con tainment vessel which perform the isolation function. In general, for each penetration at least two barriers are required between the containment atmo sphere or the RCS and the outside atmosphere, so that failure of a single barrier does not prevent isolation.
The applicant has stated that each fluid system penetrating the Waterford 3 primary containment vessel is automatically isolated by one or some combination of four actuation signals except those systems that are considered essential (that is, ESF or ESF-re1ated) or considered acceptable on some other defined basis. The four actuation signals are: (1) containment isolation actuation signal ( CIAS) which occurs on either high containment pressure or low pressurizer pressure; (2) SIAS which occurs on either high containment pressure or low pres surizer pressure (identical to CIAS but utilizing different circuitry and relays);
(3) main steam isolation signal (MSIS) which is generated by low steam generator pressure or high containment pressure; and (4) containment purge isolation signal (CPIS) which is generated by high containment radiation and is used in combination with the CIAS to isolate the containment purge valves.
The staff has reviewed the applicant's design information and evaluation and has found that there are at least two barriers between the atmosphere outside 6-14
 
the containment and the RCS or the containment atmosphere. Automatic isola tion valves are provided in those lines which must be isolated immediately following an accident. Lines that must remain in service following an accident for safety reasons are provided with at 1east one remote manual valve. Each automatically closed valve is provided with a manual switch, and its position is displayed, in the main control room. All air-operated isolation valves assume the position of greater safety upon loss of air or control power. The staff has also reviewed the closure times for the isolation valves, particularly the containment purge system isolation va1ves.
Valve closure will occur within 60 sec with most valves closing in 10 sec or less. The containment purge system isolation valves are designed to close in 5 sec. These valve closure times are acceptable. With regard to the different monitored parameters that actuate containment isolation, adequate diversity has been provided.
The staff has reviewed the applicant 1 s designation of essential systems not requiring automatic isolation. Those fluid system lines classified by the applicant as essential and not automatically isolated include the steam lines to the emergency feedwater pump turbine, the atmospheric steam dump lines, the emergency feedwater lines, the component cooling water lines to and from the fan coolers, the safety injection system (SIS sump, LPSI, and HPSI) lines, the containment spray lines, the containment vacuum relief lines, the chemical and volume control charging line, and the actuating instrument lines of the vacuum relief system. The staff finds the applicant's designation of essential systems not requiring automatic isolation acceptable. (NOTE: Upon issuance of Revision 2 of Regulatory Guide 1.141 and in accordance with NUREG-0737, 11 Clarification of TMI Action Plan Requirements,'' the applicant will be required to give careful consideration to the definition of essential and nonessential systems, identify each system determined to be essential, identify each system determined to be nonessential, describe the basis for selection of each essential system, modify the containment isolation designs accordingly, and report the results of the reevaluation to the NRC.)
NRC review has confirmed that the containment isolation system (CIS) meets the explicit requirements of GDC 54 and 57. The CIS meets the explicit requirements of GDC 55 except in cases where isolation valves for essential systems are required to be open following an accident. For these essential lines the staff finds as acceptable the provision of isolation valves which can be remote manually isolated if required. The CIS meets the explicit requirements of GDC 56 with the exception of the monitoring and actuating instrument lines of the contain ment vacuum relief system. GDC 56 specifies four acceptable configurations, each consisting of one isolation valve inside containment and one isolation valve outside containment. GDC 56 allows deviation from this requirement if it can be demonstrated that the containment isolation provisions for a specific class of lines, such as instrument lines, are acceptable on some other defined basis. The applicant has stated that additional isolation valves in the actua ting instrument lines of the containment vacuum relief system are undesirable because they would reduce the availability of the containment vacuum relief system to perform its safety function. For this reason, and because the system outside containment is closed and is located in the controlled ventilation area of the Reactor Auxiliary Building (see Section 6.2.3), we find the present design of the containment vacuum relief actuating instrument lines which contain only an excess flow check valve outside containment acceptable. The monitoring 6-15
 
instrument lines of the containment vacuum relief system contain only one outside isolation valve which is automatically isolated upon a containment isolation signal and an excess flow check valve outside containment. The staff finds this acceptable because the monitoring instrument lines form a closed system outside containment and are also located in the controlled ventilation area of the Reactor Auxiliary Building.
The CIS invokes the provisions of Regulatory Guides 1.26, 11 Quality Group Classifications and Standards for Water-, Steam-, and Radioactive-Waste Containing Components of Nuc 1 ear Power Plants, 11 and 1. 29, 11 Seismic Design Classification." The CIS also conforms to the provisions of RG 1.141, "Containment Isolation Provisions for Fluid Systems, 11 with the following exception.
The exception to the provisions of Regulatory Guide 1.141 pertains to the fail open design of the component cooling water inlet valve and outlet valves for the reactor coolant pumps (RCPs) and the control element drive mechanism (CEDM) cooler. In accordance with Regulatory Guide 1.141, the component cooling water lines for the RCPs and CEDM cooler are classified as nonessential and automati cally close on a SIAS. However, they are also capable of remote manual operation from the control room since it may be desirable to reopen these valves in the event of an accident in which the integrity of the CCWS is not breached and it is decided to restore cooling water flow to operating RCPs and CEDM cooler.
Thus, 11 depending on the postaccident conditions inside the containment, the 11 safe postaccident position of these valves may be either open or closed.
Because the applicant has shown that no single failure could fail open both the inside and outside isolation valves on these lines, the staff finds the fail open design acceptable.
Subject to the acceptability of the valve operability assurance program, the containment isolation provisions of the containment atmosphere purge system at Waterford 3 conform to the provisions of BTP CSB 6-4, 11 Containment Purging During Normal Plant Operation," with the following qualification. For plants under review for operating licenses, the requirements of BTP CSB 6-4, regarding the size of the purge system used during normal plant operation and the justifi cation by acceptable dose consequence analysis, may be waived if the applicant commits to limit the use of the containment atmosphere purge purge system to less than 90 hr/yr while the plant is in the startup, power, hot standby, and hot shutdown modes of operation. The applicant has committed to limit the use of the containment atmosphere purge system to less than 90 hr/yr while the plant is in the startup, power, hot standby, and hot shutdown modes of operation.
The staff will incorporate this requirement into the plant technical specifica tions. Furthermore, as a result of staff study of valve leakage due to seal deterioration, leakage integrity tests must be conducted periodically. This requirement, together with testing frequency, will be included in the plant technical specifications.
The staff concludes that the containment isolation system meets the require ments of GDC 54, 55, 56, and 57, satisfies the provisions of Regulatory Guide 1.141, and conforms to all staff positions and industry codes and standards, and is therefore acceptable.
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6.2.5 Combustible Gas Control System Following a LOCA, hydrogen may accumulate within containment as a result of (1) metal-water reaction between the zirconium fuel cladding and the reactor coolant and (2) radiolytic decomposition of the water in the reactor core and the containment spray soluti-0ns. The applicant has provided a combustible gas control system (CGCS) to monitor and control the hydrogen concentration in containment following a LOCA. The CGCS includes a hydrogen analyzer system, a hydrogen recombiner system, and a containment atmospheric release system (CARS).
The hydrogen analyzer system consists of two identical, independent analyzer systems, each of which can take samples from six locations within containment and one location in the shield building annulus. The hydrogen recombiner system consists of two stationary 100% capacity thermal (electric) recombiners located within containment. Both the hydrogen analyzer system and the hydro gen recombiner system are designed to Safety Class 2 and seismic Category I standards. Additionally, they meet or invoke all design, quality assurance, redundancy, power source, I&C, and single active failure requirements of ESFs.
Each of the two Westinghouse electric hydrogen recombiners is capable of pro cessing 100 scfm of containment atmosphere for postaccident hydrogen control.
The staff has reviewed tests that were conducted for a full-scale prototype and a production recombiner. The tests consisted of proof-of-principle test, testing on a prototype recombiner, environmental qualification testing, and functional tests for a production recombiner. (These tests are described in WCAP-7820 and its supplements.) The results of these tests demonstrated that the recombiner should be capable of controlling the hydrogen in a post-LOCA containment environment.
The CARS is a containment purge system provided in addition to the hydrogen recombiner system, in accordance with Section 50.44 of 10 CFR Part 50, Regulatory Guide 1. 7, 11 Control of Combustible Gas Concentration in Containment Following a Loss-of-Coolant Accident, 11 and BTP CSB 6-2, 11 Control of Combustible Gas Con centration in Containment Following a Loss-of-Coolant Accident. 11 The CARS is a redundant system consisting of two 100% capacity exhaust and supply fans and associated ductwork that, if required, purges the containment atmosphere at a controlled rate through the SBVS (see Section 6.2.3).
The applicant has analyzed the production and accumulation of hydrogen within containment using the guidelines of Regulatory Guide 1.7 and BTP CSB 6-2, and shows that one electric hydrogen recombiner actuated at a containment hydrogen concentration of 3.0 volume percent is capable of limiting the hydrogen concen tration in containment to below the Regulatory Guide 1. 7 lower flammability limit of 4.0 volume percent. NRC's confirmatory calculations utilizing the COGAP code have verified that a single hydrogen recombiner will maintain the hydrogen concentration below 4.0 volume percent if the recombiner is started one day after the beginning of the accident. The difference in the results of the staff's confirmatory analyses and the applicant's analyses is due to the applicant's use of lower zinc and zinc paint corrosion rates and a slightly lower decay heat production rate curve. The applicant, however, has committed to initiate recombiner operation within 24 hours following the beginning of a LOCA.
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Mixing of combustible gases within containment, to prevent excessive stratifica tion and to ensure uniformity of the hydrogen concentration throughout containment, is provided by the CSS and CCS (fan cooler). The turbulence accompanying the initial blowdown and natural circulation within containment will also enhance the mixing process. The staff finds that these systems and mechanisms are adequate to ensure essentially uniform hydrogen concentration within containment and limit the potential for local hydrogen pocketing.
NRC staff concludes that the CGCS satisfies the design and performance require ments of Section 50.44 of 10 CFR Part 50, 11 Standards for Combustible Gas Control Systems in Light Water Cooled Power Reactors,'' the guidelines of Regulatory Guide 1. 7 (Revision 2) and the requirements of GDC 41, 42, 43, and 50, and is, therefore, acceptable.
6.2.6  Containment Leakage Testing Program The Waterford 3 containment design includes the provisions and features required to satisfy the testing requirements of Appendix J, 10 CFR Part 50. The design of the containment penetration and isolation valves permits periodic leakage rate testing at the pressure specified in Appendix J, 10 CFR Part 50. Included are those penetrations that have resilient seals and expansion bellows; i.e.,
air locks, emergency hatches, and electrical penetrations.
The applicant has designed the Waterford 3 containment so that most potential containment leakage would be treated either by the shield building ventilation system of by the controlled ventilation area system. The applicant has identi fied systems for which through-line or penetration leakage could bypass the annulus and be released to areas of the auxiliary building which are not treated by the CVAS. The applicant has committed to perform local leak rate tests in accordance with the requirements of Appendix J to 10 CFR Part 50 and limit the total potential leakage which could bypass the SBVS and CVAS to 6% of the con tainment design leakage rate (0.5%/day by weight of the containment atmosphere) at 44.0 lb/in. 2 gauge.
The proposed reactor containment leakage test program complies with the require ments of Appendix J to 10 CFR Part 50. Such compliance provides adequate assu rance that containment leak-tight integrity can be verified periodically through out service lifetime on a timely basis to maintain such leakage within the limits of the technical specifications.
Maintaining containment leakage rates within such limits provides reasonable assurance that, in the event of any radioactivity releases within the contain ment, the loss of the containment atmosphere through the leak paths will not be in excess of acceptable limits specificed for the site. Compliance with the requirements of Appendix J constitutes an acceptable basis for satisfying the requirements of GDC 52, 53, and 54.
6.2. 7 Fracture Prevention of Containment Pressure Boundary The NRC safety evaluation review assessed the ferritic materials in the Water ford 3 containment system that constitute the containment pressure boundary to determine if the material fracture toughness is in compliance with the require ments of General Design Criterion 51, "Fracture Prevention of Containment Pressure Boundary."
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GDC 51 requires that under operating, maintenance, testing and postulated accident conditions, (1) the ferritic materials of the containment pressure boundary behave in a nonbrittle manner and (2) the probability of rapidly propagating facture is minimized.
The Waterford 3 containment system includes a freestanding ferritic steel con tainment vessel enclosed within a reinforced concrete structure. The ferritic materials of the containment pressure boundary, which are considered in our assessment, are those which have been applied in the fabrication of the contain ment vessel, equipment hatch, personnel lock, penetrations, and piping system components including the valves required to isolate the system. These components are the parts of the containment system which are not backed by concrete and must sustain loads during the performance of the containment function.
The Waterford 3 containment pressure boundary is comprised of ASME Code Class 1, Class 2 and Class MC components. In late 1979, the staff reviewed the fracture toughness requirements of the ferritic materials of Class MC, Class 1 and Class 2 components which typically constitute the containment pressure boundary. Based on this review, it was determined that the fracture toughness requirements contained in ASME Code Editions and Addenda typical of those used in the design of the Waterford 3 containment may not ensure compliance with GDC 51 for all areas of the containment pressure boundary. The staff initiated a program to review fracture toughness requirements for containment pressure boundary materials for the purpose of defining those fracture toughness criteria that most appropriately address the requirements of GDC 51. Prior to completion of this study, the staff elected to apply in NRC licensing reviews of ferritic containment pressure boundary materials the criteria for Class 2 components identified in the Summer 1977 Addenda of Section III of the ASME Code. Because the fracture toughness criteria that have been applied in construction typically differ in Code classification and Code Edition and Addenda, the staff selected the criteria in the Summer 1977 Addenda of Section III of the Code to provide a uniform review, consistent with the safety function of the containment pressure boundary materials. Therefore, the staff has reviewed the Class l, Class 2, and Class MC components of the Waterford 3 containment pressure boundary according to the fracture toughness requirements of the Summer 1977 Addenda of Section III for Class 2 components.
Considered in the NRC review are components of the containment system which are load bearing and provide a pressure boundary in the performance of the con tainment function under operating, maintenance, testing and postulated accident conditions as addressed in GDC 51. These components are the containment vessei, equipment hatch, personnel airlock, penetrations and elements of the main steam and main feedwater systems.
In some cases, materials were not fracture toughness tested or were inappro priately tested. Generally, those materials which were not fracture toughness tested were not tested because the ASME Code Edition and Addenda in effect at 1 the time the components were ordered did not require that they be tested. NRC s assessment of the fracture toughness of materials that were not fracture tough ness tested or were inappropriately tested is based on the metallurgical charac terization  of these materials and fracture toughness data presented in NUREG-0577, 0
Potential for Low Fracture Toughness and Lamellar Tearing on PWR Steam Generator and Reactor Coolant Pump Supports, 11 USNRC, October 1979 and ASME Code Section III, Summer 1977 Addenda, Subsection NC.
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The metallurgical characterization of these materials, with respect to their fracture toughness, was developed from a review of how these materials were fabricated and what thermal history they experienced during fabrication. The metallurgical characterization of these materials, when correlated with the data presented in NUREG-0577 and the Summer 1977 Addenda of the ASME Code Section III, provided the technical basis for the staff 1 s evaluation of com pliance with the code requirements for materials that were not fracture tough ness tested.
Based on the NRC review of the available fracture toughness data and material fabrication histories, and the use of correlations between metallurgical charac teristics and material fracture toughness, it is concluded that the ferritic components in the Waterford 3 containment pressure boundary meet the fracture toughness requirements that are specified for Class 2 components by the summer 1977 Addenda of Section III of the ASME Code. Compliance with these code requirements provides reasonable assurance that the Waterford 3 reactor contain ment pressure boundary will behave in a nonbrittle manner, that the probability of rapidly propagating fracture will be minimized and that the requirements of GDC 51 are satisfied.
6.3 EMERGENCY CORE COOLING SYSTEM The ECCS is designed to provide core cooling as well as additional shutdown capability for accidents that result in significant depressurization of the RCS. These accidents include failure of the RCS piping up to and including the double-end break of the largest pipe, rupture of a CRD, breaks in the steam piping, steam generator tube rupture, and loss of normal feedwater flow.
6.3.1 System Design The ECCS consists of active and passive injection systems. The passive system (safety injection tanks) is actuated when RCS pressure drops below a preset value. The active components of the ECCS are the HPSI and LPSI systems that are actuated by the SIAS.
The four safety injection tanks contain borated water covered by nitrogen pres surized to at least 600 psig. When the RCS pressure falls below the tank pressure, borated water is forced into the four cold legs.
The HPSI mode of operation, upon actuation of the SIAS, consists of the operation of two of the three high head centrifugal pumps which provide high pressure injection of borated water from the refueling water storage pool (RWSP) into the RCS. The charging pumps also align for injection following an SIAS to inject concentrated boric acid from the boric acid makeup tanks to the RCS.
Low pressure injection consists of two LPSI pumps which take their suction from the RWSP. The RWSP has a minimum volume of 443,000 gal of borated water. A comparison between the ECCS equipment at SONGS 2 & 3 and at Waterford 3 is presented in Table 6.1.
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Table 6.1 Emergency Core Cooling System Equipment at SONGS-2 & 3 and Waterford 3 SONGS Equipment                              2 & 3      Waterford 3 LPSI pumps                              2          2 Design flow (gal/min)                4150        4050 Design head (ft)                      342        342 HPSI pumps                              3          3 Design flow (gal/min)                415        380 Design head (ft)                      2830        2830 Safety injection tanks                  4          4 Design pressure (psig)                700        700 Water volume, normal (ft3 )          1743        1742 RWSP                                    2          1 Water volume, minimum (gal total)    355,000    443,000 6-21
 
6.3.2 Evaluation The staff has reviewed the system description and p1p1ng and instrumentation drawings to assure that abundant core cooling will be provided during the initial injection phase with and without offsite power and assuming a single failure. The cold leg safety injection tanks have normally open isolation valves in their discharge lines. These valves will have power removed from the motor operators to preclude inadvertent closure during the ECCS injection phase. There are three pumps in the HPSI system and two pumps in the LPSI system. In the HPSI system only two of the three available pumps are aligned for operation at any time. The pumps in each system are connected to separate power buses and are powered from separate diesel generators in the event of loss of offsite power as required by GDC 17. At least one pump in each injec tion train would be actuated assuming a single power failure. The high and low head injection systems contain parallel valves in the suction and discharge lines, thus ensuring system function even if one valve fails to open. A failure modes and effects analysis was presented by the applicant covering mechanical equipment in the ECCS. This analysis indicated that no single active or passive failure could prevent the ECCS from fulfilling its short- and long-term functions.
Electrically powered components of the ECCS, required for safety-related operation, can operate from onsite or offsite power in compliance with GDC 17.
Components include pumps, valves, and instrumentation. Power must be removed from certain components during specific modes of operation to ensure plant safety. The following valves are locked in position and have their power removed under the stated conditions:
(1) Valves 2SI-V1556, 2SI-V1557, 2SI-V1558, and 2SI-Vl559 must be locked closed except when required for hotleg injection in order to prevent premature hotleg injection following a LOCA.
(2) Safety injection tank isolation valves 1SI-Vl505, 1SI-Vl506 1SI-V1507, and 1SI-V1508 must be locked open when RCS pressure exceeds 500 psig in order to preclude the loss of a safety injection tank during LOCA from a closed isolation valve.
During the review, the staff questioned the possibility that the single manual valve 3SI-Vl09A/B in the common ECCS pump recirculation line might inadvertently be left closed and cause damage to all ECCS pumps. In response to the above concern, the applicant in Amendment 17 to the FSAR stated that valve 3SI-Vl09A/B will be removed and replaced by a spool piece. There are two motor-operated isolation valves in series in the recirculation line of each ECCS train.
These isolation valves are designed to close on an ECCS recirculation actuation signal (RAS) while the ECCS pump suctions are transferred from the RWSP to con tainment emergency sumps. Removal of valve 3SI-V109A/B is acceptable.
The large-break LOCA analyses are described in Section 15.3.3 of this report.
NRC requested that additional small-break LOCA calculations be performed using approved models to assure that the small breaks are not limiting. The results of staff review of these analyses are also presented in Section 15.3.3 of this report.
Analysis of other events requiring actuation of the ECCS in Chapter 15 shows that flows, temperatures, and pressures in the ECCS are satisfactory to mitigate 6-22
 
consequences of these events. By providing redundant cooling and limiting fuel damage, the ECCS design satisfies GDC 35.
In response to the staff 1 s question involving the capability of the HPSI pumps to operate for extended periods of time, the applicant stated that the HPSI pump design is similar to steam generator feedwater pumps manufactured by Ingersoll Rand. The applicant provided feedwater pump operating data which showed that those pumps could be operated without pump overhaul for more than 5 yr. The applicant also stated that the pumps will be inspected, and replace able parts will be replaced periodically. The HPSI pumps are expected to have major maintenance performed at significantly longer time intervals than feedwater pumps because the actual HPSI pump operation will be minimal. The routine inser vice inspections defined in the technical specifications will verify that the performance of the HPSI pumps is acceptable.
The ECCS pump rooms are provided with appropriate leakage detection systems to prevent flooding of safety-related pumps. Any leakage from the ECCS pump seals of valves is collected in a sump and pumped to the radwaste system. A Class lE level detector is mounted inside each pump room that will alarm in the control room on high water level. The operator can determine the sump with excessive leakage and shut the containment isolation valves for that train of the ECCS with the leak. In response to the staff's request, the applicant performed an analysis of possible ECCS pump room flooding assuming 50 gal/min leakage because of a passive failure of the piping system inside the pump room. The results of this analysis indicate that after receipt of safety-grade alarm in control room it will take 3 hr before the water level inside the pump room reaches 1 ft above the floor. This level of water will not damage the pumps. Three hours is considered sufficient time for the operator to isolate the faulty train and secure the leak. This is acceptable.
The ECCS is designed with satisfactory high/low pressure isolation protection.
The LPSI system is protected from RCS operating pressures by a closed motor operated isolation valve and two check valves between LPSI pump discharge and the four vessel cold legs. The motor-operated isolation valve opens automati cally on on SIAS. The HPSI system is a high pressure system, but is isolated from the RCS by a closed motor-operated isolation valve (open on SIAS) and two check valves in the line to each of the four cold legs. Both the LPSI and HPSI systems have relief valves to provide pressure relief for water trapped between closed valves should there be a temperature rise.
The environmental qualification of equipment in the ECCS will be discussed in Section 3.11 of a supplement to this report. All motor-operated valves and all pumps in the ECCS required to operate following a LOCA are located outside containment, with the exception of the shutdown cooling system isolation valves.
These valves are above the maximum post-LOCA flood level.
The RAS automatically transfers suction of the HPSI and containment spray pumps from the RWSP to the emergency sump and shuts off the LPSI pumps. The RAS meets NRC 1 s single failure requirements as discussed in Section 7.3 of this report and actuates on a low RWSP level signal.
The applicant has compared the required ECCS pump NPSH as supplied by the manu facturer with the calculated available NPSH and determined that the available 6-23
 
NPSH for the LPSI pumps exceeds the required NPSH. NRC will require that inplant test data be obtained for the HPSI pumps as discussed in Section 6.3.3.
The ECCS draws water from the RWSP during the injection phase following an SIAS.
Since this pool is located inside the RAB, the applicant has stated, and the staff concurs, no protection from freezing is required.
The applicant has proposed a method of providing simultaneous hot and cold leg injection to begin 2 hr following a LOCA to preclude an unacceptable boron con centration buildup in the core which might cause boron precipitation and reduc tion in core cooling. The applicant's calculations showed that precipitation will not occur for approximately 8 hr with no core flushing flow. This is more than adequate time for the operators to make the valve realignment necessary to switch to simultaneous hot and cold leg HPSI.
All ECCS lines, including instrument lines, have suitable containment isolation features that meet the requirements of GOC 56 and Regulatory Guide 1.11, "Instrument Lines Penetrating Primary Reactor Containment," as discussed in Section 6.2. The ECCS has no shared components between units, as required by GOC 5.
During normal operation, the ECCS lines will be maintained in a filled condition.
Suitable vents are provided and administrative procedures will require that ECCS lines be returned to a filled condition following events such as maintenance that require draining of any of the lines. Maintaining the lines in a filled condition will minimize the likelihood of water hammer occurring during system startup.
The ECCS is housed in a structure that is designed to withstand tornadoes, floods, and seismic phenomena in accordance with GDC 2. Missile protection and the protection against effects of pipe whip and discharging fluid are discussed in Sections 3.5 and 3.6 of this report. The ECCS is designed to comply with Regulatory Guide 1.29, "Seismic Design Classification."
The instrumentation needed to monitor and control the ECCS equipment following a LOCA has been reviewed. This instrumentation provides sufficient information for the operator to maintain adequate core cooling following an assumed LOCA.
Post-accident monitoring instrumentation includes pressurizer pressure and 1evel, steam generator pressure and level, shutdown cooling heat exchanger pressure and temperature, LPSI header temperature, reactor coolant temperature, contain ment pressure, and SIS water level and temperature, SIS flow, and sump level.
In response to staff questioning related to the potential for debris in contain ment to inhibit ECCS performance at Waterford 3, and the effects of a postulated high energy 1ine break (HELB) in the vicinity of the sump, the applicant has provided additional information.
The applicant has committed to establish a containment inspection procedure.
The purpose of the inspection will be to identify any materials that might have the potential for becoming debris capable of blocking the SIS sump when required for recirculation of coolant flow. The inspection of the containme1t emergency sump in included in this procedure. This inspection is performed at the end of each shutdown requiring work in the containment prior to containment isolation.
An inspection program wil1 be added to Waterford 3 preventative maintenance program 6-24
 
to satisfy the criteria of Regulatory Guide 1.82, Position C.14. The safety injection system sump components will be inspected per the inspection program during each refueling outage. The staff concludes that the above commitment by the applicant is acceptable. The staff will require these inspections in the technical specifications.
Significant blockage of the sump screen is precluded by insulation design.
There are three types of thermal insulation used inside the containment. They are: (1) metal reflective, (2) metal encapsulated, and (3) fiberglass insula tion encapsulated with glass cloth. The metal reflective insulation and the fiberglass materials after absorbing sufficient water, will sink and therefore not carry through the screen if they are dislodged during an accident. The metal reflective insulation does not contain material which could form particles small enough to pass through the fine screens at the sump. The sump suctions are guarded by coarse outer screens, or trash racks, and by fine intake screens. In case the fiberglass material is broken down into individual fibers, the fiber diameter (0.005 in.) is small enough to allow passage through the screen which has openings 0.078 in. in diameter. The screen is sized to pass any particle that can also pass through the ECCS pumps and the reactor core.
Operating procedures will be developed to periodically check ECCS performance during long-term cooling. The plant operators are also being instructed in the recognition and mitigation of ECCS performance degradation. In accordance with the requirements of NUREG-0737 (see Section 22, Item I.C.l), guidelines for alerting the operator to the symptoms of inadequate core cooling will be available.
Based on the applicant's commitment to develop procedures and operator training which address the potential for ECCS performance degradation, the staff finds the above measures acceptable to monitor ECCS performance during the long term recirculation mode at Waterford 3.
Based on the considerations noted above with respect to housekeeping requirements, the avoidance of materials likely to form small-size debris, the lack of an apparent mechanism for blockage of more than the proposed test value of 50% of screen areas of large debris, and the ability to monitor and control ECCS status, the staff concludes that the present design of Waterford 3 provides reasonable assurance that the post-LOCA recirculation of reactor coolant will not be impaired by debris, and is therefore, acceptable.
There are no high energy piping systems in the vicinity of the containment emer gency sump. Therefore, no pipe breaks are postulated to affect sump operation.
ECCS electrical loads on the emergency diesels are satisfactory and are addressed in Section 8.3 of this report.
6.3.3 Testing We require that the applicant demonstrate the operability of the ECCS by sub jecting all components to preoperational and periodic testing, consistent with Keg1.1latory Guide 1.68, i!Preoperational and Initial Startup Test Programs for Water Cooled Power Reactors, 11 and RG 1. 79, 11 Preoperational Testing of Emergency Core Cooling System for Pressurized Water Reactors, 11 and GDC 37.
6-25
 
The applicant has been required to provide additional detailed information on the preoperational test program for the ECCS.
The staff will require experimental verification that the Waterford 3 plant can operate in the recirculation mode without cavitation or air entrainment problems. The applicant has committed to full-scale model tests of the SIS sump for vortex formation and NPSH. The NPSH calculations will be verified by using the pumps performance curves developed during preoperational testing (FSAR subsections 14.2.12.2.48 and 14.2.12.2.49) and the data from the SIS sump model tests. The staff requires the test model to include the entire contain ment emergency sump compartment with gratings above the sump screen, the flow path entering the sump compartment and the proposed screen partition in between the two pump suctions. The amount of air entrainment should be measured during tests. Upon completion of the tests the applicant will provide a test report and will implement any needed design changes. We will evaluate the results of the sump test in a supplement to this report.
6.3.4 Conclusions on the Emergency Core Cooling Systems Subject to satisfactory completion of the containment sump tests, the staff concludes that the ECCS proposed by the applicant is acceptable because it meets GDC 2, 4, 5, 17, 35, 37, 56 and Regulatory Guides 1.1, 1.11, 1.29, 1.46, 1.68, and 1.79.
6.4 Control Room Habitability Based upon our evaluation, the calculated toxic gas and radiological consequences are within the acceptance criteria contained in SRP Section 6.4 so that the staff finds that the design of the control room emergency ventilation system is acceptable for the purpose of preventing significant toxic gas and radio logical exposure to operating personnel in the control room.
The control room design meets General Design Criterion 4, 11 Environmental and Missile Design Bases, 11 with respect to 11 structures, systems and components shall be designed to accommodate the effects of and to be compatible with the environ mental conditions associated with normal operation, maintenance, testing, and postulated accidents .... 11 This conclusion is based on the following (see Section 2.2.l for additional discussion):
Inlet air is sensed by ammonia and chlorine detectors which alarm in the control room and automatically initiate control room isolation.
In the event of a fire in the computer room, an alarm sounds in the control room and both supply and exhaust dampers are automatically closed, preventing the spread of smoke into the control room. The operators have the capability of manually purging smoke or fumes from the control room.
The applicant has protected the control room operators against radiation by the use of shielding and by the installation of a filtration system to remove airborne contaminants. After an accident, isolation occurs automatically in response to the accident signal (safety injection) or the high gaseous radio activity signal for inlet air. This places the control room ventilation system in a pressurization mode with 4000 cfm being recirculated through redundant particulate and carbon filtration components.
6-26
 
Should further review confirm the applicant 1 s findings in the FSAR with respect to toxic gas hazards, the staff will be able to conclude that the control room habitability systems are adequate to provide safe, habitable conditions within the control room under both normal and accident conditions, including loss-of coolant accidents; such that , adequate access and occupancy can be maintained under accident conditions without personnel receiving radiation exposures in excess of 5 rem whole body, or its equivalent to any part of the body, for the duration of the accident. Therefore, the control room design meets GDC-19, 11 Control Room, for those hazards presently identified.
11 6.5 FISSION PRODUCT REMOVAL AND CONTROL SYSTEMS 6.5.1 Engineered Safety Feature Atmosphere Cleanup System The engineered safety feature (ESF) atmosphere cleanup systems for Waterford 3 consist of process equipment and instrumentation to control the release of radioactive iodine and particulate matter following a design basis accident (OBA). In the Waterford 3 application there are four filtration systems designed for this purpose. These systems are:
(1)  Control room air conditioning system (CRACS)
(2)  Controlled ventilation area system (CVAS)
(3)  Shield building ventilation system (SBVS)
(4)  Fuel handling building ventilation system (FHBVS) 6.5.1.l Control Room Air Conditioning System The control room air conditioning system (CRACS) consists of two full size redun dant ESF air filtration units that provide continuous filtration following either a design basis accident (OBA) or a toxic chemical release. Each unit includes a medium efficiency filter; electrical heating coil; a HEPA prefilter; three 1500 ft 3/min charcoal adsorber beds, each bed 4 in. in depth; a HEPA afterfilter; and centrifugal fan. Each filter train is designed to Safety Class C and seismic Category I requirements and is housed in the reactor auxiliary building which is seismic Category I. The charcoal adsorber consists of coconut shell carbon impregnated with KI3.
There are two modes of CRACS emergency operation, pressurization and isolation.
Pressurized emergency operation is initiated by a high radiation signal from one of the monitors located at the normal outside air intake or following a receipt of a safety injection actuation signal (SIAS). Following such a sig-nal the normal outside air intake isolation valves and exhaust isolation valves will be closed. Exhaust fan operation stops and recirculation dampers are opened to automatically recirculate all air supplied to the control room. All emergency outside air isolation valves are opened. Both emergency filtration units are started to provide filtration of 200 ft 3 /min of outside air and recirculation with filtration of 3800 ft 3 /min.
The isolation mode of operation occurs upon receipt of a toxic chemical signal.
The mode of operation is quite similar to that during pressurization. However, both filtration units are started to provide filtration and adsorption at a rate of 8000 ft 3 /min. In addition, the control room operator has the option 6-27
 
of manually stopping one emergency filtration unit. No outside air is drawn into the control room in this mode.
6.5.1.2 Controlled Ventilation Area System The controlled ventilation area system (CVAS) is designed to provide filtra tion of exhaust air from the areas of the reactor auxiliary building (RAB) containing the following:
(1) Low pressure safety injection pumps (2) High pressure safety injection pumps (3) Containment spray pumps (4) Shutdown heat exchanger (5) Containment penetration area which contains recirculation safety injec-tion system sump water lines.
The CVAS operates upon receipt of an SIAS. At that time the exhaust fans are energized and the valves in the system ductwork are aligned so that all the air from the CVAS area is drawn through the CVAS filter train. Each exhaust fan is capable of drawing 3000 ft3 /min through a loaded filter train. The system evacuates the controlled ventilation area to -0.25 in. WG upon receipt of the SIAS.
The CVAS contains two redundant 3,000 cfm trains consisting of a demister; an electrical heating coil; a medium efficiency filter; HEPA prefilter; two 1500 cfm charcoal adsorber beds, each bed 4 inches in depth; a HEPA afterfilter; and an exhaust fan. The charcoal is coconut shell carbon impregnated with KI 3
* The system is designed as a seismic Category I system with Safety Class C.
6.5.1.3 Shield Building Ventilation System The shield building ventilation system 1 s (SBVS) primary function is to assure that the annular pressure following a LOCA does not become positive, thus allowing primary containment outleakage to escape unfiltered through the shield building wall to the outside atmosphere. The SBVS consists of two full capacity systems.
Each system contains a demister, an electrical heating coil, a medium efficiency filter, a prefilter HEPA, a 4-in. charcoal adsorber impregnated with KI 3 , an afterfilter HEPA, and an exhaust fan. The SBVS is located in the RAB. All of the equipment and components of the SBVS are seismic Category I, Safety Class 8.
The SBVS is actuated by SIAS. Following actuation, air is drawn through cir cumferential headers located in the upper and lower annular regions. Air enters these headers and is exhausted to two 30-in.-diameter exhaust ducts which pene trate the shield building and are connected to the SBVS unit in the RAB. The filtered air is discharged to the plant stack or recirculated back to the annulus.
Both SBVS trains are placed in operation following receipt of an SIAS signal.
The operator has the option of deactivating one of the units after he has con firmed that the other system is operating. During this phase of operation all air is fi1tered at an initial exhaust rate of 13,940 ft 3 /min to reduce the annular pressure to a setpoint of 14.4 in. WG below atmospheric pressure. At 6-28
 
this setpoint the SBVS changes to the recirculation mode of operation. If the addition of energy to the shield building from heat transfer and equipment operation and from in-leakage from the containment and outside air raises the pressure in the annulus to -3 in. WG, the automatic control system places the auxiliary exhaust vent valve to its full open position at a flow rate of approxi mately 14,560 ft 3 /min (actual) which decreases annular pressure to -6 in. WG.
If the annular pressure continues to rise until -1 in. WG the automatic control switches again to exhausting 13,940 ft 3 /min (actual) until the pressure is -8 in. WG. At this point, recirculation begins again and the cycle starts anew.
Stable operation involves maintaining annular pressure between -3 in. WG and
-6 in. WG.
The charcoal adsorber is coconut shell impregnated with KI 1. Each filter train contains five 2000 ft 3 /min capacity adsorber beds, each bea with a depth of 4 inches.
6.5.1.4 Fuel Handling Building Ventilation System The fuel handling building ventilation system (FHBVS), consists of two redun dant 100% capacity trains. Each train contains an electrical heating coil; a medium efficiency filter; a HEPA prefilter; three 1500 ft3 /min capacity charcoal adsorbers, each with a depth of 4 in; a HEPA afterfilter; and centrifugal fan.
Each train is capable of treating 4000 ft 3 /min (actual). The FHBVS is designed to seismic Category I requirements, Safety Class C. The coconut shell charcoal is impregnated with KI 3
* The operation of the FHBVS is initiated by an area radiation monitor producing a fuel handling accident signal. When such a signal is produced, the air handling unit is stopped along with the normal exhaust fans. Two isolation dampers are closed and the two FHBVS units are started along with the safety related emergency heating and ventilation room exhaust fans. The dampers associated with the normal air handling intake unit, the normal exhaust to the atmosphere, and the dampers to normally nonradioactive areas are placed in their failed position (i.e., partially open). The exhaust dampers from the noncontaminated areas are also in the failed position. However, these failed positions are completely open.
6.5.1.5 System Evaluation For the evaluation of the ESF filter systems in Section 15 of this report, the staff have assigned the filter/adsorber trains a removal efficiency of 99 %
for all forms of radioiodine and 99 % for particulates as recommended in Regulatory Guide 152, 11 Design, Testing, and Maintenance Criteria for Engineered Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants, 11 for four inch deep charcoal beds.
The staff has determined that the ESF filter systems are designed in accordance with the guidelines of Regulatory Guide 1.52 and will be capable of controlling the release of radioactive materials in gaseous effluents following a postulated DBA.
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6.5.2 Containment Spray as a Fission Product Cleanup System The containment spray system consists of two redundant trains, is initiated automatically, and is supplied with a spray solution additive upon recircula tion from the containment sump. The staff reviewed its design to evaluate its capability to mitigate the thyroid dose consequences of the loss-of-coolant design basis accident (discussed in SER Section 15.3.3) by removing airborne iodine fission products from the containment atmosphere. We have also evaluated its ability to reduce the acidity of liquids within the containment to minimize post-accident corrosion.
Upon automatic initiation, the system is designed to draw suction from the boric acid solution contained in the refueling water storage pool. When this supply is depleted, suction is automatically transferred to the safety injection 1 s sump in the floor of the containment. No additives are mixed with the boric acid prior to initially being sprayed by the system. Instead, acidity control is accomplished by the dissolution of trisodium phosphate (TSP), which is stored in open baskets within the containment. Water draining into the sump is expected to dissolve sufficient TSP to have neutralized the acidity of the sump solution within three hr, providing acceptable protection against corrosion of equipment and structures exposed to the solution.
The staff evaluated the containment spray system for effectiveness as an iodine removal ESF, and found it to be moderately effective. Unlike spray systems incorporating mixing of alkaline or redundant additives; however, the Waterford 3 spray would not dominate the other processes (such as reaction with and adsorp tion on solid surfaces; termed 11 plate-out 11 ) by which iodine vapor would also be removed from the containment atmosphere.
Regulatory Position C.l.a of Regulatory Guide 1.4 lists the airborne iodine composition to be postulated within a containment following a loss-of-coolant accident. This assumed composition is consistent with computational methods if either plate-out is the dominant short-term removal process, or if plate-out is dominated by the operating of efficient sprays. In the present evaluation, these two competing processes are comparable in magnitude. Rather than consi dering them separately, as in Regulatory Guide 1.4 Positions C.1.a and C.l.d, the staff considered them together and  1timated an overall first-order elemental iodine removal rate constant of 1.43 hr , and an overall decontamination factor of 6.4. The staff 1 s assumptions, where different from Regulatory Guide 1.4, are listed in Table 15-8. These alternate assumptions yield very similar two-hr exclusion area boundary doses as are obtained using the Regulatory Guide 1.4 assumptions, but the dose rates are distributed in time more correctly.
The NRC staff concludes that the containment spray system is adequately designed to mitigate the dose consequences of the design basis loss-of-coolant accident, although with limited effectiveness. The containment spray system is provided to reduce the concentration and quality of fission products released to the environment following postulated accidents and provides suitable redundancy in components and features that its safety function can be accomplished assuming a single failure. Thus, the system conforms to GDC 41, 11 Containment Atmosphere Cleanup. 11 The containment spray system is designed to permit periodic inspec tion and testing and, therefore, conforms to GOC 42, 11 Inspection of Containment Atmosphere Cleanup Systems 11 anc! GDC 43, "Testing of Containment Atmosphere Cleanup Systems. 11 We conclude that the SGTS design is acceptable.
6-30
 
To further assure as rapid as possible neutralization of the boric acid spray solution, the applicant has revised the proposed Technical Specification 4.5.2a to include periodic inspection of the TSP baskets for evidence of aggregation, and the mechnical dispersal of any aggregations found. With this additional specification, the system will meet the requirements of General Design Criterion 42, 11 Inspection of Containment Atmosphere Cleanup Systems. 11 6.5.3 Fission Product Control System The applicant has designed three filtered exhaust systems to control leakage of airborne radioactivity. These three systems are the fuel handling building ventilation system (FHBVS), the controlled ventilation area system (CVAS), and the shield building ventilation system (SBVS). Each of these three systems has two redundant trains, each consisting of a mist eliminator (except the FHBVS),
an electric heater, a prefilter, two banks of high efficiency particulate filters, one up stream and one down stream of two vertical 4-inch deep charcoal absorber beds, pressure and temperature sensors, and associated dampers, ducts, instruments, and controls. ESF atmosphere cleanup systems are considered in Section 6.5.1 of this report.
The CVAS and SBVS are intended to prevent uncontrolled leakage from the secondary containment in the event of an accident causing release of airborne radioactivity from the reactor core. These systems are capable of filtering and exhausting sufficient air from the enclosed volumes surrounding the containment to achieve a negative pressure of 0.25-inch water gauge or greater within less than 60 seconds following secondary containment isolation signals. The CVAS is designed to maintain constant negative pressure for the duration of any accident, while the SBVS is designed to vary its flow automatically, by means of dampers, from exhaust to recirculation within the shield building, in order to assure negative pressures while accommodating the thermal expansion and contraction of the steel containment vessel. The FHBVS is similarly capable of collecting and filtering airborne radioactive materials released from spent fuel damaged during fuel handling operations within the fuel handling building. All three systems control leakage in the sense that they prevent diffusive loss of airborne radioactivities from the buildings they service, filtering aerosol particles and absorbing iodine gases from the exhausted air prior to releasing it from the building stack.
The filtration is ineffective against noble gas fission products, krypton and xenon, for which these three systems act only to assure an elevated release point for more rapid dilution in the environment.
These three systems are designed to reduce the concentration and quality of fission products released to the environment following postulated accidents, and possess suitable redundancy (as stated above) in components and features that each can accomplish its safety function in the event of a single failure.
Thus, these three systems conform the relevant requirements of GDC 41, 11 Containment Atmosphere Cleanup."  They are also designed to permit periodic inspection and testing and, therefore, conform to GDC 42, ''Inspection of Containment Atmosphere Cleanup Systems" and GOC 43, "Testing of Containment Atmosphere Cleanup Systems." The NRC staff concludes that these systems 1 designs are acceptable.
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6.6 Inservice Inspection of Class 2 and 3 Components General Design Criterion 36, 11 Inspection of Emergency Core Cooling System, 11 Criterion 39, 11 Inspection of Containment Heat Removal System 11 ; Criterion 42, 11 Inspection of Containment Atmosphere Cleanup Systems ; and Criterion 45, 11 11 Inspection of Cooling Water System, 11 of Appendix A to 10 CFR Part 50 require that the subject systems be designed to permit appropriate periodic inspection of important component parts to assure system integrity and capability. General Design Criterion 37, uTesting of Emergency Core Cooling System 11 ; Criterion 40, 11 11 Testing of Emergency Core Cooling System ; Criterion 39, 11 Testing of Containment Heat Removal System ; Criterion 43, 11 Testing of Containment Atmosphere Cleanup 11 Systems 11 ; and Criterion 46, 11 Testing of Cooling Water System, 11 require in part that the subject systems be designed to permit appropriate periodic pressure testing to assure the structural and leaktight integrity of their components.
To ensure that no deleterious defects develop during service in ASME Code Class 2 system components, selected welds and weld heat-affected zones are inspected prior to reactor startup and periodically throughout the life of the plant.
In addition, Code Class 2 and 3 systems receive visual inspections while the systems are pressurized in order to detect leakage, signs of mechanical or structural distress, and corrosion.
Examples of Code Class 2 systems are: residual heat removal systems, portions of chemical and volume control systems (in PWR plants), portions of control rod drive systems (in BWR Plants), engineered safety features not part of Code Class 1 systems. Examples of Code Class 3 systems are: component cooling water systems and portions of radwaste systems. All of these systems transport fluids.
Section 50.55a(g), 10 CFR Part 50, defines the detailed requirements for the preservice and inservice inspection programs for light water cooled nuclear power facility components. Based upon a construction permit date of November 14, 1974, this section of the Code of Federal Regulations requires that a preservice inspection program be developed for Class 2 and 3 components and be implemented using at least the edition and addenda of Section XI of the ASME Code in effect six months prior to the date of issuance of the construction permit. Also, the initial inservice inspection program must comply with the requirements of Section XI of the ASME Code in effect no more than twelve months prior to the date of issuance of the OL, subject to the limitations and modifications listed in Section 50.55a(b) of 10 CFR Part 50.
The applicant has stated that his inservice inspection (ISI) program will comply with the rules published in 10 CFR Part 50, Section 50.55a, and Section XI of the ASME Code. The ISI program will consist of a preservice inspection plan and an inservice inspection plan.
The staff has not received a preservice inspection program from the applicant.
Before our review and evaluation can be completed, we require that a preservice inspection program be submitted in accordance with the guidelines in Q 121.2 of the FSAR.
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: 6. 7 REFERENCES*
American Society of Mechanical Engineers Boiler and Pressure Vessel Code:
ASME Code, Section XI Branch Technical Position:
BTP CSB 6-2 BTP CSB 6-4 Carolina Power & Light Report:
Study on Shearon Harris Nodalization Sensitivity Studies Code of Fedeal Regulations:
10  CFR Part 50, Appendix J 10  CFR Part 50, Appendix K 10  CFR Part 50, Section 50.44 10  CFR Part 50, Section 50.55a 10  CFR Part 50, Section 50.55a(b) 10  CFR Part 50, Section 50.55a(g)
General Design Criteria:
GDC  2 GDC  4 GDC  5 GDC  16 GDC  17 GDC  19 GDC  35 GOC  36 GDC  37 GDC  39 GDC  40 GDC  41 GDC  42 GDC 43 GDC 45 GDC 46 GDC 50 GDC 52 GDC 53 GDC 54 GDC 55 GDC 56 GDC 57 6-33
 
Louisiana Power & Light Report:
FSAR for Waterford 3:
Amendment 17 Appendix 5.4A Table 6.2-1 Letter from NRC to Carolina Power & Light, dated April 14, 1978 Regulatory Guides:
RG 1.1 RG 1.4 RG 1.7 (Revision 2)
RG 1.11 RG 1.141 RG 1.26 RG 1. 29 RG 1. 46 RG 1. 52 RG 1. 68 RG 1. 79 RG 1.82 USNRC Reports:
NUREG-75/087 NUREG-75/112 NUREG-0737 Westinghouse Report:
WCAP-7820 WCAP-7820, Supplements
*See Appendix B, Bibliography, for complete citations and availability statements.
6-34
 
7 INSTRUMENTATION ANO CONTROLS
 
==7.1 INTRODUCTION==
: 7. 1. 1 General The NRC staff has evaluated the protection and control systems of Waterford 3 using as a basis (1) the Commission's General Design Criteria, (2) the Institute of Electrical and Electronics Engineers (IEEE) standards including IEEE 1 279-1971, 11 Criteria for Protection Systems for Nuclear Power Generating Stations/
(3) the applicable Regulatory Guides for power reactors, and (4) the applicable staff branch technical positions.
The final design of the Waterford      3 plant protection and the NSSS control systems is similar to that of the      Arkansas Nuclear One, Unit 2 (AN0-2). The engineered safety features (ESFs)      that are not part of the NSSS, and the balance of plant control systems      are similar in design to those of St.
Lucie 1.
In review, the staff concentrated on those areas where changes were made in the design presented in the PSAR for the CP, where the design differs from the plants previously reviewed by NRC and the areas that have remained of concern during reviews of other similar plants.
Seismic and environmental qualification of instrumentation and control systems is addressed in the staff review of Sections 3.10 and 3.11 of the applicant's FSAR and of this SER and its supplements.
7.1.2 Specific Findings--Open Items The staff has discussed in this report the issues that need resolution. A list of SER open items follows. Resolution of these items will be reported in a supplement to this report.
(1) Emergency Feedwater Control: The emergency feedwater (EFW) control system receives actuation commands from: (a) the emergency feedwater actuation signal (EFAS), (b) the main steam isolation signal (MSIS),
(c) the manual controllers in the control room, (d) the manual controllers on the auxiliary shutdown panel. The EFW control system controls the eight EFW block valves.
Two deficiencies in the EFW control system as described in the FSAR have been noted. First, MSIS closes the EFW block valves while EFAS opens the EFW block valves. Following a steam line break both command signals will be generated. The EFW control system is to be configured in such a way that EFAS overrides MSIS. Second, EFAS (to the block valves) does not 11 seal in. 11 The system, as now configured, will cause the steam generator level to oscillate about the low level setpoint with the EFW block valves commanded to oscillate from a full open to a full closed position. The concern has been raised that the EFW valves and piping may 7-1
 
not be adequate for sustained oscillatory service. The applicant will revise the EFW control system to modulate the block valves. The revised system should be designed so that manual control overrides the EFAS signal to close the block valves, and so that the EFAS signal to fully open the block valves overrides manual control.
The applicant is to complete the revised EFW control system design and submit the final design for staff review.
(2) IE Bulletin No. 79-27: The applicant's response to this bulletin addresses hardware susceptibility. The emphasis of the bulletin is procedural.
Specifically, plant procedures should be adequate to permit safe shutdown, given loss of single instrument bus.
The applicant will identify equipment required for safe shutdown as part of the Appendix R, 10 CFR Part 50 (fire protection) review. The applicant will address IE Bulletin (IEB) 79-27 following this review and submit related procedural criteria which will be incorporated in a supplement to the SER. The actual procedures, will be reviewed by our Office of Inspection and Enforcement.
(3) IE Bulletin No. 80-06: !EB 80-06 addresses reset and override of ESFs.
The applicant 1 s response to the staff request to address this bulletin is incomplete. The bulletin and response were discussed at an April 15, 1981 meeting with the applicant at the site. The applicant agreed to submit additional information.
(4) Monitoring Safe Shutdown: The staff has requested information related to safe shutdown instrumentation in the control room and on the auxiliary control panel (LCP-43). The applicant has provided responses to NRC's specific questions.
A safe shutdown analysis is to be conducted by the applicant in accordance with 10 CFR Part 50, Appendix R. This analysis will identify equipment needed to obtain and maintain cold shutdown after a fire and identify instrumentation and control needed for shutdown from outside the control room.
The staff has suspended review of shutdown instrumentation and control pending completion of the applicant's safe shutdown analysis.
(5) Reactor Coolant Pumh Shaft Break: The applicant has performed scoping analyses of a hypot esized reactor coolant pump (RCP) shaft break (Regulatory Guide 1.70, Revision 2, Table 15-1, 3.4) and has determined that the protective system as presently designed will not provide an acceptable level of protection under all operating conditions.
The applicant will propose modifications to the plant protective system and wi11 provide the results of an analysis of this event.
Reactor protection system modifications will be reviewed by the staff and results will be reported in a supplement to this report.
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(6)  Single Failure of Control System Study: The applicant has been requested to perform a study of single failures of the control system to ascertain if such single failures and subsequent consequential failures will lead to event sequences more severe than analyzed in Chapter 15 of the FSAR.
The applicant is to commit to perform the study and provide a schedule for this effort.
(7)  TMI O en Items: The applicant's response to date to TMI-2 Items II.0.3 and I!.F.2 provides inadequate design detail. The applicant should provide sufficient detail to demonstrate conformance with NUREG-0737, 11 Clarification of TMI Action Plan Requirements. 11 7.1.3 Conclusions Subject to resolution of the open items enumerated in Section 7.1.2, the staff concludes that the applicant has identified the safety-related instrumentation and control systems and the applicable safety criteria that these systems meet, and that these criteria conform to the Commission's regulations as set forth in the General Design Criteria, applicable Regulatory Guides, Branch Technical Positions, and industry standards. These are listed in Table 7-1 of the Standard Review Plan. The staff will also be able to conclude that imple mentation of these systems in accordance with these criteria provides reasonable assurance that the plant will perform as designed in normal operation, anticipated operational occurrences, and postulated accident conditions.
7.2 REACTOR PROTECTIVE SYSTEM 7.2.1 System Description The plant protection system which is designed and built by CE consists of a reactor protection system (RPS), described below, and an engineered safety features actuation system (ESFAS), described in Section 7.3.
The RPS monitors selected parameters in the NSSS and the containment, and trips the reactor whenever established operational limits are reached. The trip parameters are:
(1)  High linear power level, (2) High logarithmic power level, (3)  High local power density, (4)  Low departure from nucleate boiling ratio (DNBR),
(5) High pressurizer pressure, (6) Low pressurizer pressure, (7) Low steam generator No. 1 water level, (8)  Low steam generator No. 2 water level, 7-3
 
(9)  High steam generator No. 1 water leve 1 ,
(10) High steam generator No. 2 water 1 eve 1 ,
(11) Low steam generator No. 1 pressure, (12) Low steam generator No. 2  pressure, (13) High containment pressure.
Four protection channels are provided for each of the trip parameters listed above. Whenever a trip parameter reaches the predetermined trip value, the channel bistable is tripped resulting in the deenergization of the channel trip relays. Contacts from the trip relays are arranged into six logic matrices representing all possible two-out-of-four combinations for any of the four redundant protective channels. Each logic matrix contains four output relays. Contacts of these relays are used to form four trip paths that con-trol the power to the trip coils of the circuit breakers to the control ele ment drive mechanism (CEDM) power supplies. Eight circuit breakers are provided.
They are arranged in four groups, consisting of two breakers in series in each group, to control the power from four parallel motor-generator sets. Opening one breaker in each of the four groups will remove the power to both CEDM power supplies allowing all of the control element assemblies (CEA) to drop into the core. Summarizing, coincident trip signals from two protective channels for the same trip parameter will scram the reactor.
In addition to the automatic trip of the reactor described above, means are also provided for a manual trip by the operator. Two independent sets of trip pushbuttons are provided, each consisting of two pushbuttons. Actuation of the pushbuttons of either set will trip the reactor. The two pushbuttons in a set need not be depressed simultaneously.
The protective channels for the high local power density and the low DNBR utilize digital core protection calculators to generate a trip signal. The remainder of the RPS uses hardwired analogue circuitry.
The reactor trip system for Waterford 3 as described in the FSAR is functionally the same as that provided for the previously reviewed AN0-2 plant. The differ ences between the designs of these two plants, deviations from the design reviewed for the CP, and other areas of concern are discussed in the following sections.
7.2.2 Differences From Preliminary Design The RPS described in the FSAR has been significantly modified from the originally proposed system reviewed for the CP (PSAR review). The changes, listed by the applicant, are as follows:
(1)  The high local power density trip is added.
(2) The thermal margin/low pressure trip is replaced by the low DNBR trip.
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(3) The core protection calculators are added to provide the high local power density and low DNBR trips; and the thermal margin/low pressure calculator is eliminated.
(4)  The low reactor coolant flow trip function is incorporated in the low DNBR trip.
(5)  Reactor coolant flowrate is calculated by use of reactor coolant pump speed instead of being inferred by differential pressure measurement.
(6)  Control element assembly position signals are incorporated in the RPS.
Two CEA calculators are provided.
(7) A high logarithmic power level trip has replaced the high rate of change trip.
These design changes provide additional operating flexibility and enhanced protection for CEA position deviation events. As discussed in Section 7.2.1 above, the final design of the RPS for Waterford 3 is the same as that of the AN0-2 plant, except for changes in the core protection calculators discussed in the following section. On this basis the staff finds the design acceptable.
Electrical transmitters which provide RCS pressure sensing for the RPS are located in insulated cabinets inside containment. Impulse lines connect these pressure transmitters to the pressurizer. Nonqualified heaters and associated controls have been installed in these cabinets to control temperature and humidity. Credit for these heaters is not taken in the safety analysis. The concern was raised that failure of the heater controls, so that the cabinet heaters were in continuous operation, could potentially degrade the pressure transducers and in turn invalidate the safety analyses. The applicant will reduce the size of these electrical heaters so that continuous operation of these heaters will not degrade the qualification and calibration of the transducers.
7.2.3 Core Protection Calculators The final design of the RPS utilizes a digital computer-based system, consisting of four core protection calculators, for deriving the low DNBR, and the high local power density trip functions. As stated by the applicant, the core protection calculator system for Waterford 3 is functionally the same as that provided for the AN0-2 plant which was reviewed extensively by the staff.
Since, however, the applicant has indicated some changes because of different number of control element assemblies, the staff requested that the applicant provide a detailed comparison of the design of the Waterford  3 and AN0-2 core protection calculator systems (Q 032.7). The applicant 1 s response included the following statements:
(1) The hardware qualification and design criteria are the same for Waterford 3 and AN0-2. Minor changes exist in cable lengths. Also the number of CEAs is different.
(2)  The CPC DNBR calculations will be derived from the CE-1 correlation (design code TORC) instead of the W-3 correlation (design code COSMO) used for AN0-2.
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(3) The core protection/core element assembly calculator (CPC/CEAC) algorithms will be modified to reflect the change in the number of CEAs and CEA subgroups.
(4) The CPC/CEAC data base constants are subject to change from AN0-2 to Waterford 3, since a large number of these constants depend upon specific core and coolant system characteristics.
The applicant has also stated that the CPC/CEAC software for Waterford 3 will include improvements in software design that are based on inplant system experience for SONGS-2 & 3 and AN0-2. All software changes will be performed in accordance with 11 CPC Protective Algorithm Software Change Procedure CEN-39(A)-P, Revision 2 11 and Supplement 1-P, Revision 01. This procedure was reviewed and approved by the staff on the AN0-2 docket.
All of the differences in the CPC software between AN0-2 and Waterford 3 will be reflected in the Waterford 3 Functional Descriptions, Software Specifica tions, and assembly language program listings. NSSS vendor changes to the CPC software are reviewed in conjunction with staff review of FSAR Section 4.4, Core Thermal Hydraulic Design. Applicant changes to the CPC software are to be restricted by plant technical specifications.
The CPCs were not reviewed, per se, at Waterford 3. The staff has taken the operating experience of AN0-2, the previous review, and acceptance of the AN0-2 CPCs, and the similarity of the Waterford 3 and AN0-2 CPCs, into account in reaching this decision.
The conclusions of the acceptability of the CPCs at Waterford 3 are based on the fo11owing:
(1) With the exception of Position 20 which addresses data links between the CPC and the plant computer, the applicant is to meet the requirements on CPCs in Table 7.1 of NUREG-0308, "Safety Evaluation Report, Arkansas Nuclear One, Unit 2. 11 (2) The data links between the plant computer and the CPCs may be connected only if the plant technical specifications include provisions to assure that (a) plant procedures shall be in effect to control modifications to CPC addressable constants, (b) these procedures are consistent with methods described in the bases to the technical specifications, (c) CPC addressable constants and their physically realistic allowed ranges (i.e., upper and lower bounds) are identified in the technical specifica tions, (d) values of addressable constants outside the allowed range are not to be entered without approval of the plant safety committee, (e) an independent verification shall be conducted to confirm that addressable constant modifications have been made as approved by the plant safety committee or the engineering staff (whichever is applicable), and (f) modifications to the CPC addressable constants based on information obtained through the plant computer data links shall not be made without approval of the plant safety committee.
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(3) CPC operating experience at AN0-2 and CPC environmental tests indicate a sensitivity of the CPCs to fluctuations, and extremes in thermal environ ment. The Waterford 3 Technical Specifications will, therefore, require CPC functional tests to confirm continued operability of each CPC channel whenever the CPC cabinet thermal environment exceeds allowable ranges.
The allowable ranges will be justified on the basis of environmental tests of the CPCs and CPC operational experience and AN0-2.
The implementation of the CPC design including both hardware and software will be confirmed during the CPC test program. The staff will audit the test program to verify acceptable performance during these tests.
With implementation by the applicant of the three positions stated above and successful completion of the test program, NRC considers the CPC design acceptable.
7.2.4 Steam Generator and Pressurizer Water Level Steam generator water level, both low and high, is used as a trip parameter in the reactor protective system. The low steam generator water level is also one of the parameters in the engineered safety features actuation system (ESFAS). The pressurizer water level signal is not a parameter of the plant protection system but it is a variable in the post accident monitoring instru mentation system and as such is safety-related.
The level measurement system for Waterford 3 uses level transmitters that are connected to the steam generators or the pressurizer by an open column reference leg. A concern has been raised previously on similar systems, !EB 79-21, regarding the effect on the measurement accuracy caused by the heatup of the reference leg because of a high energy line break (HELB) inside containment.
This effect would cause the indicated level to be higher than the actual level, resulting in erroneous information to the protection and control systems and to the operator. In addition, an error can be introduced in the level measurement by changes in steam generator and/or pressurizer bulk fluid pressure and temperature.
The applicant has analyzed the Waterford 3 level measurement system and pro vided correction tables to be used by plant operators to account for reference leg heatup and varying fluid pressure effects. The effects of flashing and hydrogen effervescence are not accounted for in these tables. The applicant states that in applying the level corrections, the operators will be trained to assume that the reference leg temperature is at the highest containment temperature reached from the beginning of the event.
The actual setpoints for the low steam generator water level trips have not yet been selected. The applicant states that the methods used for determining the trip setpoints will ensure that the signal initiates the action required by the plant safety analyses throughout the range of ambient temperatures encountered by this instrumentation, including accident conditions. The staff notes that, in the course of the initial phase of an accident, during which the steam generator tubes are covered, and during which sensed level may be in error due to the level sensor reference leg environment, the heat removal rate is governed by flashing, i.e., by the safety relief valve setpoint, and is 7-7
 
relatively insensitive to the emergency feedwater mass addition. With the present arrangement, the operator has to perform the following:
(1) Review the containment temperature history; (2) Decide which is the applicable peak containment temperature; (3) Make the necessary level set-point correction; (4) Monitor the proper auxiliary feedwater flow rate.
All of these steps have to be done in an atmosphere of tension and confusion due to the accident.
The human engineering aspect of the display function and related actions for this system is addressed by the staff in Section 22 of this SER.
The staff notes that the use of a microprocessor (on the level of on-line explicit equation) would relieve the operator of steps 1. through 3. as listed above. If the mid-point reference leg water temperature (or even pipe-wall temperature at that location) would be fed to the microprocessor, then, direct on-line read-out of the bulk water level (in the steam generator and/or pressurizer) would be accomplished thus replacing the set-point corrections.
7.2.5 Independence of Redundant Power Supplies 7.2.5.1 Reactor Protection System Power Supplies The applicant has proposed to operate the reactor protection system with one of four channels in bypass. The system would then function as a two of three channel protective system. (With one channel tripped, the system would function as a one of three channel protective system.) The proposal is based on asserted four channel independence. To demonstrate independence, the applicant must demonstrate separation of power supplies, logic, and sensors. Waterford 3 has been designed as a two battery system, that is, the four protective channels obtain power from four separate vital ac instrument buses, which in turn obtain power from two ac/dc power divisions. Hence, the demonstration of four channel independence is, a priori, incomplete. As was previously reviewed and concluded by the staff on similar designs, NRC will require that the RPS be operated as a four channel system. Separation of pressure sensors to RPS channeis was discussed at iength during a drawing review of April 14, 1981.
The applicant showed separation of pressure sensors using schematics and physical layout drawings. Physical separation of sensors and logic was demonstrated during a site visit.
NRC requires (by plant technical specification) that the RPS be used as a four channel system with bypass of a known defective channel for no more than 48 hr, and requires trip of a known defective channel after 48 hr.
7.2.5.2 Logic Matrix Power Supplies To prevent a reactor trip on the loss of a single bus, each of the six RPS logic matrices are powered by two redundant de power supplies which are each connected to a separate uninterruptible ac power bus. The same approach is also taken in the ESFAS, to prevent inadvertent actuation of ESF equipment.
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This arrangement challenges the isolation and hence independence of the uninter ruptible ac power buses. The same configuration is employed at AN0-2. A test program was conducted to demonstrate that the de power supplies are valid isolation devices in conjunction with the AN0-2 review. The applicant has confirmed that the power supply testing performed for AN0-2 is applicable to the Waterford 3 power supplies.
Based on this confirmation of the applicability of the power supply testing, the Waterford 3 power supply configuration is acceptable.
7.2.6 Testing As described by the applicant, the complete reactor trip system (RTS) can be tested without having to disconnect any of the components or without having to rely on the use of jumpers. The applicant also has committed in the technical specifications to perform at certain intervals the RTS response time test.
These tests include also the sensors, except for the neutron detectors. The response time of the neutron flux signal portion of the channel is to be measured from detector output or input to the first electronic component in the channel.
The staff considers that these tests, in accordance with the plant technical specifications (including test intervals), meet the intent of Regulatory Guide 1.118.
7.2. 7 Bypasses Trip channel bypass can be initiated manually by a controlled access switch.
Interlocks allow only one channel for any one type trip to be bypassed at one time. The bypass is manually initiated and manually removed. In addition, operating bypasses are provided for the ONBR and local power density, pressurizer pressure, and high logarithmic power level trips at established power levels.
These bypasses are initiated manually and are automatically removed whenever the permissive conditions no longer exist (see Section 7.2.5.1).
7.2.8 Conclusions The reactor trip system includes the initiating circuits, logic, bypasses, inter locks, redundancy, diversity, and actuated devices utilized to implement reactor shutdown. The scope of the review included the descriptive information function logic diagrams, schematics, and control wiring diagrams, and physical arrangement drawings.
Subject to resolution of open item 5 described in Section 7.1.2, the staff can conclude, with reasonable assurance, that the RTS conforms to applicable regulations, guides, technical positions, and industrial standards, stated in SRP Section 7.1, and is therefore acceptable.
7.3 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM 7.3.1 System Description The engineered safety features actuation system (ESFAS) is part of the plant protection system. ESFAS generates signals to actuate ESF equipment. The signals generated by the ESFAS and the associated trip input parameters are:
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(1) Safety injection actuation signal (SIAS)--low pressurizer pressure or high containment pressure.
(2) Containment cooling actuation signal (CCAS)--same as for the SIAS above.
(3)  Containment isolation actuation signal (CIAS)--same as for the SIAS above (as committed by the applicant). See Section 7.3.3 below.
(4) Containment spray actuation signal (CSAS)--high containment pressure coincident with SIAS signal.
(5) Main steam isolation signal (MSIS)--low steam generator pressure, No. 1 or No. 2.
(6) Emergency feedwater  actuation signal to steam generator No. 1 (EFAS-1)-
low steam generator  No. 1 level coincident with either no low pressure in steam generator No. 1 or high differential pressure between the steam generators with the  higher pressure in steam generator No. 1.
(7) Emergency feedwater actuation signal to steam generator No. 2 (EFAS-2)-
identical to above, except the conditions are for steam generator No. 2 versus steam generator No. 1.
(8) Recirculation actuation signal (RAS)--low refueling water storage pool (RWSP) level.
Each of the trip parameters listed above is monitored by four redundant protective channels. The actuation system logic is configured in the same manner as for the reactor trip system (see Section 7.2) with the four trip path outputs arranged into two redundant, two-out-of-four selective logics.
Each redundant logic actuates one of the two redundant groups of corresponding ESF equipment. Summarizing, coincident trip signals from two protective channels for the same trip parameter will actuate both trains of corresponding ESF equipment.
As stated by the applicant, the ESFAS for the Waterford 3 plant is functionally the same as that for AN0-2. Nevertheless, in its review, the staff found certain areas of concern. These areas are discussed below. A discussion of changes in the preliminary design is also provided below.
7.3.2 Differences From Preliminary Design The applicant identifies the following changes from the preliminary design provided in the PSAR that was reviewed for the CP:
(1) The emergency feedwater actuation signal has been added.
(2) Variable setpoints for initiation of SIAS, CCAS, and CSAS on low pressur izer pressure have been added.
(3) Variable setpoints for initiation of MSIS on low steam generator pressure are added.
(4) The group testing capability is added.
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The variable setpoint of the low pressurizer pressure trip allows controlled pressure reductions, such as shutdown depressurization, without initiating safety injection, containment cooling, or containment spray. The lowering of the trip setpoint is accomplished manually in limited steps. On increasing pressure, the trip setpoint is raised automatically. The same arrangement is used also for the variable setpoint for the low steam generator pressure trip (the variable setpoint trip for the steam generator pressure is also provided for the reactor protective system).
The components in various ESF systems are divided into groups. Selection is made so that actuation of a certain group will not affect normal plant operation.
Providing the group testing capability allows testing of various components with the plant at power.
The revised ESFAS for Waterford 3, as discussed in Section 7.3.1 above, is functionally the same as that provided for the AN0-2 and approved by the staff. On this basis the changes made in the preliminary design are considered acceptable.
7.3.3 Diversity of Actuation Signals The applicant has committed itself to provide diversity in the generation of the containment isolation actuation signal by adding the low pressurizer pressure to the high containment pressure originally proposed as the sole variable. With this change, functional diversity is provided for the SIAS, CCAS, and CIAS signals (items 1 thru 3 in Section 7.3.1 above). The remaining ESFAS, items 4 thru 8 in Section 7.3.1 above, depend on monitoring of a certain single variable. For example, CSAS depends on high containment pressure.
Initiation of CIAS by low pressure is shown in Amendment 17 of the app1icant 1 s FSAR. Electrical diagrams are not available to date. When drawings are sub mitted, the staff will confirm whether or not the circuit modifications meet the electrical criteria of Section 7.1 of the applicant 1 s FSAR.
7.3.4 Emergency Feedwater System The emergency feedwater system is automatically initiated by emergency feedwater actuation signals (EFAS) 1 and 2. These signals are generated by detection of low steam generator level and steam generator differential pressure. Feed only good generator logic is employed. EFAS is part of the ESFAS and meets the requirements of Task Action Pian item II.E.1.2.
As described in Section 7.3.1.1.6 of the FSAR, opening of the emergency feed water valves to the intact steam generator is initiated (EFAS) when the water level decreases below the low level trip setpoint. After the level rises above this setpoint, the valves will be closed. EFAS does not 11 seal in.u The staff is concerned about apparent oscillation of steam generator water level at the low level setpoint and the suitability of the emergency feedwater isolation valves and associated piping for this type of service. The applicant has stated that the emergency feedwater control system design has not been finalized (SER Section 7.1.2 open item 1). The staff will report resolution of this concern in a supplement to this report.
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The current proposed plant technical specifications prohibit bypass of more than one of four 1ike instrument channels but do not prohibit combinations of bypass among process variables which would alter the coincident logic such that EFAS would be placed in a 2-of-2 mode. Such action is clearly unacceptable.
The staff will require technical specifications which prohibit simultaneous bypass of more than 1 of the 12 instrument channels (4 steam generator differential pressure channels, 4 steam generator level channels, and 4 steam generator pressure channels). These channels provide input to the EFAS coinci dent logic for EFAS 1. Analogously, the simultaneous bypass of more than 1 of the 12 instrument channels associated with EFAS 2 is also to be prohibited.
7.3.5 Resetting of the ESFAS Signals IEB 80-06 addresses reset and override of ESFs. The applicant will submit additional information in response to IEB 80-06 (SER Section 7.12 open item 3).
7.3.6 Transfer of Spare Engineered Safety Feature Pump Waterford 3 is equipped with a spare high pressure safety injection pump, HPSI AB. Installation of HPSI AB is not a regulatory requirement. The pump is installed to avoid administrative shutdowns associated with operability of redundant HPSI trains. HPSI AB may be aligned to function in HPSI Train A or Bin 1ieu of the dedicated HPSI A or B should HPSI A or 8 be removed from service for maintenance. HPSI AB takes power from 4.16 kV bus 3AB3-S which in turn may be connected to diesel-backed buses 3A3-S or 383-S. HPSI AB is commanded to start by SIAS A or B. A single mode switch and several relays and relay contacts are employed to initiate HPSI AB, disable HPSI A or B, and ensure HPSI valve lineup consistent with use of HPSI AB.
The staff was concerned that: (1) the system would compromise separation of redundant ESF channels, and (2) the system did not provide adequate indication of successful transfer of control logic. The system was reviewed during NRC's site visit. It was concluded that adequate separation has been maintained.
The applicant will add indicating lights to show successful transfer of the control logic. In addition, the staff will require (by plant technical speci fication) a system level test of the high pressure ECCS system (pumps, power, control, valve lineup) when the HPSI AB pump is placed in service and when it is removed from service.
7.3. 7 Conclusions The ESFASs include the instrumentation and controls used to detect a plant condition requiring operation of an ESF system, to initiate action of the ESF, and to control its operation. The scope of review of the ESFAS included instrument schematics and logic diagrams and control wiring diagrams and descriptive information for the ESFAS and for those auxiliary supporting systems that are essential to the operation of either the ESFAS or the ESF systems themselves.
With resolution of the open items 1 and 3 discussed in Section 7.1.2, the staff can conclude, with reasonable assurance, that the design of the ESFAS 7-12
 
conforms to applicable regulations, guides, branch technical positions, and industry standards, stated in SRP Section 7.1, and is, therefore, acceptable.
7.4 SYSTEMS REQUIRED FOR SAFE SHUTDOWN 7.4.1 General Instrumentation and control {I&C) systems that are required to establish and maintain a safe shutdown condition for the plant are identified in Section 7.4 of the FSAR. In many cases these I&C systems are utilized in the performance of normal and emergency plant operations and as such are not exclusively utilized for the safe shutdown function. The systems considered by the applicant to be required for safe shutdown are:
(1) Emergency feedwater system, (2) Atmospheric steam dump valves, (3) Shutdown cooling system, (4) Chemical and volume control system, boron addition portion, (5) Emergency shutdown from outside the main control room.
The following ESF support systems are also required to function:
(1) Component cooling water system, (2) Onsite power system, including diesel generator system, (3) Heating, ventilating, and air conditioning systems for areas containing systems and equipment required for safe shutdown, (4) Diesel fuel oil storage and transport system.
Although the applicant does not consider, and the staff concurs, that all the criteria of the IEEE Standard 279 is directly applicable to the systems required for safe shutdown, the requirements of Section 4 of that standard were followed in the design. As stated by the applicant, the design provides redundancy and separation for the systems to meet the single failure criterion. Also, capability is provided for test and calibration to verify that all automatic and manual actuation and control devices are operable.
The applicant is required to perform a safe shutdown analysis in accordance with 10 CFR Part 50, Appendix R. This analysis will identify equipment needed to obtain and maintain cold shutdown after a fire and identify instrumentation and control needed for emergency shutdown outside the control room (SER open item 4). This analysis will either confirm the adequacy or require the modi fication of the list of systems now identified as required for safe shutdown.
The staff will review the instrumentation and control in the control room and at the auxiliary control panel, of those systems identified in the safe shutdown analysis and report staff findings in a supplement to this report.
The results of NRC's review of specific areas of the design follow.
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7.4.2 Shutdown Cooling System The shutdown cooling system (SOCS) is a low pressure system located outside of containment which interfaces with the RCS. During the shutdown cooling opera tion, a portion of the reactor coolant is circulated through the shutdown cooling heat exchangers via the low pressure safety injection pumps. Either of the two pumps in combination with the associated shutdown heat exchanger is sufficient for proper system operation. The electrical devices needed for the operation of these systems are supplied from redundant and independent Class IE power sources.
Overpressurization and consequential failure of the SOCS would result in a LOCA outside of containment. Overpressure protection is provided by redundant isolation valves. There are two SOCS suction lines, one in RCS loop No. 1 and one in RCS loop No. 2, each possessing three in-series isolation valves. Two of these valves in each of the lines are located inside the containment, the third valve is located outside the containment. Valves located inside the containment are provided with interlocks to prevent opening and to initiate automatic closure whenever the coolant pressure exceeds a preset value. There are four power supplies for these valves, two ac and two de, divided into two redundant systems, one for the valves of each of the two suction lines. This configuration provides redundancy and meets the single failure criterion on loss of a power source.
The isolation valve interlocks, described in Section 7.4.1.3 and also in Section 7.6.1.1 of the FSAR, prevent opening of the valves until the pressure decreases below 377 psig and close the valves automatically when the pressure reaches 500 psig. Pressurizer pressure is utilized as an input to the interlock circuits. Four independent pressure monitoring channels are provided, one for each of the isolation valves. Pressure sensor equipment diversity, two sensors from each of two manufacturers, has been provided and is in conformance with BTP ICSB 3.
7.4.3 Emergency Shutdown From Outside the Control Room The auxiliary control panel, located outside the main control room, contains I&C to enable the operator to achieve and maintain the plant in the hot standby condition in the event that the main control room must be abandoned. The transfer of controls from the main control room to the auxiliary control panel is done manually by means of transfer switches mounted on auxiliary panels.
Operation of the transfer switches is annunciated in the control room. The control room, transfer switches, and auxiliary control panel are physically separated. Physical separation adequacy is addressed in the staff's fire protection review discussed in Section 9.5.1 of this SER.
A safe shutdown analysis is to be conducted in accordance with 10 CFR Part 50, Appendix R. This analysis will identify equipment needed to obtain and main tain cold shutdown after a fire. This study will identify I&C needed for shutdown from outside the control room and will be used to demonstrate conformance with GDC 19.
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7.4.4 Conclusions The review of systems required for safe shutdown includes the sensors, initiating circuitry, logic elements, interlocks, redundancy features, actuated devices, and auxiliary devices that provide the I&C functions that prevent the reactor from returning to criticality and provide means for adequate residual heat removal from the core, containment, and other vital components and systems.
The scope of review of systems required for safe shutdowr1 for the plant included instrumentation schematics and logic diagrams and control wiring diagrams and descriptive information for these systems and for auxiliary systems essential for their operation. The review has included the applicant's proposed design criteria, design bases, and analyses.
Subject to resolution of open item 4 discussed in Section 7.1.2, the staff can conclude, with reasonable assurance, that the design of systems required for safe shutdown conforms to the applicable regulations, guides, technical positions, and industry standards stated in SRP Section 7.1, and is, therefore, acceptable.
7.5 SAFETY-RELATED DISPLAY INSTRUMENTATION 7.5.1 General The safety-related display instrumentation provides information to the operator to ascertain the status of the reactor core, reactor coolant system, containment, and safety-related process systems so that the operator may perform manual actions important to plant safety. The applicant has tabulated the display instrumentation in the following categories:
(1)  Plant process display system, (2) Reactor protective system monitoring, (3) Engineered safety features (ESF) system monitoring, (4) ESF support systems instrumentation, (5) Control element assembly (CEA) position indication, (6) Auxiliary control panel instrumentation (see Section 7.4),
(7) Postaccident monitoring instrumentation, (8) Bypass and inoperable status indication, (9) Safety parameter display system (SPDS).
Information is displayed in the main control room using hardwired displays and computer-driven cathode ray tube (CRT) displays. Audible alarms and visual annunciators are provided to alert the operator to deviations from normal operating conditions, such as pre-trip alarms and trips of the plant protection system, and the status, malfunction, bypass, or override conditions of safety systems.
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The results of the staff's review are presented below.
Input signals for these information display systems is obtained in part from safety systems. Where 11 nonsafety 11 displays are  employed, qualified buffers are used to separate "safety" and 11 nonsafety 11 circuits. These buffers often are simple electrical contacts attached to actuating devices in such a way that physical separation in accordance with Regulatory Guide 1.75 is maintained.
Information circuits are also segregated in dedicated closed cable trays.
7.5.2 Post Accident Monitoring Instrumentation The post accident monitoring instrumentation provides information to the operator to monitor and cope with post accident conditions.
During the review, the staff found inadequacies in the post accident monitoring information system design. The staff requested the applicant to inform NRC of its intent to meet the requirements of Regulatory Guide 1.97, Revision 2, December 1980, Section D, Implementation, which states that "Plants scheduled to be licensed to operate before June 1, 1983 should meet the requirements of NUREG-0737 and the Commission Memorandum and Order (CLI-80-21) and the schedules of these documents or prior to the issuance of a license to operate, whichever date is later. The balance of the provisions of this guide should be completed by June 1983. 1 1 The applicant has committed itself (Amendment 17) to comply with the intent of Regulatory Guide 1.97, Revision 2, by the above implementation dates. Regulatory Guide 1.97, Revision 2, is explicit (proscriptive) in nature. This will be a condition of the license. Hence, the staff considers this issue satisfactorily resolved.
7.5.3 Bypass and Inoperable Status Indication In NRC's review of the inoperable status indication system, as originally described in the FSAR, the staff found that no indication was provided for a number of systems that are considered to be important to safety. These included such systems as the containment cooling system, combustible gas control system, diesel fuel oil storage and transfer system, and HVAC systems for safety-related equipment areas. The applicant has revised the system to provide inoperable status indication for these systems, and the staff considers this issue resolved.
The indicators on the inoperable status panel are divided into three groups according to the safety systems' dependence on a common electric power supply.
These are SA, SB, and SAB. The display lights are back lit, maintained posi tion pushbuttons. The lights have a split architecture. The upper light is actuated by the plant computer. The operator can extinguish the light by depressing the respective pushbutton. This actuates simultaneously the lower light. This light again can be extinguished only by the operator by depressing the respective pushbutton. Hardwired status indication of major components is also displayed in the control room.
The applicant has provided the criteria to be used in the selection of equipment to be monitored, and provided the criteria to be employed in the display of inter-relationships and dependencies on the equipment at subsystem and system levels. Supporting systems such as motive power and component cooling are to be monitored, in addition to fundamental engineered safety features. It is 7-16
 
noted that the plant computer at Waterford 3 has expansive surveillance and logic decision capability and may be used to perform this function.
Prior to plant operation, NRC is to inspect operation of this status indication system, including the display of the inter-relationship of supporting systems.
The human engineering aspects of the display function for this system is addressed under Item I.0.1 of Section 22 of this report.
7.5.4 Safety Parameter Display System In response to the guidelines of NUREG-0696, "Functional Criteria for Emergency Response Facilities, 11 the applicant has proposed to provide for Waterford 3 a plant safety parameter display system (SPDS). The proposed SPDS consists of plant computer-driven CRT displays on the main control board. Duplication of the SPDS displays is to be provided in the Technical Support Center and the Emergency Operations Facility.
A computer-driven CRT display system was selected primarily on the basis of flexibility. This includes flexibility in changing the display formats, choice and grouping of displays by operator, and flexibility for incorporation of advanced concepts and techniques in the future. The applicant has committed to obtain an independent organization to evaluate the capability of the existing plant computer systems in meeting the design criteria set by NUREG-0696 for the SPDS. Also, a coordinated computer power supply reliability study is to be performed. The staff will review the evaluation results and include its findings in a supplement to this report.
7.5.5 Conclusions Subject to resolution of the open items 2, 3, and 4 discussed in Section 7.1.2, the staff can conclude with reasonable assurance that the design of safety related display instrumentation conforms to applicable regulations, guides, technical positions, and industry standards, stated in SRP Section 7.1, and is, therefore, acceptable.
7.6 ALL OTHER INSTRUMENTATION SYSTEMS REQUIRED FOR SAFETY 7.6.1 General The systems iisted by the applicant in this category are:
(1) Shutdown cooling system interlocks, (2) Safety injection tank isolation valve interlocks, (3) Refueling interlocks, (4) Spent fuel pool cooling and cleanup system, (5) Containment purge isolation signal, 7-17
 
(6) Reactor coolant system leak detection system, (7) Area and process radiation monitoring, (8) Containment vacuum relief system, (9)  Low temperature overpressure protection.
The shudown cooling system interlocks, included in this section, are also discussed in Section 7.4 of the FSAR. The NRC review of these interlocks is provided with the evaluation of the shutdown cooling system in Section 7.4.2 of this report. The refueling interlocks, although listed in the required-for safety category as required by the Standard Review Plan, are considered by the applicant as not safety related since no credit is taken for these interlocks in accident analyses. The results of the staff review of the remaining systems are provided below.
7.6.2 Safety Injection Tank Isolation Valve Interlocks Four safety injection tanks (SITs) are used to flood the core with borated water following depressurization as a result of a LOCA. During normal plant operation, each SIT is isolated from the RCS by two check valves in series.
In addition, a motor-operated isolation valve on each safety tank discharge is provided. Interlocks, provided by pressurizer pressure measurement channels, prevent closing the valves until the pressure decreases below 400 psig, and automatically open the valves when the pressure reaches 500 psig. In addition, the valves will open automatically on SIAS (see Section 7.3).
The applicant considers the requirements of IEEE Standard 279 as not directly applicable to the valve interlocks. The applicant has, however, provided analysis of how the design meets the requirements of Section 4 of IEEE Standard 279. The valves are locked open and the valve motor breaker handle is padlocked in the open position. Valve position indicating lights are provided in the main control room. An audible alarm is actuated whenever the pressure is above 500 psig and a valve is not fully open. The position indica tion and audible alarm are independent of the motor control power. The design as described by the applicant follows the recommendations of BTP ICSB 4 and ICSB 18, and is, therefore, acceptable.
7.6.3 ContainmentPurge System The containment atmosphere purge system consists of a containment air makeup unit and a containment purge exhaust which is connected to the exhaust portion of the reactor auxiliary building's normal ventilation system. Radiation monitors located inside the containment generate a containment purge isolation signal to the purge system isolation valves. Closing the valves prevents purging the containment when the radiation is above an acceptable level. The applicant has described conformance of this system to IEEE 279-1971, Section 3.
The system is testable from the control room. On these bases the staff finds the system acceptable.
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7.6.4 Reactor Coolant System Leak Detection System The means provided for leak detection consist of instrumentation which can detect general leakage from the RCPB. The process variables that are monitored for detection of leakage include liquid level, flow rate, pressure, and tempera ture in various sumps, tanks, and fluid lines. Also the containment atmosphere is monitored for particulate, iodine, and gaseous radioactivity. Radioactivity in the containment atmosphere indicates the presence of fission products because of an RCS leak or leakage of a contaminated secondary fluid system.
The design of the Waterford 3 RCS leak detection system is consistent with the recommendations of Regulatory Guide 1.45 (May 1973). On this basis, the staff finds this system is acceptable.
7.6.5 Containment Vacuum Relief System A containment vacuum relief system has been provided for protection against loss of containment integrity under external loading conditions. Redundant air operated valves are powered by qualified air accumulators. Actuation signals are redundant, and powered from vital instrument buses. Annunciation is provided in the control room. The system is testable. The applicant has described conformance of this system with applicable sections of IEEE 279-1971.
On these bases the staff finds the system acceptable.
7.6.6 Low Temperature Overpressure Protection The overpressure protection of the RCS during low temperature conditions is provided by relief valves located in the shutdown cooling system (SOCS) suction lines. The relief valves are spring-loaded (bellows) type. There is no instrumentation associated directly with these valves. Computer indication is provided to alert the operator when the SOCS isolation valves may be opened.
Opening these valves manually aligns the SOCS relief valves to the RCS. The setpoints for the relief valves are such that the setpoints for the SOCS isolation valve interlocks will not be reached due to a low temperature over pressure event and the SOCS relief valves will remain aligned to the reactor coolant system (see Section 7.4.2 of this report on the isolation valve interlocks).
The use of redundant, mechanical relief valves provides a reliable low tempera ture overpressure protection system and is consistent with the requirements of GDC 15.
7.6. 7 Conclusions The staff concludes, with reasonable assurance, that the design of these systems conforms to applicable regulations, guides, technical positions, and industry standards, stated in SRP Section 7.1, and is, therefore, acceptable.
: 7. 7 CONTROL SYSTEMS NOT REQUIRED FOR SAFETY 7.7.1 General The I&C systems that are considered by the applicant as required for the control of the plant, but not essential for safety, are:
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(1) Reactor regulating system, (2) Boron control, (3) Pressurizer pressure control, (4) Pressurizer level control, (5) Feedwater control system, (6) Steam bypass control system, (7) Main turbine controls, (8) Core operating limit supervisory system, (9) Plant computer system, (10) In-core instrumentation system, (11) Ex-core neutron flux monitoring, (12) Reactor power cutback system, (13) Megawatt demand setter system.
The applicant has stated that the NSSS control systems for Waterford 3 are identical to those of AN0-2, except for some differences in the steam bypass system. The reactor power cutback system and the megawatt demand setter system are not provided for AN0-2.
: 7. 7.2 Differences From Preliminary Design Additions made to the preliminary design of the control systems, as listed by the applicant, are:
(1) Core operating limit supervisory system has been added.
(2) Megawatt demand setter system has been added.
(3) Movable detector system has been added to the incore instrumentation system.
The core operating limit supervisory system (COLSS) consists of process instru mentation and algorithms implemented by the plant computer to continually monitor the limiting conditions for operation on peak linear heat rate, margin to DNBR, total core power, and azimuthal tilt. COLSS is an automated aid to the operator who is charged with maintaining the plant within the limiting conditions for operation. The movable incore detector system will permit incore intercalibration of the fixed position incore neutron detectors. Both of the above systems are installed at AN0-2. These systems enhance data aquisition and on this basis these changes in the preliminary design are acceptable. The megawatt demand setter and the reactor power cutback systems 7-20
 
are unique to the Waterford 3 plant. A discussion of these systems is provided below. Also discussed below are the concerns regarding control system failures.
: 7. 7.3 Megawatt Demand Setter System and Reactor Power Cutback System 7.7.3.1 Megawatt Demand Setter System The megawatt demand setter (MOS) system monitors NSSS limits to assure that plant power output is consistent with actual NSSS operating conditions. The MOS accepts increase or decrease power load commands from either the automatic dispatch system remote station or from the operator at the local MDS panel.
This demand is compared with various NSSS operating limits including those available from COLSS. A load rate change consistent with the operating limits is then issued to the turbine digital electro-hydraulic control system. If conditions exist in which the turbine is limiting or the NSSS is limiting, or a failure renders the MDS system inoperative, the MOS system may be placed in an 1 off 11 mode or in a tracking mode until the specific condition is cleared.
1 7.7.3.2 Reactor Power Cutback System The reactor power cutback system is a control system designed to accommodate certain types of imbalances in the operation of the plant, by providing a 11 step" reduction in reactor power. This is accomp 1 ished by dropping one or several preselected groups of full-length control element assemblies simultane ously into the core. The reactor power cutback system also provides control signals to the turbine to rebalance turbine and reactor power following the initial reduction in reactor power, as well as to restore steam generator water level and pressure to their normal controlled values.
7.7.3.3 Basis for Acceptability The safety analyses have been performed assuming either automatic operation of the control systems, if automatic operation would tend to make the consequences of an event more adverse, or operation in a manual mode (control system disabled),
if automatic operation would tend to make the consequences of an event less severe. In this case, the MDS system and reactor power cutback system are assumed to be disabled.
Credit for operation of these systems is not assumed in the safety analysis.
Failures of these systems, in and of themselves, and exclusive of potential consequential failures (see SER Section 7.1.2, open item 8), are less severe than event sequences explicitly considered in the Waterford 3 safety analysis.
The staff considers addition of these systems acceptable.
The MOS system and the reactor power cutback system are first-of-a-kind systems.
Failures of these systems will challenge ESFs. Therefore, NRC requires that the applicant report (by submittal of a Licensee Event Report) inadvertent or spurious operation or malfunction (exclusive of testing) of these systems which challenge the ESFs including reactor trip. These reports (LERs) are to be submitted for at least the first two fuel cycles of operation. Subsequently, the applicant may review and submit the operating experience gained with these systems and request relief from the reporting requirement. This reporting requirement is to be made a condition of the OL.
7-21
: 7. 7.4 Loss of Power to Control Systems A concern was raised in IEB 79-27 regarding the loss of a non-Class lE power bus resulting in a consequential contro1 system malfunction and significant loss of information to the operator. The staff has requested the applicant to provide it with results of the Waterford 3 plant review with respect to IEB 79-27 (SER Section 7.1.2, open item 2). This evaluation will appear in a supplement to this report.
7.7.5 Control System Failures Following a High Energy Line Break IEB 79-22 addresses consequential control system failure following an HELB.
The staff requested (Q 030.37) the applicant to identify the control systems, if any, which will be subject to the environment resulting from an HELB and whose failure could impact the safety analyses. The applicant's response (Amendment 17, May 1981) is acceptable.
7.7.6 Single Failure of Control System Study The applicant has been requested to perform a study of single failures of the control system to ascertain if such single failures and subsequent consequential failures will lead to sequences more severe than analyzed in Chapter 15 of the FSAR (SER open item 6 in Section 7.1.2 and Unresolved Safety Issue A-47).
7.7.7 Conclusions The staff has reviewed the controls for systems not required for safety, to determine the effects of failures or malfunctions of these controls on the reactor protection system and other plant safety-related systems. With resolu tion of SER open items 2 and 6 in Section 7.1.2, the staff can conclude, with reasonable assurance, that failures or malfunctions of these controls should not be expected to degrade the capabilities of plant safety systems to any significant degree or to lead to plant conditions more severe than those for which the safety systems are designed.
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==7.8 REFERENCES==
Branch Technical Positions:
BTP ICSB 3 BTP ICSB 4 BTP ICSB 18 Combustion Engineering Report:
CEN-39(A)-P Rev. 2 Code of Federal Regulations:
10 CFR Part 50, Appendix R General Design Criteria:
GDC 15 GDC 19 Institute of Electrical and Electronics Engineers Standards:
IEEE 279 IEEE 279-1971 Louisiana Power & Light Report:
PSAR for the CP, Waterford 3 Office of Inspection and Enforcement Bulletin:
IEB No. 79-21 IEB No. 79-22 IEB No. 79-27 IEB No. 80-06 Regulatory Guides:
RG 1.45 RG 1. 47 RG 1.70, Revision 2 RG 1.75 RG 1.97, Revision 2 RG 1.118 USNRC Reports:
NUREG-0308 NUREG-0696 NUREG-0737 NUREG-75/087 7-23
 
NRC Commission Memorandum and Order CL180-21, May 27, 1980
*See Appendix B, Bib1iography, for complete citations and availability statements.
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8 ELECTRIC POWER SYSTEMS 8.1 GENERAL CONSIDERATIONS The requirements in GDC 5, 11 Sharing of Structures, Systems, and Components, 11 GDC 17, 11 Electric Power Systems, 11 and GDC 18, "Inspection and Testing of Electric Power Systems," contained in 10 CFR Part 50, Appendix A, and the review guidance in Regulatory Guide 1.6, 11 Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems," Regulatory Guide 1.9, 11 Selection of Diesel Generator Set Capacity for Standby Power Supplies, 11 Regulatory Guide 1.75, 11 Physical Independence of Electric Systems, 11 Regulatory Guide 1.63, 11 Electric Penetration Assemblies in Containment Structures for Light Water Cooled Nuclear Power Plants," Regulatory Guide 1.32, 11 Criteria for Safety-Related Electric Power Systems for Nuclear Power Plants, 11 and IEEE Standard 308-1974, "Criteria for Class lE Power Systems for Nuclear Power Generating Stations" served as the primary bases for evaluating the adequacy of the emergency power systems for Waterford 3.
The following subsections provide the NRC staff evaluation of the design criteria and design description in the FSAR.
8.2 OFFSITE POWER SYSTEM 8.2.l General Description The offsite power system is the preferred source of power for the plant. This system includes the grid, transmission lines, transformers, switchyard components, and associated control systems provided to supply electric power to safety related and other equipment. The safety function of the offsite power system (assuming that the onsite power systems are not available) is to provide suffi cient capacity and capability to assure that the specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary will not be exceeded, and to ensure that core cooling, containment integrity, and other vital functions will be maintained in the event of postulated accidents. The objectives of the NRC review are to determine that the offsite power system (1) satisfies the criteria set forth in Section 8.1 of this report, and (2) can reliably perform its design functions during normal operation of the plant, anticipated operational occurrences, and accident conditions.
Power is supplied from the main generator to the Waterford 3 switching station through two main transformers which are in parallel. From the switching station, two overhead lines transmit power to the Waterford 3 switchyard, which is the point of connection to the grid. Besides the above two lines, there are seven other 230 kV transmission lines connected to the switchyard. The switchyard is a double bus, breaker and a half, configuration.
Each line is designed to carry the full output o{ the main generator (1200 MVA) a 230 kV (nominai) and is outed fro the switchyard to the Waterford 3 switch ing station, 2 distance of 3430 ft, ove 2 common right of way. The lines are installed on 100-f: poles and space 12C ft apar so that if one line breaks 8-l
 
it cannot fall on the second line to create a double outage. Every 230-kV breaker in the switchyard and switching station has two trip coils. The de control power for each trip coil of a 230-kV breaker is fed from a different battery. The two main transformers are connected in parallel through an isolated phase bus, which is connected in turn to the main generator bus.
Isolated phase taps are used to connect the unit auxiliary transformers to the generator bus. The bus sections are rated 25-kV class, 150-kV basic impulse insulation level with forced-air cooling and air to water heat exchangers.
Links are provided in all bus ducts to enable the disconnection of all trans formers and the generator from the bus system. Two startup transformers are provided. The high voltage bushings of each transformer are connected through an overhead line to one of the motor-operated disconnect switches in the switch ing station.
Preferred (offsite) power from the startup transformers or from the unit auxiliary transformers is distributed to the nonsafety-related loads by two 6.9-kV buses (3Al and 381) and by two 4.16 kV buses (3A2 and 382). Power is distributed from the two 4.16-kV buses 3A2 and 382 to the ESF buses 3A3-S and 383-S. All safety-related loads are supplied from these two buses. A third 4.16-kV bus 3A83-S can receive power from either bus 3A3-S or 383-S but not from both simultaneously. This bus supplies power to third-of-a-kind equipment consisting of installed spares for certain equipment on the other safety buses. Either bus 3A3-S or 383-S can supply sufficient power to shut down the plant and to maintain the plant in a safe condition under normal and OBA conditions.
During normal operation, the plant load is supplied by the generator through the two unit auxiliary transformers (UATs). One winding of each transformer is connected to the 6.9-kV bus 3Al (381) and one winding of each transformer is connected to the 4.16-kV bus 3A2 (382). These four buses supply all electrical loads, including the engineered safety features (ESF) loads, within the plant. During startup or abnormal conditions, when the main generator is not capable of delivering rated voltage and frequency, the two startup trans formers (SUTs) supply all power required by the plant equipment. Whenever the generator goes on line and provides power to the UATs, the SUTs are disconnected from the buses, allowing the generator to carry the full load of the plant.
Bus transfer under normal startup and shut down conditions is done manually as a live overlapping synchronous transfer. After synchronism is verified by the synchronous check relay, the transfer can be made in both directions. Overlay of the two supply sources is kept to a minimum, because incoming breaker, on closing, trips the running breaker Bus transfer as a result of abnormal conditions is done automatically. The transformer protective devices in conjunction with the operation of the main generator lockout relay will initiate a fast dead transfer of the station auxiliaries from the UATs to the SUTs. The conditions required to close the secondary breakers of the SUTs are (1) operation of the main generator lockout relay, (2) rated voltage on the SUT buses, (3) both main generator oil circuit breakers were not manually tripped, (4) the UAT breakers were not tripped because of overcurrent relays, and (5) the phase angle between UAT and SUT secondary voltages is not more than +20 (lead) and no less than -20 (lag) electrical degrees.
8-2
 
The 230-kV switchyard, switching station and transformer connections provide Waterford 3 with two physically independent transmission circuits. This arrangement provides access to sufficient offsite power to assure that the specified acceptable fuel design limits and design conditions of the RCPB will not be exceeded and to ensure that core cooling, containment integrity, and other vital functions will be maintained in the event of postulated accidents.
The two physically independent transmission circuits provide Waterford 3 with two immediate access circuits--exceeding the minimum requirements of GDC 17.
8.2.2 Circuit Protection and Testability The Waterford 230-kV switchyard is provided with primary and backup differen tial protection for the east and west buses and on each Waterford transmission line. Breaker failure protection is provided for all line breakers. Trans mission lines between the switchyard and switching station are provided with primary and backup pilot fiber optics relaying that extends from the bus side of the switchyard breakers to the main transformer side of the switching station breakers.
Two channels of protection are provided for this system, each channel having its own hand reset lockout relay. Each channel provides full protection for all equipment, so that either protection system may be tested with the other in service, without requiring, or causing, generator shutdown.
Each lockout relay trips (1) both generator/main transformer breakers in the switching station, (2) generator field breaker, (3) turbine, (4) UAT secondary breakers (3Al-1, 381-1, 3A2-l, and 382-1), (5) main transformer cooling equipment, and (6) UAT cooling equipment. Should either generator/main-transformer breaker fail to trip, the associated line transfer trip (PM) relay is activated and this will trip the corresponding switchyard line breakers.
The SUTs are protected with differential sudden pressure and ground detector relays that activate a lockout relay. This lockout relay trips the transformer secondary breakers, activates the transfer trip (PM) relay which trips the associated, switching station 230-kV breakers, switchyard breakers, and automa tically opens the motor-operated transformer disconnect switch.
The design of the offsite power system including its protection schemes described above permits appropriate periodic inspection and testing of important features to assess the continuity of the systems, functionability and condition of their components. The components for the offsite power supply system are testable during reactor operation. The power circuit breakers are inspected, maintained, and tested on an individual basis; and allow the 230-kV to remain energized.
The systems will have a capability to periodically test the operability and functional performance of the components of the systems, and the operability of the systems as whole. The systems meet the requirements of GDC 18, and are acceptable.
8.2.3  Grid Stability Analysis The applicant has conducted a grid stability analysis to determine the effect of the loss of Nine Mile Point Steam Electric Station, the largest generating station on the system with 1800 MW of generation capacity. Generator angle 8-3
 
swing curves determined as part of the analysis show that none of the units affected by the outage swung more than 13 degrees following the disturbance. The results of the grid stability analysis show that the loss of Nine Mile Point Station presents no system stability problems for this system disturbance.
An analysis was made to determine the probable grid frequency decay rate that would result from system separation. The case assumed was loss of all grid system ties while importing 1500 MW into the South Louisiana area. The result of the study showed the initial frequency decay rate of less than 3 Hz/sec.
This is within the acceptable limit and is, therefore, acceptable.
8.2.4 Adequacy of Station Electric Distribution System Voltages Events at the Millstone station have shown that adverse effects on the Class lE loads can be caused by sustained low grid voltage conditions when the Class lE buses are connected to offsite power. These low voltage conditions will not be detected by the loss of voltage relays (loss of offsite power) whose low voltage pickup setting is generally in the range of 0.7 per unit voltage or 1ess.
The above events also demonstrated that improper voltage protection logic can itself cause adverse effects on the Class lE systems and equipment, such as spurious load shedding of Class lE loads from the standby diesel generators and spurious separation of Class lE systems from offsite power due to normal motor starting transients.
A more recent event at Arkansas Nuclear One and the subsequent analysis per formed disclosed the possibility of degraded voltage conditions existing on the Class lE buses even with normal grid voltages, because of deficiencies in equipment between the grid and the Class lE buses or starting transients experienced during certain accident events not originally considered in the sizing of these circuits.
Based upon these above events, the staff has developed the following four-part technical position:
(1)  In addition to the undervoltage scheme provided to detect loss of offsite power at the Class lE buses, a second level of undervoltage protection with time delay should also be provided to protect the Class lE equipment; this second level of undervoltage protection shall satisfy the following criteria:
(a) The selection of undervoltage and time delay setpoints shall be deter mined from an analysis of the voltage requirements of the Class lE loads at all onsite system distribution levels; (b) Two separate time delays shall be selected for the second level of undervoltage protection based on the following conditions:
('- l. ) The frst time delay should be of a duration that establishes the existence of a sustained degraded voltage condition (i.e.,
somethinQ 1onger than a motor starting transient). Following ths del2y, an alarm in the control room should alert the operator 8-4
 
to the degraded condition. The subsequent occurrence of an SIAS should immediately separate the Class IE distribution system from the offsite power system.
(ii) The second time delay should be of such a limited duration that the permanently connected Class lE loads will not be damaged.
Following this delay, if the operator has failed to restore adequate voltages, the Class lE distribution system should be automatically separated from the offsite power system. Bases and justification must be provided in support of the actual delay chosen.
(c) The voltage sensors shall be designed to satisfy the following appli cable requirements derived from IEEE Std. 279-1971, "Criteria for Protection Systems for Nuclear Power Generating Stations: 11 (i) Class lE equipment shall be utilized and shall be physically located at and electrically connected to the Class lE switchgear; (ii) An independent scheme shall be provided for each division of the Class lE power system; (iii) The undervoltage protection shall include coincidence logic on a per bus basis to preclude spurious trips of the offsite power source; (iv) The voltage sensors shall automatically initiate the disconnec tion of offsite power sources whenever the voltage setpoint and time delay limits (cited in item l.b.ii above) have been exceeded; (v) Capability for test and calibration during power operation shall be provided; (vi) Annunciation must be provided in the control room for any bypasses incorporated in the design.
(ct) The technical specifications shall include limiting conditions for operation, surveillance requirements, trip setpoints with minimum and maximum limits, and allowable values for the second-level voltage protection sensors and associated time delay devices.
(2) The Class lE bus load shedding scheme should automatically prevent shedding during sequencing of the emergency loads to the bus. The load shedding feature should, however, be reinstated upon completion of the load sequencing action. The technical specifications must include a test requirement to demonstrate the operability of the automatic bypass and reinstatement features at least once per 18 mos during shutdown.
In the event an adequate basis can be provided for retaining the load shed feature during the above transient conditions, the setpoint value in the technical specifications for the first level of undervoltage protection (loss of offsite power) must specify a value having maximum and minimum limits. The basis for the setpoints and limits selected must be documented.
(3) The voltage  levels at the safety-related buses should be optimized for the maximum  and minimum load conditions that are expected throughout the anticipated  range of voltage variations of the offsite power sources by appropriate  adjustment of the voltage tap settings of the intervening 8-5
 
transformers. The tap settings selected should be based on an analysis of the voltage at the terminals of the Class lE loads. The analyses performed to determine minimum operating voltages should typically con sider maximum unit steady state and transient loads for events such as a unit trip, loss of coolant accident, startup or shutdown; with the offsite power supply (grid) at minimum anticipated voltage and only the offsite source being considered available. Maximum voltages should be analyzed with the offsite power supply (grid) at maximum expected voltage concurrent with minimum unit loads (e.g., cold shutdown, refueling). A separate set of the above analyses should be performed for each available connection to the offsite power supply.
(4) The analytical techniques and assumptions used in the voltage analyses cited in item 3 above must be verified by actual measurement. The verifi cation and test should be performed prior to initial full power reactor operation on all sources of offsite power by:
(a) Loading the station distribution buses, including all Class lE buses down to the 120/208-V level, to at least 30%;
(b) Recording the existing grid and Class lE bus voltages and bus loading down to the 120/208-V level at steady state conditions and during the starting of both a large Class lE and non-Class lE motor (not concurrently);
Note: To minimize the number of instrumented locations, (recorders) during the motor starting transient tests, the bus voltages and loading need only be recorded on that string of buses which previously showed the lowest analyzed voltages from item 3 above.
(c) Using the analytical techniques and assumptions of the previous voltage analyses cited in item 3 above, and the measured existing grid voltage and bus loading conditions recorded during conduct of the test, cal culate a new set of voltages for all the Class lE buses down to the 120/208 V level; (d) Compare the analytical derived voltage values against the test results.
With good correlation between the analytical results and the test results, the test verification requirement will be met. That is, the validity of the mathematical model used in performance of the analyses of item 3 will have been established; therefore, the validity of the results of the analyses is also established. In general the test results should not be more than 3% lower than the analytical results; however, the difference between the two when subtracted from the voltage levels determined in the original analyses should never be less than the Class lE equipment rated voltages.
The following items (by numbers) address our evaluation of the Waterford 3 design for conformance with the corresponding position numbers noted above.
(1) There are two redundant and independent emergency buses and each has two levels of undervoltage protection: (a) loss of power and, (b) degraded grid voltage. The scheme for the first level undervoltage relays at 4.16-kV buses is provided by induction disc relays with inverse time characteristics, viz. lAV 55C. The relay contacts are combined in a three-out-of-three logic to generate a loss of voltage signal (L0VS) and in one-out-of-three logic to generate an alarm set at 90% of bus voltage. A complete loss of 8-6
 
offsite power will result in approximately a 2-sec delay in loss-of-voltage signal (LOVS) actuation. For sustained degraded grid voltage condition, the applicant has provided three instantaneous relays (type NGV23B) with timers. The degraded grid voltage protection relays are set at 88% of rated bus voltage with time delay of 10 seconds. The applicant has pro vided the voltage profile at the 480-V level when the voltage at the 4.16 kV bus dips to 88%. The voltage at the 480-V bus does not fall below the rating of the contactor. The staff finds this arrangement to be consistent with NRC position and, therefore, acceptable.
(2)  Load shedding at Waterford 3 is accomplished by undervoltage relays which are set so as not to trip during the diesel generator loading sequence.
A temporary lockout of the undervoltage relays is provided on the first two load blocks which is accomplished by electrically interlocking the sequencer with the undervoltage relay output signals. The signal remains blocked until the third signal from the sequencer (10 sec later) removes the undervoltage relays from the lockout condition. This arrangement is consistent with NRC requirements and, therefore, acceptable.
(3)  The transformer tap settings for Waterford 3 have been initially calculated by simulating the electric power supply and the load distribution character istics on the safety-related buses. These calculations verify that the voltage levels at the safety-related buses remain within acceptable limits by simulating the most adverse cases for the expected ranges of load con ditions and the anticipated voltage variations of the offsite power source.
This meets the staff's position and is, therefore, acceptable.
(4)  The safety-related bus voltage levels will be measured as part of the pre operational test program and during plant startup. Since the extreme condi tions assumed for the worst-case calculations described above cannot be readily configured, the voltages on the buses will be measured and verified to be within acceptable limits for several different existing load condi tions prior to initial reactor power operation. Documentation of these measurements and their verification will be available for NRC inspection as part of the startup test results. This is in accordance with our position and, therefore, is acceptable.
8.2.5 Conclusions On the basis of the staff's review and above evaluation, the offsite power system for Waterford 3 meets the requirements of GDC 5, 17, and 18 and is acceptable.
8.3  ONSITE EMERGENCY POWER SYSTEM 8.3.1 Alternating Current Power Systems The ac emergency onsite power system is a Class lE system that serves as a standby to the offsite power system. The safety function of the ac onsite emergency power system (assuming the offsite power system is not functioning) is to provide sufficient capacity and capability to assure that the struturs, systems, and components important to safety perform as intended. The obJect1ves of the NRC review are to determine whether the ac onsite emergency power system has the required redundancy, meets the single failure criterion, is testable,.
and has the capacity, capability, and reliability to supply power to all required safety loads in accordance with the requirements of GDC 5, 17, and 18.
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Preferred (offsite) power from the startup transformers or from the UATs is distributed to the nonsafety-related loads by two 6.9-kV buses (3Al and 381) and by two 4.16-kV buses (3A2 and 3B2). Power is distributed from the two 4.16-kV buses 3A2 and 3B2 to the ESF buses 3A3-S and 383-S. All safety-related loads are supplied from these two buses as described below. The ESF buses 3A3-S and 3B3-S may also receive power from diesel generators, should preferred power for buses 3A2 or 382 be unavailable.
The two 4.16-kV ESF buses 3A3-S and 383-S supply equipment essential for safe shutdown of the plant. These two buses receive power either from the nonsafety related buses 3A2 and 382 or from the diesel generators (3A-S and 38-S). A third 4.16-kV bus, 3AB3-S, can receive power from either bus 3A3-S or 3B3-S, but not from both simultaneously. This bus supplies power to third-of-a-kind equipment which is installed as spares to equipment on the other safety-related buses. Either bus 3A3-S or 383-S can supply sufficient power to shut down the plant and to maintain the plant in a safe condition, under normal and OBA condi tions.
The safety-related 4.16-kV circuit-breakers operate from 125-V de control power which is supplied by the safety-related 125-V de system of the appropriate division (A or B).
Each breaker may be remotely operated from the main control room by the operator or may be automatically operated in conjunction with the diesel generator loading sequence on loss of preferred power. Breaker status is indicated by red (closed) and green (tripped) indicating lights at the main control room and at the switch gear. Breaker lights in the main control room also indicate that the breaker is in the operating position. Diesel generator 3A-S supplies power to 4.16-kV bus 3A3-S, and diesel generator 38-S supplies power to 4.16-kV bus 383-S. Each diesel generator is rated at 4400 kW, 0.8 power factor, and 4.16 kV. These ratings are sufficient to supply power to all safety-related loads in each respective division, as well as to certain nonsafety-related loads which can be manually loaded to the diesel generator. Such additional loading is limited to the rated capacity of the diesel generators. A wattmeter, varmeter, and an ammeter are provided for continuous indication of diesel generator loading.
Administrative control will be exercised to prevent loading the diesel generators over their rated capacities.
BTP ICSB 2 (PSB), found in Appendix 8A of the SRP, requires a start and load reliability test program for all diesel-generator sets of a type or size not previously used as standby emergency power sources in nuclear power plant service. The KSV-16-T Diesel Generator Set (similar to Waterford 3 Diesel Generator Set) was fully qualified for standby power supply during the qualifi cation program conducted jointly by Cooper Energy Services/Commonwealth Edison for their Zion Station and Nebraska Public Power for its Cooper Station.
The diesel generators have open drip-proof frames, Class B insulation, and are wye connected, synchronous type with static, solid-state excitation systems, capable of carrying full-rated load continuously without exceeding rated rises above 50 &deg;C ambient. Each diesel generator is furnished with automatic field flashing equipment for quick voltage buildup during the startup sequence.
The diesel generator controls are designed for both automatic and manual opera tion. The manual operation may be performed from one of two locations: a main 8-8
 
control room panel (remote) and the diesel generator control panels (local).
The choice of the operating location is controlled by 11 Local-Remote 11 selector switches located at the engine and generator control panels. Placing the selector switches in the local mode permits manual starting of the diesel generator from the local position only. The position of selector switch is indicated in the main control room. Placing the selector switches in the remote mode permits manual starting of the diesel generator from the main control room only. Regardless of the position of the 11 Local-Remote 11 selector switches, the diesel generator will start automatically on loss of offsite power or on receipt of an ESF actuation signal.
Control circuits for each diesel generator operate from separate Class lE 125-V de circuits supplied from the station battery of the same division.
All of the standby power supply system components are designed to Class lE requirements. All Class lE components are located within seismic Category I structures and are protected from potential missile and fire hazards. Physical separation and isolation have been maintained in the location and installation of equipment for redundant systems. Each diesel generator is housed in a separate concrete room in the RAB at El +21 ft MSL.
As part of the preoperational testing program, tests will be performed to demon strate that during the diesel generator loading sequence, the generator frequency and voltage are maintained above a level which would degrade the performance of any load below minimum requirements. This meets the criteria of Regulatory Guide 1.9, and is acceptable.
During the periodic testing of a diesel generator, if an SIAS occurs, the generator breaker will be tripped automatically. This permits the unit to be cleared from parallel operation with the system and enables the diesel generator to attain the emergency standby mode. In this mode of operation, the diesel governor control changes automatically to the isochronous mode which maintains the engine running at a synchronous speed corresponding to 60 Hz at the generator terminals. All noncritical protective trips except engine overspeed and generator differential are bypassed. Simultaneously, the voltage regulator changes to the automatic mode maintaining the generator at a preset constant voltage of 4160 V. The diesel generator unit is now ready to accept load in the event of a loss-of-voltage signal. If during periodic testing of a diesel generator a LOVS should occur, both the generator breaker and tie breaker will be tripped automatically and, as explained above, the unit controls will change to the standby mode.
BTP ICSB 17 (PSB) found in Appendix 8A of NUREG-75/087 (the Standard Review Plan) requires that diesel generator protective trips be bypassed when the diesel generator is required for a design basis event. All protective trips are allowed during periodic testing. The allowed exceptions to the above requirement for bypassing are diesel overspeed and generator differential current relay. Any other trips retained must utilize coincident logic in order to avoid spurious trips. In case of design basis accident (OBA), the applicant is bypassing all the protective trips except engine overspeed and generator differential. This is in full conformance with NRC's position and is acceptable.
Diesel generator alarms and annunciators are located on the engine control panel.
One "diesel generator trouble" signal is sent to the main control room annunciator 8-9
 
when any local alarm is received on the local engine control panel. The present design does not differentiate annunciation of a disabling condition from annuncia tion of the more common abnormal, but not disabling, conditions. NRC has required the addition of a dedicated alarm (per diesel generator) to explicitly indicate conditions that would make a diesel generator incapable of responding to an automatic emergency start signal. The applicant has committed to provide these alarms. The alarm system display of 11 bypassed and inoperable status" of the diesel generators, as modified, will fulfill the requirements of Regulatory Guide 1.47 and is, therefore, acceptable.
8.3.1.1 120-V Uninterruptible Alternating Current System A 120-V ac static uninterruptible power supply (SUPS) system has been provided to supply the plant protection system control and instrumentation channels.
The 120-V uninterruptible ac system consists of four sets of rectifier/inverters and power distribution panels. Each inverter is normally supplied through its rectifier from a 480-V ESF motor control center (MCC). Should this supply fail, the inverter is supplied automatically from a 125-V de ESF battery. The plant protection system (PPS), including the reactor protection system (RPS) and core protection calculator, is supplied with power from the four uninterruptible ac inverters, two from each division, to supply the four measurement channels.
The remaining safety-related control and instrumentation systems are connected to two additional inverters, one for each division (A and B) as well as certain selected nonsafety-related loads. A seventh inverter is used to supply other important but nonsafety-related loads. The plant computer is supplied from an eighth inverter, with its own battery.
Each SUPS has three sources of power available which are: normal ac, emergency de and bypass ac. The breakers feeding these three sources from the de panels and MCCs are always closed. Normal operation is with the transfer switch in the inverter output position. With all three power sources energized, the inverter takes power from the normal ac through the rectifier as its output develops a higher de voltage than the emergency de sources. A blocking diode prevents the rectifier from also feeding power into the de system. Upon loss of ac supply power, the de source automatically and without interruption powers the inverter. Upon restoration of ac, the rectifier takes over and powers the inverter. The bypass ac source is used only during required maintenance of the inverter or rectifier.
The four plant protection system (PPS) ac systems and two ac safety-related I&C systems are ungrounded. The remaining 120-V ac systems have solidly grounded neutrals. Each system is arranged so that any type of single failure or fault will not prevent proper protective action of the safety-related systems. Based upon staff review, the four uninterruptible power supplies for the RPS are independent.
8.3.1.2 Criteria for Class lE Equipment The applicant has applied the following design criteria to the Class lE equipment.
(1) Motor Size: Motor sizes have been selected based on calculations of load-torque requirements or on the basis of equipment (pump, fan, compressor, etc.) supplier 1 s recommendations.
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In all cases, motor-rated horsepowers are greater than the normal running load and the associated maximum emergency load.
(2) Minimum Motor Accelerating Voltage: Safety-related motors are designed to start and accelerate their loads within specified time with a diesel generator output voltage profile maintained above 75% and frequency above 95%.
(3) Motor Starting Torque: The motor starting torque is capable of starting and accelerating the connected load to normal speed within specified time to permit its safety function for all expected operating conditions includ ing the design minimum terminal voltage.
(4) Motor Insulation: Insulation systems have been selected based on the particular ambient conditions to which the insulation will be exposed.
For Class lE motors located within the containment, the insulation system has been selected to withstand the postulated accident environment. In general, all Class lE motors have Class B, or better, insulation and are suitable for high-humidity operating conditions.
(5) Interrupting Capacities of Switchgear: The interrupting capacities of the protective equipment have been determined as follows:
In the calculation of medium voltage switchgear interrupting capacities, ANSI C37.010-1972 has been followed. The power system, diesel generator, and connected motor contributions have been considered in determining the fault level. All motor contribution. to short circuit is postulated.
Power center, MCCs, and distribution panel circuit breakers have a sym metrical rated interrupting capability at least as great as the calculated total available symmetrical current at the point of application. Symmet rical currents have been calculated in accordance with procedures of ANSI C37.13-1963 for low voltage circuit breakers other than molded case breakers and in accordance with National Electrical Manufacturers Association (NEMA)
Standards Publication AB-1, for molded case circuit breakers.
(6) Electric Circuit Protection: Electrical protection has been designed for selective tripping, so that only the affected circuit, close to the .point of fault, is isolated. Backup protection, where provided, may require isolation of more than one circuit, should the primary protection fail.
(7) Grounding: The station ground grid has been designed based on IEEE standard formulas which were incorporated into a computer program entitled ''Ground System Design." Equipment frames are solidly connected to the station ground grid with conductors of adequate capacity to carry the maximum ground fault current because of line-to-line to ground faults for the breaker tripping time.
The system has been designed with neutral grounding for detection and alarm of ground faults. The neutral of the diesel generator is grounded through a combination grounding transformer and resistor. This will permit the diesel generator to function continuously under emergency conditions with a single ground fault in the 4.16-kV ESF system.
The 4.16-kV and 6.9-kV delta windings of the UATs and startup transformers have been grounded through resistor/transformer combinations. Neutrals of all power center transformers are resistance grounded.
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8.3.1.3 Conclusions The staff has reviewed the emergency onsite power system and has determined the following. There are no automatic transfers of loads or sources between redundant emergency buses, which is in accordance with Regulatory Guide 1.6, "Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems. 11 The two divisions of the emergency power and distribution system are independent, meet the requirements of GDC 17 and 18, the criteria of Regulatory Guide 1.9, 11 Selection, Design and Qualification of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants," Regulatory Guide 1.32, 11 Criteria for Safety-Related Electric Power Systems for Nuclear Power Plants," and IEEE Standard 308-1974, and are acceptable.
8.3.2 Direct Current Power System 8.3.2.1 Discussion The de system is designed to provide a source of reliable continuous power for the plant protection system, instrumentation and control, and other loads for startup, operation, and shutdown under normal and emergency conditions.
The de system consists of three 60-cell, 125-Vbatteries, each with two battery chargers, de load center and distribution panels. All nonsafety loads capable of being connected to the safety buses have been included in the de power supply sizing criteria.
The three banks of batteries designated 3A-S, 3B-S, and 3AB-S and their associated load centers and distribution panels have been arranged to feed the safety-related redundant de loads and the nonsafety-related loads associated with divisions A, B, and AB, respectively.
Each battery (3A-S, 3B-S) is rated 1200 amp-hr (Ah) for an 8-hr rate or 600 Ah for 1-hr rate of discharge to 1. 75 Vper cell at 25 &deg; C, and is sized to provide the maximom simultaneous combination of steady-state loads and peak loads for the periods of the emergency duty cycle. The 1-min rating of each battery to 1.75 Vper cell is 1360 A which exceeds the 1-min peak current demand of 574 A.
The load cycles will give a final voltage of not less than 1.75 Vper cell, nor will voltage fall below 105 V (1.75 V per cell) during any peak or continuous load condition. (105 Vis the minimum design charge state.)
The battery designated 3AB-S is of the same type as the 3A-S and 3B-S batteries but is rated 2,400 Ah for an 8-hr rate of discharge to 1.75 Vper cell at 25 &deg; C.
The 1-min rating to 1.75 Vper cell is 2560A which exceeds the 1-min peak current demand of 1140 A. All other requirements of this battery are the same as those for batteries 3A-S and 3B-S.
Four battery chargers, 3Al-S, 3A2-S, 3B1-S, and 382-S are provided, two for each battery 3A-S and 3B-S. Each is rated 150 A continuous capacity. Two other chargers, 3AB1-S and 3AB2-S, are provided for battery 3AB-S. These chargers are rated 200 A continuous capacity. The time required to recharge a fully discharged battery while the charger is also supplying the largest com bined demand of the steady-state de bus loads irrespective of the status of plant is 11 hr for batteries 3A-S and 3B-S and 17 hr for 3AB-S.
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Each charger is supplied from 480-V, three-phase, 60-Hz MCC and can maintain its adjusted output voltage within 0.5% for any load from zero to full-rated current, with input variations of 10% in voltage and 5% in frequency.
To assure equipment protection in the de system from damaging overvoltages from the battery charges that may occur because of faulty regulation or operator error, each battery charger is equipped with built in overvoltage shutdown pro tection circuitry to sense output overvoltages (setpoint adjustable) and shut down the battery charger after a time delay (adjustable). For the float and equalizing voltages set at 132 V and 139.8 V, respectively, the charger alarm is set at 144 V. In addition, local indication is provided in each battery charger which actuates a charger malfunction alarm to alert the operator in the main control room.
The 125-V de system is designed to meet seismic Category I requirements. The two redundant batteries and their related accessories are located in separate rooms in the RAB, a seismic Category I structure, and they are protected from potential missile hazards. The third battery has been installed in a third room in the same building. The safety-related de loads have been grouped into two redundant load groups so that the loss of either group will not prevent the minimum safety function from being performed.
Complete separation and independence are maintained between components and circuits of the three 125-V ESF de systems, including the raceways. Because of the physical and electrical separation provided for the batteries, chargers, distribution equipment, and wiring for the 125-V de ESF systems, a single failure at any point in either system will not disable the remaining systems.
Each distribution circuit is capable of transmitting sufficient energy to start and operate all required loads in that circuit. Distribution circuits of redun dant equipment are independent of each other. The distribution system is moni tored to the extent that it is shown to be ready to perform its intended function, as described in the following paragraphs. The de auxiliary devices required to operate equipment of a specific ac load group have been supplied from the same load group.
Each battery supply is continuously available during normal operation, and following a loss of power from the ac system, to start and operate all required loads.
Instrumentation is provided to monitor the status of the battery supply as follows:
(1)  Direct current bus undervoltage alarm (main control room);
(2)  Battery current indication (battery room);
(3)  Direct current voltage indication (battery room and main control room);
and (4)  Direct current ground indication (main control room).
The batteries are maintained in a fully charged condition and have sufficient stored energy to operate all necessary circuit breakers and to provide an adequate amount of energy for al1 required emergency loads.
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The battery chargers of one redundant system are independent of the battery chargers for the other redundant system. Instrumentation has been provided to monitor the status of each battery charger as follows:
(1)  Output voltage at charger; (2)  Output current at charger; (3)  Breaker position indication at charger; and (4)  Charger malfunction alarm in main control room, including input ac and de undervoltage.
Each battery charger has an input ac and output de circuit breaker for isola tion of the charger. Each battery charger power supply has been designed to prevent the ac supply from becoming a load on the battery due to a power feed back as the result of the loss of ac power to the chargers.
Equipment in the Class lE de system is protected and isolated by fuses or circuit breakers in case of short circuit or overload conditions. Indications have been provided to identify equipment that is made unavailable per the following:
Event                              Available Indication (a)  Battery charger ac                  Charger malfunction alarm input breaker trip (b)  Battery charger de                  Charger malfunction alarm output breaker trip (c)  Distribution circuit                Individual equipment alarm breaker trip Since each inverter is normally powered from an ac supply with de backup, the failure of a battery or battery charger will not in any way affect the operation of the required ac loads from the inverter, unless there is a simultaneous failure of the ac feeder.
8.3.2.2 Conclusion Based upon NRC review of de power system as described in the FSAR, the staff concludes that two fully redundant Class lE systems are provided. In addition, a third de power system associated with the n,ra-of-a-kind Class iC 1oads has been provided. All three systems are testable, independent, and conform to the guidelines of Regulatory Guides 1.6 and 1.32. These systems meet the require ments of GDC 17 and 18 and are acceptable.
8.3.3  Fire Protection Special requirements needed for the plant electrical systems to satisfy Appendix A to BTP APCSB 9.5-1 11 Fire Protection of Nuclear Power Plants 11 will be reviewed later, during the fire protection review. Additional recommenda tions may be proposed to further improve the capability of the electrical systems resulting from the fire protection review.
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8.4 OTHER ELECTRICAL FEATURES AND REQUIREMENTS FOR SAFETY This section presents staff comments on the review of certain electrical sub systems incorporated into the Waterford 3 design. The objective of the NRC review is to determine whether these electrical features and requirements are implemented in accordance with all applicable acceptance criteria set forth in Section 8.1 of this report. Review and evaluation of each of these matters are given below.
8.4.1 Containment Electrical Penetrations In order to meet the standards set forth in IEEE Standard 317-1972, 11 Electrical Penetration Assemblies in Containment Structures for Nuclear Power Generating Stations, 11 as augmented by the recommendations of Regulatory Guide 1.63, "Electrical Penetration Assemblies in Containment Structures for Nuclear Power Generating Stations," the containment electrical penetration assemblies for Waterford 3 are designed to withstand, without loss of mechanical integrity, the maximum available fault current for the period of time sufficiently long enough to allow backup circuit protection to operate assuming a failure of the primary protective device. The circuit overload protection systems for electri cal penetration assemblies meet the single failure criterion set forth in IEEE Standard 279-1971, "Criteria for Protection Systems for Nuclear Generating Stations." The applicant has applied the following design criteria to the con tainment electrical penetration circuits:
(1)  6.9 kV Circuits: Each of the four reactor coolant pump (RCP) motor circuits, which are the only circuits penetrating the containment at this voltage, is provided with differential and overcurrent protection, arranged to trip the feedbreaker. If current still flows in the feeder after a preset time (i.e., the feeder breaker fails to trip), a transfer trip signal is given to the line breaker feeding the bus.
In order to protect the 6.9-kV circuit containment penetration from a single failure of de controi power which would prevent the primary and backup feeder circuit breaker from clearing an electrical fault in the RCP motor power feeder circuit, independent sources of de control power are provided for the RCP motor feeder breaker and line breaker.
A single line-to-ground fault results in only about 10 A of fault current, because the 6.9-kV system is high-resistance grounded. Tripping is there fore not necessary to protect the penetration against this low current*.
(2)  480-V Circuits From Switchgear: These penetrations are protected by the same type of overcurrent protection as the 6.9-kV penetrations. The backup breaker receiving the transfer signal in this case is the 4.16-kV breaker supplying the station service transformer which supplies the affected 480-V bus.
(3)  480-V Circuits From Motor Control Centers: Overcurrent protection is provided on these circuits by a thermal overload relay in each phase, responsive to overloads up to locked rotor (stalled) conditions, which trip the contactor.
Should the contactor not trip, a thermal magnetic breaker will trip on overloads of this kind.
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Fault currents, in excess of locked rotor currents, cause instantaneous tripping of the breaker. Should the breaker fail to trip, backup fuses or breakers are provided which have tripping characteristics chosen to parallel the response curves of the overload relays, and of the thermal and magnetic elements of the breaker. The maximum energy let-through of this protection system is far less than that required for thermal damage to the penetration conductor. The three-fold nature of this protection ensures that no single failure will prevent tripping.
(4)  480-V and 208-V/120-V ac Circuits From Distribution Panels: These feeders are not provided with thermal overload relays and contactors, so the first stage of protection, as outlined in (3) above is omitted. However, two thermal magnetic breakers in series or thermal magnetic breakers with back up fuses still provide two levels of protection, so that no single failure will prevent tripping.
(5)  208-V and 120-V ac Motor Space Heater Circuits: These circuits are pro vided with two molded-case circuit breakers in series, either of which will trip for any fault or overload condition.
(6)  120-V ac Control Circuits From Control Transformers: These low energy circuits are protected by fuses. No backup protection is provided as the control transformers is used as a current limiter which will limit the short circuit current at the penetration to a value below the continuous rating of the penetration conductor.
(7)  125-V de Control Circuits: The de circuits are ungrounded and protected by double pole fuses or circuit breakers with backup fuses. In both cases a short circuit or overcurrent condition is detected by two devices in series; if one fails, the other provides protection.
(8)  Instrumentation Circuits: These are circuits in which the possible energy release on fault is so low that the penetration can continuously withstand this fault current. Therefore, no protection is required.
The Waterford 3 electrical containment penetrations have been designed in accord ance with IEEE Standard 317-1972 and are protected in accordance with Regulatory Guide 1.63. This aspect of the Waterford 3 design is acceptable.
8.4.2 Thermal Overload Protection Bypass Motor operated valves with thermal overload protection devices for the valve motors are used in safety systems and their auxiliary supporting systems.
Operating experience has shown that indiscriminate application of thermal overload protection devices to the motors associated with these valves could result in needless hindrance to successful completion of safety functions.
Regulatory Guide 1.106, "Thermal Overload Protection for Electric Motors on Motor-Operated Valves" (November 1975), recommends in Position C.l bypassing thermal overload devices during accident conditions. In the Waterford 3 design, the thermal overload devices associated with the Class lE motor-operated valves are bypassed when an ESF actuation signal (ESFAS) is present. The above design is in conformance with Position C.l of Regulatory Guide 1.106 and is acceptable.
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8.4.3  Power Lockout to Motor-Operated Valves The applicant has provided the list of valves that require power lockout in order to meet the single failure criterion in the fluid systems (Technical Specification Section 4.5.2). BTP ICSB 18 (PSB) in Appendix 8A of NUREG-75/087 (the SRP) requires that all such valves and their required positions be listed in the technical specifications and that the position indications for these valves meet the single failure criterion. Also, where it is determined that failure of an electrical system component can cause undesired mechanical motion of a valve or other fluid system component and this motion results in a loss of the system safety function, it is acceptable to disconnect power to the electric system of the valve.
In the drawing review meeting, the applicant stated that power lockout of these valves is accomplished by racking out the breakers. Redundant valve position indication powered from independent power sources is provided in the main control room. Technical Specification 4.5.2 includes a list of electrically operated valves, and the required positions of these valves, which require power lockout in order to satisfy the single failure criterion. Therefore, this aspect of the design is acceptable.
8.4.4 Physical Identification and Separation of Safety-Related Equipment All Class lE equipment, such as 4.16-kV switchgear, 480-V power centers, 480-V MCCs, 120-V de batteries, chargers and switchboards, diesel-generator units, inverters, de and ac distribution panels and control panels, will be identified with permanent and indelible labels. These labels will contain the name, identi fying number and safety-related division. They will be color coded to indicate the function and divisions to which the equipment belongs. In addition, a sepa rate label color code identifies them as "Class lE. 11 Cables are identified by labels applied at identification points. These labels contain the cable number, function (control, power, information, etc.), safety division and are color coded. All cables have black jackets. Color coding during installation is performed with adhesive colored markers and in addition, the cables are numbered at each end with an adhesive marker.
Raceways are identified by labels applied at identification points as discussed below; these labels contain the raceway number in black letters on a white back ground. In addition, safety-related raceway labels are color coded as described in FSAR Table 8.3-12. Pull boxes in conduit runs are identified by labels on the cover and inside the box bearing the box number and color code as for raceways.
Raceways are marked at the points required by IEEE Standard 384-1974. However, where feasible, a 50-ft maximum distance between markers is used rather than the 15 ft mentioned in the standard, as this distance has been demonstrated during actual field installation to be reasonable for long raceway runs.
Cables used in the plant are flame retardant and are installed in steel ladder or through-type trays or in steel conduit. Therefore, in areas from which missiles and other hazards are excluded, the minimum separation distances of Sections 5.13 and 5.14 of IEEE Standard 384 are generally maintained. Where 1-in. minimum separation cannot be maintained between redundant enclosed raceways and between barriers and raceways, a flame retardant material is used to provide as a minimum, the equivalence to 1-in. separation in air. Where wiring of one 8-17
 
division or channel must traverse an area dedicated to another division of channel, steel conduit, or solid tray with cover is used.
Based on NRC review of the applicant's design criteria regarding physical identification, separation, and independence of the redundant safety-related electrical systems, the staff finds this aspect of the design to be acceptable.
8.4.5 Nonsafety Loads on Emergency Power Sources Present regulatory practice for OL applications allows the connection of non safety loads in addition to the required safety loads to Class lE (emergency) power sources if it can be shown that the connection of non-safety loads will not result in degradation of the Class lE system. With the exception of plant lighting and the non-Class lE instrument inverter, all non-Class lE 4.16-kV and 480-V electrical power circuits supplied from the Class lE system, have provision for isolation through Class lE circuit breakers located in seismic Category 1 structures. Isolation is initiated by a LOVS which trips the individual 4.16-kV or 480-V power breakers feeding the non-Class lE loads.
For loads fed from 480-V MCCs, the bus is divided into Class lE and non-Class lE sections and the LOVS isolates the non-Class lE section by tripping the interconnecting tie breaker.
For the lighting and the non-Class lE inverter, an alternate approach is used.
These circuits are provided with double protection consisting of either two breakers in series or one breaker and a fuse in series to prevent them from degrading the Class lE system. These double protective devices are both arranged to coordinate with the upstream device protecting the bus.
The 120-V non-Class lE circuits use this same alternate approach. They also are provided with double protection consisting of either two breakers or one breaker and a fuse in series. These double protective devices are both arranged to coordinate with the upstream device protecting the bus. Mutual coordination between the devices is not required.
Based upon staff review, this aspect of the design is in accordance with the guidelines of RG 1.75 and, therefore, is acceptable.
8.4.6 Use of a Load Sequencer With Offsite Power The Waterford 3 design includes load sequencing for the connection of ESF loads to the emergency buses when power is being supplies either from offsite or from the diesel generators.
In the normal state; the sequencer circuit is kept continuously energized.
Thus, the status of sequencer readiness for operation is continuously monitored.
In case of loss of a 120-V de power source to the sequencer or failure of any of the sequencer relays, an alarm shall be annunciated in the control room. An alarm is also initiated in the control room each time the sequencer is tested or actuated by SIS or undervoltage contacts. Any failure in the annunciator circuitry, such as a short across the output wires, will be detected the first time the sequencer is tested. Required periodic testing is listed in Technical Specification 4.8.1.1.2.a. 7.
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In order for us to accept the use of a single sequencer for both offsite and onsite power sources, we have required the following:
(1)  A reliability study on the sequencer.
(2)  A detailed analysis to show that there are no credible sneak circuits or common mode failures in the sequencer design that could render both onsite and offsite power sources unavailable.
The following items address our evaluation of the Waterford 3 design for con formance with the corresponding numbers noted above.
(1)  The requirements of the reliability are met by continuously monitoring the sequencing circuit and periodically testing as shown in Technical Specification 4.8.1.1.2.a.7. The sequencer relays are also monitored by computer to ensure that their timing is correct.
(2)  A sneak circuit analysis was performed and as a result the system was modified to eliminate a potential relay race.
This aspect of design meets NRC requirements and is, therefore, acceptable.
8.4.7 Third-of-a-Kind Class lE Equipment The third-of-a-kind ESF electrical system consists of (1)  4.16-kV switchgear 3AB3-S (2)  480-V switchgear 3AB31-S (3)  125-V de system 3AB (4)  120-V ac and 125-V de for instrumentation Item 3 contains battery 3AB-S and does not have interconnections with the SA or SB 125-V de systems. Items 1 and 2 receive power either from system SA or system SB. The dead bus transfer is made from the main control room. To accomplish this and meet the single failure criterion, eight breakers have been provided. Control switches of breakers are key interlocked. Keys may be removed only in the trip position. All power, control, and instrumentation circuits are routed in separate raceway systems, i.e., SA, SB and SAB, which are color coded for identification.
The third-of-a-kind system is testable, independent from the other two Class lE systems and conforms to the guidelines of Regulatory Guide 1. 75 and is acceptable.
8.4.8  Isolation Panel The applicant has installed an isolation panel in order to isolate control circuits whenever an interface between two different trains (channels) is required. The panel is subdivided in several compartments, each compartment being dedicated to one channel. The isolation between trains is accomplished by using rotary type isolation relays. The shaft of the isolation relay penetrates the separation barrier between two compartments in the isolation oanel. The coil of the isolation relay is located in one compartment, and the 8-19
 
contacts of the same relay are operated by the relay shaft in the other compart ment, thus providing the physical separation between the coil and the contacts of the same relay. This method of isolation is in accordance with Regulatory Guide 1. 75 and is acceptable.
8-20
 
==8.5 REFERENCES==
American National Standards Institute:
ANSI C37.010-1972 ANSI C37.13 -1963 Branch Technical Positions:
APCSB 9.5-1 ICSB 2 (PSB)
ICSB 17 (PSB)
ICSB 18 (PSB) } in ADP 8A of NUREG-75/087 (the SRP)
General Design Criteria:
GOC 5 GDC 17 } 10 CFR 50, Appendix A GDC 18 Institute of Electrical and Electronics Engineers Standards:
IEEE  Standard 279-1971 IEEE  Standard 308-1974 IEEE  Standard 317-1972 IEEE  Standard 384 IEEE  Standard 384-1974 Louisiana Power  & Light Report:
FSAR for Waterford 3 National Electrical Manufacturers Association Standards:
NEMA Pub. AB-1 Regulatory Guides:
RG 1.6 RG 1.9 RG 1.32 RG 1. 47 RG 1.63 RG L 75 RG 1. 106
*See Appendix B, Bibliography, for complete citations and availability statements.
8-21
 
9 AUXILIARY SYSTEMS NRC staff has reviewed the design of the auxiliary systems necessary for safe reactor operation, shutdown and fuel storage and have reviewed those auxiliary systems whose failure might affect plant safety including their safety-related objectives, and the manner in which these objectives are achieved.
The auxiliary systems necessary for safe reactor operation or shutdown include the component and auxiliary component cooling water systems, the ultimate heat sink, the essential services chilled water system, the heating, ventilation and air conditioning systems for the control room and essential portions of the reactor auxiliary building, essential portions of the compressed air system, essential portions of the chemical and volume control system, and the emergency feedwater system.
The auxiliary systems necessary to assure the safety of the fuel storage facility include new fuel storage, spent fuel storage, the spent fuel pool cooling and cleanup system, fuel handling systems, and the fuel handling building heating, ventilation and air conditioning system.
The staff has also reviewed other auxiliary systems to verify that their failure will not prevent safe shutdown of the plant or result in unacceptable release of radioactivity to the environment. These systems include: the demineralized water system; potable and sanitary water system; the condensate storage facilities; nonessential portions of the compressed air system; non essential portions of the chemical and volume control system; and heating, ventilation, and air conditioning systems for nonessential portions of the reactor auxiliary building and the turbine building.
Waterford 3 is a single unit plant and, therefore, the requirements of General Design Criterion (GDC) 5 "Sharing of Structures, Systems and Components 11 which concerns the capability to maintain safe operation of multiple units when essential systems are shared are not applicable.
9.1 FUEL STORAGE FACILITY 9.1.1 New Fuel Storage The new fuel storage facility provides dry storage for a maximum of 80 fuel assemblies (more than half of a core load) and includes the new fuel assembly storage racks, and the concrete storage vault that contains the storage racks.
The fuel handling building which houses the facility is designed to seismic Category I criteria as are the storage racks and vault. This building is also designed against flooding and tornado missiles (refer to Sections 3.4.1 and 3.5.2 of this SER). Thus, the requirements of GDC 2, Design Bases for 11 Protection Against Natural Phenomena" and the guidance provided in Regulatory Guide 1.29 Seismic Design Classification 11 are satisfied.
11 9-1
 
The vau1t housing the new fuel storage racks is not located in the vicinity of any moderate or high energy lines or rotating machinery. Therefore, physical protection for the new fuel from internally generated missiles and the effects of pipe breaks is provided by means of separation (refer to Sections 3.5.1.1 and 3.6.1 of this SER). Thus, the requirements of GDC 4, 11 Environmental and Missile Design Bases" are satisfied.
The facility is designed to store unirradiated, low emission fuel assemblies.
Accidental damage to the fuel would release relatively minor amounts of radio activity that would be accommodated by the fuel handling building ventilation system. Thus, the requirements of GDC 61 11 Fuel Storage and Handling and Radioactivity Control 11 are satisfied.
The new fuel storage racks are designed to store the fuel assemblies in an array with a minimum center-to-center spacing of 21 in. which is sufficient to maintain a Keff of 0.90 or less in the normal dry condition or abnormal completely water flooded condition. The racks are designed to maintain a Keff of 0.98 or less under optimum moderation (foam, small droplets, spray, or fog ging). A hinged cover is provided over each new fuel storage cell as addi tional protection for the new fuel. Further, the applicant will utilize administrative controls to preclude sources of optimum moderation such as foam fire fighting agents in the new fuel storage area during moving of fuel when the cover is removed thereby significantly reducing the probability of such a condition. This approach is acceptable. The racks themselves are designed to preclude the inadvertent placement of a fuel assemblY. in other than the pre scribed spacing. Thus, the requirements of GDC 62, 'Prevention of Criticality in Fuel Storage and Handling 11 are satisfied.
Radiation monitoring equipment for the new fuel storage area is provided and is evaluated in Section 12 of this SER. Based on that evaluation the staff finds that the requirements of GDC 63, 11 Monitoring Fuel and Waste Storage 11 are satisfied.
Based on the review, the staff concludes that the new fuei storage faciiity is in conformance with the requirements of GDC 2, 4, 61, 62, and 63 as they relate to new fuel protection against natural phenomena, missiles, pipe break effects, radiation protection, prevention of criticality, and radiation monitoring, and with the guidelines of Regulatory Guide 1.29 relating to seismic design, and is, therefore, acceptable.
Spent Fuel Storage Part I The spent  fuel storage facility provides high density underwater storage for 1088 fuel  assemblies or approximately 5 full core loads. The facility includes the spent  fue1 storage racks and the lined spent fuel storage pool that con tains the  storage racks.
The structure housing the facility (the fuel handling building) is designed to seismic Category I criteria as are the storage racks, storage pool, and pool liner plate. The fuel handling building is also designed against flooding and 9-2
 
tornado missiles (refer to Sections 3.4.1 and 3.5.2 of this SER). Thus, the requirements of GDC 2 and the guidelines of Regulatory Guides 1.13, 11 Spent Fuel Storage Facility Design Basis 11 ; 1.102, "Flood Protection for Nuclear Power Plants"; and 1.117, 11 Tornado Design Classification," and 1.29 are satisfied for the facility.
The fuel pool is not located in the vicinity of any high energy lines or rotating machinery. Therefore, physical protection for the stored spent fuel from internally generated missiles and the effects of pipe breaks is provided by means of separation (refer to Sections 3.5.1.1 and 3.6.1 of this SER).
Thus, the requirements of GDC 4 are satisfied.
The facility is designed to store the fuel assemblies in an array which limits Keff to 0.95 or less. The high density storage racks are stainless steel with parallel rows of fuel assembly storage boxes each of which contains two neutron poison material compartments. The poison material compartment consists of an inner and outer stainless steel can around two sheets of borated silicone rubber. The racks are designed to preclude the inadvertent placement of a fuel assembly in other than the prescribed spacing. The racks can withstand the impact of a dropped fuel assembly without unacceptable damage to the fuel and can withstand the maximum uplift forces exerted by the fuel handling machine. Thus, the requirements of GDC 61 and 62 and the guidelines of Regulatory Guide 1.13 concerning fuel storage facility design are satisfied.
The design of the storage pool includes a leakage detection system in order to monitor 100% of the pool liner welds for excessive leakage, a pool water level monitoring system, and radiation monitoring systems with indication and alarm in the control room. These features satisfy the requirements of GDC 63.
Based on the review, the staff concludes that the spent fuel storage facility is in conformance with the requirements of GDC 2, 4, 61, 62, and 63 with regard to protection against natural phenomena, missiles, pipe break effects, radiation protection, prevention of criticality, and monitoring provisions, and the guidelines of Regulatory Guides 1.13 and 1.29 concerning the facility 1 s design and protection against seismic events and, therefore, the facility is acceptable.
Part II The pool liner, rack lattice structure, and fuel storage tubes are stainless steel which is compatible with the storage pool environment. In this environment of oxygen-saturated borated water, the corrosive deterioration of the type 304 stainless steel should not exceed a depth of 6.00 x 10- 5 in. in 100 years, which is negligible relative to the initial thickness. Dissimilar metal contact corrosion (galvanic attack) between the stainless steel of the pool liner, rack lattice structure, fuel storage tubes, and the Inconel and the Zircaloy in the spent fuel assemblies will not be significant because all of these materials are protected by highly passivating oxide films and are there fore at similar potentials. The Boraflex poison material is composed of nonmetallic materials and therefore will not develop a galvanic potential in contact with the meta1 components. Boraflex has undergone extensive testing to study the effects of gamma irradiation in various environments and to verify its structural integrity and suitabilty as a neutron absorbing material.
9-3
 
The annulus space which contains the Boraflex is vented to the pool. Venting of the annulus will allow gas generated by the chemical degradation of the silicone polymer binder during heating and irradiation to escape, and will prevent bulging or swelling of the inner stainless steel tube.
To provide added assurance that no unexpected corrosion or degradation of the materials will compromise the integrity of the racks, the applicant has com mitted to conduct a long-term fuel storage cell surveillance program. Surveil lance samples are in the form of removable stainless steel clad Boraflex sheets, which are prototypical of the fuel storage cell walls. These specimens will be removed and examined periodically.
From our evaluation as discussed above, we conclude that the corrosion that will occur in Waterford Unit 3 spent fuel storage pool environment should be of little significance during the 40-yr life of the plant. Components in the spent fuel storage pool are constructed of alloys which have a low differential galvanic potential between them and have a high resistance to general corrosion, localized corrosion, and galvanic corrosion. Tests under irradiation and at elevated temperatures in borated water indicate that the Boraflex material will not undergo significant degradation during the expected service life of 40 years.
The staff further concludes that the environmental compatibility and stability of the materials used in the spent fuel storage pool is adequate based on test data and actual service experience in operating reactors.
The staff have reviewed the surveillance program and concluded that the monitoring of the materials in the spent fuel storage pool, as proposed by the applicant, will provide reasonable assurance that the Boraflex material will continue to perform its function for the design life of the pool. The staff finds that the implementation of a monitoring program and the selection of appropriate materials of construction by the licensee meets the requirements of 10 CFR Part 50, GDC 61, having a capability to permit appropriate periodic inspection and testing of components, and GDC 62, preventing criticality by maintaining structural integrity of components and of the boron poison.
9.1.3 Spent Fuel Pool Cooling and Cleanup System (Fuel Pool System)
The fuel pool system is designed to maintain water quality and clarity and remove decay heat generated by spent fuel assemblies in the pool. The system includes all components and piping from inlet to exit from the storage pools, piping used for fuel pool makeup, and the cleanup filter/deminera1izers to the point of discharge to the radwaste system. The design consists of a single essential fuel pool cooling train with two fuel pool pumps and one fuel pool heat exchanger and a singie separate nonessential purification train with one fuel pool purification pump, one filter, and one fuel pool ion exchanger.
The essential portions of the system are housed in the seismic Category I flood and tornado protected fuel handling building (refer to Sections 3.4.1 and 3.5.2 of this SER). The system itself, with the exception of the cleanup portion is designed to Quality Group C and seismic Category I requirements.
Failure of the nonseismic Category I, quality group D cleanup portion in an earthquake will not affect operation of the cooling train as it is independent 9-4
 
of that portion of the piping system and, therefore, no adverse effect on safety-related equipment would result from such a failure. Therefore, the design satisfies the requirements of GDC 2 and the guidelines of Regulatory Guides 1.26, 11 Quality Group Classifications and Standards for Water-, Steam-,
and Radioactive-Waste Containing Components for Nuclear Power Plants, 11 1.13, and 1.29 with respect to seismic and quality group classification of the fuel storage facility.
The various components of the system are located in separate missile-shielded cubicles within the tornado missile protected fuel handling building and are separated from other moderate and high energy piping systems (refer to Sections 3.5.1.1 and 3.6.1 of this SER). Thus, the requirements of GDC 4 and the guidelines of Branch Technical Position (BTP) ASB 3-1 11 Protection    Against Postulated Piping Failures in Fluid Systems Outside Containment 11 are satisfied.
The design includes the capability for routine visual inspection of the system components. One fuel pool cooling pump is in operation at all times, thus the spent fuel pool cooling train is normally operable. Further, the spare pump will be operated periodically in accordance with plant technical specifications.
Thus, the requirements of GDC 45,11 11 Inspection of Cooling Water System, 11 and 46 "Testing of Cooling Water System are satisfied.
With one fuel pool pump operating, the fuel pool system maintains the fuel pool water temperature at 130&deg; F or less. The heat is load based on decay heat generation from one-third of a core that has undergone 3-yr irradiation and is placed in the pool 7 days after reactor shutdown    plus 11 previous annual one-third core refueling batches. This 11 normal11 heat load temperature is below NRC acceptance criterion of 140 &deg; F. Space for an emergency core off-load is assumed available.
With both fuel pool pumps operating, the fuel pool system maintains the fuel pool water temperature at 135&deg; F (155&deg; F if only one fuel pool pump is operating) with a heat load based on decay heat generation from one full core placed in the pool 7 days after reactor shutdown plus 12 previous annual one-third core refueling batches. These "abnormal" heat load temperatures are within accept able limits and assume the emergency core off-load has occurred and the spent fuel storage racks are full (maximum storage condition). Heat loads for the above storage modes are based on BTP ASB 9-2, "Residual Decay Energy for Light Water Reactors for Long-Term Cooling. 11 All connections to the spent fuel pool are designed to preclude possible siphon draining of the pool water. The safety-related component cooling water system provides cooling water to the fuel pool heat exchanger and transfers its heat to the ultimate heat sink (refer to Sections 9.2.2 and 9.2.5 of this SER). During periods when the fuel pool heat exchaner is not available because of maintenance, supplementary fuel pool cooling is available through the shutdown heat exchanger by connections to the fuel pool purification train. Adequate pool temperature can thus be maintained during this maintenance period. The fuel pool pumps can be powered from redundant divisions of the emergency (Class lE) power supplies. Thus, the requirements of GDC 44, 11 Cooling Water, 11 are met.
Makeup to the fuel pool is provided by the seismic Category I condensate stor age and/or refueling water storage pools via the seismic Category I component 9-5
 
cooling water makeup pumps and piping and/or nonseismic refueling water pool purification pump and piping in order to replace losses due to leakage through the liner and evaporation. Thus, the requirements of GDC 61 and the guide lines of Regulatory Guide 1.13 concerning fuel pool design are met.
The system incorporates control room alarmed pool water level, water tempera ture, and building radiation level monitoring systems, thus satisfying the requirements of GDC 63.
The staff determined that the spent fuel pool cleanup system (1) provides the capability and capacity of removing radioactive materials, corrosion products and impurities from the pool water, and thus meets the requirements of GOC 61 in Appendix A to 10 CFR Part 50, as it relates to appropriate filtering systems for fuel storage; (2) is capable of reducing occupational exposure to radiation by removing radioactive products from the pool water, and thus meets the requirements of Section 20.l(c) of 10 CFR Part 20, as it relates to maintaining radiation exposures as low as is reasonably achievable; and filters, and thus meets Regulatory Position C.2.f(2) of Regulatory Guide 8.8, as it relates to reducing the spread of contaminants from the source; and (4) removes suspended impurities from the pool water by filters, and thus meets Regulatory Position C.2.f(3) of Regulatory Guide 8.8, as it relates to removing cruds through physical action.
Based on the review, the staff concludes that the fuel pool system is in conformance with the requirements of GDC 2, 4, 44, 45, 46, 61, and 63 as relates to protection against natural phenomena, missiles and environmental effects, cooling water capability, inservice inspection, functional testing, fuel cooling and radiation protection, and monitoring provisions, and the guidelines of Regulatory Guides 1.13, 1.26, 1.29, and BTP ASB 3-1 and 9-2 relating to the systems design, seismic and quality group classification, protection against the effects of high and moderate energy line breaks and design decay heat loads and is, therefore, acceptable.
On the basis of the above evaluation, the staff also concludes that the spent fuel pool cleanup system meets GDC 61, Section 20.l(c) of 10 CFR Part 20 and the appropriate sections of Regulatory Guide 8.8 and, therefore, is acceptable.
9.1.4 Fuel Handling System The fuel handling system in conjunction with the fuel storage area provides the means of transporting, handling and storing of fuel (both new and spent fuel). The fuel handling system consists of equipment necessary for the safe handling of the spent fuel cask and for safe disassembly, handling, and reassembly of the reactor vessel head and internals during refueling operations.
The system also includes additional equipment designed to facilitate the periodic refueling of the reactor. The handling of fuel during refueling is controlled by a series of interlocks to assure that fuel handling procedures are maintained. The design assures that no failure will result in release of radioactivity in excess of that assumed in the design basis fuel handling accident.
9-6
 
The entire system is housed within the fuel handling building and reactor building (containment) which are seismic Category I, flood and tornado pro tected structures (refer to Sections 3.4.1 and 3.5.2 of this SER). Although fuel handling system components are not required to function followin an SSE, critical components of the fuel handling system are designed to seismic Cate gory I requirements so that they will not fail in a manner which results in unacceptable consequences such as fuel damage or damage to safety-related equipment. The 125-ton fuel handling building cask crane is used for handling the spent fuel shipping cask, and is designed to seismic Category I require ments. The 200-ton containment polar crane is used to move the reactor vessel head and is designed to seismic Category I requirements. The spent fuel hand ling machine which travels over the spent fuel storage racks is designed to seismic Category I requirements. The design thus satisfies the requirements of GDC 2 and the guidelines of Regulatory Guide 1.29.
The spent fuel cask storage area is located beside the spent fuel pool, sepa rated from the fuel pool by a reinforced concrete wall to the top of the fuel storage racks, and a removable bulkhead gate above the racks. The cask crane is equipped with an electrical interlock system in such a way that the cask cannot be transported over the spent fuel pool or the bulkhead gate. Further, the walls of the spent fuel pool are high enough so that a dropped cask cannot tip into the pool. The cask is transported along a prescribed path parallel to the spent fuel pool at a maximum height of 30 ft above any structural surface to minimize the possibility of damage to spent fuel or safety-related equipment located below the floor in the event of a cask drop.
Safety-related fuel handling building emergency ventilation equipment is located below the path of travel of the cask while it is being moved. However, possible damage to this equipment as a result of a cask drop will not prevent safe shutdown of the plant, nor is this equipment necessary for mitigating the consequences of such an accident since the cask can withstand this drop with out damage. Additional cask crane design features such as upper hoisting limit switches, dual electric stopping and holding brakes, and hoist rope safety factors reduce the likelihood of such an accident. Thus, the require ments of GDC 61 and the guidelines of Regulatory Guide                                        1.13 and BTP ASB 9-1, "Overhead Handling Systems for Nuclear Power Plants 11 are satisfied for handling of the spent fuel cask.
The applicant has not provided a load drop analysis for the containment polar crane. This analysis is under way as part of the applicant 1 s response to I11n:r.-n&:1?
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                                                                                                                                \..I  JI;:)
mitted to the applicant for action by generic NRC letters dated December 22, 1980, and February 3, 1981. NUREG-0612 resolved Generic Task A-36 and provides guidelines for necessary changes to assure safe handling of heavy ioads once the plant becomes operational. The applicant will submit the results of the review against NUREG-0612 guidelines at a later date. Enclosure 2 attached to the December 22, 1980 generic letter identified a number of measures dealing with safe load paths, procedures, operator training and crane inspections, testing and maintenance. The staff will require the applicant to implement these interim actions before final implementation of the NUREG-0612 guidelines and before the receipt of their OL.
9-7
 
Based on review, the staff concludes that the fuel handling system is in conformance with the requirements of GDC 2 and 61 as related to its protection against natural phenomena and safe fuel handling and the guidelines of Regulatory Guides 1.13 and 1.29 with respect to overhead crane interlocks and maintaining plant safety in a seismic event and BTP ASB 9-1 concerning potential consequences in the event of dropped loads, and is, therefore, acceptable. The staff further concludes that implementation of the interim actions of NUREG-0612 before final implementation of NUREG-0612 guidelines and before receipt of the OL provides reasonable assurance of safe handling of heavy loads until NUREG-0612 can be fully implemented and is, therefore, acceptable.
9.2 WATER SYSTEMS 9.2.1 Station Service Water System Waterford 3 does not have a station service water system. The functions normally performed by this system are included in the design of the component and auxiliary component cooling water systems (refer to Section 9.2.2 of this SER).
9.2.2 Reactor Auxiliaries Cool*                      anent Coolin Water S stem an ux1 1ary omponen The component cooling water system (CCWS) and auxiliary component cooling water system (ACCWS) supply cooling water to reactor auxiliary components and transfer their heat directly to the wet and dry cooling towers which serve as the ultimate heat sink discussed in Section 9.2.5 of this SER. The CCWS operates during all modes of plant operation. The ACCWS operates only when required for supplemental heat removal capability. These systems provide cooling to the following essential plant auxiliary components during all modes of operation including postulated accidents as they are required for safe shutdown and accident mitigation: shutdown cooling heat exchangers, containment fan coolers, diesel generators, HPSI pump coolers, LPSI pump coolers, containment spray pump coolers, and essential chillers. Cooling is also supplied to the following nonessential components during normal shutdown, normal operation and refueling: reactor coolant pumps and motors, letdown heat exchanger, fuel pool heat exchanger, boric acid and waste concentrators, sample coolers, waste gas compressor, and control element drive mechanism (CEDM) cooler. The CCWS pumps circulate water in a closed cycle from the components to be cooled through the component cooling water (CCW) heat exchanger (tube side) and dry cooling tower where the water is cooled and then piped back through the components to the pumps. The ACCWS pumps provide cooling water in a closed cycle through the CCW heat exchangers (shell side) from the wet cooling tower basins and back to the wet towers where the heat is dissipated and the water is collected in the basins from which it is recirculated.
The CCWS consists of two redundant full capacity closed coo1in piping loops A and Beach of which serves redundant essential components and 1s seismic Category I, quality group C. Each cooling loop contains one CCW heat exchanger and one dry cooling tower. Three full capacity CCW pumps, two normally operat ing and one on standby, supply both cooling loops. A baffled surge tank with 9-8
 
separate lines to the suction of the redundant pumps provides CCW pump NPSH and system makeup water requirements. Makeup to the surge tank is normally provided automatically by the nonessential demineralized water system. Makeup can also be provided by the essential (seismic Category I) CCW makeup pumps from the condensate storage pool. A nonessential normally isolated chemical feed is provided for each cooling loop. Each redundant CCW loop is also pro vided with a continuously operating radiation monitor. Additional radiation monitoring is provided on the CCW line serving components inside the contain ment (the reactor coolant pumps and CEDM). These monitors alarm in the con trol room on detection of high radiation.
During normal operation, normal shutdown and refueling, the two operating CCW pumps are connected together on the suction and discharge sides and the CCWS is operated as a common system to supply cooling water to the essential and nonessential components. During accident conditions, a safety injection actuation signal isolates the redundant CCW pumps and cooling loops from each other and the common nonessential loop from the essential portions by closing the normally open, safety-related, redundant air operated isolation valves, in series. The isolation valves between essential and nonessential portions of the CCW are designed to fail closed on loss of air supply. Those on the CCW pump suction and discharge are equipped with seismic Category I nitrogen accumulators to assure their operability in a loss of normal air supply condi tion. Each loop can remove 100% of the heat necessary for shutdown under accident conditions. Two CCW pumps are powered from independent emergency (Class lE) power supplies. The third pump is powered from the A/8 bus and can be manually aligned to either emergency power supply or cooling loop.
The CCWS contains two essential cooling loops each of which is connected to both redundant essential loops. The common supply to the nonessential boric acid and waste concentrators, sample coolers, waste gas compressor and CEDM cooler is nonseismic and remains isolated under all accident conditions. The common supply line to the nonessential fuel pool heat exchanger, reactor cool ant pumps and letdown heat exchanger is seismic Category I, quality group C.
CCW flow to these components may be manually restored by the operator from the control room under accident conditions. In response to NRC concern with loss of CCW flow to the reactor coolant pumps (RCPs) as a result of a single failure in the common supply and return lines, the applicant indicated that the RCPs have been tested and shown to operate satisfactorily without excessive seal leakage for 30 min without CCW flow. Redundant safety grade flow switches which a1arm on loss of CCW flow to the RCPs in the control room are provided to alert the operator to this condition. The staff concludes that the 30-min time period is adequate for the operator to either restore CCW flow or trip the RCPs.
The ACCW consists of two redundant, independent, full-capacity, closed cooling piping 1oops A and B, each serving redundant essential components and is seismic Category I, quality group C. Each loop contains one full-capacity ACCW pump and an evaporative wet type mechanical draft cooling tower. The pumps are powered from independent emergency (Class lE) power supplies. Each loop provides supplementary cooling to a redundant CCW heat exchanger and essential chiller under accident conditions and extreme outside ambient weather conditions when the CCWS heat removal capacity (through the dry towers) is exceeded. Initiation and control of the ACCW is provided by redundant Class lE temperature instrumentation as described in Section 9.2.5 of this SER.
9-9
 
The design of the CCWS and ACCWS as described above assures that system func tion is not lost, assuming a single active component failure coincident with a loss of offsite power. Adequate isolation is provided as indicated in the previous paragraphs. Thus, the requirements of GDC 44 are met.
The systems are housed in the seismic Category I, flood- and tornado-protected reactor auxiliary building and reactor building (refer to Sections 3.4.1 and 3.5.2 of this SER). Essential portions of the system are designed to seismic Category I, quality group C requirements. Thus, the requirements of GDC 2 and the guidelines of Regulatory Guides 1.26, 1.29, and 1.102 are met.
The systems are separated from the effects of internally generated missiles and high and moderate energy pipe breaks (refer to Sections 3.5.1.1 and 3.6.1 of this SER). Each CCW and ACCW pump is located in a separate protected compartment within the reactor auxiliary building. This building provides protection against tornado generated missiles. Thus, the requirements of GDC 4 and the guidelines of Regulatory Guide 1.117 and BTP ASB 3-1 are met.
Two CCWS pumps are normally operating. Availability of the standby CCW pump and the normally not operating ACCWS pumps is assured by periodic functional tests and inspections as delineated in plant technical specifications. The systems are located in accessible areas to permit inservice inspection as required. Thus, the requirements of GDC 45 and 46 are met.
Based on the above, the staff concludes that the CCWS and ACCWS meet the requirements of GDC 2, 4, 44, 45, and 46 with respect to the systems protection against natural phenomena, missiles and environmental effects, decay heat removal capability, inservice inspection and functional testing, and the guidelines of Regulatory Guides 1.26, 1.29, 1.102 and 1.117 and BTP ASB 3-1 with respect to the systems quality group and seismic classification as well as flood, tornado missile and pipe break protection, and are, therefore, acceptable.
9.2.3 Deminera1ized Water Makeup System The nonsafety-related quality group D (nonseismic Category I) demineralized water makeup system (primary water treatment plant and demineralized water system) provides treated and demineralized water to various plant systems and components and includes all components and piping associated with the system from the plant makeup water source (the Mississippi River) to the points of discharge to other systems and components. The system has no safety-related function. Protection from flooding for safety-related equipment resulting from failure of the system is discussed in Section 9.3.3 of this SER. The system is capable of fulfilling the normai operating requirements of the facility for acceptable makeup water with the necessary component redundancy.
Makeup to the safety-related condensate storage pool is provided by the demineralized water system via the condensate storage tank. Refer to Section 9.2.6 of this SER for further discussion. Entry of potentially radioactive water into the system is prevented by assuring a greater pressure for deminera1ized makeup water than in the potentially radioactive sources to which it discharges. Alarmed instrumentation has been provided to prevent delivery of off-specification water to safety-related systems. Failure of the system does not affect the capability to safely shut down the plant as described 9-10
 
above, thus the requirements of GDC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 are met.
Based on NRC review, the staff finds that the system meets the requirements of GDC 2 with respect to the need for protection against natural phenomena and meets the guidance of Regulatory Guides 1.26 and 1.29 concerning its seismic and quality group classification and is, therefore, acceptable.
9.2.4 Potable and Sanitary Water Systems The nonsafety-re1ated (quality group D and nonseismic Category 1) potable and sanitary water systems provides clean water for human consumption and use, and include all components and piping from the potable supply connection at the municipal water mains through various plumbing fixtures and equipment to all points of discharge. There are no cross-connections between the potable and sanitary water systems and potentially radioactive systems and, therefore, inadvertent contamination is prevented. Protection from flooding for safety related equipment resulting from failure of the system is discussed in Section 9.3.3 of this SER. Failure of the system does not affect plant safety as described above, thus the requirements of GDC 2 and the guidelines of Regula tory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 are met.
Based on NRC review, the staff finds that the system meets the requirements of GDC 2 with respect to the need for protection against natural phenomena and meets the guidelines of Regulatory Guides 1.26 and 1.29 concerning its seismic and quality group classification and is, therefore, acceptable.
9.2.5 Ultimate Heat Sink The ultimate heat sink (UHS) provides the heat dissipation capability for the reactor and its essential auxiliaries through the CCWS and ACCWS during normal operation, shutdown, refueling and accident conditions. The UHS consists of two separate, full capacity redundant divisions each of which contains a seismic Category I, quality group C dry cooling tower, and a seismic Category I, quality group C wet mechanical draft cooling tower and its associated water basin.
The fans for each dry and wet tower division are powered from independent emergency (Class lE) power supplies. Each dry/wet tower pair is capable of dissipating 100% of the plant heat load under accident conditions assuming the highest ambient temperature. The dry cooling towers alone normally provide sufficient CCW heat removal capability for plant needs. Under LOCA or severe weather conditions when the dry towers are not able to maintain the design CCW temperature, the wet cooling towers and ACCWS are automatically started on high CCW temperature for additional CCW heat removal capability. The wet tower basin also serves as a backup source of supply to the emergency feedwater system. The wet cooling tower basins can be manually interconnected through a seismic Category I line in order to take advantage of the full storage volume in the event of a single active failure to one tower. Makeup to the wet tower basins is normally provided by the nonessential demineralized water system.
In addition, makeup water can be supplied to the wet tower basins by gravity from the circulating water system for continuous once-through cooling of the ccws.
9-11
 
The applicant has used BTP ASB 9-2 to establish the heat input to the UHS due to fission product and heavy element decay. The applicant performed a heat transfer analysis assuming conservative worst site meteorology to verify the performance capability of the UHS. This analysis shows that the UHS is capable of providing sufficient cooling for 30 days under normal shutdown and accident conditions and maintain the CCWS temperature at the design maximum.
The design described above assures that adequate heat removal capability to maintain plant safety is provided by the UHS for all modes of operation including accidents coincident with a single active failure. Thus, the requirements of GDC 44 and the guidelines of Regulatory Guide 1.27 "Ultimate Heat Sink for Nuclear Power Plants 11 Positions C.l ) C.3, and C.4 regarding the UHS ability to maintain proper system temperature under all modes of operation are met. The entire UHS is seismic Category I and the dry and wet tower fans are also quality group C. The UHS is part of the nuclear plant island structure and is, therefore, protected against flooding. The UHS is protected against tornado missiles by the reactor auxiliary building walls and missile grating with the exception of two of the five cooling coils of each dry tower and the wet tower fans and fan motors. The applicant has shown by analysis that sufficient heat removal capability is provided for 24 hr to maintain plant safety and assure safe shutdown assuming only 60% of the dry towers is avail able plus the water volume in the wet tower basins and assuming the most limiting single failure coincident with loss of offsite power. During this 24-hr period, the operators can decide whether to employ the once-through cooling mode utilizing the circulating water system, or whether repairs may be made to damaged portions of the UHS. The portions of the circulating water system utilized in this mode are tornado missile protected (located underground).
The UHS is separated from high energy piping systems and internally generated missile sources. Thus ) the requirements of GOC 2 and 4 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.27 regarding UHS design against natural phenomena are met.
The dry cooling tower fans are normally operating. However, as ambient condi tions may a1low some fans to be stopped for periods of time, the dry tower fans and normally not operating wet cooling tower fans will be periodically tested in accordance with plant technical specifications. The UHS components are accessible to permit inservice inspection as required. Thus, the require ments of GDC 45 and 46 are met.
Based on the above, the staff concludes that the UHS meets the requirements of GDC 2, 4, 44, 45, and 46 with respect to protection against natural phenomena,
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inspection and testing, and the guidelines of Regulatory Guides 1.26, 1.27, and 1.29 with respect to quality group and seismic classification and design capability, and is, therefore, acceptable.
9.2.6 Condensate Storage Facilities The nonsafety-related (quality group D, nonseismic Category I) condensate and primary water storage and transfer system provides storage and transfer of condensate for various plant functions, and includes all components and piping associated with the system from the storage tank to the points of connection or interfaces with other systems. The staff has determined that the system is 9-12
 
capable of fulfilling the normal operating requirements of the facility for storage of condensate and primary water with the necessary component redundancy.
The system was evaluated and found to have no functions necessary for achieving or maintaining safe reactor shutdown conditions or for accident prevention or accident mitigation. The condensate storage tank via the condensate transfer pump provides normal makeup to the safety related condensate and refueling storage pools. However, this function is not required to maintain plant safety. Refer to Section 10.4.9 of this SER for further discussion on the condensate storage pool. Protection from flooding for safety-related equipment resulting from failure of the system is discussed in Section 9.3.3 of this SER. Thus, the system meets the requirements of GDC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29. Seismic Category I, quality group B containment isolation valves are provided at the system penetration, and are located in seismic Category I, flood and tornado missile protected structures (refer to Sections 3.4.1 and 3.5.2 of this SER),
thereby satisfying the requirements of GDC 2 and 4.
Based on the review, the staff concludes that the system meets the requirements of GDC 2 with respect to the need for protection against natural phenomena and the guidelines of Regulatory Guides 1.26 and 1.29 concerning its seismic and quality group classification and that safety-related portions meet the require ments of GDC 2 and 4 regarding protection against natural phenomena, missiles and environmental effects and is, therefore, acceptable.
9.2.7 Essential Services Chilled Water System The essential services chilled water system supplies chilled water to air handling units (fan coolers) serving essential and nonessential spaces (equip ment rooms and the main control room) throughout the reactor auxiliary build ing under normal and accident conditions. The system consists of three full capacity closed cooling piping trains each containing an essential (seismic Category I, quality group C) water chiller and its associated chilled water circulating pump and expansion tank and piping, valves and controls. Two of the piping trains (A and B) are essential, redundant (seismic Category I, quality group C), and serve redundant safety-related air handling units. The third piping train is nonessential and serves nonsafety-related units. Cool ing water to the chillers is supplied by the safety-related CCWS and ACCWS which reject the system heat to the UHS Makeup to the system is provided to the expansion tank by the essential (seismic Category I) CCW makeup pumps from the condensate storage pool. The A and 8 chillers/pumps are powered from indeoendent emeraencvv (Class lE) oower suoolies. The A/8 chiller and oump are powered from the-A/B emergency bus and can* be manually connected to either emergency power supply.
During normal operation, two of the three water chillers/pumps are operating to supply the three chilled water loops which are interconnected. The third chiller and pump are on standby. During accident conditions, a safety injec tion signal isolates the redundant essential loops from each other and the noness2ntial loop from the essential portions by closing the normally open, safety-related, redundant, air operated, fail closed isolation valves in series. Each essential loop can remove 100% of the heat necessary to assure safe plant shutdown under accident conditions. The standby chiller/pump can be manually aligned to either essential loop in the event of a failure in the A or B trains.
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The design of the essential services chilled water system assures that its function is not lost assuming a single active component failure coincident with a loss of offsite power. Adequate isolation is provided as indicated.
Thus, the requirements of GDC 44 are met.
The system is housed in the seismic Category I, flood and tornado protected reactor auxiliary building (refer to Sections 3.4.1 and 3.5.2 of this SER).
Essential portions of the system are designed to seismic Category I, quality group C requirements. Thus, the requirements of GDC 2 and the guidelines of Regulatory Guides 1.26, 1.29, and 1.102 are met.
The system is separated from the effects of internally generated missiles and high and moderate energy pipe break effects external to the system itself by its location in a separate compartment of the reactor auxiliary building (RAB)
(refer to Sections 3.5.1.1 and 3.6.1 of this SER). The RAB provides protection against tornado-generated missiles. Thus, the requirements of GDC 4 and the guidelines of Regulatory Guide 1.117 and BTP ASB 3-1 are met.
Two essential services chillers and pumps are normally operating. Availabil ity of the standby chiller/pump and any chiller not operating is assured by periodic functional tests and inspections as delineated in plant technical specifications. The system is located in accessible areas to permit inservice inspection as required. Thus, the requirements of GDC 45 and 46 are met.
Based on the above, the staff concludes that the essential services chilled water system meets the requirements of GDC 2, 4, 44, 45, and 46 with respect to the systems protection against natural phenomena, missiles and environmental effects, decay heat removal capability, inservice inspection and functional testing, and the guidelines of Regulatory Guides 1.26, 1.29, 1.102, and 1.117 and BTP ASB 3-1 with respect to the systems quality group and seismic classification, and flood, tornado missile and pipe break effect protection, and is, therefore, acceptable.
9.3 PROCESS AUXILIARIES 9.3.1 Compressed Air System The compressed air system, consisting of the instrument and service air systems, is designed to provide a reliable supply of dry, oil-free air for pneumatic instruments, controls, valves, and services. The system is not required to achieve a safe reactor shutdown or to mitigate the consequences of an accident.
The nonsafety-related (quality group D, nonseismic Category I) instrument air system consists of two full-capacity oil-free rotary compressors with inlet filter, after cooler, receiver tank, air dryer with pre- and after-filters, and a piping system for distributing air throughout the plant. The nonsafety related (nonseismic Category I) service air system for the facility consists of two full-capacity oil-free rotc:.."y compressors with inlet air filters, after-coolers, and receiver tanks. The service air system is interconnected with the instrument air system through an automatic control valve to serve as a backup source for instrument air. The backup connection is upsteam of the instrument air dryers. The instrument air compressors are powered from the emergency busses and are manually reconnected to the emergency diesel genera tors following a loss of offsite power. Pneumatically operated valves required 9-14
 
for safe shutdown of the plant following an accident or to mitigate the consequences of an accident are provided with seismic Category I passive air or nitrogen accumulators. All other air-operated valves and devices are designed for a fail-safe mode upon loss of instrument air and do not require a continuous air supply under emergency or abnormal conditions. Therefore, the system satisfies the requirements of GDC 2 and is designed to meet quality group D of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 in that its failure will not prevent safe reactor shutdown or result in unacceptable radioactive releases.
The staff evaluated the system and found it to have no functions necessary for achieving or maintaining safe reactor shutdown conditions or for accident prevention or accident mitigation. The staff determined that the system is capable of providing normal instrument and service air needs.
All compressed air system containment penetrations are provided with seismic Category I, quality group B isolation valves which are located in seismic Category I, flood and tornado protected structures. They are also protected from the effects of missiles and pipe breaks. Thus, the requirements of GDC 2 and 4 are satisfied for these portions of the system.
Based on the review, the staff finds the system meets the requirements of GDC 2 with respect to protection against natural phenomena and the guidelines of Reulatory Guides 1.26 and 1.29 concerning its seismic and quality group classification and that safety-related portions of the system meet the require ments of GDC 2 and 4 regarding protection against natural phenomena, missiles and environmental effects, and the system is, therefore, acceptable.
9.3.2 Process Sampling System Process sampling is accomplished by a primary sampling system, a secondary sampling system, and an automatic gas analyzer. The primary sampling system is designed to collect fluids and gaseous samples contained in the reactor coolant system and associated auxiliary system process streams during all modes of operation from full power to cold shutdown. The secondary sampling system is designed to collect water and stream samples from the secondary cycle and makeup demineralizer. The automatic gas analyzer periodically samples the gas space of the boron management system, the chemical and volume control system, and the waste management system. Provisions are made to assure that representative samples are obtained from well mixed streams or volumes of effluent by the selection of proper sampling equipment and location of sampling points as well as proper sampling procedures.
The process sampling system includes piping, valves, heat exchangers; and other components associated with the system from the point of sample with drawal from a fluid system up to the ana1yzing station, sampling station, or 1ocal sampling point. NRC review included the provisions proposed to sample all principal  fluid process streams associated with plant operation and the applicant 1 s proposed design of these systems including the location of sam pling points, as shown on piping and instrumentation diagrams.
The basis for acceptance has been conformance of the applicant 1 s design for the process sampling system to applicable regulations and guides, and industry 9-15
 
standards. The staff determined that the proposed process sampling system meets (1) the requirements of GDC 13 in 10 CFR Part 50, by sampling the reactor coolant, the ECCS core flooding tank, the refueling water storage tank, the boric acid mix tank, and the boron injection tank for boron concentration, which can affect the fission process, for normal operation, anticipated opera tional occurrences, and accident conditions; (2) the requirements of GDC 14 of 10 CFR Part 50, by sampling the reactor coolant and the secondary coolant for chemical impurities to ensure that the reactor coolant pressure boundary will have a low probability of abnormal leakage, rapidly propagating failure, and gross rupture; (3) the requirements of GOC 26 of 10 CFR Part 50, by sampling the reactor coolant, the refueling water storage tank, and the boric acid mix tank for boron concentrations for controlling the rate of reactivity changes; (4) the requirements of GDC 63 of 10 CFR Part 50, by sampling the spent fuel pool and the gaseous radwaste storage tank for radioactivity to detect condi tions that may result in excess radiation levels; (5) the requirements of GDC 64 of 10 CFR Part 50, by sampling the reactor coolant, the pressurizer tank, the steam generator blowdown, the secondary coolant condensate treatment waste, the sump inside containment, the containment atmosphere, and the gaseous radwaste storage tank, for radioactivity that may be released from normal operations, including anticipated operational occurrences, and from postulated accidents.
The staff further determined that the proposed process sampling system meets (a) the requirements of ANSI N13-1-1969 for obtaining airborne radioactive samples; (b) the requirements of 10 CFR Part 20.l(c) and Position 2.d(2),
2.f.(3), 2.f.(8), and 2.i.(6) of Regulatory Guide 8.8, Revision 3 (June 1978),
to maintain radiation exposures to as low as is reasonably achievable, by providing (1) ventilation systems and gaseous radwaste treatment system to contain airborne radioactive materials; (2) liquid radwaste treatment system to contain radioactive material in fluids; (3) spent fuel pool cleanup system to remove radioactive contaminants in the spent fuel pool water; and (4) remotely operated containment isolation valves to limit reactor coolant loss in the event of rupture of a sampling line; (c) the requirements of GDC 60 of 10 CFR Part 50 to control the release of radioactive materials to the environment by providing isolation valves that will fail in the closed position; and (d) Posi tions C.l, C.2, and C.3 of Regulatory Guide 1.26, Revision 3 (September 1976),
C.l, C.3, and C.4 of Regulatory Guide 1.29, Revision 3 (September 1978), and C.1.1.4, C.2.1.2, and C.2.1.3 of Regulatory Guide 1.143, by designing the sampling lines and components of the process sampling system to conform to the classification of the system to which each sampling line and component is connected, and thus meets the quality standards requirements of GDC 1 and the seismic requirements of GDC 2.
The proposed process sampling system is acceptable.
9.3.3 Equipment and Floor Drainage System The nonsafety-related (quality group D, nonseismic Category I) equipment and floor drainage system inclues all piping from equipment or floor drains to the sump, sump pumps, and piping necessary to carry potentially radioactive and potentially nonradioactive effluents through separate subsystems. Potentially radioactive drainage is collected in floor and equipment drain sumps in each building and discharged to the radwaste processing system. Drainage from 9-16
 
potentially non-radioactive sources such as turbine building liquid waste or roof drains are processed in the industrial waste system or discharged directly offsite. The containment penetration for the containment sump pump discharge line is designed to seismic Category I and quality group B requirements, and is located in seismic Category I, flood, tornado missile and environmentally protected structures, thereby satisfying the requirements of GOC 2 and 4.
NRC review considered those safety systems needed to provide safe plant shut down and the physical location of those systems with regard to potential inplant flooding. Because of their location at the lowest elevation in the reactor auxiliary building, the ESF equipment rooms, which contain the ECCS and emergency feedwater pumps and instrument cabinets required for safe plant shutdown under accident conditions, were considered of particular importance with respect to provisions for preventing water accumulation. The safety related pumps are mounted on pedestals of a minimum height of 12 in. Essential components are not housed in instrument cabinets less than 18 in. above the floor. Each redundant ESF equipment room and area is provided with separate independent sumps and sump pumps for removal of water accumulation. Back flooding  of the ESF rooms is prevented by means of a check valve on each room 1 s sump pump discharge piping. Equipment, floor drains and sumps are sized to handle all anticipated normal and transient drainage. Level indica tors and alarms are provided in the control room for monitoring all sump operating modes. Backup water level monitoring at the lowest reactor auxil iary building elevation is provided by redundant seismic Category I, Class lE level switches mounted on the floor which alarm in the control room when the water reaches a depth of 3 in. This will allow for sufficient time for operator action before an unacceptably high level is reached in these areas. Adequately sized drains are provided in other critical areas of the plant to provide for carrying off sufficient water to prevent room flooding. Thus, the system design meets the requirements of GOC 2 and the guidance of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 as its failure will not compromise plant safety or prevent a safe shutdown. In addition, the guidelines of BTP ASB 3-1 concerning internal plant flooding as a result of postulated piping failures are met.
Based on NRC review, the staff concludes that adequate protection against flooding of safety-related equipment and areas and protection against the inadvertent release of potentially radioactive liquids to the environment through plant drainage paths is provided by the measures discussed above to justify the nonsafety classification of the equipment and floor drainage system. The system is in conformance with the requirements of GDC 2 and 4 with respect to the need for protection against natural phenomena and the protection afforded against environmental effects (flooding) and the guide lines of Regulatory Guides 1.26 and 1.29 and BiP ASB 3-1 concerning seismic and quality group classification and flooding due to postulated piping failures, and is, therefore, acceptable.
9.3.4 Chemical and Volume Control System The chemical and volume control system (CVCS) is designed to control and main tain reactor coolant inventory and to control the boron concentration in the reactor coolant through the process of charging (makeup) and letdown (drawing off). The eves purifies the primary coolant by passing letdown through heat 9-17
 
xchangers and ion changers. Three positive displacement eves charging pumps supply high pressure injection (charging) of borated water into the reactor coolant for normal and emergency boration. The volume control tank serves as a means for hydrogen/oxygen control in the primary coolant and provides a reservoir for the charging pumps by collecting the purified letdown and addi tional makeup necessary. A boric acid makeup system provides any needed addi tional boron for maintaining proper primary chemistry. The system charging function is required for safe shutdown; however, letdown is not. Therefore, the charging portion contains redundant active components in order to meet the single failure criterion. Thus, as described above, the requirements of GDC 29, 11 Protection Against Anticipated Operational Occurrences, 11 and 33, 11 Reactor Coolant Makeup/' are met. The charging pumps also serve as safety injection pumps when the emergency core cooling system is required to function as described in Section 6.3 of this SER. Two of the three pumps are powered from independent emergency (Class lE) power supplies. The third is powered from the A/8 bus and is manually loaded to either emergency power supply. The CVCS also collects the controlled bleedoff from the reactor coolant pump seals and provides a means of filling, draining, and pressure testing of the reactor coolant system.
Essential portions of the eves include the charging pumps, volume control tank, and their associated piping and valves all of which are seismic Cate gory I, quality group B. The nonessential letdown and regenerative heat exchangers, ion exchangers, and their associated piping and valves are also seismic Category I and quality group B as they are part of the containment boundary. These components are located in the seismic Category I, flood and tornado protected reactor building and reactor auxiliary building (refer to Sections 3.4.1 and 3.5.2 of this SER). Thus, the requirements of GDC 2 and the guidelines of Regulatory Guides 1.26 and 1.29 are met.
Essential system components are located in separate protected compartments in the reactor auxiliary building and reactor building and are thus not exposed to internally generated missiles and high energy pipe break effects (refer to Sections 3.5.1.1 and 3.6.1 of this SER). The reactor auxiliary building and reactor building walls provide tornado missile protection. Thus, the require ments of GDC 4 with respect to missile and environmental effects and the guidelines of Regulatory Guide 1.117 and BTP ASB 3-1 are met.
Based on the above, the staff concludes that the chemical and volume control system meets the requirements of GDC 2, 4, 29, and 33 with respect to protection against natural phenomena, missiles and environmental effects, maintaining negative reactivity in accident conditions, and providing reactor coolant makeup, and the guidelines of Regulatory Guides 1.26, 1.29, and 1.117 and BTP ASB 3-1 concerning seismic and quality group classification, tornado missile and pipe break protection, and is, therefore, acceptable.
9.4 HEATING, VENTILATION, AND AIR CONDITIONING (HVAC) SYSTEMS 9.4.1 Control Room Area Ventilation S stem (Control Room Air Conditionin ys em The control room air conditioning system is designed to maintain a suitable environment for equipment operation and safe occupancy of the control room 9-18
 
under all plant operating conditions. The control room air conditioning system serves the main control room, computer room, toilet areas, kitchen and kitchenette, conference room and vault, storage and emergency storage areas, locker rooms, emergency living quarters, and corridors.
The control room air conditioning system satisfies the normal and emergency HVAC requirements in the control room and consists of two fully redundant essential trains of air handling units including filters, fans, chilled water cooling coils, electric heating coils, ductwork and dampers, isolation valves and nonessential exhaust fans. The system also includes two redundant essen tial emergency filtration units required for emergency operation each consist ing of fans, electric heating coils, ductwork and dampers, isolation valves, emergency filters and activated charcoal beds for removal of radioactivity and noxious gases. Outside air is normally provided through a single air intake with redundant essential normally open, fail closed, air operated isolation valves. Outside air is supplied in emergency conditions through two widely separated air intakes, each with two parallel series pairs (eight total) of redundant essential motor operated isolation valves; one valve in each series pair is normally open and one is normally closed. Two redundant essential 1oca1 cooling units are also provided to maintain proper control room air conditioning equipment room temperature.
Power to the redundant essential air conditioning system components is supplied by independent emergency (Class lE) power supplies thus assuring proper system function and isolation in the event of a single power supply failure. Cooling water to the chilled water cooling coils of the redundant system trains is provided from the corresponding redundant trains of the essential services chilled water system.
The control room air conditioning system is designed to automatically maintain the control room and associated areas discussed above within the environmental limits required for operation of plant controls and uninterrupted safe occu pancy of required manned areas during all operating modes including LOCA conditions. The system is designed to maintain the control room under positive pressure. Redundant radiation, chlorine gas and ammonia detectors are located near the normal system outside air intake. Receipt of a high radiation signal or safety injection signal automatically isolates the normal outside air intake and exhaust, opens the recirculation dampers, opens the emergency outside air intakes and starts the emergency filtration units. The control room is then operated in a pressurized mode drawing air from the separate emergency intake locations and passing a portion of the recirculated air through the emergency and charcoal filters for cleanup. The operator may isolate one of the emergency outside air intakes if he suspects it is con taminated. Receipt of a toxic gas signal automatically isolates the outside air intake and exhaust, opens the recirculation dampers and starts the emer gency filtration units. The control room is then operated in an isolation mode which passes a portion of the recirculated air through the emergency and charcoal fi1ters, but no outside air is provided.
The design described above conforms to the requirements of GOC 19, 11 Control Room, 11 and the guidelines of Regulatory Guide 1.95 "Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release, 11 with respect to assuring environmental limits for proper operation of plant controls and safe occupancy of the control room under all normal and accident conditions including LOCA conditions.
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All essential portions of the system are located in the reactor auxiliary building which is seismic Category I, flood and tornado protected (refer to Sections 3.4.1 and 3.5.2 of this SER). Essential portions of the system itself are seismic Category I, quality group C. Thus, the requirements of GDC 2 and the guidelines of Regulatory Guides 1.26 and 1.29 are met.
The system is physically separated from high energy systems and is thus pro tected from the effects of postulated pipe failure in high energy systems (refer to Section 3.6.1 of this SER). The control room air conditioning equipment room provides protection from internally and externally generated missiles and is provided with suitable drainage for protection against flood ing due to moderate energy piping system failure and failures in non-seismic water systems (refer to Sections 3.5.1.1 and 9.3.3 of this SER). The outside air intakes are located in the reactor auxiliary building and are tornado missile protected. Thus, the requirements of GDC 4, and the guidelines of Regulatory Guide 1.117 and BTP ASB 3-1 are satisfied.
The system incorporates provisions for the purging of smoke, or other con taminants with no recirculation by bringing in fresh outside air and exhaust ing the contaminated air to the outside.
Based on the above, the staff concludes that the control room air conditioning system is in conformance with the requirements of GDC 2, 4, and 19 as related to protection against natural phenomena, environmental effects and missiles and provides an adequate environment for equipment operation and protection to permit access for occupancy of the control room under accident conditions, and the guidelines of Regulatory Guides 1.26, 1.29, 1.95, and 1.117 and BTP ASB 3-1 relating to the system seismic and quality group classification, protection against chlorine gas release and the effects of tornado missiles, and high and moderate energy pipe breaks and is, therefore, acceptable.
9.4.2 seent Fuel Pool Area Ventilation System (Fuel Handling Building Ventila-tion System The fuel handling building ventilation system is designed to maintain a suit able environment for equipment operation and personnel access, and to limit potential radioactive release to the atmosphere during normal operation and postulated fuel handling accident conditions. The system serves the electric equipment room, fuel pool pump/heat exchanger room, bulkhead gate storage area, corridor, new fuel vault, loading area, spent fuel cask decontamination and storage areas, refueling canal area, and spent fuel storage area. The system is classified as nonessential (nonsafety-related) except that those portions required to mitigate the consequences of a fuel handling accident are classified as essential (safety-related). The system consists of a norma1 nonessential supply fan, two normal nonessential exhaust fans, and their asso ciated dampers and ductwork. The essential portion includes two redundant trains of emergency filtration exhaust units (each with an electric heating coil, medium effeciency filter, HEPA filters, charcoal adsorber and exhaust fan) and two redundant H&V (heating and ventilating) room exhaust fans. Power to the redundant emergency filtration exhaust units and H&V room exhaust fans is provided by independent emergency (Class lE) power supplies.
During normal and refueling operations, the system distributes air throughout the fuel handling building from areas of low potential radioactivity to areas 9-20
 
of progressively higher potential radioactivity. This is accomplished by continuous operation of the normal fuel handling building supply fan and one of the two normal exhaust fans. The operation of these fans is interlocked (the supply fan can not run if the exhaust fan is not on) in order to assure proper pressurization of fuel handling building areas from uncontaminated to potentially contaminated zones. Thus, the system is capable of fulfilling the requirements of the spent fuel storage facility for providing a fuel handling area environment with controlled temperature and humidity to ensure the comfort and safety of personnel and the integrity of the fuel handling equipment during normal operation and during fuel handling operations.
On detection of high radiation (indication of a fuel handling accident),
redundant radiation detectors located in the fuel handling building transmit a signal to automatically isolate the spent fuel handling and storage areas of the fuel handling building by closing redundant seismic Category I isolation dampers in the normal supply and exhaust ducts, and stopping the normal supply and exhaust fans. The redundant trains of emergency filtration exhaust units and H&V room exhaust fans are automatically started by this same signal. The emergency filtration exhaust units maintain a negative pressure in the poten tially contaminated areas and process all air through the filter/charcoal adsorbers before it is discharged to the environment. Thus, the guidelines of Regulatory Guide 1.13 for preventing release of radioactive contaminants to the environment are satisfied.
As noted above, the normal ventilation system is stopped on receipt of a high radiation signal or loss of offsite power. Air cooling to the normally operating spent fuel pool cooling pumps is terminated. To provide proper air flow to these pumps under emergency conditions, the operator may restart the normal supply and exhaust fans and thereby assure essential fuel pool cooling for maintaining the integrity of the spent fuel storage facility. These fans can be manually loaded on the emergency (Class IE) power supplies if required.
The essential portions of the fuel handling building ventilation system are located in the fuel handling building which is a seismic Category I, flood and tornado protected structure (refer to Sections 3.4.1 and 3.5.2 of this SER).
The nonessential normal ventilation system is separated from the essential portions in such a way that its failure will not prevent essential safety functions. Essential portions of the system itself are seismic Category I, quality group C. Thus, the requirements of GDC 2 and the guidelines of Regulatory Guides 1.26 and 1.29 are met.
There are no high or moderate energy systems located near safety-related por tions of the $ystem and adequate protection against internally and externally generated missiles is provided by the H&V equipment room walls (refer to Sections 3.5.1.1 and 3.6.1 of this SER). Thus, the requirements of GDC 4 and the guidelines of Regulatory Guide 1.117 and BTP ASB 3-1 are satisfied.
Based on the above, the staff concludes that the spent fuel handling building ventilation system is in conformance with the requirements of GDC 2 and 4 relating to protection against natural phenomena, missiles and environmental effects and the guidelines of Regulatory Guides 1.13, 1.26, 1.29, and 1.117 and BTP ASB 3-1 relating to protection against radioactive releases, seismic and quality group classification, protection against tornado missiles, and high and moderate energy pipe breaks and is, therefore, acceptable.
9-21
 
9.4.3 Auxiliar and Radwaste Area Ventilation S stem (Reactor Auxiliar Build-The reactor auxiliary building (RAB) ventilation system is designed to main tain a suitable environment for equipment operation and personnel access, and to limit potential radioactive release to the environment during all modes of operation. The system serves all areas of the RAB and consists of the follow ing subsystems: RAB normal ventilation system, personnel and decontamination areas ventilation system, RAB H&V (heating and ventilating) equipment room ventilation system, RAB cable vault and switchgear area ventilation system, RAB hot machine shop and decontamination area ventilation system, RAB air conditioning system, safety-related and nonsafety-related fan coolers, and controlled ventilation area system. Of these, the RAB normal ventilation system, personnel and decontamination area ventilation system, RAB hot machine shop and decontamination area ventilation system, RAB air conditioning system, and nonsafety-related fan coolers are not required for accident mitigation or safe shutdown of the plant.
The RAB normal ventilation system is classified as nonessential (quality group D, nonsafety-related) and consists of two supply fans, two exhaust fans, filters, dampers, charcoal adsorber and isolation valves. The system provides normal RAB air flow requirements for radwaste areas, safeguard pump rooms, and emergency diesel generator rooms and distributes air from areas of low potential radioactivity to areas of progressively higher potential radioactivity and exhausts through the plant vent. The system is isolated by redundant fail closed, air operated, seismic Category I, isolation valves on receipt of a safety injection signal and, therefore, its failure will not compromise plant safety. Thus, the requirements of GDC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 with respect to protection of safety-related systems from failure of nonsafety-related systems are met.
The personnel and decontamination area ventilation system is classified as nonessential (quality group D, nonsafety-related) and consists of two air handling units. The system provides air to various health physics areas, locker rooms, laboratories, storage areas and work shops, and exhausts through the RAB normal ventilation system. The system is separated from safety-related systems and, therefore, its failure will not compromise plant safety and the requirements of GDC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 are satisfied.
The emergency diesel generator ventilation system supplies combustion and cooling air for emergency operation of the diesel generator and is thus clas sified as essential (safety-related). It consists of an individual full capacity exhaust fan and outside air intake for emergency air flow for each diesel. The fans automatically start on startup of their associated diesel and are powered by their respective emergency (Class lE) power supply. The system is seismic Category I, quality group C and is located in the seismic Category I, flood and tornado protected RAB (refer to Sections 3.4.1 and 3.5.2 of this SER). Each fan is separated from the effects of internally generated missiles and high energy piping (refer to Sections 3.5.1.1 and 3.6.1 of this SER). The fan and intakes are provided with tornado missile barriers. Thus, the requirements of GDC 2 and 4 with respect to protection against natural phenomena, missiles and environmental effects and the guidelines of Regulatory Guides 1.26, 1.29, and 1.117 and BTP ASB 3-1 with respect to quality group and seismic classification, tornado missiles, and pipe break effects are met.
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The RAB cable vault and switchgear areas ventilation system is classified as essential (safety-related) as it maintains a suitable environment for essential electrical equipment including switchgears, batteries, and relays during normal and accident conditions. It consists of two separate essential supply subsystems serving different RAB areas each with two redundant full-capacity air handling units, two redundant full-capacity essential exhaust fans for each of the four battery rooms, one nonessential normal exhaust fan, two nonessential smoke purging exhaust fans, and two redundant full-capacity essential H&V room ventilation fans. Redundant essential equipment is powered from independent emergency (Class lE) power supplies. Under normal operating conditions, one train of each supply air handling unit subsystem is operating automatically in a temperature controlling recirculation mode drawing minimum outside air, the normal exhaust fan is on, one of each pair of battery room exhaust fans is operating to prevent possible hydrogen accumulation, and the H&V room fans are automatically operating to control temperature. The status of the battery room exhaust fan is provided to the operator in the main control room, and loss of an exhaust fan is alarmed in the control room. Emergency operation of the system is initiated by a safety injection actuation signal which closes the redundant outside air intake dampers, starts both trains of air handling supply units for operation in a fully recirculating mode, and all battery room exhaust fans, and trips the normal exhaust fan. Essential portions of the system are seismic Category I, quality group C and are located in the seismic Category I, flood and tornado protected RAB (refer to Sections 3.4.1 and 3.5.2 of this SER). The system is separated from the effects of inter nally generated missiles and high energy piping (refer to Sections 3.5.1.1 and 3.6.1 of this SER), and the outside air intake and exhaust louvers are pro tected from tornado missiles by the RAB. Thus, the requirements of GDC 2 and 4 with respect to protection against natural phenomena, missiles and environ mental effects and the guidelines of Regulatory Guides 1.26, 1.29, and 1.117 and BTP ASB 3-1 with respect to quality group, seismic classification, tornado missiles and pipe break effects are met.
The RAB hot machine shop and decontamination area ventilation system is classified as nonessential (quality group D, nonsafety-related) and consists of two supply and two exhaust air handling units, one pair for the hot machine shop the other for the decontamination area. The system maintains a suitable environment for personnel and is separated from safety-related systems; thus its failure will not compromise plant safety, and the requirements of GOC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 are satisfied.
The RAB air conditioning system is classified as nonessential (quality group D, nonsafety-related) and consists of a sing1e air handling unit and    ' exhaust rl a biac k..up fan coo.er f.an, an_                      l . Th
                                  ... e sys_em t    . tams main  ' a su,_a
                                                            . t b 1,e environmen +... -f,or personnel and various nonessential electrical equipment during normal opera tion and is separated from safety-related systems, thus its failure will not compromise plant safety and the requirements of GDC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 are satisfied.
Fan coolers are located in various rooms of the RAB in order to maintain suit able equipment operating environments during normal and accident conditions (safety-related coolers only). Chilled water to the fan coolers is provided by the essential services chilled water system. Nonsafety-related fan coolers 9-23
 
are separated from safety-related fan coolers and chilled water to them is automatically isolated in accident situations so that their fai1ure will not compromise plant safety and thus, the requirements of GDC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 are satisfied.
Safety-related fan coolers are provided in the following essential equipment areas: shutdown cooling heat exchanger area A&B; safeguard pump A, A/Band 8 areas; charging pump A, A/8 and Bareas; emergency feedwater pump A&Bareas; component cooling water heat exchanger A&Bareas; and component cooling water pump A, A/Band Bareas. Fan coolers serving individual safety-related pump rooms (A or B) are started automatically when the associated pump starts. The fan coolers and their associated pumps are powered from the same independent emergency (Class lE) power supply. Each A/Bpump is served by two redundant full-capacity fan coolers, each powered from independent emergency (Class lE) supplies, one of which starts when the pump starts. Each fan cooler serving an essential heat exchanger is powered from the emergency power supply corres ponding to the heat exchanger designation (A or B) and is started by room temperature. All safety-related fan coolers are seismic Category I, quality group C and are located in the seismic Category I, flood and tornado protected RAB (refer to Sections 3.4.1 and 3.5.2 of this SER). They are separated from the effects of internally generated missiles and high energy piping, and are protected from tornado missiles by the RAB walls (refer to Sections 3.5.1.1 and 3.6.l of this SER). Thus, the requirements of GDC 2 and 4 with respect to protection against natural phenomena, missiles and environmental effects and the guidelines of Regulatory Guides 1.26, 1.29, 1.117 and BTP ASB3-1 with respect to quality group, seismic classification, tornado missiles, and pipe break effects are met.
The controlled ventilation area system is classified as essential (safety related) as it provides filtration of exhaust air from areas of the RABcon taining the low pressure safety injection pumps, high pressure safety injec tion pumps, containment spray pumps, shutdown heat exchangers, and the contain ment penetration area containing the recirculation SIS sump water lines. It consists of two redundant full-capacity exhaust fans powered from independent emergency power supplies, HEPA filters, charcoal absorbers, associated ductwork and redundant fail-closed, air operated isolation valves. The RABnormal ventilation system provides air flow to these areas under normal operating conditions. On receipt of a safety injection actuation signal, the exhaust fans are started, valves are closed, and a negative pressure is maintained in the above areas with all exhaust air from them being processed in the filters and charcoal before discharging to the atmosphere. Two safety-related, redun dant, full-capacity air handling units and exhaust fans, each pair of which is powered from an independent emergency power supply, are provided to maintain a suitable environment for the controlled ventilation area system equipment.
The system is seismic Category I, quality group Candis located in the seismic Category I, flood and tornado protected RAB (refer to Sections 3.4.1 and 3.5.2 of this SER). The system is separated from the effects of internally generated missiles and high energy piping (refer to Sections 3.5.1.1 and 3.6.1 of this SER). The RABprovides protection against tornado missiles. Thus, the require ments of GDC 2 and 4 with respect to protection against natural phenomena, missiles and environmental effects and the guide1ines of Regulatory Guides 1.26, 1.29, 1.117 and BTP ASB 3-1 with respect to quality group, seismic classification, tornado missiles and pipe break effects are met.
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Based on the above, the staff concludes that the reactor auxiliary building ventilation system is in conformance with the requirements of GDC 2 and 4 relative to protection against natural phenomena, missiles and environmental effects and the guidelines of Regulatory Guides 1.26, 1.29, and 1.117 and BTP ASB 3-1 relating to quality group and seismic classification, tornado missiles, and high and moderate energy pipe breaks and is, therefore, acceptable.
9.4.4 Turbine Area Ventilation System (Turbine Building Ventilation System)
The turbine building ventilation system meets the turbine building air flow requirements and is classified as nonessential (quality group D and nonsafety related). The system maintains an acceptable environment for personnel and the nonessential equipment served during normal plant operation. The system is separated from safety-related plant systems and areas; therefore, failure of the system will not compromise the operation of any essential plant systems or result in an unacceptable release of radioactivity. The requirements of GDC 2 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 are satisfied.
Based on NRC review, the staff concludes that the turbine building ventilation system meets the requirements of GDC 2 with respect to the need for protection against natural phenomena and meets the guidelines of Regulatory Guides 1.26 and 1.29 concerning its quality group and seismic classification and is, therefore, acceptable.
9.4.5 Engineered Safety Features Ventilation System Discussion on ventilation systems in areas housing engineered safety features is included in Section 9.4.3 of this SER.
9.5 OTHER AUXILIARY SYSTEMS 9.5.1 Fire Protection 9.5.1.1 Introduction The staff has reviewed the Waterford Unit 3 Fire Protection Program Reevaluation submitted by the applicant by {{letter dated|date=July 1, 1977|text=letter dated July 1, 1977}}. The submittal was in response to NRC request to evaluate the fire protection program at Waterford 3 against the guidelines of Appendix A to BTP APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants.'' Staff review was based only on the above submittal; the staff has not made a site visit to the plant-to observe fire protection features, because the construction of the plant has not progressed to the level where such a visit would be meaningful. The staff has requested the applicant to identify any specific exception taken to NRC guidelines in Appendix A to BTP 9.5-1 and Appendix R to 10 CFR Part 50 and has also requested information related to maintaining a post-fire shutdown capability.
All systems, areas, and evaluations discussed herein are subject to revision following a fire protection site visit and the receipt of the requested information. This review will be completed by October 1981, and the results will be reported in a supplement to this SER.
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9.5.1.2 Fire Protection Systems Description and Evaluation (1) Water Supply Sstems: The water supply system consists of three fire pumps separate y connected to a buried, 10-in. pipe loop around the plant.
The fire pumps are rated at 2000 gal/min at 100 psig head. One pump is electric motor driven and two are diesel engine driven. The fire pumps are located in a separate fire pump house and are separated by 3-hr fire-rated walls. Automatic sprinklers are provided to protect the fire pump building.
A separate jockey pump, rated at 200 gal/min at 100 psig, maintains the yard fire main pressure at 100 psig. If the fire main pressure drops to 90 psig, the electric motor driven fire pump will automatically start.
The first diesel engine driven fire pump will start automatically if the pressure drops to 85 psig, and the other diesel pump will start auto matically if the pressure falls to 80 psig. Separate audible and visual alarms are provided in the control room for each pump to monitor pump operation, prime mover availability, power failure, and failure of a fire pump to start.
All valves in the fire protection water supply system are electrically supervised by alarms in the control room.
The pumps take suction from two 260,000-gal vertical ground level water storage tanks, arranged so that all fire pumps can take suction from either or both tanks. However, as presently designed, either a break in the pump suction headers or in the pump discharge lines, including the cross-connection between the two discharge lines, could cause the loss of all three fire pumps.
To meet the guidelines of Appendix A to BTP 9.5-1, the applicant will be required to install additional valves in the fire pump suction header and discharge lines to preclude a single break from shutting down all three fire pumps.
The greatest water demand for the fixed fire suppression systems is 1200 gal/min and, coupled with 750 gal/min for hose streams, creates a total water demand of 1950 gal/min. However, as presently designed, the fire water system also supplies lubricating water for the circulating water air evacuation pumps and the circulating water pumps. This additional demand on the fire pumps has not been specified and included in the total water demand of 1950 gai/min; therefore, it is not clear that the Appendix R requirement for a 2-hr water supply at maximum demand is met. In addition, the water storage capacity does not meet Appendix A guidelines calling fer a minimum of two 300,000-gal storage tanks. The acceptability of the water storage capacity, the pump capacities and the supply of the non-fire re1ated pump cooling systems will be determined after the maximum water demand is established.
(2)  Sprinkler and Standpipe Systems: The automatic sprinkler systems and standpipe risers are connected to common interior water supply headers.
The interior headers are fed from each end through separate supply con nections to the looped yard system with appropriate valves so that 9-26
 
sections can be isolated to perform maintenance or to prevent a single break from impairing the entire distribution system. In addition, header and divisional valve arrangement is such that no single failure can impair both primary and backup fire protection systems protecting a single fire area. The water supply valves to the suppression systems are electrically supervised with alarms in the control room. In addition, the sprinkler systems have waterflow alarms in the control room.
The automatic sprinkler systems, e.g., wet pipe sprinkler systems, pre action sprinkler systems, on-off multicycle sprinkler systems, and water spray systems, will be designed to the recommendations of National Fire Protection Association (NFPA) Standards No. 13, 11 Standard for the Instal lation of Sprinkler Systems 11 and No. 15, 11 Standard for Water Spray Fixed Systems. 11 The areas that have been equipped with automatic water suppression systems include the following:
Cable vault, Zone RAB 4 Electrical penetrations A and B, Zones RAB 5 and 6 Diesel generators 3AS and 3BS, Zones RAB 15 and 16 Diesel oil feed tank spaces A and B, Zones RAB 15A and 16A Hydraulic baler, Zone RAB 22 Emergency diesel generator fuel oil tanks A and 8, Zones RAB 40 and 41 Reactor coolant pumps lA, 2A, 18, and 28, Zone RCB In addition to these areas, other areas may need to be protected by automatic sprinkler systems to comply with the guidelines for protection of redundant safe shutdown systems as delineated in Section 9.5.1.4 of this SER.
Manual hose stations are located throughout the plant to ensure that an effective hose stream can be directed to any safety-related area in the Pilant. The standpipes are consistent with the requirements of11 NFPA 14,
    'Standard for the Installation of Standpipe and Hose Systems.      However, Appendix A guidelines calling for minimum 4- and 21/2-in.-diameter pipe sizes for multiple and single hose station supplies, respectively, have not been met by the 2-in.-diameter standpipes installed.
NRC review of the water suppression systems will be completed after the site visit to the plant.
(3) Gaseous Fire Suppression Systems: A Halon total flooding system ik used as the primary ext1ngu1sh1ng agent in the nonsafety-related computer room underfloor spaces. The system is designed to produce a 5 to 7% Halon concentration with a soaking time of 15 to 20 min. The system is activated by cross-zoned ionization detectors.
The Halon suppression system is installed in accordance with the require ments of NFPA 12A, 11 Standard on Halogenated Fire Extinguishing Agent Systerns--Ha 1 on 1301. 11 9-27
 
NRC review of the gaseous fire suppression system will be completed after the site visit to the plant.
(4) Fire Detection Sstems: The fire detection systems consist of ionization detectors, associated electrical circuitry, electrical power supplies and the fire annunciation panels. The systems provide both a local audible alarm and audible and visual alarms in the control room. Such detection systems are or will be installed in all areas of the plant containing safe shutdown related system components. This includes the control room, the new and spent fuel pool areas, and areas of cable concentration.
Other areas may need fire detection systems to comply with NRC guidelines.
The fire detection systems will be installed according to NFPA 720, 11 Standard for the Installation, Maintenance, and Use of Proprietary Protective Signaling Systems. 11 NRC review of the fire detection system will be completed after the site visit to the plant.
9.5.1.3 Other Items Related to Fire Protection Programs (1)  Fire Barriers and Fire Barrier Penetrations: Walls and floor/ceiling assemblies separating fire areas and zones consist of 2- or 3-hr fire rated construction. Cable tray penetrations of the fire barriers are designed to provide a fire resistance rating of 3 hr. Piping penetra tions are designed to varying fire resistances based on the fire loading of the areas involved. The adequacy of those barriers and penetration seals of less than 3-hr fire resistance rating will be evaluated after the staff visits the site.
(2) Fire Doors and Dampers: The applicant has indicated that all doorways and access hatches in fire area boundaries are protected by 3-hr rated fire door assemblies.
The applicant has not provided automatic fire dampers at the fire barrier penetrations of safety-related ventilation systems. This is unacceptable, and NRC will require that all ductwork penetrations of required fire barriers be provided with 3-hr rated fire door dampers, and that the area around the outside of the duct be sealed to provide a complete 3-hr rated fire barrier. Areas where nonsafety-related ductwork has been provided with 11/2-hr fire dampers will be reviewed and the acceptability of such dampers in lieu of 3-hr fire door dampers will be determined after the staff visits the site.
9.5.1.4 Plant Areas Containing Redundant Divisions The applicant's analysis identified numerous plant areas where redundant divisions of cables, conduits and equipment are in close proximity to each other and, therefore, could be vulnerable to a single fire event in either transient or permanently installed combustibles. The only protection pre sently intended for these areas (in addition to any sprinkler systems identi fied in Section 9.5.1.2 of this SER) is a fire retardant coating applied to redundant safety train cable trays that cross over each other. The coating 9-28
 
will be applied to each tray to a distance of 5 ft out from the centerline of the crossover. The same coating will be applied where safety-related cable trays cross over nonsafety-related trays. No protection is proposed for circuits not located in cable trays or for redundant equipment in similar situations. In general, such a protection method is not considered adequate.
The staff will review plant areas containing redundant divisions of safe shutdown systems during its site visit for adequacy of separation and protec tion. Except for areas that may be identified during our site visit and subsequent review, NRC will require that a11 areas that contain redundant safe shutdown systems which are not separated by 3-hr fire-rated barriers be pro vided with an automatic, wet-pipe sprinkler system designed to cover the entire area as well as an early warning smoke detection system. In addition, in those areas where the redundant systems are separated by less than 20 ft of clear, open air space, an ASTM E-119 rated fire barrier which will completely enclose one of the redundant systems should be provided. The barrier should protect the circuit integrity/equipment availability of that system for 1-hr under fire test conditions.
Where safe shutdown capability cannot be assured by barriers and suppression and detection systems, an alternate shutdown system will be provided. Among such areas are the control room and cable spreading room. The alternate shutdown system should be completely independent of the area for which it is being provided so that a fire in either area that damages redundant systems will not affect the shutdown capability from the other area. When an alter nate shutdown system is provided, the 1-hr ASTM E-119 fire barrier for one redundant system need not be provided.
9.5.1.5 Emergency Lighting The applicant presently is providing ac emergency lighting in areas where safety functions are performed, and 8-hr battery power supplied emergency lighting in access routes to these areas and for emergency evaluation. NRC will require that the applicant provide individual 8-hr battery pack emergency lighting units in a11 areas of the plant that may be necessary to man for safe plant shutdown and in access and egress routes to all fire areas.
9.5.1.6 Fire Protection for Specific Areas Specific plant areas have not been reviewed in detail since the staff has not yet received the requested additional information pertaining to safe shutdown systems and associated circuits and it has  not been to the site to review the areas. However, based on the applicant 1 s response to NRC guidelines; there are many areas of the plant that do not conform to NRC guidelines for protec tion and separation of critical plant systems and/or areas. Many areas appar ently exist where a single fire event could damage redundant safe shutdown systems. From the descriptions provided by the applicant, several areas may require alternate shutdown systems as defined in Section 9.5.1.4 of this SER.
Some of the specific areas of concern that will be addressed after a site visit include the following:
9-29
 
o An oil containment and collection system has not been provided for the reactor coolant pump lube oil system.
o Redundant safety division switchgear areas are not separated from each other by fire-rated barriers.
o Combustible flooring and/or floor covering and wall coverings are provided in some areas, including the computer room and the new fuel storage area.
o Pressurized water type portable hand fire extinguishers are not utilized in the plant. Reliance is placed on dry chemical and CO 2 extinguishers.
o Effects of failure or inadvertent operation of the fire suppression systems have not been analyzed.
9.5.1.7 Administrative Controls and Fire Brigade Insufficient information has been provided by the applicant to evaluate this aspect of the overall fire protection program. NRC will require that a minimum five-man fire brigade be maintained on site at all times, with adequate dedicated breathing apparatus for all fire brigade members.
9.5.1.8 Conclusions The fire protection program at Waterford 3 is reviewed in accordance with Appendix A to Branch Technical Position ASB 9.5-1 and Appendix R to 10 CFR Part 50. A fire protection review field trip has not been made because a sufficient amount (90%) of the instrumentation and control wiring and power cables has not yet been installed. Also, the applicant has not provided the details of the design of the alternate shutdown system. A fire protec tion review field trip has been tentatively scheduled for September 1981.
A fire protection program evaluation will be completed 1 month after the site visit and the staff's review of the applicant's alternative shutdown system.
9.5.2 Communication Systems The communication system is designed to provide reliable intraplant and inter plant (or plant-to-offsite) communications under both normal plant operation and accident conditions.
9.5.2.1 Intraplant Systems The intraplant communications systems provide sufficient equipment of various types so that the plant has adequate communications to start up, continue safe operation, or safely shut down. The intrap1ant systems include:
(1)  Public Address System: The public address system is arranged as a redundant system with four independent speaker transmission lines supplying nine zones, and each zone is covered by two channels. Speakers in each zone are connected to alternate channels. Telephone instruments have access to the loud-speaker-paging network. Power for the paging system is provided by the 120-V ac uninterruptible power system. The preamps and power amplifiers are monitored by a supervisory signal; the active tone generators are a1so supervised. Failure of any of these components is detected and annunciated in the main control room.
9-30
 
The onsite alarm signals are generated by one of two redundant tone generators. In case one unit fails, the standby tone generator is auto matically connected to the system. The alarm signal is broadcast over the entire site through the paging system loudspeakers.
Special microphones and loudspeakers are to be provided in areas where the noise levels are high.
(2) Telephone Communication: Intraplant voice communication is provided by a Private Automatic Branch Exchange (PABX) telephone system which will also interconnect with the central office of the South Central Bell Telephone System. The intraplant PABX independent touchtone system has the capacity for 30 simultaneous conversations on a dial-up basis between extension stations located strategically throughout the plant areas. In the event of a system malfunction, including power failure, a telephone switch sends an alarm signal to the control room.
Each PABX extension station has access to all telephones in the plant as well as to the loudspeaker paging network and the radio paging transmitter.
The PABX system is supplied 120-V ac power from the plant uninterruptible power system.
(3)  Sound Powered S&#xa5;stem: The intraplant sound-powered telephone system provides communication through 11 dedicated sound-powered headset intercom circuits. These circuits are terminated in the main control room.
Headset jack stations are conveniently located in the control room and critical areas throughout the plant. This system does not require any power supply because all required energy is generated by the speaker.
9.5.2.2 Interplant (Plant-to-Offsite) Communication Systems The design basis for interplant communications is to provide dependable communi cations for reliable operation. During normal operation, offsite telephone service is provided to the plant by the South Central Bell central office trunks. In the event that commercial telephone service is lost, an emergency communications link will be set up from the main control room, the central alarm station, and/or secondary alarm station via the two-way radio system and/or LP&L 1 s microwave system, which are both available to the plant. The intraplant communications powered from the 120-V ac static uninterruptible power system includes:
(1)  LP&L 1 s Microwave 5&#xa5;stem: ihe Waterford 3 microwave system is an extension of existing LP&[ microwave system for Waterford 1 & 2 and provides five voice channels interfaced with Waterford 3 PABX system.
(2) Two-Way Radio Sstem: The operation and maintenance radio system has two modes of operation: one-way (paging) and two-way. The base station can be used as a repeater for portable-to-portable and portable-to-base station communication, or in conjunction with the PABX telephone system.
The plant security radio system consists of a base station controlled from the central alarm station, the secondary alarm station, and the access control facility and portable transceivers for the plant security force.
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The operations and maintenance and security radio systems utilize the FM band operating on different frequencies, and the base stations are remotely controlled and monitored from their consoles. An antenna system is provided for interior building radio signal coverage. For offsite radio communication there is a two-way base station. This will provide communica tion with the Sheriffs and Civil Defense Offices. Monitor receivers are provided to receive signals transmitted by the Sheriff or Civil Defense on their respective assigned frequency.
(3) Commercial Telephone: Telephone calls from the plant into the South Central Bell System can be made from designated unrestricted service phones located in strategic areas of the plant.
The scope of review included assessment of the number and types of communications systems provided, assessment and adequacy of the power sources, and verification of functional capability of the communications system under all conditions of operation.
The basis for acceptance in the staff review was conformance of the design criteria and bases and design of the installed communication systems to the acceptance criteria in Section II of SRP Section 9.5.2. Another basis for acceptance was conformance to industry standards and the ability of the systems to provide effective communications from diverse means within the Waterford 3 plant during normal and emergency conditions, assuming maximum potential noise levels.
Based on NRC review, the staff concludes that the installed communication systems at Waterford 3 plant conform to the above cited standards, criteria, and design bases; they can perform their design functions and are, therefore, acceptable.
Special  requirements needed for the communication systems to satisfy Appendix A to BTP APCSB 9. 5-1 wi 11 be reviewed at a 1 ater date during the fire protec 11 II tion review of Waterford 3. Additional requirements resulting from the fire protection review may be imposed to further improve the capability of the 1 i ghting system.
9.5.3 Lighting System The lighting system for Waterford 3 is designed to provide adequate lighting in all areas of the station and consists of normal and normal/emergency ac lighting systems and an emergency de lighting system. The design is based on illumination levels that equal or exceed those recommended by the Illuminating Engineering Society for central stations.
Normal ac li9hting for the plant is supplied by normal plant 208/120-V three phase four-wire distribution system for all areas except the main control room.
Normal/emergency ac lighting is provided by two lighting panels each with a normal and an emergency bus section. Upon loss of offsite power the normal bus section is disconnected. The 10% of the building lights that are supplied by the emergency section of each panel will be supplied by the diesel generator.
9-32
 
The normal/emergency ac panels provide the lighting for the main control room, one supplied by Division A and one supplied by Division B. Failure of either or both ac supplies results in automatic energization of the de lighting which provides sufficient illumination for plant shutdown and other essential services.
In general, all ac lighting at the plant is mercury vapor or fluorescent; in areas such as containment where such lighting is prohibited, incandescent lighting is used.
Two redundant emergency de lighting systems are furnished, each powered from one of the ESF 125-V de batteries. The de emergency lighting system provides illumination during loss of the normal/emergency ac lighting sources in the main control room and remote shutdown room only. In the balance of the plant areas, de emergency lighting is provided by self-contained storage battery lighting fixture assemblies. The de lighting system uses incandescent lamps.
The plant lighting systems are designed so that a single failure cannot degrade the essential lighting below a safe level.
The plant lighting systems are tested at installation and the means are installed for testing the de emergency system.
The scope of the review of the lighting system for Waterford 3 included assess ment of all components necessary to provide adequate lighting during both normal and emergency operating conditions, the adequacy of the power sources for the normal and emerQency lighting systems, and verification of functional capability of the lighting system under all conditions of operation.
The basis for acceptance in the staff review was conformance of the design bases and criteria, and design of the lighting systems and necessary auxiliary supporting systems to the acceptance criteria in Section II of SRP Section 9.5.3.
Other basis for acceptance was conformance to industry standards, and the ability to provide effective lighting in all areas of the Waterford 3 plant under all conditions of operations.
Based on this review, the staff concludes that the various lighting systems provided at the Waterford 3 plant conform with the above cited standards, criteria, and design basis; they can perform their design function, and are, therefore, acceptable.
Special requirements for the emergency lighting system to satisfy Appendix A to BTP APCSB 9.5-1 will be reviewed separately during the fire protection review of the Waterford 3 piant. Additional requirements resulting from the fire protection review may be imposed to further improve the capability of the lighting system.
9.5.4 Emergency Diesel Engine Fuel Oil Storage and Transfer System 9.5.4.1 Emergency Diesel Engine Auxiliary Support Systems (General)
There are two emergency diesel generators for the plant and each diesel engine has the following auxiliary systems which are addressed in detail in the SER sections indicated:
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(1)  Fuel oil storage and transfer system (Section 9.5.4.2),
(2)  Cooling water system (Section 9.5.5),
(3)  Starting system (Section 9.5.6),
(4)  Lubrication system (Section 9.5.7), and (5)  Combustion intake and exhaust system (Section 9.5.8).
This section of the SER applies to all of the above systems, The diesel generator and its auxiliary support systems, including the fuel oil storage tanks are housed in a seismic Category I reactor auxiliary building which provides protection from the effects of tornadoes, tornado missiles and floods. Therefore, the requirements of GDC 2 and 4 and recommendations and guidance of Regulatory Guide 1.115, 11 Protection Against Low-Trajectory Turbine Missiles," and Regulatory Guide 1.117 are met.
Protection from the effects of tornadoes, tornado missiles, and floods are evaluated in Section 3 of this report.
Since Waterford 3 is a single unit, the requirements of GDC 5 are not applicable.
The diesel engine, the engine mounted and separate skid mounted portions of the auxiliary support system piping, and components normally furnished with the diesel generator package are designed to seismic Category I requirements and follow the guidelines of the Diesel Engine Manufacturers Association (DEMA) standards. The diesel engine, and its mounted auxiliary support systems P.iping and components conform to the requirements of IEEE Standard 387-1977,
'Standard Criteria Diesel-Generator Units Applied as Standby Power Supplies for Nuclear Power Generating Stations, 11 which endorses the Diesel Engine Manu facturers Association (DEMA) standard and guidelines of Regulatory Guide 1.9, "Selection, Design and Qualification of Diesel-Generator Units Used as Onsite Electric Power Systems at Nuclear Plants." The diesel engine and its auxiliary support systems meet the quality control requirements of 10 CFR 50 Appendix 8.
The quality assurance program is evaluated in Section 17 of this report.
The applicant will perform preoperational and startup tests of the diesel engine auxiliary support systems in accordance with recommendations and guide lines of Regulatory Guide 1.68, "Initial Test Programs for Water Cooled Reactor Power Plants. 11 The adequacy of the test program is evaluated in Section 14.1 of this report.
The design of the diesel engine auxiliary support systems are evaluated with respect to the recommendations and guidelines of BTP ASB 3-1 and MEB 3-1, "Postulated Break and Leakage Locations in Fluid System Piping Outside Contain ment." Evaluation of protection against dynamic effects associated with the postulated pipe system failures is covered in Section 3.6 of this report.
The adequacy of the fire protection for the emergency diesel generator and associated auxiliary support systems with respect to the recommendations and guidelines of BTP ASB 9.5-1 is evaluated in Section 9.5.1 of this report.
The designs of the diesel generator auxiliary support systems also have been evaluated with respect to the recommendation of NUREG/CR-0660, "Enhancement of 9-34
 
Onsite Emergency Diesel Generator Reliability. 11 This report made specific recommendations on increasing the reliability of nuclear power plant emerency diesel generators. Requests concerning these recommendations were transmitted to the applicant during the review process. The applicant responded in the amendments to the FSAR stating how it meets or will meet the recommendations of NUREG/CR-0660.
The staff reviewed these responses and has determined that conformance to the recommendations is as follows:
Recommendation                            Conformance          SER Section
: 1. Moisture in Air Starting System      Yes                  9.5.6
: 2. Dust and Dirt in DIG Room            Yes                  9.5.8
: 3. Turbocharger Gear Drive Problem      Not Applicable
: 4. Personnel Training                    Yes                  9.5.4.1
: 5. Automatic Prelube                    Yes                  9.5.7
: 6. Testing, Test Loading and            Yes                  9.5.4.1 Preventive Maintenance
: 7. Improve the Identification            Yes                  9.5.4.1 of Root Cause of Failures
: 8. 0/G Ventilation and Combustion        Yes                  9.5.8 Air Systems
: 9. Fuel Storage and Handling            Yes                  9.5.4.2
: 10. High Temperature Insulation            ii:
9.5.4.1 for Generator
: 11. Engine Cooling Water                  Yes                  9.5.5
: 12. Concrete Dust Control                Yes                  9.5.4.1
: 13. Vibration of Instruments              Yes                  9.5.4.1
*Explicit conformance is considered unnecessary by the staff in view of the equivalent reliability provided by the design, margin, and qualification testing requirements that are normally applied to emergency standby diesel generators.
9-35
 
The present diesel enerator design meets the requirements of GDC 17, Electric 11 1
Power System,u 18, Inspection and Testing of Electric Power Systems, and 21, 11 11 Protection System Reiiability and Testability," of 10 CFR Part 50 and is in conformance with recommendations of NUREG/CR-0660 for enhancement of diesel generator reliability and the related NRC guidelines and criteria. This will provide reasonable assurance of diesel generator reliability throughout the design life of the plant.
9.5.4.2 Emergency Diesel Engine Fuel Oil Storage and Transfer System The design function of the emergency diesel engine fuel oil storage and transfer system is to provide a separate and independent fuel oil supply train for each diesel generator, and to permit operation of the diesel generator at ESF load requirements for a minimum of 7 days without replenishment of fuel. The system is designed to meet the requirements of GDC 2, 4, 5, and 17. Meeting the requirements of GDC 2, 4, and 5 is discussed in Section 9.5.4.1 of this SER.
There are two emergency diesel generators for the p1 ,t. Each diesel engine fuel oil storage and transfer system consists of a 610 gallon day tank sufficient to power the diesel engine at rated load for approximately 2 hours, a 41,000 gallon storage tank sufficient to power the diesel engine at maximum continuous load conditions for seven days, an ac motor-driven transfer pump powered from the associated diesel and the.associated piping, valves, instrumentation, and controls.
Each diesel engine fuel oil storage and transfer system is independent and physically separated from the other system supplying the redundant diesel generator. A single failure within any one of the two systems will affect only the associated diesel generator. Therefore, the requirements for GDC 17 as related to the capability of the fuel oil system to meet independence and redundancy criteria are met.
Except for the diesel oil storage tank fill and vent lines, and fuel oil drain lines 7EG1-43 and 7EG1-44 from the engine to the storage tank, the diesel*
engine fuel oil storage and transfer system piping and components up to the diesel engine interface, including auxiliary skid mounted piping are designed to seismic Category I, ASME Section III, Class 3 (Quality Group C) criteria and conform to the guidelines of Regulatory Guides 1.26 and 1.29.
The engine mounted piping and components, from the engine block to the engine interface, are considered part of the engine assembly and are seismically qualified to Category I requirements as part of the diesei engine package.
The design of this piping and the associated components has not been defined by the applicant. The applicant had been requested to provide the industry standards to which the engine mounted piping and components are designed. In Amendment 17, the app1icant stated that he is discussing the matter with the engine manufacturer and will inform NRC of the results.
The diesel oil storage tank fill and vent lines and fuel oil drain lines 7EG1-43 and 7EG1-44 are seismically supported. This piping and the associated components are designed, manufactured, and wil1 be inspected in accordance with the guidelines and requirements of ANSI Standard B31.1, Code for Pressure Piping,"
11 9-36
 
ANSI N45.2, 11 Quality Assurance Program Requirements for Nuclear Facilities,&deg; and 10 CFR 50 Appendix B. This fuel oil piping and associated components are intentionally overdesigned (subjected to low working stresses) for the applica tion, thereby resulting in high operational reliability. The design of this fuel oil piping and components to the cited design philosophy and standards is considered equivalent to a system design to ASME Section III Class 3 require ments with regard to system functional operability and inservice reliability.
The design of the emergency diesel engine fuel oil storage and transfer system conforms to ANSI-Nl95, 11 Fuel Oil Systems for Diesel Generators.11 In addition, the fuel oil quality and tests will conform with the guidelines of Positions C.2.a through C.2. of Regulatory Guide 1.137, 11 Fuel Oil Systems for Standby Diesel Generators, with the exception that Position C.2.f, 11 Removal of Accumulated Sediment and Cleaning of the Tanks, 11 wi11 be performed at every refueling outage and not every 10 years.
The scope of review of the diesel engine fuel oil storage and transfer system included layout drawings, piping and instrumentation diagrams, and descriptive information in Section 9.5.4 of the FSAR for the system and auxiliary support systems essential to its operation.
The basis for acceptance in NRC review was conformance of the design criteria and bases and design of the diesel engine fuel oil storage and transfer system to the requirements of GDC 17 with respect to redundancy and physical independ ence, the guidance of the cited regulatory guides, and the recommendations of NUREG/CR-0660, and industry codes and standards.
Based on NRC review, the staff concludes that the emergency diesel engine fuel oil storage and transfer system meets the requirements of GDC 2, 4, 5, and 17, meets the guidance of the cited regulatory guides, can perform its design safety function, and meets the recommendations of NUREG/CR-0660 and industry codes and standards, and is, therefore, acceptable on the condition that the applicant provides the information requested on the engine-mounted fuel oil piping and components. Upon receipt of this information NRC will report its findings in a supplement to this SER.
9.5.5 Emergency Diesel Engine Cooling Water System The design function of the emergency diesel engine cooling water system is to maintain the temperature of the diesel engine within a safe operating range under all load conditions and to maintain the engine coolant preheated during standby conditions to improve starting reliability. The system is designed to meet the requirements of GDC 2, 4, 5, 17, 44, 45, and 46. Meeting the requirements of GDC 2, 4, and 5 is discussed in Section 9.5.4.1 of this SER.
The emergency diesel engine cooling water system is a closed loop system and cools the cylinder liners, cylinder heads, turbocharger cooling spaces, and turbocharger combustion air coolers when air temperature is below 105 &deg; F. The major components of this system for each diesel engine includes turbocharger air coolers, jacket water cooler, an engine-driven jacket water coolant pump, an expansion tank (standpipe), a motor-driven jacket water circulation pump, an electric immersion heater, a thermostatic 3-way valve, required instrumenta tion, controls and alarms, and the associated piping and valves to connect the 9-37
 
equipment. When the diesel engine is operating, the heat generated is transferred to the component cooling water system by means of the jacket water cooler.
During operation of the diesel engine, temperature regulation of the diesel engine coolant is accomplished automatically through the action of a temperature sensing three-way thermostatic valve. When the enine is idle, the engine coolant is heated to a temperature of 120 &deg; F to 130 F by an electric heater and continuously circulated through the engine. The temperature is controlled by a thermostat to keep the engine warm and ready to accept loads within the prescribed time interval. The disel generator is capable of operating fully loaded without secondary cooling for a minimum of one minute. Sufficient water is contained in the engine and standpipe to absorb the heat generated during this period. This time is in excess of the time needed to restore component cooling water to the diesels in the event of a loss of offsite power. Alarms have been provided to enable the control room operator to monitor the diesel generator cooling while the unit is in the standby mode or in operation.
There are two emergency diesel generators for the Waterford 3 plant and each has a physically separate and independent cooling water system. Therefore, the requirements of GDC 17 and 44 as related to redundancy and single failure criteria are met.
The diesel engine cooling water system piping and components up to the diesel engine interface, including auxiliary skid mounted piping are designed to seismic Category I, ASME Section III, Class 3 (Quality Group C) requirements and meet the recommendations of Regulatory Guides 1.26 and 1.29. The engine mounted piping and components, from the engine block to the engine interface, are considered part of the engine assembly and are seismically qualified to Category I requirements as part of the diesel engine package. The design of this piping and the associated components, has not been defined by the applicant.
The applicant had been requested to provide the industry standards to which the engine mounted piping and components are designed. In Amendment 17, the appli cant stated that he is discussing the matter with the engine manufacturer and will inform NRC of the results.
The diesel engine cooling water system conforms with BTP ICSB-17, as it relates to engine cooling water protective interlocks. The diesel generator system protective interlocks are discussed in Section 8.3 of this report.
The diesel engine cooiing water system has provisions to permit periodic inspection and functional testing during standby and normal modes of power plant operation as required by GDC 45 and 46.
The scope of review of the emergency diesel engine cooling water system included layout drawings, piping and instrumentation diagrams, and descriptive informa tion in Section 9.5.5 of the FSAR for the system and auxiliary support systems essential to its operation.
The basis for acceptance in the staff review was conformance of the design criteria and bases and design of the diesel engine cooling water system to GDC 17 and 44 with respect to redundancy and physical independence, GDC 45 and 9-38
 
46 with respect to inspection and testability of the system, the guidance of the cited regulatory guides, the recommendations of NUREG/CR-0660, industry codes and standards, and the ability of the system to maintain stable diesel engine cooling water temperature under all load conditions.
Based on NRC review, the staff concludes that the emergency diesel engine cooling water system meets the requirements of GDC 2, 4, 5, 17, 44, 45, and 46, meets the guidance of the cited regulatory guides, can perform its design safety function, and meets the recommendations of NUREG/CR-0660 and industry codes and standards. It is, therefore, acceptable on the condition that the applicant provides the information requested on the engine mounted cooling water piping and components. Upon receipt of this information the staff will report its findings in a supplement to this SER.
9.5.6 Emergency Diesel Engine Starting Systems The design function of the emergency diesel engine starting system is to provide a reliable method for automatically starting each diesel generator such that the rated frequency and voltage is achieved and the unit is ready to accept required loads with 10 seconds. The system is designed to meet the requirements of GDC 2, 4, 5, and 17. The meeting of the requirements of GDC 2, 4, and 5 is discussed in Section 9.5.4.1 of this SER.
There are two emergency diesel generators for the Waterford 3 plant. Each emergency diesel generator has an independent and redundant air starting system consisting of two separate fuil capacity air starting subsystems each with sufficient air capacity to provide a minimum of five consective cold engine starts. Redundancy in starting systems is provided so that a malfunction or failure in one system does not impair the ability of the other system to start the diesel engine. This meets the requirements of GDC 17.
Each subsystem includes an air compressor, an air dryer, a receiver tank, intake air filters, injection lines and valves, air-to-cylinder distributor and starting valves, instrumentation, controls, alarms, and the associated piping to connect the equipment. Alarfils annunciate on the local panel and in the main control room to enable the operators to monitor the air pressure of the diesel generator starting air system.
The diesel engine air starting system piping and components, from the isolation valves before the receivers to the diesel engine interface, including auxiliary skid-mounted piping, are designed to seismic Category I, ASME Section III, Class 3 (Quality Group C) requirements and meet the recommendations of Regula tory Guides 1.26 and 1.29. The compressors and air dryers which are not required during the starting cycle of the diesel generator are designed to ASME Section VIII requirements. The engine-mounted piping and components, from the engine block to the engine interface, are considered part of the engine assembly and are seismically qualified to Category I requirements as part of the diesel engine package. The design of this piping and the associated components has not been defined by the applicant. The applicant had been requested to provide the industry standards to which the engine mounted piping and components are designed. In Amendment 17, the app1icant stated that it is discussing the matter with the engine manufacturer and will inform NRC of the results.
9-39
 
The scope of review of the emergency diesel engine starting system included layout drawings, piping and instrumentation diagrams, and descriptive informa tion in Section 9.5.6 of the FSAR for the system and auxiliary support systems essential to its operation.
The basis for acceptance in NRC review was conformance of the design criteria and bases and design of the diesel engine air starting system to the require ments of GDC 17 with respect to redundancy and physical independence, the guidance of the cited regulatory guides, the additional guidance in Section II of SRP Section 9.5.6 and the recommendations of NUREG/CR-0660, and industry codes and standards, and the ability of the system to start the diesel generator within a specified time period.
Based on NRC review the staff concludes that the emergency diesel engine air starting system meets the requirements of GDC 2, 4, 5, and 17, meets the guidance of the cited regulatory guides and SRP Section 9.5.6, it can perform its design safety function, and meets the recommendations of NUREG/ CR-0660 and industry codes and standards, and is, therefore, acceptable on the condition that the applicant provides the information requested on the engine mounted air starting piping and components. Upon receipt of this information the staff will report its findings in a supplement to this SER.
9.5.7 Emergency Diesel Engine Lubricating Oil System The design safety function of the emergency diesel engine lubricating oil system is to provide a supply of filtered lubrication oil to the various moving parts of the diesel engine including pistons and bearings. The system is designed to meet the requirements of GDC 2, 4, 5, and 17. Meeting the requirements of GDC 2, 4, and 5 is discussed in Section 9.5.4.1 of this SER.
Major components of emergency diesel engine lubricating oil system include an engine-driven pump, a motor-driven standby pump, a motor-driven lube oil cir culation and prelube pump, a lube oil collection sump, strainers and filters, two lube oil coolers, an electric heater and thermostatic three-way valve, instrumentation, controls, and alarms, and associated piping and valves to connect the equipment. A common nonseismic maintenance lube oil storage tank is provided only for lube oil storage during engine maintenance. Crankcase pressure relief valves are provided for protection from crankcase explosion.
Alarms and protective devices are provided to enable the control room operator to monitor the diese1 generator lube oil system during standby, startup or operation.
The emergency diesel engine lubrication oil system is an integral part of the diesel engine and thus meets the requirements of GOC 17, with respect to system independence and single failure criteria. The system has two subsystems that circulate lube oil through the engine for lubrication and cooling when the engine is operating or on standby. The engine heat is rejected to the component cooling water system. The two subsystems are: (1) the engine lube oil system, and (2) the circulation and prelubrication lube oil system. The engine lube oi1 system supplies oil to all main bearings 1 the camshaft bearings, cam followers, engine wearing parts, and turbocharger. The circulation and prelubrication lube oi1 system is operated only when the diesel engine speed 9-40
 
is less than 280 rpm or the engine is on standby, at which time the lube oil 1s heated by an electric heater and circulated through the engine continuously by an ac motor-driven pump to improve the first try starting reliability.
This portion of the system has an alarm to indicate pump and/or heater failure.
The diesel engine lubrication oil system piping and components up to the diesel engine interface, including auxiliary skid mounted piping are designed to seismic Category I, ASME Section III, Class 3 (Quality Group C) requirements and meet the recommendations of Regulatory Guides 1.26 and 1.29. The engine mounted piping and components, from the engine block to the engine interface, are considered part of the engine assembly and are seismically qualified to Category I requirements as part of the diesel engine package. The design of this piping and the associated components, has not been defined by the applicant.
The applicant had been requested to provide the industry standards to which the engine mounted piping and components are designed. In Amendment 17, the applicant stated that it is discussing the matter with the engine manufacturer and will inform NRC of the results.
The diesel generator lubricating oil system conforms with BTP ICSB-17 (PSB),
as it relates to diesel engine lubrication system protective interlocks. The diesel generator system protective interlocks are discussed in Section 8.3 of this report.
The scope of review of the diesel generator lubricating oil system included piping and instrumentation diagrams and descriptive information in Section 9.5.7 of the FSAR for the system and auxiliary support systems essential to its operation.
The basis for acceptance in the NRC review was conformance of the design criteria and bases and design of the diesel engine lubricating oil system to the requirements of GDC 17 with respect to redundancy and physical independence, the guidance of the cited regulatory guides, the additional guidance in subsec tion II of SRP Section 9.5.7, and the recommendations of NUREG/CR= 0660 and industry codes and standards.
Based on NRC review, the staff concludes that the emergency diesel engine lubricating oil system meets the requirements of GDC 2, 4, 5, and 17, meets the guidance of the cited regulatory guides and SRP 9.5.7, can perform its design safety function, and meets the recommendations of NUREG/CR-0660 and industry codes and standards, and is, therefore, acceptable on the condition that the applicant provides the information requested on the engine mounted lubricating oil piping and components. Upon receipt of this information NRC will report staff findings in a supplement to this SER.
9.5.8 Emergency Diesel Engine Combustion Air Intake and Exhaust System The design function of the emergency diesel engine combustion air intake and exhaust system is to supply filtered air for combustion to the engine and to dispose of the engine exhaust to atmosphere.
A separate source of combustion air for each diesel engine is taken from the diese1 generator building air intakes through an air filter, intake silencer, turbocharger compressor and intercoolers. The path of the exhaust gas discharge
 
is through the turbocharger, exhaust silencer and exhaust ducting to the outside of the building. This meets the requirements of GDC 17 with regard to system independence, redundancy, and single failure criteria.
The exhaust system is separate from the air intake system to reduce the possi bility of contamination of the intake air with recirculated exhaust gases.
The location of the air intake structure and design precludes the intake of fire extinguishing agents and other noxious gases and dust and other deleterious material that would affect diesel generator operation.
Accumulation of dust, including dust generated from concrete floors and walls, on the electrical equipment associated with starting of the diesel generators (e.g., auxiliary relay contacts, control switches, etc.) is limited by the diese1 generator building ventilation system design and operation, plant design, and administrative procedures.
The diesel engine air intake and exhaust system piping and components up tc the diesel engine interface are designed to seismic Category I requirements and conform to the guidelines of Regulatory Guide 1.29. The engine-mounted piping and components, from the engine block to the engine interface, are considered part of the engine assembly and are seismically qualified to Category I requirements as part of the diesel engine package. This piping and the associated components, such as fabricated headers, fabricated special fittings, and the like (including air intake and exhaust piping beyond engine interface) are designed, manufactured, and inspected in accordance with the guidelines and requirements of ANSI Standard B31.1, 11 Code for Pressure Piping, 11 ANSI N45.2, "Quality Assurance Program Requirements for Nuclear Facilities, 11 and 10 CFR 50 Appendix B. The intake and exhaust piping and associated components are intentionally overdesigned (subjected to low working stresses) for the application, thereby resulting in high operational reliability. The design of the air intake and exhaust piping and components to the cited design philosophy and standards is considered equivalent to a system design to ASME Section III Class 3 requirements with regard to system functional operability and inservice reliability.
The scope of review of the diesel generator intake and exhaust system included layout drawings, piping and instrumentation diagrams, and descriptive informa tion in Section 9.5.8 of the FSAR for the system and auxiliary support system essential to its operation.
The basis for the acceptance in the NRC review was conformance of the design criteria and bases and design of the diesel engine air intake and exhaust system to GDC 17 with respect to redundancy and physical independence; the guidance of the cited regulatory guides; the additional guidance in subsec-tion II of SRP Section 9.5.8; and the recommendations of NUREG/CR-0660, industry codes and standards; and the ability of the system to provide sufficient combustion air and release of exhaust gases to enable the emergency diesel generator to perform on demand.
Based on NRC review, the staff concludes that the emergency diesel engine intake and exhaust system meets the requirements of GDC 2, 4, 5, and 17, meets the guidance of the cited regulatory guides and SRP Section 9.5.8, can perform its design safety function, meets the recommendation of NUREG/CR-0660 and industry codes and standards, and is, therefore, acceptable.
9-42
 
==9.6 REFERENCES==
American National Standards Institute:
ANSI 831.1 ANSI N45.2.1-1973 ANSI N195 American Society of Mechanical Engineers Boiler and Pressure Vessel Code:
ASME Section III ASME Section VIII American Society of Testing Materials ASTM E-119 Branch Technical Positions:
BTP APCSB 9.5-1 BTP ASS 3-1 BTP ASS 9-1 BTP ASB 9-2 BTP ICSB 17 BTP MEB 3-1 Code of Federal Regulations:
10 CFR Part 50, Appendix B General Design Criteria:
GOC 1 GDC 2 GDC 4 GDC 5 GDC i3 GDC 14 GDC 17 GDC 18 GDC 19 GDC 21 GDC 26 GDC 29 GDC 33 GDC 44 GDC 45 GDC 46 GDC 60 GDC 61 GDC 62 GDC 63 GDC 64 Institute of Electrical and Electronics Engineers:
IEEE Standard 387-1977 9-43
 
Letter from LP&L submitting Waterford Unit 3 Fire Protection Program Reevaluation, dated July 1, 1977**
Louisiana Power and Light Co. report:
FSAR for Waterford 3 Sections 9.5.5 and 9.5.8 Waterford Unit 3 Fire Protection Program Reevaluation National Fire Protection Association Standards:
NFPA 12A NFPA  13 NFPA  14 NFPA  15 NFPA  72D Regulatory Guides:
RG 1. 9 RG 1.13 RG 1. 26 RG 1. 27 RG 1. 29 RG 1. 37 RG 1. 68 RG 1.95 RG 1.102 RG 1.115
,      RG 1.117 RG 1. 137 RG 1.143 RG 8.8 USNRC reports:
NUREG-0612 NUREG/CR-0660 NUREG-75/087
    *See Appendix 8 1 Bibliography, for complete citations and availability statements.
  **See Appendix A, Chronology.
9-44
 
10 STEAM AND POWER CONVERSION SYSTEM 10.1
 
==SUMMARY==
DESCRIPTION The steam and power conversion system is designed to remove heat energy from the primary reactor coolant loop via two steam generators and to generate elec tric power in the turbine-generator. After the steam passes through the high and low pressure turbines, the main condensers deaerate the condensate and transfer the rejected heat to the open cycle circulating water system which uses the Mississippi River to dissipate the rejected heat. The condensate is reheated and returned as feedwater to the steam generator. The entire system is designed for the maximum expected energy from the nuclear steam supply system.
A turbine steam bypass system is provided to discharge directly to the condenser up to 63% of the main steam flow around the turbine during transient conditions.
This bypass capacity together with a 10% reactor automatic step load reduction capability is sufficient to withstand a 73% generator load loss without tripping the turbine or causing control rod movement or tripping the reactor.
10.2 TURBINE-GENERATOR 10.2.1 Turbine Generator Design The turbine-generator converts steam power into electrical power and has a turbine control and overspeed protection system. The design function of the turbine control and overspeed protection system is to control turbine action under all normal or abnormal conditions and to assure that a full load turbine trip will not cause the turbine to overspeed beyond acceptable limits, and to minimize the probability of generation of turbine missiles in accordance with the requirements of GDC 4, 11 Environmental and Missile Design Bases." The turbine control and overspeed protection system is, therefore, essential to the overall safe operation of the plant.
The turbine-generator is manufactured by the    Westinghouse Corporation and is a tandem-compound type (single shaft) with one    double-flow high pressure turbine and three double-flow low pressure turbines. The rotational speed is 1800 rpm and is designed for a gross generator output    of 1153 MWe at a nominal piant exhaust pressure of 3.86 in. Hg (absolute).
The turbine-generator is equipped with    a digital electrohydraulic control (EHC) system. The EHC system consists of an    electronic governor using solid state control techniques in combination with    a high pressure hydraulic actuating system.
The system includes electrical control    circuits for steam pressure control, speed control, load control, and steam    control valve positioning.
Overspeed protection is accomplished by three independent systems; i.e., normal speed governor, mechanical overspeed, and electric backup overspeed control systems. The normal speed governor modulates the turbine control valves to maintain desired speed load characteristics and it will close the intercept 10-1
 
valves and control valves at 103% of rated speed. The mechanical overspeed sensor trips the turbine stop, control, and combined intermediate valves by deenergizing the hydraulic fluid systems when 111% of rated speed is reached.
The turbine steam valves close in 0.25 sec, after overspeed condition is detected.
These valves are designed to fail closed on loss of hydraulic system pressures.
The electrical backup overspeed sensor will trip these same valves when 111.5%
of rated speed is reached by independently deenergizing the hydraulic fluid system. Both of these actions independently trip the energizing trip fluid system. The overspeed trip systems can be tested while the unit is on-line.
Therefore, the requirements of GDC 4 are met.
In order to protect the turbine-generator, the following signals will shut down the turbine: (1) manual emergency trip, (2) low bearing oil pressure, (3) con denser vacuum loss, (4) excessive rotor vibration, (5) low stator hydrogen cooling water flow, (6) low seal oil differential pressure, (7) excessive differ ential expansion, (8) high exhaust hood temperature, (9) high level in feed water heaters number 5 and 6, (10) reactor trip, (11) excessive thrust bearing wear, (12) turbine overspeed at 111% of rated speed, (13) turbine overspeed at 111.5% of rated speed, (14) high level moisture separator-reheater shell drain tank, (15) low level turbine oil tank, (16) EHC de power bus undervoltage, and (17) tripped generator lockout relays.
An inservice inspection program for the main steam stop and control valves and reheat valves is provided and includes: (1) dismantling and inspection of all turbine steam valves, at approximately 3-1/3-yr intervals during refueling or maintenance shutdowns coinciding with the inservice inspection schedule, (2) exercising and observing at least once a week the main steam stop and control, reheat stop, and intercept valves.
The applicant will include preoperational and startup tests of the turbine generator in accordance with Regulatory Guide 1.68, "Initial Test Programs for Water Cooled Power Plants." The adequacy of the test program is evaluated in Section 14.1 of this report.
The turbine generator system meets the recommendations of BTP ASB 3-1, "Protec tion Against Postulated Piping Failures in Fluid Systems Outside Containment,"
and BTP MEB 3-1, "Postulated Break and Leakage Locations in Fluid System Piping Outside Containment." Evaluation of protection against dynamic effects associated with the postulated pipe system failure is covered in Section 3.6 of this report.
The scope of review of the turbine generator included descriptive information in Section 10.2 of the FSAR, and flow charts and diagrams. The basis for accept ance in the staff review was conformance of the design criteria and bases and design of the turbine-generator system to GDC 4 with respect to the prevention of the generation of turbine missiles, the additional guidance in subsection II of SRP Section 10.2 and industry codes and standards.
Based on NRC review, the turbine-generator overspeed protection system meets the requirements of GDC 1 and 4, the guidance of SRP Section 10.2, can perform its designed safety function, and is, therefore, acceptable.
10-2
 
10.2.2 Turbine Disc Integrity The NRC staff reviewed Section 10.2.3 of the FSAR for Waterford 3 and concludes that the integrity of the turbine will be adequate and that reasonable assurance is provided that the applicable parts of GOC 1 and 4 of 10 CFR Part 50 will be met.
The turbine discs and rotors are forged from vacuum degassed steel by processes that minimize flaws and provide adequate fracture toughness. These materials have the lowest fracture appearance transition temperatures and highest Charpy V-notch energies obtainable on a consistent basis. The maximum tangential stress in discs and rotors resulting from centrifugal forces, interference fit, and thermal gradients does not exceed 0. 75 of the yield strength of the materials at 115% of the rated speed.
The preservice inspection program calls for 100% ultrasonic test (UT) of each rotor and disc forging before finish machining and magnetic particle test (MT) after finish machining. No MT flaw indications are permissible in bores, holes, keyways, and other highly stressed regions.
Since 1979 the staff has known of the stress corrosion problems in low pressure rotor discs in Westinghouse turbines. Appropriately conservative inspection intervals have been effective in monitoring crack growth to permit repair or replacement of discs well in advance of failure. The applicant has submitted to the staff the material properties of the low pressure turbine discs, as well as the calculations of critical crack sizes. The method used to predict crack growth rates is based on evaluating all of the cracks found to date in Westing house turbines, past history of similar turbine disc cracking, and results of laboratory tests. This prediction method takes into account two main parameters; the yield strength of the disc, and the temperature of the disc at the bore area where the cracks of concern are occurring. The higher the yield strength of the material and the higher the temperature, the faster the crack growth rate will be.
The staff evaluated the data submitted by the applicant and, in addition, performed independent calculations for crack growth and critical crack size.
NRC staff concludes that Waterford 3 may be safely operated until the first refueling outage, at which time the low pressure turbine discs should be inspected.
Inservice inspection will include UT of the bore and keyway areas of each disc and MT and visual inspection of all accessible areas.
The turbine meets NRC criteria regarding the use of materials with acceptable fracture toughness and adequate design. Preservice and inservice inspection criteria are in accordance with current staff guidelines. The materials, processes and designs used by the applicant are therefore considered acceptable.
The staff concludes that these provisions offer reasonable assurance that the probability of disc failure with missile generation is low during normal opera tion, including transients up to design overspeed.
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10.3 MAIN STEAM SUPPLY SYSTEM 10.3.l Main Steam Supply System (Up to and Including the Main Steam Isolation Valves)
The function of the main steam supply system is to convey steam from the steam generators to the high-pressure turbine and other auxiliary equipment for power generation. The steam produced in the two steam generators is routed by two main steam lines up to the common header at the high pressure turbine. Each main steam line contains one main steam isolation valve (MSIV). The portions of the main steam lines from the steam generators through the containment and up to and including the main steam isolation valves and including the main steam safety valves, and atmospheric dump valves are located in flood and tornado protected structures (refer to Sections 3.4.1 and 3.5.2 of this SER) and are Quality Group B and seismic Category I, thereby satisfying the requirements of GDC 2, "Design Bases for Protection Against Natural Phenomena, 11 and the guidelines of Regulatory Guides 1.26, "Quality Group Classifications and Standards for Water-,
Steam- and Radioactive-Waste-Containing Components for Nuclear Power Plants;'
and 1.29, "Seismic Design Classification. 11 The MSIVs are designed to close in a maximum of 3 seconds upon receipt of a main steam isolation signal or containment isolation actuation signal. The valves are designed to stop steam flow from either direction. Failure of one MSIV to close coincident with a steam line break will not result in the uncontrolled blowdown of more than one steam generator. In the event of a steam line break upstream of an MSIV and a failure of the MSIV to close on the unaffected steam generator, blowdown of the unaffected steam generator is prevented by the closure of the nonseismic Category I turbine stop valves and turbine bypass valves that serve as an acceptable backup for this accident.
Safety valves and power-operated relief (atmospheric dump) valves are provided for each steam generator immediately outside the containment structure upstream of the main steam isolation valves. The power-operated relief valves {one per steam generator) are air operated and fail in the closed position on loss of air supply. Backup seismic Category I air accumulators are provided for these valves in order to maintain their operability manually from the control room.
The backup air supply is sized to maintain the valves operable for 36 hr. The power-operated relief valves are also equipped with handwheels for local manual operation. Thus, the requirements of GDC 34, 11 Residual Heat Removal," are satisfied.
The equipment required to function in order to assure main steam isolation when called upon is protected against the effects of high energy pipe breaks (refer to Section 3.6.1 of this SER). This equipment is located in tornado missile protected structures and is located such that it is not affected by internally generated missiles (refer to Section 3.5.1.1 and 3.5.2 of this SER). Thus, the requirements of GOC 4 and the criteria of Regulatory Guide 1.117, "Tornado Design Classification, 11 and of BTP ASB 3-1 are satisfied. Environmental qualification of this equipment is discussed in Section 3.11 of this SER.
Based on the above, the staff concludes that the main steam supply system from the steam generators through the main steam isolation valves meets the require ments of GDC 2 and 4 with respect to protection against seismic events, floods, tornadoes, missiles and pipe break effects, the requirements of GDC 34 with 10-4
 
respect to residual heat removal capability and the single failure criterion, the guidelines of Regulatory Guides 1.26, 1.29, and 1.117 and BTP ASB 3-1 relat ing to the system's seismic and quality group classification, protection against tornado missiles and high and moderate energy pipe breaks and is, therefore, acceptable.
10.3.2 Main Steam Supply System (Downstream of Main Steam Isolation Valves)
This portion of the main steam system is not required to effect or support safe shutdown of the reactor.
The main steam system is designed to deliver steam from the steam generators to the high-pressure turbine. The main steam and turbine steam systems provide steam to the feedwater pump turbines, emergency feedwater pump turbine, waste and boric acid concentrators, turbine gland seal system, feedwater heaters, turbine bypass system, and steam supply to the moisture separator reheaters.
The main steam system from the MSIV to the turbine stop valves and all branch lines are designed to the criteria of ANSI 831.1 and are nonseismic, except for the piping from the MSIV to the end of the reactor auxiliary building (column line G) which is designed seismic Category I.
The scope of review of the main steam supply system (between the main steam isolation valve and up to an including the turbine stop valves) included descrip tive information in Section 10.3 of the FSAR, and flow charts and diagrams.
The basis for acceptance in the staff review was conformance of the design criteria and bases and design of main steam supply system to the acceptance criteria in subsection II of SRP Section 10.3.
Based on NRC review, the staff concludes that the main steam supply system between the main steam isolation valves and up to and including the turbine stop valves is in conformance with the above cited criteria and design bases, can perform its designed functions, and is, therefore, acceptable.
10.3.3 Steam and Feedwater Systems Materials GDC 1 requires, in part, that systems important to safety be designed to quality standards commensurate with the importance to safety of the functions to be performed. The materials utilized in the steam and feedwater systems are reviewed for compliance with GDC 1.
The mechanical properties of materials selected for Class 2 and 3 components of the steam and feedwater systems satisfy Appendix 1 of Section III of the ASME B&PV Code, Parts A, B or C of Section II of the Code.
The fracture toughness properties of ferritic materials satisfy the requirements of the Code. These fracture toughness tests and mechanical properties required by the Code provide reasonable assurance that ferritic materials will have adequate safety margins against the possibility of nonductile behavior or rapidly propagating fracture.
Welders are not qualified specifically for limited access as stipulated by Regulatory Guide 1.71, "Welder Qualification for Areas of Limited Accessibility. 11 However, the production controls imposed by the architect/engineer (welding supervisor selecting the most highly skilled for limited access welds and butt 10-5
 
welds in these systems are nondestructively inspected) are at least as effective as specific recommendations of the regulatory guide.
The onsite cleaning and cleanliness control during fabrication satisfy the posi tions given in Regulatory Guide 1.37, 11 Quality Assurance Requirements for Cleaning of Fluids Systems and Associated Components of Water-Cooled Nuclear Power Plants, 11 and the criteria of ANSI Standard N 45.2.1-1973, 11 Cleaning of Fluid Systems and Associated Components During Construction Phase of Nuclear Power Plants. 11 Low alloy steel is not utilized for main steam and feedwater systems components.
Therefore, Regulatory Guide 1.50, 11 Control of Preheat Temperature for Welding of Low-Alloy Steel, 11 is not applicable.
Tubular products are nondestructively examined in accordance with the Code.
Conformance with the codes, standards, and regulatory guides mentioned consti tutes an acceptable basis for assuring the integrity of steam and feedwater systems, and for meeting in part the requirements of GDC 1.
10.3.4 Secondary Water Chemistry In late 1975 NRC incorporated provisions into the Standard Technical Specifica tions that required limiting conditions for operation and surveillance require ments for secondary water chemistry parameters. The technical specifications for a11 pressurized water reactor plants that have been issued an operating license since 1974 contain either these provisions or a requirement to estab lish these provisions after baseline chemistry conditions have been determined.
The intent of the provisions was to provide added assurance that the operators of newly licensed plants would properly monitor and control secondary water chemistry to limit corrosion of steam generator components such as tubes and tube support plates.
In a number of instances, the technical specifications have significantly restricted the operational flexibility of some plants with little or no benefit with regard to limiting degradation of steam generator tubes and the tube support plates. Based on this experience and the knowledge gained in recent years, the staff concluded that Technical Specification limits are not the most effec tive way of assuring that steam generator degradation will be minimized.
Because of the complexity of the corrosions phenomena involved and the state of the art as it exists today, the staff is of the opinion that, in lieu of specifying limiting conditions in the technical specifications, a more effec tive approach would be to institute a license condition that required the implementation of a secondary water chemistry monitoring and control program containing appropriate procedures and administrative controls.
The required program and procedures are to be developed by applicants with input from their reactor vendor or other consu1tants, to account for site and plant specific factors that affect chemistry conditions in the steam generators.
Plant operation following such procedures would provide assurance that licensees would devote proper attention to controlling secondary water chemistry, while also providing the needed flexibility to allow them to deal effectively with any off-normal condition that might arise.
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In the FSAR, the applicant provided details of a secondary water chemistry moni toring and control program. At NRC request, the applicant provided additional information by letter of April 16, 1981. The proposed program addresses the six program criteria of the staff position as discussed below, and is based on the steam generator water chemistry program recommended by the NSSS vendor (Combus tion Engineering).
The proposed program monitors the critical parameters to inhibit steam generator corrosion and tube degradation. The limits and sampling schedule for these parameters have been established for steam generator blowdown and feedwater/
condensate under power operation, startup, shutdown, and wet layup conditions.
The control points for the critical parameters and the process sampling points have been identified in the submittals. The analytical techniques for measuring the values of the critical parameters are indicated in the submittals, and reference to the plant chemcial procedures is given for the complete procedures.
The procedure for recording and management of data is stated in each analytical procedure for a given parameter. The procedure defining corrective actions for off-control point chemistry conditions and the procedures identifying the sequence and timing of administrative events to initiate corrective actions are given in the submittals. The authority ultimately responsible for inter pretation of secondary-side water chemistry data is the site Chemical and Environmental Engineer.
The applicant's secondary water chemistry monitoring and control program:
(a) is capable of reducing the probability of abnormal leakage in the reactor coolant pressure boundary by inhibiting steam generator corrosion and tube degradation, and thus meets the requirements of General Design Criterion 14; (b) adequately addresses all of the program criteria delineated in the NRC staff letter to LP&L dated August 24, 1979; (c) is based on the NSSS vendor's recommended steam generator water chemistry program; (d) monitors  the secondary coolant purity in accordance with Branch Technical Position MTEB 5-3, revision 1, and thus meets acceptance criterion 3 of Standard Review Plan Section 5.4.2.1, "Steam Generator Materials,"
revision l; (e) mon1ors the water quality of the secondary side water in the steam generators to detect potential condenser cooling water in-leakage to the condensate, and thus meets Position 2 of Branch Technical Position MTEB 5-3, revision 1; (f)  describes the methods for control of secondary side water chemistry data and record management procedures and corrective actions for off-control point chemistry, and thus meets Position 3 of Branch Technical Position MTEB 5-3, revision 1. However, the applicant proposed an alternate approach for meeting the 96-hour corrective action standard of Position 3.1.a.(6) in the event of a condenser leak. The alternative approach consists of (a) implementing corrective actions and limiting operation under transient chemistry conditions of feedwater and steam generator blowdown for up to four hours, and (b) chemistry limits for 10-7
 
immediate shutdown. Immediate shutdown will also be considered if the transient limits are exceeded for longer than four hours. This alterna tive approach to Branch Technical Position MTEB 5-3 is acceptable since:
(i)      it establishes a specific continuously monitored condensate sample point for confirming a condenser leak, (ii)      it provides an early indication of impurities entering the steam gener ator before the entire steam generator secondary side reaches or exceeds its operational limits, and (iii)      it provides an effective limit to the quantity of impurities entering the steam generator.
On the basis of the above evaluation, the staff concludes that the proposed secondary water chemistry monitoring and control program for Waterford 3 meets (1) the requirements of General Design Criterion 14 insofar as secondary water chemistry control assures primary boundary material integrity, (2) Acceptance Criterion 3 of Standard Review Plan Section 5.4.2.1, revision 1, (3) Positions 2 and 3 of Branch Technical Position MTEB 5-3, revision 1, and (4) the program criteria in the staff's position and, therefore, is acceptable. The staff will condition the operating license to require that the proposed secondary water chemistry monitoring and control program be carried out.
10.4 OTHER FEATURES OF THE STEAM AND POWER CONVERSION SYSTEM 10.4.1 Main Condenser The main condenser is designed to function as a heat sink for the turbine exhaust steam, turbine bypass steam, and other turbine cycle flows, and to receive and collect condensate flows for return to the steam generators. The main condenser transfers heat to the circulating water system which uses the Mississippi River to dissipate the rejected heat.
The main condenser is not required to effect or support safe shutdown of the reactor or to perform in the operation of reactor safety features. The main condenser has three shells and is designed to produce a turbine back pressure of 3.86 in. Hg absolute when operating at rated turbine output. The main con denser design includes provisions for condensate deaeration and hotwell surge storage of condensate for approximately a 5-minute supply at design conditions.
Offgas from the main condenser is processed in the condenser evacuation system which is described and evaiuated in Section 10.4.2 of this report.
The main condenser is designed to accept full load exhaust steam from the main turbine and reactor feedwater pump turbines, up to 63% of the main steam flow from the turbine bypass system, and other cycle steam flows. The main condenser is also designed to deaerate the condensate to the required water quality.
Stainless steel tubes have been used to minimize corrosion and erosion of con denser tubes. Condenser tube leakage could result in degradation of the feed water quality with potential for corrosion of secondary system components.
The applicant monitors condensate sodium content by means of an automatic hotwell sampling system to give an indication of tube leakage. The applicant, in response to a request for additional information, provided details on the detection, control, and correction of condenser cooling water leakage into the condensate.
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The adequacy of the secondary sampling system for leak detection is evaluated in Section 9.3 of this report.
The applicant will include preoperational and startup tests of the main condenser in accordance with recommendations of Regulatory Guide 1.68. The adequacy of the test program is evaluated in Section 14.1 of this report.
The scope of review of the main condenser included layout drawings and descriptive information of the condenser in Section 10.4.1 of the FSAR. The basis for accept ance in the staff review was conformance of the design criteria and bases and design of the condenser to the acceptance criteria in subsection II of SRP Section 10.4.1 and industry standards.
Based on NRC review the staff concludes that the main condenser is in conformance with the above cited criteria and. design bases, can perform its designed function and is, therefore, acceptable.
10.4.2 Main Condenser Evacuation System The main condenser evacuation system at Waterford 3 is designed to establish and maintain main condenser vacuum by removing noncondensible gases from the condenser. The system consists of three 100% capacity condenser vacuum pump assemblies. Each assembly consists of a rotary water seal type two stage vacuum pump and seal water system. Each seal water system includes one centrifugal circulating pump, one heat exchanger, and one separator. The main condenser evacuation system is designed to Quality Group D and to a nonseismic design classification.
Only one vacuum pump is required during normal operation. Noncondensible gases and water vapor are drawn directly from each shell of the condenser. The mixture flows through the condenser vacuum pumps, then to the separator where most of the water vapor is condensed and the noncondensible gases are released to the atmosphere via the discharge silencer. The condensate is drained to the indus trial waste sump.
The noncondensible gases and the condensate are monitored for radioactivity before being discharged to the atmosphere and the industrial waste sump. The presence of radioactivity indicates a primary to secondary leak in the steam generator. If radioactivity is detected, the vacuum pump exhaust could be diverted for discharge to the plant stack and the condensate to the waste management system.
The scope of NRC's review included the system capability to process radioactive gases and the design provisions incorporated to monitor and control releases of radioactive materials in gaseous effluents in accordance with GDC 60 and 64 of Appendix A to 10 CFR Part 50. Based upon NRC evaluation, the staff finds the main condenser evacuation system acceptable. The basis for the staff 1 s acceptance is the conformance of the design and the design criteria of the main condenser evacuation system to the applicable regulations cited above.
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10.4.3 Turbine Gland Sealing System The turbine gland sealing system provides sealing of the turbine generator shaft and the main feedwater pump turbine shafts against leakage of air into the turbine casings and escape of steam into the turbine building. The system consists of individually contro l led diaphragm-operated valves, relief valves, and a gland steam condenser. The gland steam condenser receives leakoff steam and air.
The condenser returns the seal leakage to the main condenser as condensate.
Noncondensible gases are monitored for radioactivity. If radioactivity is present, the gases are discharged to the plant stack. Otherwise, they are discharged to the atmosphere via the discharge silencer. The components of the turbine gland sealing system are Quality Group D and are nonseismic.
Having reviewed the system description and design criteria for the components of the turbine gland sealing system, the staff finds them consistent with the criteria given in Regulatory Guide 1.26 and, therefore, acceptable.
The basis for acceptance is the conformance of the design, design criteria, and design bases for the turbine gland sealing system to Regulatory Guide 1.26.
Based upon this, the proposed turbine gland sealing system is considered acceptable.
10.4.4 Turbine Bypass System The turbine bypass system is designed to bypass up to 63% of main steam flow to the main condenser. This capacity together with a 10% reactor automatic step load reduction capability is sufficient to withstand a 73% generator load loss without tripping the turbine or causing control rod movement. The turbine bypass system is used to control coolant temperature as follows: (1) during the reactor heatup to rated pressure; (2) while the turbine generator is being brought up to speed and synchronized; (3) during power operation when the reactor steam exceeds the transient turbine steam requirements; and (4) during reactor cooldown. This system is not required to perform during accident conditions.
The bypass system is composed of the following: (1) six air operated valves, (2) associated instruments and controls, and (3) p1p1ng. Each valve is rated for a capacity of approximately 10.5% of the main steam flow at full load pres sure and temperature. The six bypass valves are connected to the main steam header downstream of the main steam isolation valves and discharge the steam directly to the main condenser (two valves to each condenser shell). The turbine bypass system is not a safety-related system and is not required for plant shut down following an accident. The turbine bypass valves are designed to fail closed upon loss of electric power or air system pressure to the valve control system. The turbine bypass valves are designed to close on loss of main condenser vacuum.
The applicant will include preoperational and startup tests of the turbine bypass system in accordance with recommendations of Regulatory Guide 1.68. The adequacy of the test program is evaluated in Section 14.1 of this report. The turbine bypass system can be tested while the unit is on line.
The turbine bypass system meets the recommendations of BTP ASB 3-1 and MEB 3-1.
Evaluation of protection against dynamic effects associated with the postulated pipe system failures is covered in Section 3.6 of this report.
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The scope of review of the turbine bypass system included drawings, piping and instrumentation diagrams, and descriptive information of the system in Section 10.4.4 of the FSAR.
The basis for acceptance in the staff review was conformance of the design criteria and bases and design of the turbine bypass system to the acceptance criteria in subsection II of SRP Section 10.4.4 and industry standards.
Based on NRC review, the turbine bypass system is in conformance with the above cited criteria and design bases, can perform its designed function, and is, therefore, acceptable.
10.4.5 Circulating Water System The nonsafety-related (Quality Group D, nonseismic Category I) circulating water system (CWS) is designed to remove the heat rejected from the main condenser to the environment via the Mississippi River. The CWS is not required to main tain the reactor in a safe shutdown condition or mitigate the consequences of accidents.
The applicant provided an analysis of the effects of possible flooding resulting from a postulated failure of a CWS component. Flooding in the turbine building will result from this postulated failure. The analysis further postulated that the CWS was not shut off and that all four circulating water pumps were operating at runout. Grade elevation in the area of the CWS is 14.5 ft and water would exit the turbine building at this elevation. All safety-related equipment is protected up to an elevation of 30.0 ft against external flooding. No safety related equipment is located in the turbine building, and no paths exist by which the circulating water could enter safety-related structures. Since no safety-related equipment is affected by a postulated failure in the CWS, the requirements of GDC 4 and the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 with respect to protection of safety-related systems from failure of nonsafety-related systems are satisfied.
Indication of potential failure in CWS components is provided to the operators in the control room. The turbine building sumps are equipped with level indi cators and alarms which are annunciated in the control room. CWS performance (temperature and pressure) is also monitored in the control room by the plant computer.
Based on NRC review; the CWS meets the reauirements of GOC 4 with respect to environmental effects attributable to pipe breaks since the system design meets the guidelines of Regulatory Guide 1.26 and Position C.2 of Regulatory Guide 1.29 with respect to protection of safety-related systems from failure in nonsafety-related systems, and is therefore acceptable.
10.4.6 Condensate Cleanup System The condensate cleanup system includes all components and equipment necessary for the removal of dissolved and suspended impurities which may be present in the condensate. Condensate cleanup is accomplished by operation of the steam generator blowdown system in conjunction with the process sampling system.
Based upon our review of the proposed operation of the condensate cleanup system in conjunction with the steam generator blowdown system, the staff concludes that the design and operation of the CCU conforms to the applicable guides, 10-11
 
staff positions, and industry standards and is acceptable as having met the requirements of GDC 14 as it relates to maintaining acceptable chemistry control for PWR secondary coolant.
10.4.7 Condensate and Feedwater System The condensate and feedwater system includes all components and equipment from the condenser outlet through the containment isolation valves to the steam generators and to the heater drain system. The system serves no safety function and is, therefore, classified as nonsafety-related (Quality Group D, nonseismic Category I). Adequate isolation is provided at connections between seismic and nonseismic Category I systems and, therefore, failure of nonsafety-related portions of the condensate and feedwater system will not affect safe plant shutdown. The portion of the system between the check valves located outside the containment including the containment isolation valves and up to the steam generators is safety related and designed to seismic Category I, Quality Group 8 requirements in order to assure feedwater system isolation in accident situa tions. This portion of the system is located in a seismic Category I, flood and tornado protected structure (refer to Sections 3.4.1 and 3.5.2 of this SER),
thus the requirements of GDC 2 and the guidelines of Regulatory Guides 1.26 and 1.29 are satisfied. The structure also provides protection against tornado missiles. The essential equipment is separated from the effects of internally generated missiles and is not affected by failures in high energy piping (refer to Sections 3.5.1.1 and 3.6.1 of this SER) thus the requirements of GDC 4 and the guidelines of Regulatory Guide 1.117 and BTP ASB 3-1 are satisfied. Environ mental qualification of this equipment is discussed in Section 3.11 of this SER.
Automatic isolation of the main feedwater system is provided when required to mitigate the consequences of a steam or feedwater line break. The main feedwater isolation valves close within 5 sec on receipt of a main steam isolation signal.
The main feedwater control and control bypass valves serve as an acceptable backup means for feedwater isolation and receive the same isolation signals as the main feedwater isolation valves.
The condensate/main feedwater system is the normal means for starting up and shutting down the plant. The emergency feedwater system (refer to Section 10.4.9 of this SER) automatically provides flow to the steam generators for decay heat removal upon failure of the condensate and feedwater system.
The condensate/feedwater system is designed to preclude the potential for damaging flow instabilities (waterhammer). The feedwater piping is routed in a manner that minimizes its being drained by providing a vertical drop in the piping immediately outside the steam generator feedwater nozzle and by providing two check valves on each line between the steam generators and the feedwater pumps. Further, C-tubes have been provided on the feedwater distribution ring (spargers) which discharge above the spargers to provide further assurance that the feedwater piping remains full. In addition, the applicant has committed to perform preoperational tests utilizing normal plant operating procedures to demonstrate the ability to restore steam generator level following a low level transient without causing unacceptable feedwater/steam generator waterhammer.
Thus, the guidelines of BTP ASB 10-2, "Design Guidelines for Waterhamrner in Steam Generators With Top Feedring Designs, 11 are met.
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Based on the above, the staff concludes that the safety-related portion of con densate and feedwater system meets the requirements of GDC 2 and 4 with respect to its protection against natural phenomena, missiles and pipe break effects, and meets the guidelines of Regulatory Guides 1.26, 1.29, and 1.117 and BTP ASB 3-1 and 10-2 with respect to its quality group and seismic classification and tornado missile, and pipe break protection, and design for prevention of damaging waterhamrner, and is, therefore, acceptable.
10.4.8 Steam Generator Slowdown System The steam generator blowdown system (SGBS) assists in the control of the concentration of chemical impurities and radioactive materials in the secondary coolant. The scope of review of the SGBS included seismic and quality group classifications and design process parameters. The review has included the applicant's evaluation of the proposed system operation.
The SGBS design meets the primary boundary integrity requirements of General Design Criterion 14 as it relates to maintaining acceptable secondary water chemistry control during normal operation and anticipated operational occurrences.
The SGBS is seismic Category I and Quality Group B from its connection to the steam generator inside primary containment up to and including the first isola tion valve outside containment in accordance with Regulatory Guides 1.26 and 1.29, because this portion is considered an extension of the primary containment.
The SGBS downstream of the isolation valves meets the quality standards of Position C.1.1 of Regulatory Guide 1.143. The SGBS meets the quality standards requirements of General Design Criterion 1 and the seismic requirements of General Design Criterion 2.
The SGBS meets the applicable requirements of General Design Criteria 1, 2, and 14 and is therefore acceptable.
10.4.9 Auxiliary (Emergency) Feedwater System The following section is the staff's evaluation of the Waterford 3 emergency feedwater system (EFWS). This evaluation is presented in two parts. The first part is the evaluation of the EFWS against the criteria of the SRP. The second part is the evaluation of the EFWS against the criteria developed after the TMI-2 accident and enumerated in the NRC generic letter of March 10, 1980 and identified in Item II.E.1.1 of NUREG-0660 and NUREG-0737.
10.4.9.l Emergency Feedwater System Standard Review The staff has reviewed the Waterford 3 EFWS against the Acceptance Criteria of SRP Section 10.4.9. These criteria are:
(1) GDC 2, "Design Bases for Protection Against Natural Phenomena, 11 as related to structures housing the system and the system itself being capable of withstanding the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, and floods.
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(2)  GOC 4, 11 Environmental and Missile Design Bases," with respect to structures housing the system and the system itself being capable of withstanding the effects of external missiles and internally generated missiles, pipe whip, and jet impingement forces associated with pipe breaks.
(3)  GDC 5, "Sharing of Structures, Systems and Components, 11 as related to the capability of shared systems and components important to safety to perform required safety functions.
(4)  GDC 19, "Control Room, 11 as related to the design capability of system instrumentation and controls for prompt hot shutdown of the reactor and potential capability for subsequent cold shutdown.
(5)  GDC 44, 11 Cooling Water, 11 to assure:
(a) The capability to transfer heat loads from the reactor system to a heat sink under both normal operating and accident conditions.
(b) Redundancy of components so that under accident conditions the safety function can be performed assuming a single active component failure.
(This may be coincident with the loss of offsite power for certain events.)
(c) The capability to isolate components, subsystems, or piping if required so that the system safety function will be maintained.
(6)  GDC 45, "Inspection of Cooling Water System;' as related to design provi sions made to permit periodic inservice inspection of system components and equipment.
(7)  GDC 46, "Testing of Cooling Water System," as related to design provisions made to permit appropriate functional testing of the system and components to assure structural integrity and leak-tightness, operability and perform ance of active components, and capability of the integrated system to function as intended during normal, shutdown, and accident conditions.
(8)  Regulatory Guide 1.26, "Quality Group Classifications and Standards for Water-, Steam- and Radioactive-Waste-Containing Components for Nuclear Power Plants," as related to the quality group classification of system components.
(9)  Regulatory Guide 1.29, 11 Seismic Design Classification, 11 as related to the seismic design classification of system components.
(10) Regulatory Guide 1.62, "Manual Initiation of Protective Actions, 11 as related to design provisions made for manual initiation of each protective action.
(11) Regulatory Guide 1.102, "Flood Protection for Nuclear Power Plants, 11 as related to the protection of structures, systems, and components important to safety from the effects of flooding.
(12) Regulatory Guide 1.117, 11 Tornado Design Classification, 11 as related to the protection of structures, systems, and components important to safety from the effects of tornado missiles.
(13) BTP ASB 3-1, "Protection Against Postulated Piping Failure in Fluid Systems Outside Containment, 11 as related to breaks in high and moderate energy piping systems outside containment.
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(14) BTP ASS 10-1, 11 Auxiliary Feedwater System Pump Drive and Power Supply Diversity for Pressurized Water Reactor Plants," as related to auxiliary feedwater pump drive and power supply diversity.
The following evaluation discusses the implementation of the above acceptance criteria and follows the format of the review procedures identified in SRP Section 10.4.9. The staff review is based on information contained in FSAR Section 10.4.9, and a system walkdown performed during a site visit on March 26, 1981.
The EFWS is designed to supply an independent source of water to the steam generator during accident and transient conditions in the event of a loss of main feedwater supply. The major components of the Waterford 3 EFWS are three essential safety grade pumps, one 700 gal/min (nominal) steam turbine driven pump and two 440 gal/min (nominal) motor driven pumps. The EFWS water supply is provided by the condensate storage pool with a backup supply available from the wet cooling tower basins. The system provides two redundant flowpaths (one to each steam generator) each flowpath containing redundant active components.
Since Waterford 3 is a single unit plant, GDC 5 is not applicable.
(1)  The staff has reviewed the FSAR in order to verify the acceptability of the EFWS design with respect to its classification and operating characteristics.
(a) Minimum performance requirements for the EFWS have been identified and are sufficient for the various functions of the system. This is discussed in more detail in the following section of this report.
(b) Adequate isolation of the EFWS from nonessential systems is included in the system design. The EFWS connects to the nonessential main feedwater system in the safety-related portion downstream of the main feedwater isolation valve and check valve. The main feedwater flushing (cleaning) connections to each EFWS piping train from the feedwater lines are provided with a check valve and locked closed motor operated valve and to the blowdown filters with a locked closed motor operated valve. A check valve and normally closed manual isolation valve provides isolation of the EFWS suction from the nonessential chemical addition system. The above features provide sufficient isolation to assure that the system function is not impaired in the event of failure of a nonessential component. Therefore, the staff concludes that the EFWS meets the isolation requirements of GDC 44.
(c) The entire EFWS is designed to seismic Category I requirements and Quality Group C requirements with the exception of the portion from the main feedwater line connection through the flow control/isolation valves which is seismic Category I and Quality Group B. Therefore, the staff concludes that the EFWS itself meets the requirements of GDC 2 and guidelines of Regulatory Guides 1.26 and 1.29 with respect to its seismic and quality group classification.
(d) Provision for EFWS testing and inspection are included in the design.
Each EFWS pump is equipped with a recirculation line to the condensate storage pool for periodic functional testing purposes. Periodic testing of EFWS pumps and valves is identified in the plant technical specifi cations. Therefore, the staff concludes that the EFWS meets the 10-15
 
requirements of GDC 46 with respect to functional testing. The EFWS components are located in areas that are accessible during normal plant operation to permit periodic inservice inspection. Therefore, the staff concludes that the EFWS meets the requirements of GDC 45 regarding design provisions for inservice inspection.
(2) The staff has reviewed the EFWS design for protection against the effects of natural phenomena, pipe breaks or cracks in fluid systems outside con tainment, single system component failures, loss of an onsite motive power source, or loss of offsite power.
(a) Protection against failure of nonseismic Category I plant features is provided. Failure of nonseismic Category I systems, components or structures will not adversely affect EFWS function. All EFWS components are located in seismic Category I structures or are provided with protection against failure of nonseismic Category I components.
Therefore, the staff concludes that the EFWS is protected from earth quakes and meets the requirements of GDC 2.
(b) Protection against missiles, tornadoes and floods is provided. The EFWS is located in the tornado missile and flood proof reactor auxil iary building. The EFWS flow control/isolation valve and EFWS turbine steam supply valve are located in a compartment on the roof of the reactor auxiliary building. This compartment is protected from tornado missiles by grating. A portion of the EFWS piping upstream of the flow control/isolation valves to steam generator No. 2 is exposed above the reactor auxiliary building roof, however, this piping has sufficient wall thickness to withstand the most severe postulated tornado missile at this elevation without damage. The EFWS flow control/isolation valves and EFWS turbine steam supply valves are exposed to outside ambient environmental extremes since the above mentioned compartment is open to the outdoors. Environmental qualifica tion of EFWS components is discussed in Section 3.11 of this SER.
Each EFWS pump is mounted on a 2 ft-3 in.-high pad for protection against internal flooding. The motor driven pumps are located in separate watertight cubicles which are provided with adequate drainage and are designed to protect the pumps from internal missiles. The turbine driven pump is located in a separate area which is provided with adequate drainage and is separated from internal missile sources (refer to Sections 3.4.1, 3.5.1.1 and 3.5.2 of this SER for further discussion). Therefore, the staff concludes that the EFWS is protected from floods, tornadoes, and missiles and meets the requirements of GDC 2 and 4 and the guidelines of Regulatory Guides 1.102 and 1.117.
(c) The EFWS is not used during startup and shutdown, therefore, it is not designed as a high energy system, and pipe breaks were not postulated in the EFWS. Protection against moderate energy pipe cracks in the EFWS is provided by separation of equipment. The EFWS is protected against the effects of high and moderate energy line breaks in other systems. These include the effects of pipe whip, jet impingement, and flooding. EFWS pumps are not located near any high energy piping systems. However, each redundant pair of EFWS isolation/control valves is located in the separate main steam and main feedwater piping penetratior. area. The portion of these lines near essential EFWS components is part of the break exclusion boundary, and thus pipe whip is not postulated to occur because of the design of the 10-16
 
piping in this area. Further, the separation provided for the redundant valves assures EFWS function considering environmental effects from a postulated main steam or feedwater line crack.
Floor drainage, raised mounting, and separation are employed to provide protection for EFWS components against internal flooding resulting from line breaks. Therefore, the staff concludes that the EFWS is protected against the effects of pipe whip, jet impingement, and flooding associated with pipe breaks and meets the requirements of GDC 4 and the guidelines of BTP ASB 3-1 with respect to pipe breaks outside containment. Protection against the effects of pipe breaks is discussed further in this SER under Section 3.6.1. Environmental qualification of EFWS components with respect to pipe breaks is discussed in Section 3.11 of this SER.
In order to demonstrate the adequacy of the plant design to preclude the occurrence of fluid flow instabilities (waterhammer) in system inlet piping, the applicant has committed to perform a preoperational test using the standard operating procedures to verify that unaccept able waterhammer will not occur. This test will demonstrate the ability of the EFWS to restore steam generator level following a low level transient without causing unacceptable feedwater/steam generator waterhammer. The staff concludes that completion of the test without unacceptable feedwater hammer damage will accomplish NRC 1 s test objective. Refer to Section 10.4.7 of this SER for further discussion concerning feedwater hammer.
(d) The EFWS can function as required in the event of a loss of offsite power. The heat transfer path from the steam generator under this condition is to the atmosphere via the atmospheric dump valves. The turbine driven pump receives main steam from both steam generators through an air operated valve, one on each steam supply line which fails open on loss of the air supply. These valves are normally closed and open on receipt of an emergency feedwater actuation signal (EFAS).
The steam supply lines to the turbine driven pump are located upstream of the main steam isolation valves. The EFWS pump turbine exhausts to the atmosphere. The motor driven pumps are powered from separate emer gency ac vital buses. The EFWS discharge valves are air operated, normally closed and open on receipt of an EFAS. They also fail open on loss of the normal air supply but are provided with a seismic Cate gory I backup air accumulator to facilite their operability. Therefore, the EFWS meets the requirements of GDC 44 with respect to its ability to transfer heat from the reactor coolant system under accident conditions Refer to item (i) below for further discussion.
(e) The EFWS is designed to accommodate a single failure in any active system component without loss of function. The EFWS consists of two trains, (fed by three pumps) one supplying each steam generator.
Each train consists of two sets of two valves (eight valves total) one air operated isolation valve and one air operated throttle valve in series and a second isolation and throttle valve in series arranged in paralled with the first set for each train. One isolation valve and one throttle valve from each set is powered from the same de vital bus. A power supply failure causes the associated valves to fail open. Thus, adequate feedwater is assured to an intact steam generator in the event of a high energy line break or other postulated design 10-17
 
basis event concurrent with a single failure. The trains are cross connected through open manual valves in series so that any EFWS pump can supply both steam generators in the event of a single failure.
The EFWS pumps are provided with two suction connections to the conden sate storage pool. Steam supply to the turbine driven pump is provided from both steam generators through separate air operated valves which fail open on loss of the air supply. Redundant isolation is provided for all portions of the EFWS from nonessential systems (see item lb above). Therefore, the EFWS meets the requirements of GDC 44 with respect to the single failure criterion.
(f)  The turbine driven EFWS pump train provides a diverse means of assuring feedwater supply to the steam generator independent of all offsite or onsite ac power sources for 2 hr. The turbine driven pump bearings do not require cooling from an ac dependent source and the pump can operate without area forced ventilation for the 2-hr period. Automatic actuation and control of this train is provided from the vital de power source. Therefore, the EFWS meets the power diversity position of BTP ASB 10-1.
(g)  The EFWS pumps and flow control/isolation valves are automatically started and opened on receipt of an emergency feedwater actuation signal (EFAS). Steam generator water level is then automatically controlled by level signals to the EFWS throttle valves. Therefore, the staff concludes that the EFWS provides instrumentation and control for prompt initiation of a shutdown in accordance with the require ments of GDC 19.
(h)  Manual capability to initiate and control the EFWS pumps/valves and
    . isolate either EFAS train is provided in the control room. This capability is also provided from the auxiliary control panel. In addition, local manual control is available to the operator. There fore, the EFAS meets the manual initiation guidelines of Regulatory Guide 1.62.
(i)  Automatic EFWS function is provided in the event of a main steam or main feedwater line rupture. Redundant instrumentation is provided at each steam generator to automatically isolate EFWS flow to a depressurized steam generator and to automatically assure EFWS flow to the intact steam generator. The EFAS is designed to determine which steam generators are intact and automatically provide flow accordingly. Therefore, the EFWS meets the requirements of GDC 44 with respect to its ability to transfer heat under accident conditions and provide isolation to assure system function.
(j)  The turbine driven EFWS pump or both motor driven pumps together are designed to provide 100% of the flow necessary for residual heat removal over the entire range of reactor operation including all postulated design basis accidents in accordance with the conservatisms assumed in the accident analysis. However, any one EFWS pump can supply ade quate flow for decay heat removal under realistic conditions. A minimum of 170,000 gal of water is reserved by technical specification in the condensate storage pool. This volume is sufficient for cooldown of the reactor coolant system to the shutdown cooling system cut in temperature (350&deg; F) following any design basis accident. Additional 10-18
 
water is also available from the wet cooling tower basins for maintain ing hot standby for at least 2 hr prior to initiating the shutdown cooling system. Therefore, the EFWS meets the decay heat removal requirements of GDC 44.
 
==
Conclusion:==
The emergency feedwater system includes all components and equipment from the condensate storage pool (including valves and cross connections) to the connection with the steam generators. Based on the review of the applicant 1 s proposed design criteria, design bases, and safety classification for the emer gency feedwater system, and system performance requirements during normal, abnormal, and accident conditions, the design of the emergency feedwater system and supporting systems is in conformance with the Commission 1 s regulations as set forth in GDC 2, 4, 19, 44, 45, and 46, and meets the guidelines contained in Regulatory Guides 1.26, 1.29, 1.62, and 1.117, and BTP ASB 10-1 and ASB 3-1 and, therefore, is acceptable.
10.4.9.2 Emergency Feedwater System Review (TMI-2 Considerations)
The staff has reviewed the Waterford 3 emergency feedwater system against the requirements of the {{letter dated|date=March 10, 1980|text=March 10, 1980 letter}}, which corresponds to Item II.E.1.1 of NUREG-0660 and NUREG-0737.
Introduction and
 
==Background:==
The TMI-2 accident and subsequent investigations and studies highlighted the importance of the auxiliary feedwater system (AFWS) in the mitigation of transients and accidents. As part of the assessment of the TMI-2 accident and related implications for operating plants, NRC evaluated the AFWS for all operating plants having nuclear steam supply systems (NSSS) designed by Westinghouse (NUREG-0611) or Combustion Engineering (NUREG-0635).
Evaluations of these system designs are contained in the two reports just cited along with NRC recommendations for each plant and the concerns that led to each recommendation. The objectives of the evaluation were to: (1) identify necessary changes in AFWS design or related procedures at the operating facilities in order to assure the continued safe operation of these plants, and (2) to identify other system characteristics of the AFWS which, on a long-term basis, may require system modifications. To accomplish these objectives, the staff:
(1) Reviewed plant-specific AFWS designs in light of current regulatory guidance (SRP), and (2) Assessed the relative reliability of the various AFWSs under various loss of feedwater transients (one of which was the initiating event of TMI-2) and other postulated failure conditions by determining the potential for AFWS failure as a result of common causes, single point vulnerabilities, and human error.
In accordance with the requirements of Item II.E.1.1 of NUREG-0660, 11 NRC Action Plan Developed as a Result of the TMI-2 Accident, 11 and NUREG-0737, 11 Clarifica tion of TMI Action Plan Requirements, 11 NRC has included the following results of the Waterford 3 emergency feedwater system review in this SER:
(1)  NRC has applied the generic results and recommendations from the above described reviews for operating plants to the Waterford 3 EFWS.
10-19
 
(2) NRC has reviewed the detailed Waterford 3 EFWS reliability analysis submitted by the applicant. The staff's evaluation of this reliability analysis follows:
In FSAR Amendment 13, the applicant provided Appendix 10.4.98 entitled 11 Emergency Feedwater System Reliability Analysis." This analysis was revised in subsequent amendments, and evaluated the EFWS reliability for the three postulated transient and accident scenarios identified for study in NRC's {{letter dated|date=March 10, 1980|text=March 10, 1980 letter}} utilizing fault three methodology. Overall numerical system unavailability for the three cases was determined using the NRC approved failure rate data base. Results of the applicant 1 s analysis indicated that the Waterford 3 EFWS ranked in the high reliability range for case 1, Loss of Main Feedwater, and case 2, Loss of Offsite Power, and in the medium reliability range for case 3, Loss of All ac Power.
Dominant contributors to EFWS unreliability were also identified. A signif icant plant-specific contributor to unreliability for cases 1 and 2 involves a potential maintenance error performed during the feedwater system cleaning procedure (identified as 11 MEl 11 in the Emergency Feedwater System Reliability Analysis). It has a significant effect on system availability since a portion of the EFWS piping is utilized to perform the feedwater cleaning procedure, and the EFWS must be entirely valved out to perform the feed water system flushing operation, and a failure by the operator to restore the EFWS is possible. The applicant has minimized this possibility by:
(a)    Providing second operator (independent) verification of valve position after performing the cleaning procedure, (b) Performing an EFWS flow verification test by using an EFWS pump to pump water from the condensate storage pool to the steam generator after performing the cleaning procedure, (c) Providing position indication with annunciation in the control room on the EFWS valves that are realigned for the cleaning procedure.
These provisions reduce the possibility of this error and are acceptable.
The applicant has satisfactorily complied with the reliability study stipulations of NRC's {{letter dated|date=March 10, 1980|text=March 10, 1980 letter}}, and the EFWS reliability assessment is acceptable.
(3) The staff has reviewed the applicant's deterministic comparison of the Waterford 3 EFWS against SRP Section 10.4.9 and BTP ASB 10-1, and finds that the EFWS design is in compliance. Environmental qualification of the EFWS is being reviewed by the Equipment Qualification Branch as a separate item, and will be reported in Section 3.11 of a supplement to this SER.
(4) The staff has reviewed the applicant's response to its request in Enclosure 2 of the {{letter dated|date=March 10, 1980|text=letter dated March 10, 1980}}, regarding the design basis for the EFWS flow requirements. The applicant provided this information in FSAR Table 10.4.9A-3. The staff's evaluation of the applicant 1 s response against the design basis accidents and transients as identified in Chapter 15 verifies that adequate EFWS flow is provided and, therefore, the design basis for the EFWS flow requirements is acceptable.
10-20
 
The implementation of the following recommendations identified from the above reviews has improved the reliability of the Waterford 3 EFWS. The applicant will incorporate all short- and long-term recommendations of the {{letter dated|date=March 10, 1980|text=March 10, 1980 letter}} before receipt of the OL.
10.4.9.3  Implementation of Recommendations (1)  Short-Term Recommendations o    Recommendation GS-1: 11 The licensee should propose modifications to the Technical Specifications to limit the time that one AFW system pump and its associated flow train and essential instrumentation can be inoperable. The outage time limit and subsequent action time should be as required in current Technical Specifications; i.e., 72 hours and 12 hours, respectively. 11 In response, the applicant indicated in FSAR Table 10.4.9A-2 that the proposed Waterford Technical Specification, Section 3.7.1.2 applies.
This specification limits the plant operation with one EFWS pump out of service to 72 hr and the subsequent action time to 12 hr. The staff concludes that this technical specification is in compliance with its recommendation and is, therefore, acceptable.
0    Recommendation GS-2: 11 The licensee should lock open single valves or multiple valves in series in the AFW system (AFWS) pump suction piping and lock open other single valves or multiple valves in series that could interrupt all AFW flow. Monthly inspection should be performed to verify that these valves are locked and in the open posi tion. These inspections should be proposed for incorporation into the surveillance requirements of the plant Technical Specifications.
See Recommendation GL-2 for the longer-term resolution of this concern."
In FSAR Table 10.4.9A-2 the applicant responded to this recommenda-tion by stating that the EFWS inciuding the pump suction supply from the condensate storage pool has redundant parallel flow paths (piping and valves) so that closure of a single valve can not interrupt all flow. Even though there are parallel paths, all manual valves in the EFWS suction supply lines to the EFWS pumps and discharge lines from the pumps are locked open and are provided with limit switches for position indication in the control room. Based on the above, the staff concludes that the applicant 1 s response is acceptable, and the monthly inspection and survei11ance requirements in the technical specifications are not required.
0    Recommendation GS-3: 11 The licensee has stated that it throttles AFW system flow to avoid waterhammer. The licensee should reexamine the practice of throttling AFW system flow to avoid waterhammer. The licensee should verify that the AFW system will supply on demand sufficient initial flow to the necessary steam generators to assure adequate decay heat removal following loss of main feedwater flow and reactor trip from 100% power. In cases where this reevaluation results in an increase in initial AFW system flow, the licensee should provide sufficient information to demonstrate that the required initial AFW system flow will not result in plant damage due to waterhammer. 11 10-21
 
Because of the design of the Waterford 3 plant, throttling of EFWS flow to avoid waterhammer will not be necessary. The applicant indicated in FSAR Table 10.4.9A-2 that throttling of the EFWS to avoid waterhammer will not be utilized. Based on the applicant's response, the staff concludes that Recommendation GS-3 is not applicable to Waterford 3.
o Recommendation GS-4: "Emergency procedures for transferring to alter nate sources of AFW supply should be available to the plant operators.
These procedures should include criteria to inform the operator when, and in what order, the transfer to alternate water sources should take place. The following cases should be covered by the procedures:
(a)  11 The case in which the primary water supply is not initially available. The procedures for this case should include any opera tor actions required to protect the AFW system pumps against self-damage before water flow is initiated.
(b) 11 The case in which the primary water supply is being depleted.
The procedures for this case should provide for transfer to the alternate water sources prior to draining of the primary water supply.11 In response to this recommendation, the applicant indicated in Table 10.4.9A-2 that plant procedures will provide criteria for transfer to the alternate water source (wet cooling tower basins) for both the case where primary water supply (condensate storage pool) is not initially available and the case where the primary water supply is being depleted. The applicant's response is acceptable pending verification of the plant procedures by the Office of Inspection and Enforcement.
o Recommendation GS-5: 11 The as-built plant should be capable of providing the required AFW flow for at least two hours from one AFW pump train, independent of any alternating current power source. If manual AFW system initiation or flow control is required following a complete loss of alternating current power, emergency procedures should be established for manually initiating and controlling the system under these conditions. Since the water for cooling of the lube oil for the turbine-driven pump bearings may be dependent on alternating current power, design or procedural changes shall be made to eliminate this dependency as soon as practicabie. Until this is done, the emer gency procedures should provide for an individual to be stationed at the turbine-driven pump in the event of the loss of all alternating current power to monitor pump bearing and/or lube oil temperatures.
If necessary, this operator would operate the turbine-driven pump in a manual on-off mode until alternating current power is restored.
Adequate lighting powered by direct current power sources and communi cations at local stations should also be provided if manual initiation and control of the AFW system is needed. (See Recommendation    GL-3 for the longer-term resolution of this concern.) 11 10-22
 
In response to this recommendation, the applicant indicated in FSAR Table 10.4.9A-2 that the turbine-driven pump is capable of being auto matically initiated and operated independent of any ac power source for at least 2 hr. Refer to Recommendation GL-3 for further discussion of this feature. Based on the applicant's response, the staff con cludes that the provisions available in the existing Waterford 3 EFWS meets the requirements outlined in this recommendation and are, therefore, acceptable.
o Recommendation GS-6: "The licensee should confirm flow path availabil ity of an AFW system flow train that has been out of service to perform periodic testing or maintenance as follows:
(a) "Procedures should be implemented to require an operator to deter mine that the AFW system valves are properly aligned and a second operator to independently verify that the valves are properly aligned.
(b) 11 The licensee should propose Technical Specifications to assure that prior to plant startup following an extended cold shutdown, a flow test would be performed to verify the normal flow path from the primary AFW system water source to the steam generators.
The flow test should be conducted with AFW system valves in their normal alignment. 11 In FSAR Table 10.4.-9A-2, the applicant responded to this recommendation stating that plant procedures will be implemented requiring that an operator verify that EFWS valves are properly aligned and that a second operator independently verify proper valve alignment as required by the first part of this recommendation. The first part of this recom mendation is, therefore, satisfied pending verification of the plant procedures by the Office of Inspection and Enforcement.
In addition, the EFWS is not used to supply feedwater to the steam generators during normal plant startup and shutdown. Therefore, the availability of an EFWS flowpath from the primary water source (con densate storage pool) to the steam generators is not automatically verified during normal plant startup. The applicant has, therefore, revised proposed plant Technical Specification 4. 7.1.2 to include a requirement that a flow test be performed to verify the normal flow path from the condensate storage pool to the steam generators after a11,y
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The second part of this recommendation is, therefore, satisfied.
o Recommendation GS-7: 11 The licensee should verify that the automatic start AFW system signals and associated circuitry are safety grade.
If this cannot be verified, the AFW system automatic initiation system should be modified in the short-term to meet the functional requirements listed below. For the longer term, the automatic initia tion signals and circuits should be upgraded to meet safety-grade requirements as indicated in Recommendation GL-5.
10-23
 
(a) "The design should provide for the automatic initiation of the auxiliary feedwater system flow.
(b) 11 The automatic initiation signals and circuits should be designed so that a single failure will not result in the loss of auxiliary feedwater system function.
(c) "Testability of the initiation signals and circuits shall be a feature of the design.
(d) 11 The initiation signals and circuits should be powered from the emergency buses.
(e) "Manual capability to initiate the auxiliary feedwater system from the control room should be retained and should be imple mented so that a single failure in the manual circuits will not result in the loss of system function.
(f) "The alternating current motor-driven pumps and valves in the auxiliary feedwater system should be included in the automatic actuation (simultaneous and/or sequential) of the loads to the emergency buses.
(g) "The automatic initiation signals and circuits shall be designed so that their failure will not result in the loss of manual capability to initiate the AFW system from the control room."
In response to this recommendation, the applicant stated in FSAR Table 10.4.9A-2 that the Waterford 3 EFWS is designed so that automatic initiation signals and circuits are redundant and meet safety-grade requirements. Refer to Recommendation GL-5 for further evaluation.
0    Recommendation GS-8: The present design of Waterford 3 provides for automatic 1n1t1ation of EFWS system flow. Recommendation GS-7 verifies automatic initiation of this system. Therefore, this recommendation is not applicable to Waterford 3.
(2) Additional Short-Term Recommendations 0    Recommendation: "The licensee should provide redundant leve 1 indi cation and low level alarms in the control room for the AFW system primary water supply, to allow the operator to anticipate the need to make up water or transfer to an alternate water supply and prevent a low pump suction pressure condition from occurring. The low level alarm setpoint should allow at least 20 minutes for operator action, assuming that the largest capacity AFW pump is operating."
In response, the applicant indicated in FSAR Table 10.4.9A-2 that condensate storage pool level is monitored by redundant level trans mitters powered from redundant Class lE power sources. Each trans mitter provides redundant level indication in the control room. Two annunciator system windows powered by two separate power supplies within the plant annuniciator system are provided to alarm 1 1 low-low 11 level in the pool. The two power supplies within the annunciator system  are backed by a common battery-backed power source. The 11 low low level alarm setpoint allows at least 30 min for operator action, 11 10-24
 
assuming that the largest capacity EFWS pump is operating. The applicant's response to this recommendation is acceptable.
0    Recommendation:* "The licensee should perform a 48-hour endurance test on all EFW system pumps, if such a test or continuous period of operation has not been accomplished to date. Following the 48-hour pump run, the pumps should be shut down and cooled down and then restarted and run for one hour. Test acceptance criteria should include demonstrating that the pumps remain within design limits with respect to bearing/bearing oil temperatures and vibration and that pump room ambient conditions (temperature, humidity) do not exceed environmental qualification limits for safety-related equipment in the room.11 In FSAR Table 10.4.9A-2, the applicant committed to perform a 48-hr endurance test on all EFWS pumps during preoperational testing. The applicant also committed to provide a copy of test results including:
(a) A brief description of the test method and instrumentation used, (b) A plot of bearing and bearing oil temperature vs. time for each pump demonstrating that the temperature design limits were not exceeded, (c) A plot of pump room ambient temperature and humidity vs. time to demonstrate that the pump room ambient conditions do not exceed environmental qualification limits for safety-related equipment in the room, and (d) A statement confirming that the pump vibration limits were not exceeded.
The response to this recommendation is acceptable. The Office of Inspection and Enforcement wi11 verify the acceptabi1 ity of the EFWS pump test results. If the results are not acceptable, NRC will require modifications and provide a safety evaluation regarding the tests and modifications.
0    Recommendation: "The licensee should implement the following require ments as spec1fied by Item 2.1.7.b on page A-32 of NUREG-0578:
Safety-grade indication of auxiliary feedwater flow to each steam generator shall be provided in the control room. The auxiliary feed water flow instrument channels shall be powered from the emergency buses consistent with satisfying the emergency power diversity require ments for the auxiliary feedwater system set forth in Auxiliary Systems Branch Technical Position 10-1 of the Standard Review Plan, Section 10.4.9.
In FSAR Table 10.4.9A-2 the applicant responded to this recommendation by stating that the EFWS design includes safety-grade, redundant indi cation of EFWS flow to each steam generator in the control room.
*This recommendation has been revised from the original recommendation in NUREG-0611 and NUREG-0635.
10-25
 
The EFWS instrument channels are powered from the emergency buses.
The staff reviewed this response as part of Item II.E.1.2 of NUREG-0737 and provides an evaluation in Section 7.3.4 of this report.
0    Recommendation: 11 Licensees with plants which require local manual realignment of valves to conduct periodic tests on one AFW system train, and there is only one remaining AFW train available for operation should propose Technical Specifications to provide that a dedicated individual who is in communication with the control room be stationed at the manual valves. Upon instruction from the con trol room, this operator would realign the valves in the AFW system train from the test mode to their operational alignment. 11 In response to this recommendation, the applicant indicated in FSAR Table 10.4.9A-2 that the Waterford 3 plant does not require the realign ment of local manual valves to conduct periodic tests on any EFWS trains. Periodic pump surveillance tests can be conducted by merely starting a pump, and water is recirculated to the condensate storage pool. This recommendation is, therefore, not applicable to Waterford 3.
(3) Long-Term Recommendations 0    Recommendation GL-1: 11 For plants with a manual starting AFW system
[AFWS], the licensee should install a system to automatically initiate the AFW system flow. This system and associated automatic initiation signals should be designed and installed to meet safety-grade require ments. Manual AFW system start and control capability should be designed and installed to meet safety-grade requirements. Manual AFW system start and control capability should be retained with manual start serving as backup to automatic AFW system initiation. 1 1 Because the applicant 1 s response to Recommendation GS-7 stated that the Waterford 3 EFWS design already includes safety-grade automatic start, Recommendation GL-1 is not applicable to Waterford 3.
0    Recommendation GL-2: "Licensees with plant designs in which all (primary and alternate) water supplies to the AFW systems pass through valves in a single flow path should install redundant parallel flow paths (piping and valves).
Licensees with plants in which the primary AFW system water supply passes through valves in a single flow path, but the alternate AFW system water supplies connect to the AFW system pump suction piping downstream of the above valve(s), should instaii redundant vaives parallel to the above valve(s) or provide automatic opening of the valve(s) from the alternate water supply upon low pump suction pressure.
The licensee should propose Technical Specifications to incorporate appropriate periodic inspections to verify the valve positions. 11 In response to this recommendation, the applicant indicated, in FSAR Table 10.4.9A-2 that the EFWS pumps are provided with suction supply by two separate lines from the primary water source (condensate storage 10-26
 
pool) such that there is no single valve which if left closed could interrupt all flow. This recommendation, therefore, does not apply to Waterford 3.
0 Recommendation GL-3: 11 At least one AFW  system pump and its associated flow path and essential instrumentation    should automatically initiate AFW system flow and be capable of being    operated independently of any ac power source for at least two hours. Conversion of de power to ac power is acceptable. 11 In response to this recommendation, the applicant indicated in FSAR Table 10.4.9A-2 that the turbine-driven EFWS pump and its associated flowpath and essential instrumentation automatically initiate EFWS flow and is capable of being operated independent of any ac power source for at least 2 hr. The turbine steam supply valves are fail open air operated valves powered by redundant de solenoids and are provided with passive backup air accumulators. Each pump discharge line to the steam generators contains redundant fail open air operated isolation and flow control valves and are controlled by redundant de buses and are provided with passive backup air accumulators. The turbine lube oil cooler receives cooling water from an extraction point on the first stage of the pump. The turbine driven pump can operate for more than 2 hr without additional ambient air cooling.
The staff confirms that the turbine-driven EFWS pump train is avail able to supply emergency feedwater independent of onsite1 or offsite ac power supplies. Based on this review, the applicant s response is acceptable.
0 Recommendation GL-4:  11 Licensees having plants with unprotected normal AFW system water supplies should evaluate the design of their AFW systems to determine if automatic protection of the pumps is neces sary following a seismic event or a tornado. The time available before pump damage, the alarms and indications available to the control room operator, and the time necessary for assessing the problem and taking action should be considered in determining whether operator action can be relied on to prevent pump damage. Consideration should be given to providing pump protection by means such as automatic switchover of the pump suctions to the alternate safety-grade source of water, automatic pump trips on low suction pressure, or upgrading the normal source of water to meet seismic Category I and tornado protection requirements.u In response to this recommendation, the applicant indicated in FSAR Table 10.4.9A-2 that the primary EFWS water source (the condensate storage pool) is a seismic Category I component and is located in the reactor auxiliary building which provides protection against the effects of tornado missiles. This recommendation, therefore, does not apply to Waterford 3.
0 Recommendation GL-5 11 The licensee should upgrade the AFW system automatic initiation signals and circuits to meet safety-grade requirements. 11 10-27
 
In response to this recommendation, the applicant indicated in FSAR Table 10.4.9A-2 that the present EFWS automatic initiation signals and circuits are safety grade. The staff reviewed the applicant's design as part of Item II.E.1.2 of NUREG-0737 in detail and provides an evaluation in Section 7.3.4 of this report.
10-28
 
==10.5 REFERENCES==
American National Standards Institute:
ANSI B31.1 ANSI Standard N45.2.l-1973 American Society of Mechanical Engineers Boiler and Pressure Vessel Code:
ASME Section II, Parts A, B, and C ASME Section III, Appendix I Branch Technical Positions (SRP Sections 3.0 and 10.0):
BTP ASB  3-1 BTP ASB  10-1 BTP ASB  10-2 BTP MEB  3-1 Code of Federal Regulations:
10 CFR Part 50 General Design Criteria:
GDC 1 GDC 2 GDC 4 GDC 5 GDC 19 GDC 34 GDC 44 GDC 45 GDC 46 GDC 60 GDC 64 Letter (generic) from NRC to all applicants with NSSS designed by Westinghouse or Combustion Engineering, dated March 10, 1980 Louisiana Power and Light Co. report:
FSAR for Waterford 3 Amendment 13 Section 10.3 Section 10.4.1 Section 10.4.9 Table 10.4.9A-2 Table 10.4.9A-3 10-29
 
Regulatory Guides:
RG 1.26 RG 1. 29 RG 1. 37 RG 1.50 RG 1. 62 RG 1.68 RG 1.71 RG 1.102 RG 1.117 USNRC reports:
NUREG-0578 NUREG-0611 NUREG-0635 NUREG-0660 NUREG-0737 NUREG-75/087
*See Appendix 8, Bibliography, for complete citations and availability statements.
10-30
 
11 RADIOACTIVE WASTE SYSTEM 11.1
 
==SUMMARY==
DESCRIPTION The radioactive waste management systems are designed to provide for controlled handling and treatment of liquid, gaseous, and solid wastes. The liquid radio active waste system processes wastes from equipment and floor drains, sample wastes, decontamination and laboratory wastes, regenerant chemical wastes, and laundry and shower wastes. The gaseous radioactive waste system provides ho1dup capacity to allow decay of short-lived noble gases from the primary coolant and treatment of ventilation exhausts through high efficiency particulate air (HEPA) filters and charcoal adsorbers as necessary to reduce releases of radioactive materials to as low as is reasonably achievable (ALARA) levels in accordance with 10 CFR Part 20 and 10 CFR Section 50.34a. The solid radioactive waste system provides the capability for the solidification, packaging, and storage of radioactive waste generated during station operation before shipment offsite to a licensed facility for burial.
In evaluating the liquid and gaseous radioactive waste systems, the staff considered: (1) the capability of the systems for keeping the levels of radio activity in effluents ALARA based on expected inputs over the life of the plant, (2) the capability of the systems to maintain releases below the limits of 10 CFR Part 20 during periods of fission product leakage from the fuel at design levels, (3) the capability of the systems to meet the processing demands of the station during anticipated operational occurrences, (4) the quality group and seismic desin classification applied to the equipment and components and structures housing these systems, (5) the design features that will be incorporated to control the releases of radioactive materials in accordance with GDC 60 of 10 CFR Part 50, and (6) the potential for gaseous release because of hydrogen explosions in the gaseous radwaste system.
In the evaluation of the solid radioactive waste treatment system the staff considered: (1) system design objectives in terms of expected types, volumes, and activities of waste processed for offsite shipment, (2) waste packaging and conformance to applicable federal packaging regulations and provisions for controlling potentially radioactive airborne dusts during compacting operations, and (3) provisions for onsite storage prior to shipping.
In the evaluation of the process and effluent radiological monitoring and sampling systems the staff considered the system's capability to: (1) monitor all normal and potential pathways for release of radioactive materials to the environment, (2) control the release of radioactive materials to the environment, and (3) mon itor the performance of process equipment and detect radioactive material leakage between systems.
The staff has determined the quantities of radioactive materials that will be released in liquid and gaseous effluents and the quantity of radioactive waste that will be shipped offsite to a licensed burial facility. In making these 11-1
 
determinations, the staff has considered waste flows, activity levels and equipment performance, consistent with expected normal plant operation, including anticipated operational occurrences, over the projected 30-yr operating life of the plant.
The estimated releases of radioactive materials in liquid and gaseous effluents were calculated using the PWR GALE Code described in NUREG-0017, "Calculated Releases of Radioactive Materials in Gaseous and Liquid Effluents From Pressurized Water Reactors (PWR GALE Code), 11 April 1976. The principal parameters used in these calculations are given in Table 11.1. The liquid and gaseous source terms are given in Tables 11.2 and 11.3, respectively. The source terms given in Tables 11.2 and 11.3 were used to calculate individual doses in accordance with the mathematical models and guidance contained in Regulatory Guide 1.109, 11 Calculation of Annual Average Doses to Man From Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance With 10 CFR Part 50, Appendix I."
Meteorological factors in the dose calculations were determined using the guidance in Regulatory Guide 1.111, 11 Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents From Routine Releases From Light-Water-Cooled Reactors.11 The calculated individual doses are given in Table 11.4.
In lieu of performing a cost-benefit analysis to show conformance with Sec tion II.D of Appendix I of 10 CFR Part 50, a comparison was made between the design objectives of the Annex to Appendix I and calculated doses to the maxi mally exposed individual and the quantity of tritium in liquid effluents, and the quantity of I-131 released by the plant in gaseous effluents. Table 11.5 presents this comparison.
11.2 SYSTEM DESCRIPTION AND EVALUATION 11.2.1 liquid Waste Processing System The liquid waste processing system at Waterford 3 consists of process equipment and instrumentation necessary to collect, process, monitor, and recycle and/or dispose of radioactive liquid wastes. The liquid waste processing system is designed to collect and process wastes based on the origin of the waste in the plant and the expected levels of radioactivity. All liquid waste except steam generator blowdown is processed on a batch basis to permit optimum control of releases. Before liquid waste is released, samples are analyzed to determine the types and amounts of radioactivity present. Based on the results of the anslysis, the waste is recycled for eventual reuse in the plant, retained for further processing, or released to the environment under controlled conditions.
A radiation monitor in the discharge line will automatically terminate liquid waste discharges if radiation measurements exceed a predetermined ievei. The liquid waste processing system consists of the boron managment system, the liquid waste management system, and the steam generator blowdown system. In addition, the chemical and volume control system (CVCS) processes letdown from the primary system to control boron concentration and maintain reactor water purity. In NRC's evaluation model, the staff assumed that a portion of the chemical and volume control system flow will be released through the coolant radwaste system for tritium control.
11-2
 
T a ble 11.1 Principal parameters and conditions used in c alculating releases of r adioactive materia l in liquid and g aseous effluents from Waterford 3 Reactor power level (MWt)                                          3560 Pla nt capacity factor                                              0.80 F a iled fuel                                                      0.12%a Primary system Mass of coolant (lb)                                          4.6 X 10 5 Letdown rate (gal/min)                                        40 Shim bleed rate (gal/day)                                      1.87 X 103 Leakage to secondary system (lb/day)                          100 Leakage to containment building (lb/day)                      b Leakage to auxiliary building (lb/day)                        160 Frequency of degassing for cold shutdowns (times/yr)          2 Letdown cation demineralizer flow (gal/min)                    8 Secondary system Steam flow rate (lb/hr)                                        1.5    X    10 7 Mass of liquid/steam generator (lb)                            1.6    X    10 5 Mass of steam/steam generator (lb)                            1.3    X    104 Secondary coolant mass (lb)                                    2.8    X    10 6 Rate of steam leakage to turbine area (lb/hr)                  1.7 X      103 Containment build                                                  2.7 X      106 of con                                                24 on a, nment ow                                n)                  0 Cont      ent atmo                              m1 n)              10,000 Pre-      e c eanu                                                  16 Iodine partition factors (as/liquid)
Leakage to auxiliary building                                  0.0075 Leakage to turbine area                                        1.0 Main condenser/air ejector (volatile species)                  0.15 Liquid radwaste system decontamination factors Boron management    Liquid waste        Steam generator Materia l        system              management system    blowdown e\le+o.m J;;> V'-111 Iodine          1 X 10 4            1 X  1Q4            1 X 102 Cesium,          2 X 104              1 X  10 5            1 X 101 rubidium Other            1 X 10 5            1 X  10 5            1 X 102 aThis v a lue is const ant and corresponds to 0.12% of the operating power product source term as given in NUREG-0017 (April 1976).
bl%/d ay of the prim ary coolant noble gas inventory and 0.001%/d a y of the primary coolant iodine inventory.
11-3
 
Table 11.1 (continued)
All nuclides System                                        except iodine    Iodine Liquid waste management system, waste concentrator decontamination factor          104              103 Boron management system, boric acid con centrator package decontamination factor      103              102 Cesium,    Other System                                              Anions  rubidium    nuclides Boron preconcentrator ion exchanger                  10      2          10 Primary coolant letdown demineralizer, decontamination factor (Li 3 B03 )                  10      2          10 Boric acid condensate ion echnger and waste condensate ion exchanger (HOH)                      10      10          10 Steam generator blowdown demineralizer              102      10          102 Containment building internal recirculation system, charcoal filter decontamination factor (iodine removal)                                                          10 Reactor auxiliary building ventilation system, charcoal adsorber decontamination factor (iodine removal)                                                          10 Containment building internal recirculation system, HEPA filter decontamination factor (particulate removal)                                                    100 Reactor auxiliary building ventilation system, HEPA filter decontamination factor (particulate removal)                                                    100 11-4
 
Table 11.1 (continued)
Liguid Waste Inputs Collection Decay Flow rate  Fraction    Fraction    time      time Stream              (gal/day)  of PCA      discharged  (days)    (days)
Shimbleed rate      1870      1.000      0.120        36.200    2.660 Equipment drains      250      0.820      0.120        36.200    2.660 Dirty wastes        1380      0.075      1. 000        2.030    0.100 Slowdown            86900                  0.0          0.000    0.000 Gaseous Waste Inputs There is not continuous stripping of full letdown flow Holdup time for xenon (days)                                60 Holdup time for krypton (days)                              60 Fill time of decay tanks (days)                            60 11*5
 
Tab le 11.2 Calculated annual releases of radioactive materials in liquid effluents from Waterford 3 Nuclide                                      Nuclide Corrosion & Activation                      Fission Products (Continued)
Products Cr-51                          7.0(-5)      Te-129                      3.0(-5)
Mn-54                          1.0(-3)      I-130                        2.1(-4)
Fe-55                          6.0(-5)      Te-131m                      5.0(-5)
Fe-59                          4.0(-5)      I-131                        9.2(-2)
Co-58                          4.6(-3)      Te-132                      7.2(-4)
Co-60                          8.8(-3)      I-132                        4.2(-3)
Zr-95                          1. 4(-3)    I-133                        5.8(-2)
N b-95                          2.0(-3)      I-134                        2.0(-5)
Np-239                          3.0(-5)      Cs-134                      1. 5(-2)
Fission Products                            I-135                        9.6(-3)
Br-83                          4.0(-5)      Cs-136                      7.0(-2)
Sr-89                          1.0(-5)      Cs-137                      2.6(-2)
Mo-99                          2.4(-3)      Ba-137m                      1.5(-3)
Tc-99m                          2.8(-3)      Ce-144                      5.2(-3)
Ru-103                          1.4(-4)      All othersb                  6.0(-5)
Ru-106                          2.4(-3)
Ag-106m                        4.4(-4)        Total (except tritium)    2.4(-1)
Te-127                          2.0(-5)        Tritium release          480 Te-129m                        5.0(-5) a= exponential notation; 1.0(-4) = 1.0 x 10-4 b = nuclides whose release rates are less than 10- 5 Ci/yr are not listed individually but are included in the category 11 All others. 11 11-6
 
Table 11.3 Calculated annual releases of radioactive materials in gaseous effluents from Waterford 3 Release {Ci/yr)
Plant stack,  Plant stack,    Turb ine building Nuclides    continuous    intermittent    exhaust, continuous Kr-83m      a              a              a Kr-85m      5              2              a Kr-85      450            170            a Kr-87      2              a              a Kr-88      8              2              a Kr-89      a              a              a Xe-13lm    5              66              a Xe-133m    10            45              a Xe-133      830            7200            a Xe-135m    a              a              a Xe-135      15            12              a Xe-137      a              a              a Xe-138      1              a              a I-131      4.0(-2) b      1.4(-2)        5.4(-2)
I-133      4.9(-2)        4.8(-3)        6.5(-2)
Mn-54      4.7(-3)        4.0(-6)        C Fe-59      1.6(-3)        1.4(-6)        C Co-58      1.5(-2)        1.4(-5)        C Co-60      7.3(-3)        6.2(-6)        C Sr-89      3.4(-4)        3.1(-7)        C Sr-90      6.2(-5)        5.5(-8)        C Cs-134      4.7(-3)        4.0(-6)        C Cs-137      7.8(-3)        6.9(-6)        C C-14        7              1              a Ar-41      a              25              a H-3        940            a              a a = less than 1.0 Ci/yr for noble gases and carb on-14; less than 10-4 Ci/yr for iodine.
b = exponential notation; 1.0(*4) = 1.0 X 10* 4*
c = less than 1.% of total for this nuclide.
11-7
 
Table 11.4  Calculated annual dose commitments to  a  maximally exposed individual near Waterford 3 Location                Pathway                          Doses (mrem/yr/unit)
Noble gases in gaseous effluents Gamma air    Beta air dose (mrad/  dose (mrad/
Total body  Skin      yr/unit)      yr/unit)
Nearest site a land boundary          Direct radiation (0.6 mi ESE)            from plume        0.64        1.9        1.1          3.3 Iodine and particulates in gaseous effluents (Other organ if greater Total body  Thyroid    than 10% of dose)
Nearest b residenee, milk
* Ground deposit  0.05        0.05 cow (infant)
* Inhalation      0.04        0.2 (0. 9 miles NW)
* Milk (to a receptor)        0.22        11. 4 Liquid effluents (Other organ if greater Total body  Thyroid    than 10% of dose)
Nearest drinking water at St.
Charles Parish          Water ingestion    <0.01        0.03 Nearest fish at discharge              Fish ingestion    0.08        0.03      0.11 (liver)
(Include other pathway if greater than 10% of the dose) a 11 Nearest 11 refers to that site boundary location where the highest radiation doses from gaseous effluents has been estimated to occur.
b 11 Nearest11 refers to the location where the highest radiation dose to an individual from all applicable pathways has been estimated.
11-8
 
T able 11.5 Comparison of calculated dose commitments to a maximally exposed individual from effluents from Waterford 3 to design objec tives of the Annex to Appendix I RM-50-2                    C alcuJ ated Effluents                                  design objec tives a      doses Annual dose per site Liquid effluents Dose to tota l body or any organ        5 mrem/yr                  0.1 mrem/yr from all p athways Non-tritium releases                    5 Ci/unit                  0.24 Ci/unit Noble gas effluents ( at site boundary)
Gamma dose in air                        10 mrad/yr                1.1  mrad/yr Bet a dose in air                        20 mr ad/yr                3.3  mr ad/yr Dose to total body of an individual      5 mrem/yr                  0.7  mrem/yr Dose to skin of an individual            15 mrem/yr                1.9  mrem/yr Radioiodine and particulates c Dose to a ny organ from all pathways    15 mrem/yr                12 mrem/yr I-131 releases                          1 Ci/unit                  0.11 Ci/unit aGuides on Design Objectives proposed by the NRC staff on February 20, 1974; considers doses to individuals from all units on site. From "Concluding Statement of Position of the Regulatory Staff, 11 Docket No. RM-50-2, Feb. 20, 1974, pp. 25-30, U.S. Atomic Energy Commission, Washington, O.C., also published as Annex to Appendix I to 10 CFR Part 50.
boesign Objectives from Sections II.A, II.B, II.C and II.0 of Appendix I, 10 CFR Part 50, considers doses to m aximally exposed individuals and popula tion per reactor unit. From Federal Register V. 40, p. 19442, May 5, 1975.
cDose contributions from carbon-14 and tritium h ave been added to the calcu lated doses.
11-9
 
Steam generator b1owdown is flashed to steam in a flash tank, with the liquid being cooled in a heat exchanger before passing through a filter and a deminera lizer and then routed to the main condenser. The flashed steam is routed to the extraction steam line of the No. 4 heater. In the evaluation, the staff assumed that none of the blowdown is discharged to the discharge structure of the circulating water system. Laundry, hot shower, and contaminated shower wastes are collected in the laundry tanks and discharged without treatment to the circulating water system discharge.
11.2.1.1 Chemical and Volume Control System A letdown stream of approximately 40 gal/min of primary coolant is removed from the primary reactor coolant system for processing through the CVCS. The letdown stream is cooled through the letdown heat exchangers, reduced in pressure, filtered, and processed through one of two mixed-bed demineralizers in the Li3 B0 3 form. At the end of core cycle life, this letdown stream is passed through an anion demineralizer to remove boron when the feed and bleed mode of operation is not practicable.
The processed letdown stream is collected in the volume control tank and reused in the primary coolant system. The eves is used to control the primary coolant boron concentration by diverting a portion of the treated letdown stream to the boron management system (BMS) as shim bleed. The staff estimated that the input to the BMS from the eves letdown stream was approximately 1870 gal/day.
Primary coolant-grade water from equipment drains, equipment leakage, and from relief valves inside containment are collected in the containment drain header and the recycle and ion exchange drain headers and are routed to the reactor drain tank and equipment drain tank, respectively. The staff estimated that the input to the reactor and equipment drain tanks was approximately 250 gal/day.
The 1870 gal/day shim bleed and the 250 gal/day input from the reactor and equip ment drain tanks are processed in the BMS.
11.2.1.2 Boron Management The boron management system treats the shim bleed from the eves and the wastes collected in the equipment drain tank and the reactor drain tank. The shim bleed is diverted to the flash tank by the volume control tank diversion valve.
The wastes from the reactor drain tank and the equipment drain tank are pumped to the flash tank. From the flash tank the wastes are pumped to one of the four holdup tanks. When a decision is made to process the wastes in one of the holdup tanks, the wastes are pumped to the preconcentrator ion exchanger for treatment before processing in the boric acid concentration package. The distillate from the boric acid concentrator package is polished by the boric acid condensate ion exchanger and collected in one of four boric acid condensate tanks. The bottoms of the boric acid concentrator are collected in the waste concentrate storage tank and then pumped to the solid waste management system for solidification. The wastes collected in the boric acid condensate tanks can be recycled to the primary system, discharged to the primary water storage tank, recycled for additional treatment by discharge back to the holdup tanks, or discharged to the environment via the circulating water system.
11-10
 
In the evaluation, the staff assumed that 12% of the treated wastes were discharged to the circulating water system and that 88% of the treated wastes were recycled to the primary system.
11.2.1.3 Waste Management System The waste management system (WMS) collects miscellaneous nondetergent wastes and processes this waste. In addition, it collects, in two laundry tanks, detergent waste from the laundry, laundry sump, contaminated showers, and contaminated sinks. Normally the wastes in the laundry tanks will be sampled and the contents analyzed to assure releases are within 10 CFR Part 20 limits.
Following this confirmation, the contents of the tank will be discharged through a filter directly to the circulating water discharge.
The miscellaneous nondetergent wastes will be collected in two waste tanks.
The source of these wastes are the waste drain header and containment sump pumps, safeguards room sump pumps, and miscellaneous radioactive sumps. The sources to the waste drain header include miscellaneous valve leakoffs, miscellaneous equipment drains, etc.
As wastes are collected in the two waste tanks, they are processed on a batch basis. The wastes are pumped through an oil separator filter prior to processing in the waste concentrator package. The distillate from the waste concentrator package is polished in the waste condensate ion exchanger and collected in the two waste condensate tanks. The bottoms from the waste concentrator package are sent to the waste concentrate storage tank for eventual solidification in the solid WMS. The wastes collected in the two waste condensate tanks are discharged to the circulating water system.
NRC evaluation assumed that 1375 gal/day of wastes were collected from the waste drain header and the various radioactive sumps and treated in the liquid WMS.
The staff evaluation assumed that 100% of the treated wastes were released to the circulating water discharge.
11.2.1.4 Steam Generator Slowdown System Slowdown from the two steam generators flows to the blowdown tank. From the blowdown tank it is pumped through a blowdown heat exchanger prior to under going filtration in the blowdown filter package and demineralization in the blowdown demineralizer package. The blowdown leaves the demineralizer package and is returned to the condenser, The blowdown demineralizers are mixed bed demineralizers which are regenerated. The regenerant solution is collected in the regenerant waste tank. If a primary to secondary leak exists, the regenerant solution can be pumped to the waste tanks for treatment in the WMS. The blowdown filters will be flushed and the flush solution will be collected in the filter flush tank. If a primary to secondary leak is present, the flush solution can be sent to the dewatering tank of the solid WMS for eventual solidification.
If no primary to secondary leaks exist or the leak is small, then the regenerative solution and the filter flush will be discharged to the metals waste pond of Waterford 1 and 2 as long as the concentrations discharged to the pond remain within 10 CFR Part 20 limits and within the design objectives of Appendix I of 10 CFR Part 50.
11-11
 
In the NRC evaluation, the staff assumed a blowdown rate of 31.7 gal/min per steam generator and that none of the blowdown was discharged to the environ ment. It was also assumed that approximately 50 gal/day of regenerant solution would result from regenerating the steam generator blowdown demineralizers and that this solution would be sent to the waste tanks of the liquid WMS for treatment before eventual discharge. The staff assumed that all regenerant solutions were discharged.
11.2.1.5 Industrial Waste System The industrial waste system consists of floor drains, equipment drains, and curbed area drains that collect the turbine building operational waste liquids.
It is intended that these wastes will be drained to one of two industrial waste sumps. It is also intended that the contents of the industrial waste sumps will be discharged through a radiation monitor to an oil separator. The wastes are then pumped by the oil separator pumps to the circulating water system discharge. If the radiation monitor detects a high radiation level, automatic valves are activated that close the discharge path to the oil separator and direct the effluent to the waste tanks of the WMS for treatment.
The NRC evaluation assumed that 7200 gal/day was collected in the turbine drains and discharged to the circulating waste system without treatment.
11.2.1.6 Conformance With NRC Regulations and Staff Positions The liquid radioactive waste treatment system is located in the reactor auxiliary building which is designed to seismic Category I criteria. The proposed seismic design and quality Qroup classification and capacities of principal components considered in the 11quid radwaste system evaluation are listed in Table 11.6.
We find the applicant's proposed liquid radioactive waste treatment system design meets the guidance of Regulatory Guide 1.143, "Design Guidance for Radioactive Waste Management Systems, Structures and Components, Installed in Light-Water Cooled Nuclear Power Plants.11 The system design also includes measures intended to control the release of radioactive materials that result from potential over flows from indoor and outdoor storage tanks. Tank levels are monitored either locally or in the control room and high level alarms will be activated should preset levels be exceeded. Overflow provisions such as sumps, dikes, and overflow lines permit the collection and subsequent processing of tank overflow.
The staff concludes that these provisions can control the release of radioactive materials to the environment.
NRC has determined that during normal operation, the proposed liquid radioactive waste treatment system is capable of reducing the release of radioactive materials in liquid effluents to less than 1 Ci/yr, excluding tritium and dissolved gases, and to 480 Ci/yr of tritium. The calculated annual releases of radionuclides in liquid effluents are given in Table 11.2.
NRC has determined that during normal operation, including anticipated opera tional occurrences, the liquid radioactive waste treatment system is capable of reducing the release of radioactive materials in liquid effluents such that the annual dose commitment to the total body or to any organ of an individual is less than 3 millirem and 10 millirem, respectively, in conformance with Section II.A of Appendix I.
11-12
 
Table 11.6 Design parameters of principal components considered in the evaluation of liquid and gaseous radioactive waste treatment systems of Waterford 3 Capacity    Seismic Quality Component                                Number  (each)      category group Liquid Boron management system Reactor drain tank                    1        1600 gal              D Reactor drain tank pump                1        50 gal/min  I        C Equipment drain tank                  1        4000 gal              D Equipment drain tank pump              1        50 gal/min  I        C Flash tank                            1        400 gal      I        C Flash tank pump                        2        150 gal/min  I        C Holdup tank                            4        47,960 gal  I        C Holdup drain pump                      2        50 gal/min  -        D Preconcentrator ion exchanger          2        100 ga 1/min -        D Boric acid concentrator package        2        20 gal/min  -        D Boric acid condensate ion exchanger    2        50 gal/min  -
Boric acid condensate tank            4        17,200 gal  -        D D
Boric acid condensate pump            2        50 gal/min            D Waste management system Waste tank                            2        3600 gal    -        D Waste pump                            2        50 gal/min Waste concentrator package            1        20 gal/min  -        D D
Waste condensate ion exchanger        1        50 al/min            D Waste condensate tank                  2        15, 500 gal Waste condensate pump                  2        50 gal/min  -        D D
Steam generator blowdown system Blowdown tank                          1        3760 gal    -        D Slowdown pump                          2        250 gal/min  -        D Blowdown demineralizer                2        700 gal/min  -        D Regenerant waste tank                  1        20,000 gal  -        D Regenerant waste tank pump            1        200 gal/min  -        D Filter flush tank                      1        5000 oal              D Filter flush tank pump                1        100 gal/min  -        D Gaseous Gaseous waste management system Gas surge tank                        1        20 ft 3      I.      C Waste gas compressor                  2        2 scfm*      I        C Gas decay tanks                        3        600 ft 3    I        C
*Standard cubic feet per minute.
11-13
 
NRC has also calculated the release of radioactive materials in liquid effluents, exclusive of tritium and noble gases, and found it to be less than 5 Ci/yr and the total body and any organ dose less than 5 millirem per year from the site in accordance with the option to Section II.D of Appendix I as provided in the Annex to Appendix I. The staff concludes that the liquid radwaste treatment system is capable  of reducing liquid radioactive effluents to 11 as low as reason ably achievable u levels in accordance with 10 CFR Section 50.34a of Appendix I to 10 CFR Part 50, and the Annex to Appendix I.
It has also been determined that the liquid radwaste treatment system is capable of reducing the release of radioactive materials in liquid effluents to concen trations below the limits in 10 CFR Part 20, during periods of fission product leakage from the fuel at design levels. Based upon these findings the staff concludes that the design of the liquid radioactive waste treatment system is acceptable.
11.2.2 Gaseous Waste Processing Systems The gaseous waste processing systems consist of the gaseous waste management system (GWMS), the vent gas collection header (VGCH), the building ventilation systems, the main condenser evacuation system (MCES), the atmospheric dump valves, and the turbine gland sealing system (TGSS). These systems are designed to collect, store, process, monitor, recycle, and/or discharge potentially radio active gaseous wastes which are generated during normal operation of the plant.
The systems consist of equipment and instrumentation necessary to reduce releases of radioactive gases and particulates to the environment. The principal sources of gaseous waste are the effluents from the gaseous waste processing system, condenser vacuum pumps, and ventilation exhausts from the reactor auxiliary building, reactor containment, and turbine area.
The GWMS collects, in the gas surge tank, the hydrogenated fission product gases from the flash tank, the volume contro1 tank, and the reactor drain tank. These gases are then compressed into three gas decay tanks. Releases from the gas decay tanks are mixed with air from the reactor auxiliary ventilation system before release to the environment via the plant stack. Ventilation exhaust air from the containment is also released via the plant stack. If the radio active concentration in containment air exceeds a predetermined concentration, the air will be circulated through an internal cleanup system consisting of HEPA filters and charcoal adsorbers before release to the environment. Ventila tion air from the fuel building is released, without treatment. The turbine area releases are made directly to the atmosphere. Exhausts from the MCES and TGSS are processed through the HEPA filters and charcoal adsorbers of the plant stack when the release rate of I-131 from the MCES reaches 2.0 x 10-4 &#xb5;Ci/sec.
Otherwise, they are released to the atmosphere untreated through the discharge silencer.
11.2.2.1 Gaseous Waste Management System The GWMS co11ects, in the gas surge tank, the gases from the containment vent header and the gas surge header. The sources of the gases to the gas surge header are the flash tank, the volume control tank > and the refueling failed 11-14
 
fuel detector vent. The collected gases remain in the gas surge tank until the pressure builds to a point which actuates one of the two waste gas compres sors. At that time the waste gas compressor feeds a preselected gas decay tank until the pressure in the gas surge tank drops below a preset level at which point the waste gas compressor stops. When the gas decay tank approaches its upper operating pressure, another gas decay tank is lined up to receive the waste gas compressor's discharge. The filled tank is then isolated for decay.
If the pressure in the surge tank builds because of a surge of inputs, then the second compressor will start. The three gas decay tanks, which have a volume of 600 ft3 and were designed for a pressure of 380 psig, were assumed, in the staff evaluation, to have a decay time of 60 days and a fill time of 60 days.
The gases were assumed to be released via the plant stack without further treatment.
The WMS is designed to prevent or preclude an explosive mixture but is not designed to withstand an explosion. A sequential gas analyzer package is provided to monitor H2 and 0 2 concentrations in various plant components where explosive mixtures could develop. The gas analyzer is capable of analyzing a single source for as long as required by manually overriding the sequence selector.
The sequential analyzer monitors the containment vent header, the gas surge tank and each of the gas decay tanks. Other tanks which are not part of the gaseous WMS are also monitored. The applicant has also made a commitment to install either an H 2 or an 02 monitor between the waste gas compressor and the gas decay tanks.
11.2.2.2 Vent Gas Collection Header The VGCH collects gases primarily from aerated vents of process equipment in the WMS, BMS, eves, and fuel pool system. The principal sources are the holdup tanks, the waste tanks, and the waste condensate and boric acid condensate tanks.
Since these gases are low in activity, they are routed directly to the plant stack. However, the vent pipe from the source does contain a radiation monitor that will alarm on high activity.
Staff evaluation assumed that the fission product discharges from the VGCH are less than 1% of the releases from the GWMS.
11.2.2.3 Containment Ventilation System Radioactive gases are released inside the containment when primary system compo nents are opened.or when primary system leakage occurs. In the NRC evaluation the staff assumed that the containment is purged 24 times a year. Before purging, the containment atmosphere is recirculated through HEPA filters and charcoal adsorbers. The staff assumed that radionuclide removal during the recirculation phase was based on a flowrate of 10,000 ft3 /min, a mixing efficiency of 70%, a particulate decontamination factor of 100 for HEPA filters, and an iodine decon tamination factor of 10 for charcoa1 adsorbers. The purge exhaust gases are released to the plant stack where they will undergo additional filtration in a HEPA filter and charcoal adsorber. NRC assumed additional decontamination factors of 100 and 10 for particulates and radioiodines, respectively, because of the HEPA filters and charcoal adsorbers in the stack.
11-15
 
11.2.2.4 Ventilation Releases From Other Buildings Radioactive materials are introduced into the plant atmosphere as a result of leakage from equipment containing radioactive materials. The staff estimated that 160 lb/day of primary coolant will leak to the reactor auxiliary building with an iodine partition factor of 0.0075. Small quantities of radionuclides are released to the turbine building atmosphere based on an estimated 1700 lb/hr of steam leakage. The plant ventilation systems are designed to induce air flows from potentially less radioactively contaminated areas to areas having a greater potential for radioactive contamination. NRC calculations assumed that effluents from the fuel handling buildings and from the turbine building are released directly to the environment without treatment. Effluents from the reactor auxiliary building are released to the plant stack, and thus particulates and radioiodines are removed by the HEPA and charcoal adsorber, respectively.
11.2.2.5 Main Condenser Evacuation System Offgas from the main condenser air ejectors contains radioactive gases as a result of primary-to-secondary coolant system leakage. In its evaluation, the staff assumed a primary-to-secondary leak rate of 100 lb/day. Noble gases and iodine are contained in the steam generator leakage and are released to the environment through the MCES in accordance with the partition factors listed in Table 11.1. The exhaust from the MCES is released to the environment through HEPA filters and charcoal adsorbers of the plant stack when the release rate of I-131 reaches 2.0 x 10-3 uCi/sec. When the release rate is lower than this, the release will be from the discharge silencer. Our evaluation assumed that all of the exhaust from the MCES was released from the plant stack.
11.2.2.6 Turbine Gland Sealing System The TGSS provides sealing of the turbine-generator shaft and main feedwater pump turbine shafts against leakage of air into the turbine casings and escape of steam into the turbine building. As a part of this system, the gland seal condenser returns seal leakage to the main condenser as condensate. Nonconden sible gases from the gland seal condenser are discharged to the discharge silencer. If the release rate of I-131 reaches 2 x 10-4 mci/sec at the discharge silencer, the release is routed to the plant stack for filtration and adsorption. The staff assumed that releases from the TGSS were negligible.
11.2.2. 7 Atmospheric Steam Dump Valves Steam release from valve operation was considered to be negiigib1e in the unt' 1, I\\,,
evaluation.
11.2.2.8 Conformance With NRC Regulations and Staff Positions The proposed seismic design and quality group classification and capacities of the principal equipment in the gaseous radioactive waste processing system are listed in Table 11.6. The gaseous radioactive waste processing system of Water ford 3 is in conformance with Regulatory Guide 1.143. The gaseous radioactive waste processing system is located in the reactor auxiliary building which is a seismic Category I structure. The staff has compared the design, testing, 11-16
 
and maintenance of HEPA filters and charcoal adsorbers installed in normal ventilation exhaust systems with the guidelines of Regulatory Guide 1.140 (October 1979), and concludes that they are acceptable.
The staff has expressed concern as to the capability of the applicant to leak test the RABventilation system in accordance with Regulatory Guide 1.140.
The staff's concern was whether sufficient DOP could be generated in this high flow rate system (156,000 cfm) such that the detector would be able to detect DOP downstream of the HEPA filters. Regulatory Guide 1.140 recommends a limit of 30,000 cfm per filter train. The applicant has provided data from one vendor which indicates that sufficient DOP can be generated for such a high volume system. The applicant has also committed to test the RABventilation system in accordance with ANSI N510-1980. The staff finds this commitment acceptable.
NRC has determined that the proposed gaseous radwaste treatment and plant venti lation systems are capable of reducing the release of radioactive materials in gaseous effluents to approximately 9000 Ci/yr of noble gases, 0.10 Ci/yr of iodine-131, 1000 Ci/yr of tritium, and 0.05 Ci/yr of particulates.
The calculated annual release of radionuclides in gaseous effluents is given in Table 11.3. Using the source terms given in Table 11.3, the staff has deter mined that the annual air dose per reactor in an unrestricted area is less than 10 mrad for gamma radiation and 20 mrad for beta radiation. The annual individual external doses per reactor from gaseous effluents in an unrestricted area is less than 5 mrem (total body) and 15 mrem (skin). The annual dose in an unrestricted area from all pathways from release of radioiodines and radioactive material in particulate form is less than 15 mrem to any organ. The calculated annual doses are given in Table 11.4 and these meet the requirements of Sec-tions II.Band II.C of Appendix I to 10 CFR Part 50.
The staff has compared the calculated doses to the maximally exposed individual and curies of I-131 expected to be released to the design objectives of the Annex to Appendix I and has concluded that the proposed gaseous radwaste system meets the requirements of the option paragraph D of Section II of Appendix I to 10 CFR Part 50. Table 11.5 presents this comparison.
The gaseous waste treatment and ventilation systems are capable of reducing releases of radioactive materials in gaseous effluents to ALARA levels in accordance with 10 CFR Section 50.34a, Appendix I to 10 CFR Part 50 and the Annex to Appendix I. The proposed gaseous radwaste treatment system and plant ventilation systems are capable of reducing the release of radioactive materials in gaseous effluent to concentrations below the limits of 10 CFR Part 20 during periods of fission product leakage from the fuel at design levels.
11.2.3 Solid Radioactive Waste Treatment System The solid radioactive waste system is designed to process two general types of solid wastes: 11 wet 11 solid wastes, which require solidification prior to shipment; and ndry 11 solid wastes, which require packaging and, in some cases, compaction prior to shipment to a licensed burial facility. Wet solid wastes consist mainly of spent filter cartridges, demineralizer resins, and evaporator bottoms which contain radioactive materials removed from liquid streams during processing.
Wet solid wastes are combined with portland cement and sodium silicate in 11-17
 
containers (50-cubic-feet containers and 55-gal drums) to form a solid matrix.
The containers are subsequently sealed and placed in a shield, as required, for offsite shipment.
Dry solid wastes, consisting mainly of ventilation air filtering medium (charcoal),
contaminated clothing, paper, rags, laboratory glassware, and tools, are compacted in 55-gal drums.
11.2.3.1 Wet Solid Wastes The sources of wet solid wastes will be spent resins, evaporator bottoms, and filter cartridges. The spent resins will come from the ion exchangers in the eves, BMS, WMS, and fuel pool system which are sluiced to the spent resin tank.
The evaporator bottoms come from the waste concentrator package and the boric acid concentrator package, which send their bottoms to the waste concentrate storage tank. The filter cartridges are collected from the purification filter of the eves and fuel pool systems, from the boric acid preconcentrator filters, from the oil separator and waste filters of the WMS, and from the laundry filter.
Spent resin is collected in the spent resin tank. From the spent resin tank, the resin is sent to the dewatering tank where the resin is conditioned for the desired moisture content for processing. The resin is pumped by positive displacement pumps to the process mixing pump where the resins are mixed with portland cement. Downstream of the process pump mixer, sodium silicate is added. The mixed stream of resin, cement, and sodium silicate flows into the container through the fill port.
Evaporator bottoms are treated in an identical manner to the spent resins except that the bottoms are not sent to the dewatering tank but are transferred directly from the waste concentrate storage tank to the process mixing pump. The treat ment of the bottom is identical after that step of the process. The solid waste system is also capable of mixing resin and evaporator bottom wastes to form a mixture in the container.
The filter cartridges are initially lifted into the filter transfer cask. The transfer cask is then moved to the drumming station by the filter transfer vehicle. At the drumming station the filter transfer cask is lifted and the filter cartridge dropped into a liner for solidification.
On the basis of NRC evaluation and recent data from operating plants, the staff has determined that approximately 13,000 ft 3 /yr of solidified wet waste would be expected containing an activity of approximately 1000 Ci. The principal radionuclides in the solid wastes will be long-lived fission and corrosion products, mainly Cs-134, Cs-137, eo-58, and Co-60.
11.2.3.2 Dry Solid Wastes A hydraulic press is used to compact low activity solid waste such as contami nated clothing, rags, paper, laboratory equipment, and supply items. This waste is placed in a 55-gal drum and compressed by a vertical moving piston. The hydraulic press contains its own hood, ventilation fans, and HEPA filter. The displaced air is vented through the HEPA filter to the ventilation ducts.
11-18
 
The staff estimated that 10,000 ft 3 /yr of dry waste would be generated with an activity of 5 Ci.
11.2.3.3 Conformance With Federal Regulations and NRC Staff Positions The solid radwaste system is housed in the reactor auxiliary building and con forms to the design, construction, and testing criteria of Regulatory Guide 1.143.
The reactor auxiliary building is designed to seismic Category I criteria. In addition, the solid radwaste system will incorporate a process control program.
The process control program will be submitted when the radiological effluent technical specifications are proposed. The packaging and shipping of all wastes will be in accordance with the applicable requirements of 10 CFR Parts 20 and 71, and 49 CFR Parts 170 through 178.
The solid waste system design will be capable of processing the wastes expected during normal operations, including anticipated operational occurrences. However, our evaluation of the solid radwaste system has resulted in three areas of concern. They are:
(1) the space allocated for the compaction operation, storage of uncompacted and compacted trash is inadequate; (2) during a refueling outage, bags of trash will accumulate in the area of the compaction equipment, thus resulting in a potential radiation area or in airborne contamination which would be unnecessary if adequate space was allocated for the compaction operation; (3) storage space for liners and drums containing solidified waste is at most marginly adequate; and It is the staff position that sufficient space should be allocated for the storage of uncompacted and compacted trash and for the compaction operation.
The space allocated for solidified waste is marginally acceptable. In the event of temporary burial site restrictions or scheduling delays for truck transport of the waste, the storage sapce would be inadequate. The applicant has made a commitment to move the trash compactor to another location and to increase the space available for storage of solidified and compacted waste. The staff finds this satisfactory. With this commitment the staff finds the solid waste management system acceptable.
11.3 Process and Effluent Radioloaica1 Monitors The process and effluent radiological monitoring systems are designed to provide information concerning radioactivity leve1s in systems throughout the plant, indicate radioactive leakage between systems, monitor equipment performance, and monitor and control radioactivity levels in plant discharges to the environs.
Table 11. 7 provides the proposed locations of continuous monitors, the type of detector, and the range. Monitors on certain effluent release lines will auto matically terminate discharges should radiation levels exceed a predetermined value. Systems which are not amenable to continuous monitoring, or for which detailed isotopic analyses are required, are periodically sampled and analyzed in the plant laboratory.
11-19
 
Table 11.7 Process and effluent monitors Monitor                              Type of detector                Range (&#xb5;Ci/cm3)
Gaseous 10 10 3
                                                                                +
Gaseous waste management system        scintillation Fuel handling building exhausts A&B    scintillation  (gases)        8x10 8xl0- 3 scintillation  (particulate)  10 3x10- 6 scintillation  (radioiodines) l.Sxl0 l.Sxl0- 6 Plant stack                            scintillation  (gases)        8x10 8x10- 3 scintillation  (particulate)  10 3xl0- 6 scinti11ation  (radioiodines) l.5xl0 1.5xl0 - 6 Condenser vacuum pumps                scintillation  (gases)        10 10- 1 Liauids Component cooling water monitor A/B  y scintillation                10                                                                                10-2 Component cooling water monitors      y scintillation                10- 7  -
10-2 Stearn generator blowdown monitor    y scintillation                10-6  1 +
Process radiation monitor (CVCS)      y scinti11ation                10- 4  -
2xl0 2 Liquid waste management              y scintillation                10-6  1 Boron management                      y scinti11ation                10-6  1 Dry cooling tower sumps 1&2          y scinti11ation                10 10- 2 10- 6    10-1 Reactor building sump                y scinti11ation Industrial waste sumps - Turbine      y scintillation                10-6  1 Building Steam Generator Slowdown Heat        y scinti 11ation                10- 7  -
10-2 Exchanger Cooling Water 11-20
 
The staff has reviewed the locations and types of effluent and process monitors provided. Based on the plant design and on continuous monitoring locations and intermittent sampling locations, the staff has reached the following conclusions with regard to normal and potential release pathways:
(1) The containment purge line does not include either an in-line process monitor or an automatic control feature which would terminate the release upon a high radiation signal. It is our position that an in-line monitor is required for the containment purge line and that isolation of the contain ment purge on a high radiation signal from either the process monitor or the stack monitor be an automatic control feature and not dependent upon operator action.
(2) The applicant has indicated that upon a high radiation signal from the normal exhaust monitor of the fuel handling building the plant operator will be alerted to the fact that additional radiation surveys and sampling are required to determine the source of the radioactive leakage. It is our position that, upon a high radiation signal from the normal fuel handling building exhaust monitor, the normal fuel handling building exhaust should be automatically isolated and release routed through the fuel handling building ESF filter system.
(3) The spent fuel treatment system does not contain any process monitors which alert the plant operator of the buildup of activity in the spent fuel pool.
It is our position that such a monitor is required.
(4) The applicant has indicated that the contents of the regenerative waste tank are pumped to the regenerative waste transfer sump. From there    the wastes are pumped to the waste collection basin #2 (Unit 1 and 2 1 s metals waste pond). There is no radioactivity monitor on this line. It is our position that since this is an unmonitored release point a radiation monitor will be required to be installed.
The staff has determined that the monitoring provisions for the remaining systems are adequate for detecting radioactive material leakage to normally uncontami nated systems and for monitoring plant processes which affect radioactivity releases. On this basis the staff finds that the monitoring provisions presented by the applicant when coupled with the additional monitoring requirements the staff has imposed will meet the requirements of Criteria 60, 63, and 64 of the General Design Criteria and the guidelines of Regulatory Guide 1.21, 11 Measuring, Evaluatina. and Reoortina Radioactivitv in Solid Wastes and Releases of Radio active Materials in Liquid and GaseousvEffluents from Light-Water-Cooled Nuclear Power Plants. 11 11-21
 
==11.4 REFERENCES==
Code of Federal Regulations:
10  CFR Part 20 10  CFR Part 50, Appendix I 10  CFR Part 50, Appendix I, Annex - USAEC below 10  CFR Part 50, Appendix I, paragraph D 10  CFR Part 50, Appendix I, Sections II.A, II.B, II.C, II.D 10  CFR Part 50.34a 49  CFR Sections 170-178 Federal Register V.40, p. 19442, May 5, 1975 GDC 60 Regulatory Guides:
RG  1.40, October 1979 RG  1.109 RG  1.111 RG  1.143 USAEC, 11 Concluding Statement of Position of the Regulatory Staff,U Docket No. RM-50-2, February 20, 1974, pp. 25-30. Also published as Annex to Appendix I to 10 CFR Part 50.
USNRC Reports:
NUREG-0017 NUREG-75/087
*See Appendix 8, Bibliography, for complete citations and availability statements.
11-22
 
12 RADIATION PROTECTION The staff has reviewed the Waterford 3 proposed radiation protection program as described in Chapter 12 of the FSAR with respect to planning, designing, and operating the station to assure that occupational radiation exposure will be within the limits of 10 CFR Part 20 and will be as low as reasonably achievable (ALARA) in accordance with the guidelines of Regulatory Guides 8.8 and 8.10 or alternatives provided. Toward this end the NRC review covered management's policies and organizational structure for radiation protect1on; facility and equipment design considerations, as well as methods used to develop plans and procedures for ensuring that occupational radiation exposure is ALARA; sources used for input for design of shielding and ventilation of facilities; the area monitoring program and features of the airborne radioactivity monitoring systems, and the health physics program where objectives are to ensure that good radiation protection practices including implementation of many of the above objectives will be followed at the station.
Policy, design, operational considerations, and standard practices relating to maintaining occupational exposures ALARA conform to Commission regulations, appropriate Regulatory Guides, and industry standards.
12.1 ENSURING THAT OCCUPATIONAL RADIATION EXPOSURES ARE AS LOW AS REASONABLY ACHIEVABLE 12.1.1 Policy Consideration The applicant has committed to a policy to maintain occupational exposure ALARA by assuring that Waterford 3 will be designed, constructed, and operated in a manner consistent with Regulatory Guides 8.8 and 8.10. LP&L has identified the specific corporate plan to implement that policy, and specified in detail facility and equipment design considerations to assure its accomplishment.
This objective is reached through administrative exposure control procedures, adequate work planning, and safe practices in all activities related to unit operation. An independent review of radiation protection design and analysis was performed by Ebasco Service Incorporated (Ebasco) who has been retained for radiation protection engineering. The station technical support engineer, who is responsible for maintaining the health physics program, has the specific responsibility and authority for ensuring that the radiation protection program maintains exposures ALARA. The health physics engineer is responsible for ensuring that the ALARA policy is implemented and monitored. He will review exposure records and will compare results from past experience to assess the effectiveness of the ALARA effort. The applicant 1 s commitment to Regulatory Guide 8.10 assures that station management will also review these records and seek to identify exposure areas that indicate high exposure trends and their need for improvement in plant procedures or equipment if they will substantially reduce exposure at a reasonable cost.
12-1
 
12.1.2 Design Considerations The general arrangements and shielding prov1s1ons of Waterford 3 are in accordance with Regulatory Guide 8.8 and are designed to provide to operating personnel levels of exposure that are ALARA. Experience from operating plants has been applied. Additionally, in response to the staff's review questions, the applicant has amended applicable sections of Chapter 12 of the FSAR to demonstrate that design features have been added for assuring that occupational radiation exposures are ALARA. As an example, the applicant details features that have been incorporated into the design to minimize plugging by resins and sludge by virtue of appropriately sizing piping; the applicant is employing low leakage valves and is using valve packing glands that have provisions to adjust packing compression to reduce leakage.
Whenever possible, piping containing radioactive material is either run in shield pipe chases or shielded cubicles to minimize exposure to plant personnel.
High radiation level equipment is located away from traffic ways that personnel use often; labyrinths and/or shielding doors are used to eliminate radiation streaming; penetrations are made with as small as possible diameters and are not in direct line with major radioactive sources; radioactive components are located in separate shielded cubicles to minimize exposure during maintenance and inspection activities; and all components and piping within a single cubicle are flushable with demineralized water. To facilitate draining, round bottomed tanks are used that slope toward the drain for easy flushing of sediment, and valves are located so that operation and maintenance is conveniently performed in low radiation areas by use of extension stems offset from sources of radiation.
Coatings that can be easily decontaminated are used on all floor surfaces in controlled zones. The radiation protection design review is an ongoing review performed throughout all phases of the design; formal reviews are conducted at regular intervals. These reviews are performed by the applicant and Ebasco radiation protection engineers, and consider source calculations, shield thick ness calculations, activation calculations, and mapping of dose rates for a particular layout. These design reviews and criteria conform to the guidelines of Regulatory Guide 8.8 (Revision 3) and are acceptable. Additional radiation protection criteria relevant to design features are discussed in Section 12.3.
12.1.3 Operational Considerations Operational considerations were factored into the design considerations previously described and were derived from experience at operating plants. Procedures pertaining to radiation safety for routine and nonroutine activities are developed and recommended by heaith physics personnel to assure that occupational exposure is kept ALARA. Consequently maintenance, repair, surveillance, and refueling procedures and methods, used by the applicant, are prepared, approved, and imple mented to minimize radiation exposure in accordance with Regulatory Guide 8.8.
Detailed written procedures including checkoff lists and instructions are also prepared and approved to conform to 10 CFR Part 20 or exceed those requirements in minimizing exposures. Some of these procedures include the use of temporary shielding to augment permanent shielding where excessive radiation levels encountered during maintenance could cause an individual to exceed administrative guidelines for exposure; the performance of all operations of solid waste manage ment with remote activated equipment; and the development of time-radiation dose schedules to indicate stay time of individuals in different radiation fields.
12-2
 
The staff concludes that the policy considerations, design considerations and operational considerations related to assuring that occupational radiation exposure will be ALARA conform to the regulations and appropriate Regulatory Guides and are acceptable.
12.1.4 Decommissioning NRC is currently reviewing the question of decommissioning of reactor plants as a generic technical activity (8-34). In addition, Battelle Northwest is now engaged in studies of reactor decommissioning alternatives, including protec tive storage or mothballing, entombment, dismantlement, and combinations of these alternatives. These studies will evaluate safety, environmental aspects, and costs of each decommissioning alternative and have resulted in the publica tion of two documents applicable to LWRs, NUREG/CR-0672, 11 Technology, Safety and Costs of Decommissioning a Reference Boiling Water Reactor Power Station, 11 and NUREG/CR-0130, "Technology, Safety and Costs of Oecommmissioning a Reference Pressurized Water Reactor Power Station. 11 In addition, the NRC Office of Stan dards Development is conducting a study to evaluate the dose commitment for radio active material released to unrestricted use from decommissioning of nuclear reactor facilities. Experience has been gained in the decommmissioning of Elk River, Hallam, Fermi 1, Saxton, Peach Bottom, and numerous smaller test and research reactors. This experience was factored into the Battelle Northwest report. This decommissioning experience will be used as background information in the modification of existing regulations and guides on reactor decommissioning and in the development of any new standards of guides on reactor decommissioning.
For Waterford 3, those design features incorporated by the applicant for maintain ing occupational radiation exposure ALARA during plant operation and maintenance will also serve to maintain radiation exposures ALARA during decommissioning operations.
12.2 RADIATION SOURCES The applicant has provided radiation source terms for full power operation, shutdown conditions, refueling operations, and for various postulated accidents.
These source terms are used as inputs to shield design calculations, personnel protective measures and dose assessments for each plant system according to the amount of activity present and adjacent zoning and access control. Sources include neutron and gamma fluxes outside the reactor vessel, coolant activities, and fission and corrosion products. During power operation, 16 N determines the shielding requirement of the secondary shield wall and portions of the chemical and volume control system. Accident source terms to determine shielding requirements for emergency accessways, control room, and containment shielding are also provided. Source terms used for normal operation and anticipated opera tional occurrences are based on ANSI Standard N237, 11 Radioactive Materials in Principal Fluids Streams of Light-Water Cooled Nuclear Power Plants. 11 Conse quently, all radioactive sources that form the basis of the shield design have been consjdered. Based on typical data from operating plants, sources of the maximum expected airborne concentrations from equipment leakage during reactor operations and at shutdown have been tabulated inside major plant buildings in frequently occupied areas. The assumptions and parameters used in determining these leakage calculations are also provided and found to be appropriate for input to shielding calculations and design objectives for the ventilation systems.
12-3
 
Health physics regimen and plant operating experience will be implemented to ensure that plant personnel will not be exposed to concentrations of airborne radioactive material exceeding those specified in 10 CFR Part 20 and will be maintained at levels that are ALARA. Consequently, the source terms used to develop radiation shielding and estimated airborne radioactivity concentrations are acceptable.
12.3 RADIATION PROTECTION DESIGN FEATURES 12..1 Facility Design Features The applicant has addressed facility and equipment design considerations, plan ning and procedure programs, and techniques and practices employed in the overall design for maintaining doses ALARA. The following areas of the FSAR were reviewed with respect to these features:
(1)  The description of equipment design to be used for assuring that occupa tional exposure will be ALARA.
(2) Information concerning implementation of Regulatory Guide 8.8, Section C.2.
(3) The description of any special protection features that use shielding, geometric arrangement or remote handling to reduce occupational exposure.
(4) Information concerning the implementation of Regulatory Guides 1.21, 1:52, 1.69, and ANSI 13.1.
The applicant describes features including design for filters, demineralizers, heat exchangers, tanks, pumps, and associated piping with respect to shielding.
Penetrations, whenever required, will be appropriately designed to minimize personnel exposure. All field run process piping potentially containing radio active materials are positioned to limit exposure to plant personnel. Where necessary and practicable, interior surfaces of piping and ductwork are designed to minimize contamination buildup.
Analysis for neutron and gamma streaming from the annulus between the reactor pressure vessel and the biological shield indicates high neutron dose rates on the containment operating floor with lower dose rates expected in areas which may require access. The presently designed ring girder support, although it does provide some shadow shielding effects, may not be a completely satisfactory shield. The applicant will make a decision on providing neutron shielding around the annulus if neutron measurements dictate the need for the shield. Anchor plates have been installed to support such a shie1d. By installing these plates at this time, radiation exposure to construction workers installing shielding will be of lesser impact since their occupancy time in the radiation field from neutron activated materials would be reduced. However administrative controis will be used, whether or not a shield is erected, to keep exposure ALARA. As specified in Section 12.1.2, changes to layouts with respect to radiation expo sure, maintenance, operability, and access are reviewed by radiation protection engineers.
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12.3.2 Shielding Radiation shielding at Waterford 3 is designed to ensure that radiation exposure levels are kept ALARA and that the criteria of 10 CFR Part 20 are met. Shields are designed to provide protection against radiation for operating personnel both inside and outside the plant. Plant areas have been classified into radia tion zones based on expected frequency and duration of occupancy. The design of the radiation shielding will consider the dose rate criterion for each zone based on maximum access time requirements in each compartment within the zone.
The health physics staff will update entry requirements in accordance with 10 CFR Section 20.203. Shielding analysis will be made using accepted codes, models, and assumptions. The basic shielding analysis was performed using computer codes accepted by the staff such as ISOSHLD SPAN-4, MORSE-CG. Besides limiting exposure to plant personnel, contractors, visitors, etc., the plant shielding also functions to reduce neutron activation of equipment, piping, supports, etc., and to limit radiation damage to equipment and materials to below the specified integrated life dose limits.
All concrete shielding in the plant is based on the criteria of Regulatory Guide 1.69 which provides the guidance on the fabrication and installation of concrete radiation shields. Consequently, the shielding design and construction is acceptable to the staff.
12.3.3 Ventilation The applicant 1 s ventilation systems are designed to provide ventilation air suitable to ensure that airborne concentrations to which personnel may be exposed meet the requirements of 10 CFR Part 20. In the design of all ventilation systems, the applicant intends to meet this objective and maintain exposures ALARA by (1) directing the airflow from areas of lesser potential contamination to areas of greater potential contamination, (2) providing airborne radiation monitoring, (3) providing back draft dampers and isolating dampers to allow servicing of redundant equipment without discontinuing system operation, (4) allowing adequate space around units for servicing and replacement, (5) providing ease of main taining filters to preclude additional radiation exposure. After initial operation, periodic testing for filters and adsorbers will be performed and frequency of changeout will be determined as a result of these tests.
The design criteria agrees with those given in Regulatory Guide 8.8, and the atmospheric cleanup units conform to Regulatory Guide 1.52 with respect to occupational exposure so that the Waterford 3 ventilation system is acceptable.
12.3.4 Area Radiation Monitoring and Airborne Radioactivity Monitoring Instrumentation The applicant 1 s area radiation monitoring system (RMS) is designed to (1) inform operations personnel of radiation levels in areas where area RMSs are located, (2) provide warning when abnormal levels occur by audible and visual alarms both locally and in the control room and cathode-ray tube (CRT) alarm signal in the health physics office, (3) warn of equipment malfunction, and (4) provide a continuous record of radiation level at key locations throughout the plant.
In the event of accidents inside containment or the fuel handling building, the respective area RMS provides for a containment purge isolation signal and 12-5
 
a signal to isolate the fuel handling building and start emergency ventilation.
There are 33 area RMSs in the plant, all of which contain a remotely operated integral check source and will alarm in the event that abnormally high radiation levels exceed preset dose rate levels or whenever circuit failures occur. The criteria for area RMS locations are based on (a) occupancy factors, (b) potential for exposure to high radiation, (c) potential for equipment failure, (d) storage of new and spent fuel, and (e) normally or potentially radioactive release points.
The design objectives of the airborne radioactivity monitoring system include the following: (1) to inform operations personnel of airborne activity trends and give early warning of abnormal increases in activity levels; (2) to help detect integrity of systems inside the reactor coolant pressure boundary and other areas of the plant; (3) to warn of potential overexposure to airborne radioactivity so that breathing apparatus can be applied as required; (4) to furnish records of gross airborne trends and the amount of radioactive releases to the environment; and (5) for the control room monitor, to provide capability to alarm and initiate isolation of the main control room ventilation system during postulated accidents. The guidance of Regulatory Guide 1.21 has been factored into the design of the airborne radioactivity monitoring system. These objectives are acceptable.
Eleven airborne radioactivity monitoring systems are installed in buildings where potentially radioactive sources exist. Considerations for location of the monitors were based on areas where personnel normally have access and where airborne radioactivity can abruptly increase. Additionally, containment monitors are located to detect unidentified leaks and ventilation duct monitors will alarm when they exceed alarm setpoints. The sensitivity of the air monitors allows detection of less than one maximum permissible concentration in air within most of the cubicles monitored. Source location could then be identified by means of collecting local air samples in specific cubicles being monitored by the duct monitor. Each detector comprising the airborne radioactivity monitoring system is calibrated at the factory using National Bureau of Standards traceable calibration isotopes prepared to simulate the effluent for which the monitor will be used. A recalibration of the detectors will be performed at periodic intervals. The applicant also plans to conduct routine surveys for airborne radioactivity in all normally occupied plant areas with portable continuous air monitors when needed. All installed instruments have independent emergency battery power supplies that are activated whenever a power failure occurs.
Emergency power is also provided for all accident monitoring systems. The appli cant's area radiation and airborne radioactivity monitoring systems satisfy the design objectives of Regulatory Guide 8.8 and are acceptable.
12.4 DOSE ASSESSMENT The applicant has based its estimate of annual man-rem exposure on experience from currently operating reactors and the manner in which its own station has been designed and will be operated. LP&L has performed an assessment of the doses in accordance with Regulatory Guide 8.19. The assessment considers doses that wi11 be received by plant and contractor personnel based on occupancy factors in zones to be occupied, the dose rates in these zones, estimates of occupancy times, and the manpower necessary to perform the various tasks involved in plant operations. The annual collective dose equivalent for Waterford 3 is expected to be on the order of 414 man-rems. Currently operating PWRs average 410 man-12-6
 
rems per unit annually, with particular plants experiencing an average lifetime annual dose as high as 1300 man-rems. These dose averages are based on widely varying yearly doses of PWRs. The basis for the applicant 1 s estimation is asso ciated with detailed dose estimates by specific tasks for the following work functions; reactor operations and surveillance, routine maintenance (normal and refueling operations), and special maintenance (e.g., steam generator main tenance, reactor coolant pump seal inspection and repair), inservice inspection, waste processing, and refueling. The applicant 1 s exposure estimates are consistent with Regulatory Guide 8.19 and the staff 1 s ALARA policy and are, therefore, acceptable.
12.5 HEALTH PHYSICS PROGRAM 12.5.1 Program and Staff Organization The applicant 1 s stated policy for radiation protection is to maintain personnel radiation protection exposures within the provisions of 10 CFR Part 20 and other applicable regulations and technical specifications, and beyond that, to keep them ALARA in accordance with Regulatory Guides 8.8 {Rev. 3) and 8.10 {Rev. 1).
The health physics engineer will implement and enforce the Waterford 3 health physics program. However, the ultimate responsibility of the health physics program lies with the station superintendent. The health physics engineer is the radiation protection manager at Waterford 3 who, although not having the qualifications as required by Regulatory Guide 1.8 per se, does meet the intent of those qualifications in that he is a knowledgeable professional with suffi cient experience to provide the supervision and technical direction necessary to implement the program required for radiation protection. Instead of the required three years of professional experience in applied radiation protection work at a nuclear power facility, as specified in Regulatory Guide 1.8, the incumbent has two years of this type experience. He has participated in four refuelings at Arkansas and St. Lucie nuclear power plants with his participation including a supervisory role during the refueling at Arkansas. In addition to this experience, he has a Masters Degree in Health Physics. The staff finds the health physics engineer at Waterford 3 to be a qualified radiation protection manager. He reports to the technical support superintendent. However, he has direct access to the assistant plant manager and/or plant manager for matters of radiological health and safety dealing with policy determination, interpreta tion, and implementation. He is also a member of the plant operations review committee. His backup will have the qualifications specified in NUREG-0731.
Thus, the salient recommendations of NUREG-0731 are satisfied with respect to the RPM reoortina and staffina.
I      ..,,,
It is the responsibility of the health physics group to prepare and recommend procedures for controlling radiation doses and intakes with the limits of 10 CFR Sections 20.101 and 20.103 for all routine and nonroutine activities and that such exposures are kept ALARA; to provide radiation protection controls for personnel and operations onsite; to provide radiation surveys of station areas and maintain records of results; to assist in the station training program; to provide, maintain, and calibrate radiation detection instrumentation; to provide, maintain, and issue protective clothing; to assist in shipping and receiving all radioactive materials; to assist in decontamination of personnel and equipment; and be responsible for the respiratory protection program.
12-7
 
12.5.2 Health Physics Facilities The health physics staff maintains facilities for conducting its routine opera tions such as access control checkpoints, a shielded counting room for counting air and swipe samples, an instrumentation calibration room for checking health physics survey instruments, a change room for obtaining clean protective clothing and for removal and handling contaminated protective clothing after use, and a personnel decontamination room. The counting room will contain a multichannel pulse height analyzer with an associated Geli detector, a gas flow proportional counter, and a liquid scintillation counting system for tritium determination.
A whole-body counter will be available from a commercial firm as needed for in-vivo measurements of station personnel. A thermoluminescent dosimeter (TLD) reader and associated equipment is on site to enable prompt processing of TLD badges to immediately verify exposure.
12.5.3 Health Physics Instrumentation Continuing evaluation and review of the radiological status of the station will be carried out by health physics personnel so that levels of radiation will be known at a11 times in areas where personnel are working. Equipment to be used for radiation protection purposes include portable alpha, beta, gamma, and neutron survey meters. As a result of NRC review questions, the applicant has increased the proposed portable survey instrument inventory so that there will be sufficient instrumentation to accommodate the need to monitor large numbers of operations that may be required in radiation areas and high radiation areas throughout the plant during major maintenance and refueling outages and for accidents.
In arriving at the total number of instruments, the applicant has considered those instruments that will be in a calibration, maintenance, or inoperative on-the-shelf status. Airborne gaseous, particulate and iodine samplers, and continuous air monitors are available. For contamination control, portal moni tors and friskers are used at exits from radiation control areas and to monitor personnel leaving the stations. Protective clothing and respiratory equipment are also used, as required, to keep exposure ALARA.
All plant personnel are required to wear a TLD as the primary method for deter mining beta-gamma exposure. Albedo neutron dosimetry devices will be issued to those individuals subject to neutron exposure as required by job assignment.
A day-to-day-estimate of neutron exposure will be made using neutron rem-meters and stay-time calculations. Pocket dosimeters will be issued as a secondary method for beta-gamma dosimetry and will also provide a day-to-day estimate of personnel exposure for gamma radiation. Exposure records for each individual will be maintained in accordance with Regu1atory Guide 8. 7 and ANSI Standard N343-1978 for fission and activation products. The bioassay program at Water-ford 3 will follow the guidance of Regulatory Guide 8.9. The whole-body counter will be located at the station for in-vivo counting of station personnel, visitors, contractors, etc. Counting will be conducted on a scheduled basis and other bioassay methods (e.g., excreta samples) are provided when deemed necessary.
12.5.4 Procedures Health physics personnel will routinely survey selected areas of the plant for assessing radiation levels, radioactive contamination, and airborne radioactivity concentrations. These surveys will be performed at a selected frequency depending 12-8
 
upon location, potential radiation levels, occupancy factor, and station operating status. Contaminated areas will be barricaded and posted with appropriate warn ings before decontamination. Entry will be controlled by health physics personne1.
Approval of radiation work permits by the health physics engineer will permit entry and work in radiation and/or contamination areas, based upon procedural requirements. These permits state radiation levels in the area, allowable stay times, protective clothing and respiratory equipment required, and dosimetry and other procedural requirements.
On the basis of the plant health physics related equipment and procedures and the applicant 1 s consideration of relevant regulatory guides dealing with radia tion protection and administrative controls for quality control related activities during the operation of the plant (i.e., Regulatory Guide 1.33), the staff con cludes that the applicant 1 s health physics program will provide plant personne1 with adequate protection against the radiation hazards associated with the normal operation of the p1ant and will limit occupational exposure to ALARA conditions in accordance with Regulatory Guide 8.8 exposures as stated in 10 CFR Part 20.
In the FSAR, the applicant has committed to the guidance offered in the following Regulatory Guides with respect to operating the radjation protection program at Waterford 3: 1.16, 1.21, 1.33, 1.39, 1.52, 1.69, 1.109, 8.2, 8.3, 8.4, 8.7, 8.8, 8.9, 8.10, 8.15, and 8.19.
12-9
 
==12.6 REFERENCES==
American National Standards Institute:
ANSI 13.1 ANSI Standard N237 Code of Federal Regulations:
10 CFR Part 20 10 CFR Section 20.101 10 CFR Section 20.103 10 CFR Section 20.203 Louisiana Power and Light Co.
FSAR for Waterford 3, Chapter 12 Regulatory Guides:
RG 1.8 RG 1.16 RG 1.21 RG 1.33 RG 1.39 RG 1.52 RG 1.69 RG 1.109 RG 8.2 RG 8.3 RG 8.4 RG 8.7 RG 8.8 RG 8.9 RG 8.10 RG 8.15 RG 8.19 USNRC reports:
NUREG-0731 NUREG/CR-0130 NUREG/CR-0672
*See Appendix B, Bibliography, for complete citations and availability statements.
12-10
 
13 CONDUCT OF OPERATIONS 13.1 ORGANIZATIONAL STRUCTURE AND QUALIFICATIONS In FSAR draft Amendment 17, received by the NRC April 14, 1981, and in an {{letter dated|date=April 20, 1981|text=April 20, 1981 letter}}, the applicant has presented its proposed corporate and plant organizations and the qualifications of key personnel.
The NRC staff has performed a preliminary review of the information provided but has not completed its detailed review, which is continuing.
An audit team composed of members of the Office of Nuclear Reactor Regulation and of the Office of Inspection and Enforcement will visit the applicant's cor porate office and the Waterford 3 plant to review the proposed organization for operation of Waterford 3. This review will include all staff, from the senior corporate officer who will be in overall charge of nuclear operations down to and including the proposed operating staff at the plant. The team will review the organizational structure for operation and for support of the plant staff, the levels of staffing, the experience level of principal individuals of both the corporate staff and the plant staff, and the interfaces between the plant staff and its corporate support structure. During the visit the team will also audit the appropriate management directives and administrative proce dures that the applicant's staff will use in performing its duties. The team expects to gain a feeling for the responsibilities and attitudes of the indivi duals, as well as an understanding of how they fit into the organization and how they interface with other onsite and offsite organizational units.
The audit team's visit has not yet been scheduled because the applicant's staffing level to date and the state of management readiness are not high enough for NRC to gain the insight needed to complete the review.
Although the review to date has been preliminary, the staff has noted some items of concern. The following discussion addresses these concerns.
Figure 13.l shows the LP&L corporate organization. The highest level of manage ment that is concerned solely with nuclear matters is the Assistant Vice President, Nuclear Operations. He is responsible for all nuclear matters except quality assurance.
The Assistant Vice President, Nuclear Operations reports to the Vice President, Power Production, who is responsible for construction and operation of all generating facilities, both fossil and nuclear. The corporate Safety Review Committee (see Section 13.4 of this report) and Quality Assurance Manager report to the Vice President, Power Production.
The Vice President, Power Production, reports to the Senior Vice President, Operations, which is one of five executive positions reporting to the President.
13-1
 
[-- - - -- I:-]
BOARD OF DIRECTORS PARALLEL REPORTING PiUH DURING EMERGENCY IN CRITICAi. SITUATIONS                                                                ____
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                                              - -                                                                                                      II, ASST SECRETARY
                                                                                                                                                      ---- PUBLIC RELATIONS DIRECTOR OF 7
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PUBLIC RELATIO CONSUMIR SI RVICESOEP T                      G. (). ENGINEEflllNG                      DIVISIONS                POWER PRODUCTION VICE PRESIDENl
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CONSUM[ R SERVICES                          CHI E F ENGINEER
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_ 1---tt--                                                                                                                            OOR            s    ICES l -- -
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ENVIRON'L AFFAIRS I      NORTHERN DIVISION                        WESTBANK DIVISION                                                                                                                            . -- -              -
SOUTHEASTERN DIVISION N                                        --      -*      - ---                                                                                                                          ENVIRON'L AFFAIRS l ::::::::::::: :
MANAGER DIVISION MANAGE"                          DIVISION MANAGER                  DIVISION MANAGE R                                                                                -- - -        -
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F REVIEW ITTEE                                                                            MANAGE R GENERAT'O STATIONS-FOSSIL PROOUCTION OPERATIONS MANAGER
______________________ _J
                                                                                                                                                                                                                                            ]
ASSISTANT VICE            QUALITY ASSURANCE FOSSIL PLANT                                                                                                                            PLANT MAINTENANCE SERVlES j                                                                                    [,    RESIDENT-NUCLEAR              DUALITY ASSURANCE MANAGERS                                                                                                                            BETTERMENT 8
OPERATIONS                    MANAGER r---------,-------------------
_          l  _          __                    _ L __ _____
WATERFORD 3 A/E                      MIDDLE SOUTH SE RV ICES
    -- -                                                                                WATERFORD 3                    WATERFORD 3 CONSTRUCT--*  I ON MANAG ER TS:
PROJECT/OFFSITE SUPPORT              PLANT MANAGER NUCLEAR EBJ\SCO II, THER CONSL              NUCLEAR ACTIVITIES OEPT.
                                                                                  - --          ---                                                                                                          LOUISIANA POWER 8. LIGHT CO.
Waterford Steam Electric Station LP&L GENERAL OHICE MANAGEMENT SITE DUALITY                    GENERAL OFFICE                              & SUPPORT ORGANIZATION ASSURANCE                    DUALITY A    ANCE
                                                                                                                                                                        -- --- :                                      Figure 13.1
 
The staff has discussed the corporate organization with the applicant. During initial discussions, two major concerns were noted: a lack of nuclear plant operating experience in upper management and the dual responsibilities of the Vice President, Power Production, for both nuclear and fossil plant operation.
Draft guidelines, as presented in NUREG-0731, 11 Guidelines for Utility Management Structure and Technical Resources, 11 call for an 11 upper level executive, 11 such as a Vice President, to be in charge of nuclear matters only (essentially no nonnuclear responsibilities) and to have a significant amount of nuclear expe rience. This 11 senior executive" should have a combination of education, training, and experience in technical and managerial skills that allows him to perform the duties of the position. Although the position is primarily managerial, with high-level decision-making authority, a base of technical and operational nuclear knowledge should exist in that person and should be supplemented through staff qualifications and training related to the specific facility. Typically, the qualifications of the senior nuclear executive might include a bachelor's degree or equivalent education and experience in science, or an engineering degree in a field associated with power production and 10 years of experience in power plant design and operation, 5 years of which should be specific to nuclear power plants. Operational and engineering management capabilities should be demonstrated by the individual's credentials of experience.
In initial discussions with the applicant, the present Assistant Vice President, Nuclear Operations, had the title Waterford 3 Project Director, not what is considered evidence of the high corporate authority normally associated with the responsibilities and authority of Vice President. Furthermore, the Assistant Vice President's nuclear experience concerns only the licensing and construction of Waterford 3. The Vice President, Power Production has stated that he spends about 50% of his time on the Waterford 3 project and that represents his only nuclear experience. The Senior Vice President and the President have had essentially no nuclear experience other than their involvement in the Waterford 3 project.
Shortly after a meeting with the applicant in April 1981, LP&L submitted a {{letter dated|date=April 20, 1981|text=letter dated April 20, 1981}}. With this letter was the notification that the Waterford 3 Project Director had recently been named Assistant Vice President, Nuclear Operations. NRC reviewed the position description for the Assistant Vice President and an excerpt from the LP&L Board of Directors meeting of April 14, 1981. The excerpt recorded the election by the Board of Mr. Maurin, formerly Project Director, to the office of Assistant Vice President, Nuclear Operations. At that point the staff was not convinced that the position includes adequate authority to* carry out the functions that NRC believes are required of an upper level executive position. It appeared that the Assistant Vice President would not have final authority to execute a contract calling for services or equipment needed in an emergency. It was not clear that he would have final hiring and firing authority for the people under him.
Another staff concern is the number of II fi ltering 11 levels between the Assistant Vice President, Nuclear Operations, and the President. The relationship between the top nuclear position and the uppermost management position should be close so as to give greater assurance that top management will always be adequately informed of nuclear matters, giving top management the opportunity to correct problems before they become significant safety events. After the staff had expressed this concern to the applicant, an emergency reporting line was added 13-3
 
to the corporate organization chart, allowing the Assistant Vice President to report directly to the President in emergencies or critical situations. The position description for the Assistant Vice President incorporates that reporting authority.
The staff also reviewed the qualifications and experience of the plant manage ment personnel and the offsite support management personnel. If such people collectively had strong experience in commercial nuclear power plant operation, NRC staff might feel that this would compensate for the lack of such experience at the upper management levels. However, the two technically-oriented managers that report to the Assistant Vice President, although having had extensive operating experience in the naval nuclear program, have no commercial nuclear power plant operating experience. In fact, it appears, from the 15 resumes of people reporting to the Waterford 3 Project/Offsite Support Manager, that only two have any significant nuclear experience. The resumes of the plant staff tell a similar story. Of the 11 technical support personnel presently on the Plant Manager's staff, only four have any commercial nuclear operating exper ience and only two of these four have extensive experience.
Only one of the six nuclear operations supervisors (senior reactor operator (SRO) license) has commercial plant operating experience; the other five have only naval nuclear operating experience.
The applicant has stated that the writing of plant operating procedures, includ ing startup and test procedures, is done predominantly by contractors rather than by plant personnel. The plant personnel are involved primarily to the extent of reviewing these procedures. THe staff does not consider this process to be a desirable one. The plant operating personnel are being deprived of the educational value (learning plant systems and their interactions) of writing and testing the procedures.
LP&L is wholly owned by Middle South Utilities (MSU), which also owns other generating companies. These other companies include Arkansas Power & Light Company, which operates two PWRs, and Mississippi Power & Light Company whose Grand Gulf nuclear power station is expected to start up at the end of 1981 or early 1982. Middle South Services (MSS), a subsidiary of MSU, provides specific services, usually of a specialized, technical, or professional nature, to MSU and to the operating companies. Although MSS includes a Nuclear Activities Department, that Department is concerned primarily with fuel management, reactor analysis, and quality assurance. The staff expects that MSS 1 contribution to technical support of Waterford 3 will be minimal in terms of safe reactor operation.
The applicant has described its plans for acquisition of additional vital per sonnel. The positions the applicant is trying to fill in this category are shown in Table 13.1. As can be seen by comparing these positions with those shown on plant staff and corporate support staff organization charts Figures 13.2, 13.3 and 13.4, many of those positions yet to be filled are upper levels of supervision requiring experienced personnel. Normally, these are positions that should be filled several years before the plant begins to operate so that the personnel will be intimately familiar with the plant and will be performing their functions smoothly during the preoperational startup and test program.
13-4
 
Table 13.1 Aquisition of Vital Personnel Plant Staff Title                    Number        Qualifications Operation Superintendent          1      SRO, 3 years operating PWR experience, BS desirable Assistant Plant Manager            1      BS, 5 years operating nuclear Operations and Maintenance                experience, SRO desirable Plant Engineering Department      1      BS, 3 years operating nuclear Supervisor                                experience, SRO desirable General Support Superintendent    1      Operating nuclear experience in related areas (clerical, stores, document control, security)
Nuclear Operations Supervisors    6      RO, 2 years operating PWR experience Nuclear Auxiliary Operators      10      Navy (Cold License)
Nuclear Auxiliary Operators      10      High School Graduate, Navy Desirable (Hot License)
Plant Utility Engineers            3      BS, 2 years operating nuclear experience STA Engineering Supervisor        1      BS, SRO, 2 years operating PWR experience Plant Associate II/I Engineers    5      BS Offsite Support Title                    Number        Qualifications Onsite Safety Review              1      BS; 3 years nuclear experience; Engineering Supervisor                    8 years responsible experience, SRO/RO desirable Onsite Safety Review Engineering  1      BS, 2 years nuclear experience Special Projects/Training          1      BS, 2 years nuclear experience Associate II/I Engineer Nuclear Training Director          1      BS, 3 years nuclear experience -
training. SRO qualification desirable.
13-5
 
WATERFORD 3 PLANT MANAGER NUCLEAR I                              I                                I                                                      I START-UP                      OPIER. 6 MAINT.                  QUALITY CONTFOL.                                          PLANT SERVICES ENGINEERING                    ASSISTANT PLANT                      ENGINEER                                            ASSISTANT PLANT SUPERVISOR                    MANAGER- NUCLEAR                                                                          MANAGER - NUCl.&#xa3;AR I
I                          I                                                                                                                          I OPERATIONS                  S T A COORD.                MAMENANCE                  PLAN. 8 SCHED.        TECt-f\llCAI..Slff'CRT    GE t&#xa3;RAL SUFfffiT HEALTH PHYSICS SU l?fP'W2NS IN NUCLEAR 0&#xa3;Nl            ENGINEERING SUPERV ISOR MAlTAE SUPE IN EN NT NUCLEAR ENGINEER          TECt-f'IIK:ALS.f'RRT SUF&#xa3;RIN1ENDENT GENERAL SUFf'CRT SUF&#xa3;AT            ENGINEER I                          I                      I
::.: -.::.ICAL l'.WNT. RECTAK:AL MAINT.              I ac MAINT.          MAM ENGINEERING                    TRAINING MECWWICAL                  ELECTRK:AL            INSTR. 8 COITAOW:              UTILITY                      TRAINING ASST. !IUPERINTEWENT      ASST. 9.Jf&#xa3;Rllf1Ef,UNT      ASST. SlffRIN1ENDENT          ENGINEER                  SUPERINTENC&#xa3;NT I                      I NUCLEAR                                          Ct-EM. a ENVIR.        PLANT El'Q..EERING ENGINEER                                              ENGINEER          ENGINEERN3 ORG.
I                      I                        I ADMIN. SERVICES            SECURITY                SPECIAL SERVICES SENIOR                SECURITY                BLDG. FOREMAN ACCOUNTA NT            SUPERV ISOR I
I                          I                      I CLERICAL              MllTERIALS 6 STCRES      rYn *.cNT CONTROL OFFIC SPERVI &sect;)R NUC. PIJ. M 8 S SUPERVISOR              sufrf'J Figure 13.2 Waterford 3 Organization Structure
 
OJECT
                                                                                                  ]
NAGER
                                                                                        - -*- -- (11 l                                                      l- -- -                                                                  PROJECT CONTROL/
                                                                                                                  -- 1*--
coo,,.Tioo                ENGINEERING                AOMINISTRA TIVE                                ::TE SAFETY
* CONTRACT ADMIN.
ENGINEERING                ENGINEERING                    SERVICES                                  [  REVIEW      ]
fNGINEEnlNG SUPERVISOR                SUPERVISOR              UTILITY ENGINEER                                  ENGINEER            OFFICE SUPERVISOR l
111
______J --
111                        (11                        (1)                                                                      (H I
(SEE FIGURE 13.4)                                        (SEE FIGURE 13.41 J
MECHANICAL/CIVIL                                                    ---            - *-----*
ENGINEER                ENGINEERlG ENGINEER                        SPECIAL PROJ/TRAINING            RECORDS/CLERICAL                                            TECHNICIAN w                            (11                                                                ----                            (11
                                                                                                                                        ----            - ---(11
.....,I            l&C ASSOCIATE ENGINEER 1/11 11)
DEPARTMENTAL CLERK (11              UTILITY ENGINEER                                                                                            ENGINEER 111                                                                                                (31 ENGINEERING CLERK A TECHNICIAN 111 ELECTRICAL                                              111 ENGINEER
          ---  *--- -      111 CLERK B/C SUPPORT ASSOCIATE                                                                            (21 ENGINEER 1/11 121 COST CONTROL/                                                          STENO(TYPIST CONTRACT ADMINISTRATION UTILITY ENGINEER 111
                                                                              -                      121 ACCOUNTING/
AUDITING SENIOR ACCOUNTAN
          .              . ti LOUISIANA POWER 8. LIGHT CO.
Waterford Steam Electric Station NOTES:
(XI-- N UMBER OF PERSONNEL ASSIGNED TO POSITION                                                                                  LPl!.L POWER PRODUCTION DEPARTMFNT
        * - LOCATED ON-SITE                                                                                                                  WA TERrOR0 3 f'ROJFCT "OFFSITF SUPPORT ORGANIZATION Figure 13.3
 
ENGINEERING                      TECHNICAL SERVICES ENGINEERING                          ENGINEERING SUPERVISOR                            SUPERVISOR (1)                                (1)
MAINTENANCE              MECHANICAL                LICENSING ENGINEER          THERMAL HYDRAULICS              ENGINEER (1)        ENGINEER                            (1)
(1)
REFUELING/OPERATIONS            MECHANICAL                LICENSING ENGINEER              PLANT SYSTEMS          UTILITY ENGINEER ENGINEER (1)                      (1)                    (1)
MECHANICAL              NUCLEAR FUEL SITE SUPPORT          METALLURGY &              MANAGEMENT ENGINEER                MATERIALS
......                                        ENGINEER                  ENGINEER w                                  (1)                      (1)                  (1)
I (X)
CIVIL - PLANT                  I& C              NUCLEAR FUEL STRUCTURAL &            PLANT COMPUTERS              ANALYSIS CONTAINMENT                ENGINEER                ENGINEER DESIGN ENGINEER    (1)                      (1)                  (1 I SUPPORT                    I& C                CHEMISTRY/
UTI l.lTY ENGINEER          PLANT SYSTEMS          RADIO CHEMISTRY ENGINEER                ENGINEER (2)                      (1)                  (1)
SUPPORT                ELECTRICAL          RADIATION CONTROL/
ASSOCIATE                ENGINEER                  PHYSICS ENGINEER 1/11                                      ENGINEER (3)                      (1)                    (1)
      "Tl SUPPORT (D
NOTES:
(X) - NUMBER OF PERSONNEL ASSIGNED TO POSITION UTILITY ENGINEER
              * - LOCATED ON-SITE                                                  (2)
 
In recent conversations, the staff told the applicant about the concerns addressed above. As a result, the applicant has provided, in a {{letter dated|date=May 15, 1981|text=letter dated May 15, 1981}}, additional information concerning the authority of the Assistant Vice President, Nuclear Operations, and concerning the addition to plant and corporate staffs of individuals having strong backgrounds in commercial nuclear power plant operations. This information indicates that the Assistant Vice President, Nuclear Operations, has adequate authority to contract for services or equipment needed in an emergency and to hire and fire those beneath him.
In the {{letter dated|date=May 15, 1981|text=May 15, 1981 letter}}, the applicant has committed to providing a full-time advisor to the Plant Manager. This individual will have a strong background in commercial nuclear power plant operation. The applicant also committed to providing a similar individual to assist directly the Assistant Vice President, Nuclear Operations. Both of these individuals, to be employees or to be obtained by contract, will be retained in their positions until adequate operating experience has been gained by the LP&L personnel.
The applicant has also committed to filling the position of Assistant Plant Manager, Operations and Maintenance, with an individual who has a BS degree and a minimum of 5 years of operating nuclear experience of which at least three are on a commercial PWR. In addition, an Operations Superintendent is expected to be hired during the summer of 1981. The Operations Superintendent will be an SRO-licensed individual with at least 3 years of operating PWR experience.
A further commitment has been made to provide that every operating shift will include an individual with commercial PWR nuclear power plant experience. LP&L expects to meet this commitment with qualified LP&L shift personnel. In the event, however, that LP&L's recruitment efforts do not yield this result, LP&L will meet this commitment by securing individuals with such operating experience to stand shifts with LP&L operating personnel at least through Waterford 3 1 s commercial operating date while LP&L's shift employees gain hands-on experience.
The information the applicant has provided, concerning the authority of the Assistant Vice President, Nuclear Operations, is a positive contribution to assuring that management's consideration of safety matters will receive adequate attention. The addition of staff advisors to the Assistant Vice President, Nuclear Operations, and the Plant Manager; the operating experience requirement for the Assistant Plant Manager, Operations and Maintenance, and the Operations Superintendent; and the covering of each operating shift with a more experienced individual are positive steps in improving the operating experience of the plant and corporate staffs.
Interim
 
== Conclusions:==
As noted above, NRC review of the applicant's organizational structure and qualifications is incomplete. However, based upon the review to date, the staff has formed the following interim conclusions:
(1) The applicant's recent proposal to assign experienced advisors to the Assistant Vice President and the Plant Manager is a step in the right direction for augmenting the staff's experiential knowledge. The staff considers in similar light the applicant 1 s proposal to cover each operating shift with experienced personnel and to require PWR operating experience for the Assistant Plant Manager, Operations and Maintenance, and the Operations Superintendent.
13-9
 
(2)  The applicant should accelerate its plan to acquire the needed corporate and plant staff personnel so that the organizational units will be func tioning smoothly during the preoperational startup and test program.
(3)  After the applicant has staffed the offsite support groups and plant operating and support groups with supervisory personnel, and these groups have been functioning for several months, the staff will complete its review, including an audit team visit, and will report the results of that review in a supplement to this report.
13.2  TRAINING 13.2.1 Corporate and Plant Staff Training Program In FSAR Amendment 17 and in the {{letter dated|date=April 20, 1981|text=April 20, 1981 letter}}, the applicant has discussed its training programs for both corporate and plant staff personnel.
All training will be the responsibility of a Training Engineering Supervisor who reports to the Assistant Vice President, Nuclear Operations. This Supervisor will have a BS degree in engineering or the physical sciences and a minimum of 3 years of nuclear plant operating experience. The applicant is recruiting this Supervisor. Training to date has been concentrated on preparing potential reactor operators and senior reactor operators for the NRC examinations. The staff has no evidence that other proposed training has been accomplished.
The training program includes the following elements:
(1)  LP&L corporate training (2)  Cold license training (3)  Senior reactor operator upgrade training (4)  Training for operator candidates who have previously held licenses at other nuclear facilities (5) Shift technical advisor training (6) Emergency plan training (7) Training for nonlicensed personnel including operators (a) General employee training (b) Skills training (i) Nonlicensed operations personnel (ii) Radiation protection personnel (iii) Plant chemistry personnel (iv) Maintenance personnel (v) Plant engineering personnel LP&L will have its own simulator and permanent training facilities by January 1985. The general outline of the training program appears to be satisfactory.
However, NRC has not completed its review of the details of the program and its schedule as applied to the various unlicensed personnel groups and disciplines.
These matters will be reviewed with the applicant during the staff 1 s audit team visit (see Section 13.1 of this report). The staff wil1 also review the quali fications of training personnel and the directives and administrative procedures governing the operation of the training group. The results of that review will be reported in a supplement to this SER.
13-10
 
13.2.2 Licensed Operator Training Program The Waterford 3 Plant Manager has overall responsibility for the conduct and administration of the training program for all plant staff personnel. Direct responsibility for accomplishing this task will be the function of the Waterford 3 Training Superintendent. Guidance for this training will be provided in the Plant Operating Manual. The program has been formulated to ensure that Waterford 3 staff receives adequate training in nuclear technology and other subjects important to safe operation of the plant. The training program will be annually reviewed utilizing position task analyses which will, if necessary, cause upgrading of qualifications and training for operating personnel, including maintenance and technical personnel. This review will continue to justify the acceptability of the training program to assure the effective performance of safety-related functions.
The applicant 1 s training staff and members of other organizations who routinely provide instruction on systems related to plant safety, integrated response, transients, or simulator courses will demonstrate their technical competence to instruct personnel who perform safety-related functions. This will be accomplished by either demonstrating their SRO qualifications and enrollment in appropriate requalification programs, or successfully completing an instructor certification program accepted by the NRC. The program for formal education and training of the reactor operator has been designed to meet the individual needs of the participants, depending upon their background, previous training, and expected job assignment. The program conforms to the guidance set forth in ANSI Nl8.l-1971, and requirements of 10 CFR Part 55 and Item I.A.2.1 of the TMI Action Plan (see NUREG-0737).
The training program for personnel who will be cold licensed consists of the following discrete segments: courses in nuclear power plant steam and mechanical fundamentals; power plant electric fundamentals, mathematics and general physics review; PWR technology, system description, heat transfer, fluid flow and ther modynamics; mitigating core damage; reactor systems simulator training; research reactor training; and refresher training. The applicants for cold licenses will also spend 10 weeks observing operations at the St. Lucie Nuclear Power Plant.
The cold training program conforms to those offered by Combustion Engineering, Inc. and approved by NRC.
Plans for requalification training conform to the criteria of Appendix A of 10 CFR Part 55 and follow the guidance given in ANSI NlB.1-1971. Also, the applicant has submitted a detailed licensed operator replacement training program. This program is detailed in Section 13.2.3 of the Waterford 3 FSAR and conforms to the guidance in ANSI Nl8.l-1971.
On the basis of NRC review, the staff has concluded that the training program and schedules for all operators and senior operators are acceptable for the preoperational test program, for operator licensing examination, and fuel loading.
SRP Section 13.2, Training; 10 CFR Part 55; Regulatory Guide 1.8; ANSI Nl8.1-1971; and H. R. Denton's {{letter dated|date=March 28, 1980|text=March 28, 1980 letter}} were used in the conduct of this review.
13-11
 
13.3 EMERGENCY PREPAREDNESS EVALUATION 13.3.l  Introduction Evaluation by the NRC of the state of emergency preparedness associated with the Waterford 3 plant involves review of LP&L emergency preparedness and the Federal Emergency Management Agency's (FEMA) findings on State and local radio logical emergency preparedness. This evaluation addresses the applicant's emergency preparedness. Supplement(s) to this evaluation will address the findings and determinations of FEMA on the adequacy of the State and local emergency response plans and the NRC staff's overall conclusions on the status of emergency preparedness associated with the Waterford site and related emergency planning zones (EPZs).
The Waterford 3 site is located on the west bank of the Mississippi River in St. Charles Parish, Louisiana, approximately 12 mi W of New Orleans, with the plume exposure pathway EPZ (plume EPZ) located within the parishes of St. Charles and St. John the Baptist. The plume EPZ includes the area within approximately 10 mi of the site and the entire towns of Garyville, Edgard, Reserve, La Place, Killona, Taft, Norco, Goodhope, Hahnville, New Sarpy, Destrehan, St. Rose, Luling, Mimosa Park, Boutte, and Paradis, and portions of Lac De Allemandes, Lake Pontchartrain, and the Mississippi River.
LP&L filed, by {{letter dated|date=April 27, 1981|text=letter dated April 27, 1981}}, a comprehensive revision to Water ford 3 FSAR Section 13.3, "Emergency Planning" (hereinafter referred to as the Plan or Waterford Emergency Plan). The Waterford Emergency Plan, as amended (Amendment 17, April 1981), was reviewed against the requirements of 10 CFR Section 50.47(b), 10 CFR 50, Appendix E, and the criteria of the 16 Planning Standards in Part II of the "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," NUREG-0654/FEMA-REP-l, Rev. 1, dated November 1980.
Before the aforementioned review, NRC staff met with LP&L staff on February 10, 1981 to discuss the Waterford Emergency Plan. As a result of this meeting, LP&L revised certain portions of the Plan (April, 1981) by amending FSAR Section 13.3. Amendment 17 included LP&L's response to the staff comments that were transmitted to LP&L on March 30, 1981. LP&L commitments for further upgrading of the Plan are contained in Section 13.3.2 of this report.
Section 13.3.2 of this report lists each standard followed by a summary of applicable portions of the Plan as they apply principally to the standard.
Section 13.3.3 of this report provides the staff 1 s conclusions.
13.3.2 Evaluation of the Emergency Plan 13.3.2.1 Assignment of Responsibility (Organization Control)
Standard: Primary responsibilities for emergency response by the nuclear facility applicant and by State and local organizations within the EPZs have been assigned, the emergency responsibilities of the various supporting orga nizations have been specifically established, and each principal response organization has staff to respond and to augment its initial response on a continuous basis.
13-12
 
Emergency Plan Evaluation: The Plan describes the functions and responsibilities of each State and local organization with response roles.
The Assistant Secretary of the Office of Environmental Affairs (ASOEA), through the Louisiana Nuclear Energy Division (LNED) under Act 449 of the 1979 Legisla ture, has the authority to develop and implement a Statewide radiological emergency preparedness plan and coordinate the development of specific emer gency plans for Waterford 3 nuclear power facility, including planned protective actions for the population and the establishment of appropriate boundaries for which planning for nuclear emergencies will be undertaken, to respond to any emergency that involves possible or actual release of radioactive material; to coordinate decontamination efforts; to issue relocation and evacuation recommendations; and to otherwise protect the public welfare and safety in any manner deemed necessary and appropriate.
The ASOEA or his designee is responsible for notifying the public that a radiological incident has occurred and for providing an evaluation of the incident in terms of public health. If protective actions are indicated, specific guidance shall be provided and the appropriate information shall be released.
Other Federal, State, and local agencies will provide assistance, as required, to LNED in evaluating the radiological hazards and providing implementation of appropriate protective action in accordance with the Louisiana Peacetime Radiological Response Plan and its Waterford 3 attachment.
The Louisiana Department of Public Safety, Office of Emergency Preparedness (LOEP) will coordinate all emergency actions of the various State and local agencies when evacuation is necessary. This agency will receive immediate notification from LNED in the event of a site or general emergency.
St. Charles Parish Civil Defense and Sheriff Offices and St. John the Baptist Parish Civil Defense and Sheriff Offices are responsible for implementing protective actions in their respective parishes.
In the event of an emergency, the Waterford Site Emergency Coordinator will contact LNED, LOEP, and St. Charles and St. John the Baptist Parishes by dedicated 24-hr/day communication linkup.
The Emergency Director will be responsibie for activating and directing the Corporate Command and Recovery Center (LP&L General Office) and ensuring that the functional groups provide a coordinated response in support of the onsite emergency organization.
Written agreements have been executed with the Federal, State, and local agencies and organizations identified in the Plan as providing radiological support, medical assistance, medical transportation, and fire protection during an emergency. The Plan does not contain agreement letters with the following support organizations identified in the P1an as providing additional laboratory facilities and engineering and technical support:
(1)  Arkansas Power and Light Company (Arkansas Nuclear One) 13-13
 
(2)  Mississippi Power & Light Company (Grand Gulf)
(3)  Middle South Services LP&L has committed to develop the letters of agreement with Arkansas Nuclear One, Grand Gulf, and Middle South Services and include them in Appendix C to the Plan when they are available.
The emergency response functions of agencies in St. John the Baptist Parish and St. Charles Parish are covered by laws, plans, acts, and ordinances as discussed in Appendix E to the Waterford Plan. The assistance provided by EPA and LNED laboratories is also addressed in Appendix E. In addition, Appendix E to the Plan addresses the major urban centers and parishes within the 50-mi EPZ and identifies the designated shelter areas in the surrounding parishes.
Appendix C of the Plan contains agreement letters that must be upgraded with regard to access control of the plume EPZ.
(1) U.S. Coast Guard: The agreement letter with the U.S. Coast Guard (USCG) found on page C-1 of Appendix C to the Plan covers only access control-of the waterway within the Waterford 3 exclusion area. The agreement letter in the Louisiana State Plan between the USCG and the Louisiana Office of Emergency Preparedness, dated October 17, 1980, may be used as the basis for updating the letter between LP&L and USCG with regard to access control of the 10-mi EPZ.
(2) Missouri Pacific Railroad Company: The agreement letter with the Missouri Pacific Railroad Company, dated November 1, 1978, covers only that por tion of the right of way that traverses the exclusion area.
(3) Lafourche Basin Levee District: Amendment 15 to Waterford 3 FSAR Section 13.3, dated February 1981, contained an agreement letter between LP&L and Lafourche Basin Levee District Board of Commissioners which referred to exclusion area control at Waterford 3. Amendment 17 to the FSAR, which deleted the reference of the Lafourche Basin Levee District from Appendix C, stated that the Lafourche Basin Levee District does not provide access control on any levees in which it has jurisdiction. Since the Lefourche Basin Levee District has jurisdiction over the levees that transverse the Waterford 3 10-mi EPZ, access control of these levees should be clarified; the agency or agencies having the authority and capability to establish access control must be identified in the Plan and appropriate letter(s) of agreement must be established and included in the P1an.
The following items require resolution:
(1)  Existing agreements must be updated with regard to access control of the 10-mi EPZ.
(2)  The jurisdiction of the Lafourche Basin Levee District over that portion of the levee that lies within the plume EPZ must be ciarified and written arrangements for access control thereof must be established.
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13.3.2.2 Onsite Emergency Organization Standard: Onshift facility applicant responsibilities for emergency response are unambiguously defined, adequate staffing to provide initial facility accident response in key functional areas is maintained at all times, timely augmentation of response capabilities is available, and the interfaces among various onsite response activities and offsite support and response activities are specified.
Emergency Plan Evaluation: The Nuclear Operations Supervisor (NOS), designated as the Emergency Coordinator, has the responsibility and authority to implement the Plan and initiate any necessary emergency actions. He is relieved by the Plant Manager, Nuclear after that individual arrives onsite and becomes thoroughly cognizant of the situation. The Emergency Coordinator operates from the Technical Support Center (TSC). The Emergency Coordinator will not delegate the responsi bility to notify and make protective action recommendations to offsite authorities.
The Plan identifies a line of succession, up to the Plant Manager, Nuclear, for the position of Emergency Coordinator. However, the Plan does not identify the specific conditions for higher level utility officials assuming this function.
Station staff emergency assignments have been made and the relationship between the emergency organization and normal staff complement are specified and illustrated in the Plan. Positions and/or titles of shift and plant staff personnel, both onsite and offsite, assigned emergency functional duties are listed. The shift and augmented staffing specified in the Plan meet the specific staffing criteria expressed in Table B-1 of NUREG-0654.
When an emergency condition arises, the Nuclear Operations Supervisor is designated as the Emergency Coordinator and it is his responsibility to evaluate the situation. If, in his judgment, conditions meet or exceed any of the emergen cy classification action levels, it is his responsibility to implement the Plan.
There is 24-hr/day communication linkage capability between the Waterford 3 site and federal, state, and local response agencies and organizations to ensure rapid transmittal of accurate notification information and emergency assessment data.
The authority, responsibility, and duties of the plant staff personnel for coping with emergencies are defined for both the normal operating staff and the augmented staff. The operational relationships between the onsite emer-gency centers and offsite agencies are identified. The Emergency Director is responsible for assuring continuity of the applicant resources and overall management of the emergency and recovery operation.
The Plan has established the framework for a long-term augmented facility operator emergency organization. This organization is under the command and control of the Emergency Director at the Corporate Command and Recovery Center (LP&L General Office). The Site Support Manager and his staff will be responsible for the operation of the near-site emergency operations facility (EOF).
Interfaces between and among the applicant's onsite and offsite organizations and governmental and private sector organizations have been specified.
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The following item requires resolution:
A description of the specific conditions under which utility officials above the position of Plant Manager, Nuclear would succeed to the position of Emergency Coordinator.
13.3.2.3 Emergency Response Support and Resources Standard: Arrangements for requesting and effectively using assistance resources have been made, arrangements to accommodate State and local staff at the applicant 1 s near-site emergency operations facility have been made, and other organizations capable of augmenting the planned response have been identified.
Emergency Plan Evaluation: Request for support under the Federal Radiological Monitoring and Assessment Plan (formerly Radiological Assistance Plan and Interagency Radiological Assistance Plan) will be coordinated through LNED.
The Emergency Coordinator has the responsibility to notify federal, state, and local officials, as appropriate, upon declaration of an emergency. Appendix C to the Plan contains an agreement letter with Region 2 Department of Energy (DOE) and an up-to-date DOE Region 2 Radiological Assistance Plan.
Provisions have been made to accommodate representatives from federal, state, and local government organizations and from contractor and other support groups at the EOF. It will be the central location for collecting and provid ing information and making recommendations for offsite protective actions.
The Plan provides information concerning specific applicant, state, and local resources available to support federal response, and the expected arrival times of Federa1 assistance at the site.
The Plan states that LP&L will dispatch a representative to the St. Charles Parish emergency operations center (EOC), which has been identified by LNED, LOEP, St. Charles Parish officials, and St. John the Baptist Parish officials as the primary EOC for an emergency at Waterford 3.
In addition to the Waterford 3 site laboratory facility, the Plan identifies laboratory facilities at LNED, Arkansas Nuclear One, and Grand Gulf Nuclear Station that may be utilized. However, the general capabilities of Arkansas Nuclear One and Grand Gulf laboratories and their expected availability is not described. Written agreements with Arkansas Power and Light and Mississippi Power and Light have been discussed in Section 13.3.2.l above. LP&L has committed to the development of available resources at Arkansas Nuclear One and Grand Gulf.
13.3.2.4 Emergency Classification System Standard: A standard emergency classification and action level scheme, the bases of which include facility system and effluent parameters, is in use by the nuclear facility applicant and State and local response plans call for re liance on information provided by facility applicant for determinations of minimum initial offsite response measures.
Emergency Plan Evaluation: The four standard emergency classes (i.e., Unusual Event, Alert, Site Emergency, and General Emergency) have been established by 13-16
 
the applicant. Observable and measurable emergency action levels (EALs) which, if exceeded, will initiate each emergency class, consistent with the criteria of Appendix 1 to NUREG-0654, have been established. EALs are provided using specific instrumentation, parameters, and equipment status. Emergency Plan Procedures contain specific information and guidance for determining the appropriate EAL and properly classifying the emergency condition, as well as the appropriate actions to be taken.
The applicant must make some minor clarifications to the classification and EAL section of the Plan and provide the aforementioned procedures for staff review.
The following items require resolution:
(1)  The initiating conditions for the Unusual Event Classification, described in Subsection 13.3.3.1.1 of the Plan should include example initiating condition 12 (Security Threat or Attempted Entry or Sabotage) listed on page 1-5 of Appendix 1 to NUREG-0654, Rev. 1.
(2) The initiating conditions for the Alert classification, described in Subsection 13.3.3.1.2 of the Plan, should include example initiating condition 16 (Ongoing Security Compromise) listed on page 1-9 of Appendix 1 to NUREG-0654, Rev. 1.
(3) The initiating conditions for the Site Area Emergency classification, described in Subsection 13.3.3.1.3 of the Plan, should include example initiating conditions 14 (Imminent loss of physical control of the plant) and 16.C (Entry of uncontrolled flammable gases into vital areas. Entry of uncontrolled toxic gases into vital areas where lack of access to the area constitutes a safety problem) listed on pages 1-13 and 1-14, respectively, of Appendix 1 to NUREG-0654, Rev. 1.
13.3.2.5 Notification Methods and Procedures Standard: Procedures have been established for notification by the applicant to State and local response organizations and for notification of emergency personnel by all response organizations. The content of initial and followup messages to response organizations and the public have been established.
Means to provide early notification and clear instructions to the populace within the plume EPZ have been established.
Emergency Plan Evaiuation: The Plan and associated procedures establish and describe a notification and verification system which is consistent with Appendix 1 to NUREG-0654. The system provides for notification of LNED, St.
Charles Parish Sheriff, and St. John the Baptist Parish Sheriff for each class of emergency, and for notification of LNED, St. Charles Parish Sheriff and Civil Defense Office, and St. John the Baptist Parish Sheriff and Civil Defense Office for Site Emergency and General Emergency.
The Plan has established procedures for notifying, alerting, and mobilizing LP&L emergency response personnel, including both staion and corporate staff.
The information to be reported to the offsite agencies in the event of an emergency has been predetermined in accordance with the recommendations in 13-17
 
NUREG-0654 and the format of the notification messages is included in the Plan. A means for verification of the messages has been provided. The Plan specifies the supporting information to be provided for inclusion in written messages intended for release to the public, including recommended protective actions.
The applicant is currently developing an alert and notification system to be used to promptly inform the public within the plume exposure pathway EPZ. The applicant has described the system and has committed to meet the criteria of Appendix 3 to NUREG-0654.
13.3.2.6 Emergency Communications Standard: Provisions exist for prompt communications among principal response organizations to emergency personnel and to the public.
Emergency Plan Evaluation: Primary and backup communication links which include provisions for 24-hr/day notification are provided with the Federal, State, and local emergency response organizations within the 10-mi EPZ. The Plan includes organizational titles and alternates for both ends of the communication links.
The offsite communication systems include the National Alert Warning System (NAWAS), commercial telephone, dedicated telephone lines, microwave, and radio. The Plan provides for periodic testing of the entire communication system.
The Plan illustrates the communications between the State and local EOC, radiological monitoring teams, NRC headquarters, NRC Regional EOC, EOF, TSC, and the radiological monitoring team assembly areas.
The Plan describes the arrangements for offsite medical support and contains written agreements for offsite medical care and for transportation to these faciiities. The Plan describes a coordinated communication link for fixed and mobile medical support facilities.
13.3.2. 7 Public Information Standard: Information is made available to the public on a periodic basis on how they wi11 be notified and what their initial actions should be in an emergency; the principal points of contact with the news media for dissemination of information during an emergency (including physical location or locations) are established in advance; and procedures for coordinated dissemination of information to the public are established.
Emergency Plan Evaluation: The applicant wi11 institute a public education program for the public within the plume EPZ. The program provides for the annual update of information provided. This information will include: (1) educational information on radiation, (2) contact for additional information, (3) protective measures, and (4) special needs of the handicapped. The Plan describes the program for ensuring that the transient population within the plume EPZ is provided an opportunity to become aware of the information.
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The applicant will conduct annual training for personnel of the news media which will acquaint these persons with the Plan, information concerning radia tion, and points of contact for release of public information during an emergency.
The applicant has committed to establish an Emergency News Center in the Emergency Operations Facility. The Emergency News Director is responsible for disseminating information to the public via the media, holding press conferences, and releasing information approved by the Site Support Manager. The director will notify and coordinate in a timely manner with the Louisiana Nuclear Energy Division, the NRC, and local officials before statements and bulletins are publicly disseminated.
13.3.2.8 Emergency Facilities and Equipment Standard: Adequate emergency facilities and equipment to support the emergency response are provided and maintained.
Emergency Plan Evaluation: Emergency facilities to support an emergency response have been established as follows:
(1)  Technical Support Center (TSC):
A dedicated, onsite TSC has been established for management and engineering personnel to support reactor control functions, to evaluate and diagnose plant conditions, and for a more orderly conduct of plant emergency operations.
Located in the control room envelope, the Waterford 3 TSC has the same heating, ventilating, air conditioning, and radiological habitability as the control room for postulated accident conditions. Permanent radiation monitoring is installed in the TSC. These systems continuously monitor radiation dose rates and airborne radioactivity concentrations. These monitoring systems include local alarms set to provide early warning to TSC personnel of adverse conditions that could affect the habitability of the TSC.
The TSC will have facilities to support the plant management and technical personnel who will be assigned there during an emergency and will be the primary onsite communications center for the plant during the emergency. TSC personnel will use the TSC data system to analyze the plant steady-state and dynamic behavior before and throughout the course of an accident. This information will be transmitted to the TSC via the plant computer to two CRT (cathode-ray tube) consoles. Power supply to the plant computer is provided from the emergency diesel generators. The results of this analysis will be used to provide guidance to the control room operating personnel in the manage ment of abnormal conditions and in accident mitigation. TSC personnel will also use the environmental and radiological information available from the TSC data system to perform the necessary functions of the EOF when this facility is not operational. The TSC may also be used to provide technical support during recovery operations following an emergency.
The TSC Supervisor will coordinate activities in the TSC and will be assisted by the Technical Support Coordinator, Health Physics Coordinator, Operations Coordinator, and their supporting staffs. The TSC will be staffed in a timely manner in accordance with Table B-1 to NUREG-0654, Rev. 1.
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Communications in the TSC include hotline telephones to the NRC Operations Center; dedicated telephone on the NRC health physics network, plant telephone system to control room, operational support center (OSC), and EOF; radio system to radiological monitoring teams (LP&L frequency), and to St. Charles Parish and St. John the Baptist Parish (Civil Defense and State Police frequency); and NAWAS to Louisiana Nuclear Energy Division, Louisiana Office of Emergency Preparedness, Louisiana State Police Headquarters, St. Charles Parish, and St. John the Baptist Parish.
The TSC will have a complete and up-to-date repository of plant records and procedures at the disposal of TSC personnel to aid in their technical analysis and evaluation of emergency conditions. In particular, up-to-date as-built drawings of the plant systems are needed to diagnose sensor data, evaluate data inconsistencies, and identify and counteract faulty plant system elements.
To ensure that TSC personnel can remain self-sufficient, emergency equipment and supplies are stored in the Technical Support Center.
(2)  Operational Support Center:
The designated location for the OSC is an area in the service building. The OSC is an assembly area where the operations support personnel and members of the emergency teams report in an emergency situation. The OSC will accommodate at least 100 people. Communications will be provided with the control room, the TSC and the LP&L near-site emergency operations facility. Emergency supplies including respiratory protection, protective clothing, and portable lighting and commmunications equipment are provided.
(3)  Emergency Operations Facility:
LP&L Luling District Office which is approximately 8 mi SE of Waterford 3 has been designated as the near-site emergency operations facility. The EOF will have facilities for:
(a)  Management of overall licensee emergency response (b)  Coordination of radiological and environmental assessment (c)  Determination of recommended public protective actions (d)  Coordination of emergency response activities with Federal, State, and local agencies.
Facilities will be provided in the EOF for the acquisition, display, and evaluation of all radiological, meteorological, and plant system data pertinent to determine offsite protective measures. The EOF will not only be used for coordination of offsite radiological monitoring during an emergency but will also be used to coordinate emergency response activities with those of Federal, State, and local organizations.
The EOF will be the central location for information dissemination to the public via the news media. This facility will be used for the receipt and analysis of all field monitoring data and coordination of sample media.
Capability for personnel decontamination will be provided.
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The Site Support Manager will manage all activities at the EOF. Additionally the Technical Support Manager, the Emergency News Director, and their respective staffs will coordinate their activities from the EOF. The EOF will be staffed in a timely manner.
The communication systems that may be utilized at the EOF are:
(a)  Hotline telephone on the NRC emergency notification system to the NRC Operations Center (b)  Dedicated telephone on the NRC health physics network (c)  Commercial telephone system (d)  Radio system to radiological monitoring teams (LP&L frequency) and to St.
Charles Parish and St. John the Baptist Parish (Civil Defense and State Police frequency)
(e)  NAWAS system to Louisiana Nuclear Energy Division, Louisiana Office of Emergency Preparedness, St. Charles Parish, St. John the Baptist Parish, and Waterford 3 Technical Support Center.
The EDF technical data system will receive, store, process and display information sufficient to perform assessments of the actual and potential onsite and offsite environmental consequences of an emergency condition. Data providing information on the general condition of the plant also will be available for display in the EOF.
The EDF will have ready access to up-to-date plant records, procedures, and emergency plans needed to exercise overall management of licensee emergency response resources.
(4)  Corporate Command and Recovery Center A Corporate Command and Recovery Center will be established at the LP&L General Office under the direction of the Emergency Director to direct and manage the recovery effort. This center will support the LP&L nearsite emergency operations facility.
The TSC, OSC, .and EOF are activated for Alert, Site, and General Emergencies.
LP&L has committed to establishing the TSC and EDF that conform to NUREG-0696.
The Plan describes the fellowing to be used for assessing eme;gencies:
(a) meteorological instrumentation, (b) radiological monitors to include field survey monitors, (c) process monitors, (d) fire detection devices, (e) an environmental radiological monitoring program, (f) laboratory facilities, and (g) seismic and hydrologic monitors. Engineering analyses are currently in progress to determine the design, technical feasibility, and installation require ments for equipment required by NUREG-0737. These include: (a) radiation and process instrumentation, (b) high-range effluent monitors, (c) post-accident sampling capability, and (d) in-plant iodine instrumentation. Subsection 13.3.6.5.1.6 of the Plan has been revised to provide a description of the onsite capability and resources for providing initial values and continuing assessment that meet the requirements of NUREG-0737. As the effort to establish compliance with the requirements of NUREG-0737 continues, the emergency plan will be updated through the submittal of amendments.
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The environmental radiological monitoring program provides environmental data for the site and surrounding areas. The program consists of many sampling stations that may be used for accident assessment. The program will be upgraded before fuel loading to meet the NRC Radiological Assessment Branch Technical Position for the Environmental Radiological Monitoring Program.
Maps showing preselected radiological sampling and monitoring points will then be included in the Waterford 3 Emergency Plan. Identification of points will include the designators in Table J-I of NUREG-0654.
The Waterford 3 plant has an onsite meteorological monitoring system designed to comply with the criteria of Regulatory Guide 1.23, Revision 1 and Appendix 2 of NUREG-0654, Revision 1. The onsite meteorological monitoring program will consist of two independent tower locations. Each location will be fenced and contain an equipment shelter, a meteorological tower, a complete lightning protection system, and adequate night illumination.
The 60-m (199 ft) primary tower will monitor wind speed and direction, and temperature difference (t) at 10 and 60-m. The 40-m (130 ft) backup tower will monitor the above meteorological parameters at the 10-m level (t at 10-40 m).
Signals from both meteorological towers will be transmitted to the plant.
Meteorological information coming into the computer will be available for use by the Computerized Emergency Planning and Data Acquisition System (CEPADAS) for prediction of effluent transport and diffusion. The National Weather Service (NWS) will provide backup meteorological data from two nearby locations:
New Orleans International Airport and the NWS Office in New Orleans.
The Plan provides for emergency equipment to be located at key locations onsite and at St. Charles Hospital, EOF, and LP&L's General Office offsite.
Appendix G to the Plan contains lists of typical emergency equipment at each specified location. The Emergency Planning Coordinator is responsible for planning and scheduling, on a quarterly basis and after each use, the inventory and inspection of designated emergency equipment. Portable radiation monitoring equipment included in these inventories will be calibrated in accordance with approved procedures. Instruments/equipment removed from the emergency equipment inventory for calibration or repair will be replaced with normal station equipment such that the emergency equipment is always at its full complement.
The Plan states that hydrologic information may be obtained from the U.S. Army Corps of Engineers.
In addition to seismic instrumentation onsite, seismic information wiii be available from several offsite seismic stations as described in Subsection 13.3.6.5.2.6 of the Plan.
13.3.2.9 Accident Assessment Standard: Adequate methods, systems, and equipment for assessing and monitoring actual or potential offsite consequences of a radiological emergency condition are in use.
Emergency Plan Evaluation: The Plan identifies specific instrument readings and other observable and measurable parameters which, if exceeded, will initiate an emergency as discussed in Section 13.3.2.4 of this report. A methodology for 13-22
 
relating radionuclide releases to Protective Action Guides (PAGs) is specified in the Emergency Plan Implementing Procedures and is provided as part of the Computerized Emergency Planning and Data Acquisition System (CEPADAS) which will be installed by LP&L at Waterford 3. Based on continuous online and off line acquisition and processing of radioactive effluent and meteorological data, CEPADAS will perform an assessment of radiological releases under both routine and accident conditions. Following an accidental release of radioactivity, CEPADAS will perform dose projections based on the best release and atmospheric dispersion data available. The source of the data will be, preferably, effluent monitors and the meteorological tower and, less preferably, the operator. The output of CEPAOAS is a series of tables and figures which indicate the radio logical impact of the accident as a function of time following the release of radioactivity.
Backup manual dose assessment procedures are included in the Emergency Plan Implementing Document. CEPAOAS will be loaded on the Waterford 3 plant computer at the end of April 1981. After loading, the system will undergo benchmark testing for compatibility with the plant computer. Subsequent testing will continue as the system is integrated with the plant's effluent and meteorological monitors. It is expected that the system will be fully operational before fuel loading.
The Plan describes monitors which will be used for initial values and continuing assessment as described in Section 13.3.2.8 above. Engineering analyses are being performed to determine the design, technical feasibility, and installation requirements for special equipment as described in Section 13.3.2.8.
The Plan illustrates the relationship between containment monitor readings and the activity in containment. The containment monitor reading will provide an indication of the source term of radioactive material within, and potentially available for release from the containment. Airborne releases from the contain ment will be exhausted through the plant stack, which is a common monitored release point for the normal exhaust from the reactor auxiliary building, as well as emergency exhaust from the shield building ventilation system and the controlled ventilation area system. The relationship between radiation monitor readings and the principal effluent release points is discussed in the Plan.
The Plan describes the offsite monitoring program which includes, but is not limited to, capability and resources for field monitoring within the plume EPZ.
The plan also describes activation, notification means, field team composition, transportation, communication, monitoring equipment, deployment times, and capa bility to detect and measure radioiodine in the plume EPZ as low as 10- 7 &#xb5;Ci/cc under field conditions.
A projected dose from a liquid release, whether it be within normal limits or assumed to be an incident, can be determined through procedural methods. The concentrations of radioactivity being released can be determined from installed radiation monitors, samples, release records, or, if necessary, can be estimated, The release rate and flowpath can be determined as well. The appropriate dilution factors may be applied to the concentration in the effluent at the point of measurement to allow for the additional dilution by circulating water. Therefore, specific concentrations can be determined through the use of procedures included in the emergency plan implementing document.
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13.3.2.10 Protective Response Standard: A range of protective actions has been developed for the plume EPZ for emergency workers and the public. Guidelines for the choice of protective actions during an emergency, consistent with federal guidance, are developed and in place, and protective actions for the ingestion exposure pathway EPZ appropriate to the locale have been developed.
Emergency Plan Evaluation: The Plan establishes guides for determining when protective actions are required onsite to include evacuation, use of protective clothing, and the use of respiratory protection. Monitoring and decontamination of onsite evacuees will be conducted at the designated assembly area. The storage locations for emergency equipment and supplies are specified in the Plan. Personnel accountability will be performed at the assembly area within 30 min of the emergency. Accountability thereafter is continuously monitored by the security computer for those individuals entering the protected area.
The actuation of fire alarms, radiation alarms, radiation alert alarms, telephone calls, and public address announcements, as applicable, will immediately alert employees, visitors, contractors, and other onsite personnel to hazardous condi tions and actions they must take. Such actions may be to assemble in emergency teams, report to accountability stations, evacuate specific areas within the site, or evacuate the site. Notification will include the control room of the adjacent fossil units, Waterford 1 and 2. Coordination of protective actions for personnel assigned to these units will be the responsibility of their staffs.
Provisions are made for transportation and evacuation routes, including alter nates, for onsite personnel. Additional onsite protective measures include the use of individual respiratory protection, protective clothing, and radio protective drugs.
The Plan provides for recommending offsite protective measures depending on the projected dose to the environs. The particular recommendation may be sheltering or evacuation depending on the magnitude of the projected dose, the meteorological conditions, the nature of the release, and the predetermined evacuation time estimates for the sector(s) affected. The Plan contains maps and information regarding evacuation routes and areas, shelters, and the population distribution around the facility.
The Plan contains time estimates for evacuation within the plume EPZ. The evacuation time estimate study provided by the applicant is currently being reviewed by the staff.
LP&L has committed to establishing a personnel decontamination facility at the near-site EOF for those contaminated. individuals evacuated from the site. The design is currently in progress. Following the completion of the design it will be described in the Plan. Specific procedures for performing decontamination will be described in the implementing procedures.
The following item requires resolution:
Evacuation time estimates, currently under review by the staff, must satisfy the criteria of Appendix 4 to NUREG-0654. A supplement to this 13-24
 
report will provide the staff's conclusions as to the acceptability of the evacuation time estimates.
13.3.2.11 Radiological Exposure Control Standard: Means for controlling radiological exposures, in an emergency, are established for emergency workers. The means for controlling radiological exposures shall include exposure guidelines consistent with EPA Emergency Workers and Lifesaving Activity Protective Action Guides.
Emergency Plan Evaluation: The applicant has established a radiation protection program for controlling radiological exposures in the event of an emergency.
Emergency exposure guidelines have been provided for the various categories of radiation workers. These guidelines are consistent with the EPA Emergency Worker and Lifesaving Activity Protective Action Guides. Emergency procedures specify the persons authorized to permit emergency exposures in excess of 10 CFR Part 20 limits.
The Plan provides for 24-hr/day determination of doses received by onsite emergency workers and offsite response personnel and for appropriate record keeping.
The Plan provides for personnel decontamination facilities. Onsite contami nation control measures for personnel, equipment, and access control are provided. The criteria for decontamination of personnel and equipment are specified in implementing procedures. Procedures have been established for contamination control measures with regard to drinking water and food supplies and criteria for permitting return of areas to normal use.
LP&L has committed to establishing a decontamination facility at the near-site EDF as described in Section 13.3.2.10 above.
13.3.2.12 Medical and Public Health Support Standard: Arrangements are made for medical services for contaminated and injured individuals.
Emergency Plan Evaluation: The applicant has made arrangements with the St.
Charles Hospital located approximately 8 mi from the site and the Ochsner Clinic to provide medical support for personnel injured or exposed to radiation and/or radioactive materials. Ground transportation is provided by an onsite company ambulance. Augmented transportation capability by air rescue will be available from West Jefferson General Hospital. Onsite first aid facilities are provided by LP&L. Provisions for transportation to an offsite medical facility by personal or company vehicle are also described in the Plan.
LP&L has committed to incorporating the Emergency Medical Assistance Plan for St. Charles Hospital and Ochsner Clinic in the Waterford 3 Emergency Plan.
13.3.2.13 Recovery and Reentry Planning and Postaccident Operations Standard:  General plans for recovery and reentry are developed.
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Emergency Plan Evaluation: The Plan describes the applicant's general plans for recovery and reentry. The Emergency Director (Senior Vice President, Operations) is responsible for determining the need for and aspects of the recovery plan and organization. Any changes or additions to this organization dictated by the nature of the accident will be made by the Emergency Director.
Emergency plan procedures provide instructions for reentry activities.
The Senior Vice President, Operations will make the decision to shift from the emergency organization to the long-term recovery organization and initiate notification of the appropriate officers and department heads. He will then activate the Corporate Command and Recovery Center and manage the recovery operation.
The Vice President, Power Production will assume the duties of the Recovery Manager and will be responsible for the overall recovery of the plant.
13.3.2.14  Exercises and Drills Standard: Periodic exercises are (will be) conducted to evaluate major portions of emergency response capabilities, periodic drills are (will be) conducted to develop and maintain key skills, and deficiencies identified as a result of exercises or drills are (will be) corrected.
Emergency Plan Evaluation: An emergency exercise will be conducted annually and will be based on an accident scenario postulating at least a Site Emergency.
The scenario will be varied so that all plans and preparedness organizations are tested within a 5-yr period. One exercise will start between midnight and 6:00 a.m. and another between 6:00 p.m. and midnight once every 6 years. Some exercises will be unannounced.
The Emergency Planning Coordinator is responsible for the planning, scheduling, and coordinating of drills and exercises. All drills and exercises are approved by the Plant Manager. The annual exercise is approved by the Vice President, Power Production.
Each drill and exercise is conducted to test the state of emergency preparedness and is designed to meet a list of specific objectives which are specified in the Plan. The Emergency Planning Coordinator will coordinate and implement Plan revisions and required corrective actions resulting from the drills and exercises.
Drills are supervised instruction periods aimed at testing, developing, and maintaining skills in the following areas and frequencies:
(1)  Communication drills: Initial plant contact with State and county governments will be tested monthly; communications with Federal response agencies and States within the 50-mi EPZ will be tested quarterly, and communications between the site, State, and local EOCs and field assessment teams will be tested annually. Communication drills will include the aspect of understanding the content of messages.
(2) Fire drills, quarterly.
(3) Medical emergency drills, annually.
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(4)  Radiological monitoring drills, annually.
(5)  Health physics drills, semiannually.
13.3.2.15 Radiological Emergency Response Training Standard: Radiological emergency response training is provided to those who may be called upon to assist in an emergency.
Emergency Plan Evaluation: The Plan provides for training and qualifying personnel on the emergency tasks for which they are responsible as specified in the Plan. The Training Superintendent is responsible for coordinating the training of all station personnel. All Waterford 3 personnel are indoctrinated on the Plan and the Emergency Plan Implementing Procedures (EPIPs). The Plan describes specialized training and retraining for personnel assigned to the emergency organization, including licensed operators, radiation emergency team, first aid and rescue team, fire brigade, security team, Onsite Emergency Organization, and Offsite Emergency Support Organization, and the Emergency Planning Coordinator .
LP&L will provide training and annual retraining for those offsite organizations whose services may be required in an emergency, such as fire, police, medical support, and rescue personnel. The training will be consistent with the organization 1 s emergency functions.
Each member of the First Aid and Rescue Team will receive the Standard Red Cross Multimedia First Aid Course.
The training program for members of the LP&L emergency organization will include practical drills as discussed in Section 13.3.2.14 of this evaluation.
13.3.2.16  Responsibility for the Planning Effort:  Development, Periodic Review, and Distribution of Emergency Plans Standard: Responsibilities for plan development and review and for distribution of emergency plans are established, and planners are properly trained.
Emergency Plan Evaluation: The Emergency Planning Coordinator, a member of the plant staff, is responsible, in part, for the coordination and compatibility of the Plan with State and local plans and EPIPs, assisting in coordinating emergency preparedness training, coordinating emergency exercises and drills, coordinating review audits and updating the Plan and EPIPs, ensuring the main tenance and inventory of emergency equipment, and ensuring that all elements of the total emergency organization are informed of changes to the Plan and EPIPs. The Plan describes the Plant Manager as having overall emergency responsibility onsite. The Plan identifies the Senior Vice President, Operations as having overall authority and responsibility for emergency response planning.
The Plan together with the appended letters of agreement and other planning documents will be reviewed and updated once a year.
An independent audit of the emergency preparedness program will be performed at least every 12 months.
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The Plan and EPIPs will be reviewed by the Plant Operations Review Committee and the Safety Review Committee, and will be distributed in accordance with approved administrative procedures.
Telephone numbers in the EPIPs will be updated quarterly.
13.3.3 Conclusions Based on NRC review against the criteria in 11 Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants,t NUREG-0654, Revision 1, November 1980, the staff 1
concludes that the Waterford 3 Nuclear Station Radiation Emergency Plan, upon satisfactory correction of those items requiring resolution and those items committed to by LP&L as identified in Section 13.3.2 of this evaluation, will provide an adequate planning basis for an acceptable state of emergency pre paredness and will meet the requirements of 10 CFR 50 and Appendix E thereto.
After receiving the findings and determinations made by FEMA on State and local emergency response plans, and after reviewing the revision(s) to the applicant's Plan, a supplement to this report will provide the staff's overall conclusion on the status of emergency preparedness for Waterford 3 and related EPZs.
The final NRC approval of the state of emergency preparedness for the Waterford 3 site will be made following implementation of the emergency plans to include development of procedures, training and qualifying of personnel, installation of equipment and facilities, and a joint exercise of all the plans (site, State, and local).
13.4 REVIEW AND AUDIT In FSAR Amendment 17 and in its {{letter dated|date=April 20, 1981|text=April 20, 1981 letter}}, the applicant has pro posed to establish three groups of people to perform independent reviews of important matters affecting plant safety. These groups are the corporate Safety Review Committee (SRC), the Plant Operations Review Committee (PORC),
and the Onsite Safety Review Subgroup. In addition, the Quality Assurance Program will provide an independent review and audit of operation, maintenance, and testing activities. The results of the quality assurance reviews and audits will be presented to the SRC.
An SRC will be established with the responsibiiity for formal offsite review and evaluation of plant design, operation, maintenance and test programs. The SRC is appointed by, and will report to the Vice President, Power Production.
Membership is as follows:
(1)  Assistant Vice President, Nuclear Operations (Chairman)
(2)  Waterford 3 Project/Offsite Support-Project Manager (3)  Quality Assurance Manager (4)  Corporate Safety Engineer (5)  Manager System Nuclear Operations (Middle South Services)
(6)  Waterford 3 Plant Manager, Nuclear (7)  Waterford 3 Project/Offsite Support Group Engineering-Engineering Supervisor 13-28
 
(8) Waterford 3 Project/Offsite Support Group Technical Services-Engineering Supervisor (9) Waterford 3 Project/Offsite Support Group-Discipline engineers (as appro-priate)
LP&L has committed to having the Safety Review Committee established and imple mented by July 1, 1981, To ensure that formal onsite review and evaluation of plant operation, main tenance and test programs are conducted, a Plant Operation Review Committee has been established and has been performing review and evaluation of plant activities since February 1, 1980. The PORC is appointed by, and reports to the Waterford 3 Plant Manager, Nuclear. The composition is as follows:
(1) Designated Assistant Plant Manager (Chairman)
(2) Technical Support Superintendent (Vice Chairman)
(3) Maintenance Superintendent, Nuclear (4) Operations Superintendent, Nuclear (5) Nuclear engineer (6) Health Physics engineer (7) Instrumentation and Control engineer (8) Quality Control engineer The applicant has committed to providing an Independent Safety Engineering Group to perform the functions of and be staffed in accordance with the require ments of Item I.B.1.2 of NUREG-0737, 11 Clarification of TMI Action Plan Requirements. 11 The applicant calls this group the Onsite Safety Review Subgroup.
The Onsite Safety Review Subgroup will consist of five dedicated, full-time, site based engineers who report offsite to the Waterford 3 Project/Offsite Support Manager. This group will be composed of three utility engineers, one engineer, and one supervisor. The technical disciplines represented in this group will be electrical, instrumentation and controls, mechanical, radiation protection, and nuclear. The supervisor of this group will have a BS degree in engineering or the physical sciences and 8 yrs of responsible experience of which 3 yrs will be nuclear experience. The applicant finds it is also desirable for the supervisor to have previously held an SRO or RO (reactor operator) license.
The other four engineers in this group will have, as a minimum, a BS degree in engineering or the physical sciences and 2 years of nuclear experience in their discipiine.
This group will be fully staffed and functional by fuel loading. The applicant is currently actively recruiting the supervisor and engineer for this group.
During the remainder of construction and startup, this group will be responsible for developing and implementing the Onsite Safety Review Program. This will include, in addition to the development of the formalized written program and supporting procedures, actual on-the-job experience (minimum 3 mo) at operating nuclear power facilities. Although this group will not be fully staffed and functional until fuel loading, the applicant anticipates that this group will be providing independent review of plant staff activities beginning during the fourth quarter of 1981.
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The staff has not completed its review of the staffing of these groups, the staff qualifications, and the details of their functions and prescribed activities. During the audit team visit (see Section 13.1 of this report),
NRC staff will review these matters, including the directives and administrative procedures governing the operation of these groups, and will report the results of the review in a supplement to this report.
13.5 PLANT PROCEDURES 13.5.1 Administrative Procedures All safety-related operations at Waterford 3 will be conducted in accordance with detailed written and approved procedures. The applicant has stated in FSAR Amendment 15, that the administrative procedures will be consistent with the recommendations of Re?iulatory Guide L 33 11 Qua 1 ity Assurance Program Requirements (Operation), 1 Revision 2, February 1978.
Cognizant station supervisors are responsible for initiating, preparing, and controlling plant procedures consistent with their responsibilities and ensuring that work is performed in accordance with the latest applicable documents. Review of those procedures that affect the public health and safety is accomplished by the Plant Operations Review Committee (PORC). The Plant Manager approves and promulgates plant procedures after the PORC review.
Many of the administrative procedures required for the conduct of operation for Waterford 3 will be written, utilized and proven to be adequate for proper administrative control during the initial phases of Waterford startup. A detailed schedule for individual plant procedures is being developed as part of a startup scheduling effort. Plant procedures shall be completed and approved six months prior to fuel loading. Plant emergency procedures will be generated by the plant staff with a separate independent review to be conducted by the nuclear steam supply system vendor. A listing of procedures required for plant operation has been formulated, reviewed and approved, and will be used for tracking the progress of procedure generation.
Administrative procedures are reviewed for adequacy by the Office of Inspection and Enforcement prior to authorization for plant operation. In addition, selected administrative procedures, identified following the TMI-2 accident, are of particular interest to the staff. These procedures, discussed in numbers I.C.2 through I.C.6 of Section 22 of this report under the heading 11 TMI Action Item, 11 will be reviewed for adequacy by the staff prior to authorization for plant operation.
13.5.2 Operating and Maintenance Procedures The Waterford 3 operating and maintenance procedures will be reviewed using the criteria of the revised standard review plan. This review is currently underway and the results wi11 be reported in a supplement to this SER.
13.6 PHYSICAL SECURITY The applicant has submitted security plans entitled 11 Waterford Steam Electric Station Unit 3 Physical Security Plan," 11 Waterford Steam Electric Station 13-30
 
Unit 3 Guard Training & Qualification Plan," and 11 Waterford 3 Steam Electric Station Safeguards Contingency Plan, for protection against radiological 11 sabotage.
As a result of the staff 1 s evaluation, certain portions of the security plan were identified as requiring additional informtion and upgrading to satisfy the requirements of Section 73.55 and Appendices Band C of 10 CFR Part 73.
The applicant filed revisions to their guard training and qualification plan and to their safeguards contingency plan. The revised plans are considered to meet the requirements of 10 CFR Part 73, and therefore to be acceptable. The applicant has filed detailed commitments to revise the physical secur}ty plan responsive to staff comments. The security plan, when revised in accordance with the applicant 1 s written commitments, will be considered to meet the require ments of 10 CFR Part 73 and therefore to be acceptable.
An ongoing review of the progress of the implementation of these plans will be performed by the staff to assure conformance with the performance requirements of 10 CFR Part 73.
13-31
 
==13.7 REFERENCES==
American National Standards Institute:
ANSI Nl8.l-1971 Code of Federal Regulations:
10 CFR Part 50, Appendix E 10 CFR 50.47(8) 10 CFR Part 55 EPA Emergency Workers and Lifesaving Activity Protective Action Guides Letters:
Agreement letter with the Missouri Pacific Railroad Co., November 1, 1978 Agreement letter between USCG and Louisiana Office of Emergency Preparedness, October 17, 1980 Letter from H. R. Denton, NRC, dated march 28, 1980 Letter from LP&L to NRC, dated April 20, 1981 Letter from LP&L to NRC, dated May 15, 1981 Louisiana Power and Light Co.:
Excerpt from Board of Directors meeting of April 14, 1981 FSAR for Waterford 3, Amendment 15 FSAR for Waterford 3, Amendment 17 FSAR for Waterford 3, Sections 13.2.3, 13.3.2, 13.3.3 Regulatory Guides:
RG 1.8 RG 1.23, Rev. 1, September 1980 Standard Review Plan:
SRP Section 13.2 State of Louisiana:
Act 449 of 1979 Legislature Peacetime Radiological Response Plan USNRC report:
NUREG-0654/FEMA-REP-1, November 1980 NUREG-0696, Rev. 1 NUREG-0731 NUREG-0737
*See Appendix B, Bibliography, for complete citations and availability statements.
13-32
 
14 INITIAL TEST PROGRAM The testing activities to be performed on safety-related systems at Waterford 3 are divided into three major phases: prerequisite testing, preoperational testing, and initial startup testing.
Prerequisite testing will generally begin as installation and/or construction of individual structures, components, and systems near completion. The prime objective of this phase is to verify that construction activities associated with the respective structure, component, and system have been completed and documented. Another function is to verify that the components within the sy?tem can be put safely into operation. The testing requirements associated with this phase will verify installation integrity, component operability, and appli cable system functional characteristics, and will ensure that the structures, components, and systems are ready for preoperational testing.
Preoperational testing will be performed to demonstrate the capability of systems, structures, and components to meet safety-related performance requirements.
These tests will be performed on plant systems, structures, and components that are designed to perform a nuclear safety-related function. Preoperational testing will be completed before loading fuel, with certain limited exceptions where tests or parts of tests will be deferred until the core has been loaded.
In such cases, sufficient tests will be performed before fuel loading to provide reasonable assurance that the postloading test will be successful.
Initial startup testing will commence with the initial fuel load and will include the following areas of testing: precritical tests, initial criticality, low power physics tests, power ascension tests, and the nuclear steam supply system (NSSS) warranty run. The purpose of precritical testing is to perform and/or resolve outstanding tests and deficiencies from the preoperational testing program, and to complete the required post-fuel-load tests. The balance of the testing associated with this phase of the program is designed to assure that fuel loading is effected in a safe manner; that the plant is safely brought to rated capacity; that plant performance is satisfactory in terms of established design criteria; and to demonstrate, where practical, that the plant is capable of withstanding anticipated transients and postulated accidents.
The staff review concentrated on the administration of the test program and the completeness of prerequisite, preoperational, and startup tests.
The Commission's Safety Evaluation Report, issued at completion of NRC's con struction permit review, was reexamined to determine the principal design criteria for the plant and to identify any specific concerns or unique design features that would warrant special test consideration. Chapters 1 through 12 of the FSAR were reviewed for familiarization with the facility design and nomenclature. Chapters 13 and 17 were reviewed to become familiar with the applicant's organizational structure, qualifications, administrative controls, 14-1
 
and quality assurance program as they app1y to or impact the initial test program. Chapter 15 was reviewed to identify assumptions pertaining to per formance characteristics that should be verified by testing and to identify all structures, systems, components, and design features that were assumed to function (either explicitly or implicitly) in the accident analysis. licensee event reports for operating reactors of similar design were reviewed to identify potentially serious events and chronic or generic problems that might warrant special test consideration. Standard technical specifications for Combustion Engineering PWRs were reviewed to identify all structures, systems, and com ponents that would be relied upon for establishing conformance with safety limits or limiting conditions for operations. Finally, the Startup Test Reports for other PWR plants were reviewed to identify problem areas that should be emphasized in the Waterford 3 initial test program.
The object of the staff review of FSAR Chapter 14 was to determine whether the acceptance criteria stated in the Standard Review Plan are met. The review covered several aspects of the initial test program including the following major considerations:
(1) The applicant's organization and staff for performing the initial test program were reviewed. An adequate number of appropriately qualified personnel are assigned to develop test procedures, conduct the tests, and review the results of the tests. Plant staff personnel are used to maximize the training benefits of the test program.
(2) The applicant stated that the test procedures were developed using input from the NSSS vendor, the architect-engineer, the applicant's engineering staff, and other equipment suppliers and contractors as needed. The appli cant also stated that its review of operating experiences at similar plants was factored into the development of the test procedures.
(3) The applicant stated that the tests are being conducted using approved test procedures, and that administrative controls cover (a) the completion of test prerequisites, (b) the completion of necessary data sheets and other documentation, and (c) the review and approval of modifications to test procedures. The applicant stated that administrative procedures also cover implementation of modifications or repair requirements identified as being required by the tests and any necessary retesting.
(4) The applicant stated that the results of each test are reviewed for technical adequacy and completeness by qualified personnel including NSSS vendor and architect-engineer as appropriate. Preoperational test results are reviewed before fuel loading, and the startup test results from each activity or power level will be reviewed before proceeding to the next activity or power level.
(5) The applicant stated that normal operating and emergency procedures are used in performing the initial test program, thereby verifying the correct ness of the procedures to the extent practical.
(6) The applicant's schedule for conducting the initial test program a11owed adequate time to conduct all preoperational tests and startup tests. The schedule for performing the startup tests established that systems required to prevent, limit, or mitigate the consequences of postulated accidents wi11 be tested before exceeding 25% of rated power, and that the safety 14-2
 
of the plant will not depend on the performance of untested systems, structures, and components. Preoperational test procedures will be avail able for NRC Inspection and Enforcement review at least 60 days before the expected performance of the test, and startup test procedures will be available at least 60 days before fuel loading.
(7) The abstract of each test procedure presented in Chapter 14 of the FSAR was reviewed. The staff verified there are test abstracts for those struc tures, systems, components, and design features that: (a) will be used for shutdown and cooldown of the reactor under normal plant conditions and for maintaining the reactor in a safe condition for an extended shut down period; (b) will be used for shutdown and cooldown of the reactor under transient (infrequent or moderately frequent events) conditions and postulated accident conditions and for maintaining the reactor in a safe condition for an extended shutdown period following such conditions; (c) will be used for establishing conformance with safety limits or limiting conditions for operation that will be included in the facility technical specifications; (d) are classified as engineered safety features or will be relied on to support or ensure the operation of engineered safety features within design limits; (e) are assumed to function or for which credit is taken in the accident analysis of the facility, as described in the FSAR; and (f) will be used to process, store, control, or limit the release of radioactive materials.
(8) The test objectives, prerequisites, test methods, and acceptance criteria for each test abstract were reviewed in sufficient detail to establish that the functional adequacy of the structures, systems, components, and design features will be demonstrated.
(9) The test program 1 s conformance with applicable regulatory guides was reviewed. The review included: Regulatory Guides 1.20, 11 Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing11 ; 1.41, 11 Preoperational Testing of Redundant Onsite Electric Power Systems to Verify Proper Load Group Assignments";
1.52, 11 Design, Testing, and Maintenance Criteria for Atmosphere Cleanup System, Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants"; 1.68, 11 Preoperational and Initial Startup Test Programs for Water-Cooled Powers Reactors"; 1.68.2, 11 Initial Startup Test Program to Demonstrate Remote Shutdown Capability for Water-Cooled Nuclear Power Plants''; 1.79, "Preoperational Testing of Emergency Core Cooling Systems for Pressurized Water Reactors 11 ; 1.80, "Preoperational Testing of Instrument Air Systems''; and 1.108, 11 Periodic Testing of Diesel Generator Units Used as Onsite Electrical Power Systems at Nuclear Power Plants."
The applicant made a number of changes to the initial test program because of staff comments. Examples of these changes are as follows:
(1) The qualification requirements for those personnel who prepare preopera tional and startup test procedures was significantly upgraded, as were the specified minimum requirements for the Joint Test Group members.
(2) Acceptance criteria for the major preoperational and startup tests were expanded to ensure that quantifiable reference data were available to establish whether the actual test objectives had been attained.
14-3
 
(3)  A formal review of testing and operating experiences at other nuclear power stations using Combustion Engineering NSSS was included. This ensured that before the Waterford 3 preoperational test program began, potential problem areas could be identified and any special testing, procedure modifi cation, or design changes could be made.
(4)  Expanded descriptions of auxiliary startup instruments used during initial criticality were provided, and documentation that would require adequate overlap of source and intermediate range neutron instrumentation was established.
(5)  Testing was added to demonstrate that, for hot containment penetrations where coolers are not used, concrete temperatures do not exceed design limits.
(6)  Testing was added to verify that emergency de loads not previously verified by vendor tests can start and operate at a voltage equal to the battery design minimum voltage.
(7)  Testing was added to more fully demonstrate the ability of the emergency diesel generators and their support 'equipment to provide reliable emergency power.
(8)  Testing was added to more accurately determine the reactor protection system trip response times.
(9)  Natural circulation tests were expanded and will be repeated for training purposes to comply with TMI-2 Action Plan Item I.G.l for low power training and testing.
Based on NRC review, including the items discussed above, the initial test pro gram described in the application meets the acceptance criteria of Section 14.2 of the Standard Review Plan. The successful completion of the program will demonstrate the functional adequacy of plant structures, systems, and compo nents. The staff also concluded that the initial test program described meets the test requirements of GDC 1 of 10 CFR Part 50 Appendix A and Section XI of 10 CFR Part 50, Appendix B.
14-4
 
REFERENCES*
General Design Criterion:
GDC 1 Louisiana Power and Light Co. report:
FSAR for Waterford 3, Chapters 1-14, 17 Regulatory Guides:
RG 1.20 RG 1. 41 RG 1.52 RG 1. 68 RG 1.68.2 RG 1. 79 RG 1. 80 RG 1.108 USNRC reports:
NUREG-0660, Item I.G.1 NUREG-75/087 See Appendix 8, Bibliography, for complete citations and availability statements.
14-5
 
15 ACCIDENT ANALYSIS 15.1 GENERAL DISCUSSION 15.1.1 Introduction The staff has evaluated the response of the Waterford 3 plant to postulated disturbances in process variables and to postulated malfunctions or failures of equipment. The potential consequences of each event are examined to determine their effect on the plant, to determine whether plant protection systems are adequate to limit consequences of such occurrences, and to ensure that the design criteria of the applicable regulations are met. The criteria set forth in NUREG-75/087 (Standard Review Plan) are considered an applicable means for meeting the regulations.
Initial plant conditions for the safety analyses are given in Table 15.1. This range of initial conditions corresponds to a range compatible with the monitoring functions of the core operating limit supervisory system (COLSS) which is a nonsafety-related instrumentation system that aids the operator in maintaining the plant within the limiting conditions of operation (LCD). COLSS monitoring and calculational functions include peak linear heat rate, margin to departure from nucleate boiling (DNB), total core power, and azimuthal tilt. COLSS compares these parameters to their LCOs and provides an alarm to the operator via the plant computer if an LCO is approached or exceeded.
A range of fuel parameters based on first-core values are used for the safety analyses. These include Doppler weighting factors from 0.85 to 1.15, moderator temperature coefficients from +0.5 x 10- 4 L\p/&deg; F to -3.3 x 10- 4 L\p/&deg; F, shutdown control element assembly (CEA) reactivity worth available at full power and zero power at -8.85% P and -4.4.5% P, respectively, and decay heat generation rate based upon an infinite reactor operating period at full power. The decay heat curve used in the analyses is that required by 10 CFR 50, Appendix K.
The reactivity insertion curve, used to represent the control assembly insertion, accounts for a stuck rod, in accordance with GDC 27.
CE-1 is the DNB correlation used to determine thermal margins in the transient analyses. The applicability of CE-1 is discussed in Section 4.4 of this report.
The reactor protection system (RPS) trips considered in the analyses in accord ance with GDC 20 are:
(1) High logarithmic power level, (2) High linear power level, (3) Low departure from nucleate boiling ratio (DNBR) (core protection calculator (CPC)),
(4) High local power density (CPC),
15-1
 
Table 15.1 General initial conditions Pa rameter and abbreviation        Unit              Range Core power, B                      % of 3410 MWt      8<102 Radial 1-pin peaking factor                            FRl. 7 FR (with uncertainty)
Axial shape index, ASI*                                -0.6< ASI<+/-0.6 Core inlet coolant flowrate, G      % of 143  X 106    100<G<120 lbm/hr Core inlet coolant                  OF                520<T<560 tempe rature, T System pressure, P                  psia              2000<P<2300 A      - Aupper
*AS!= lower              where Alower =  area under axial shape in A total                    lower half of core; Aupper =  area under upper half axial shape in of core; and Atotal =  total area under axial shape .
15-2
 
(5) High pressurizer pressure, (6) Low pressurizer pressure, (7) Low steam generator water level, (8) Low steam generator pressure.
Time delays to trip and uncertainties in trip times are included in the analysis.
The CPC system consists of four digital calculators (one in each RPS protection channel) which calculate DNBR and local power density. These values are compared with trip setpoints for initiation of a low DNBR trip and high local power density trip.
The low DNBR trip is provided to trip the reactor core when the calculated DNBR approaches a preset value. The algorithms which calculate the minimum DNBR include allowance for sensor and processing time delays and uncertainties.
Many events as analyzed in Chapter 15 of the Waterford 3 FSAR have their minimum DNBR reach exactly 1.19 as calculated by the CE-1 correlation.
Input to the CPC includes core inlet and outlet temperature, pressurizer pressure, reactor coolant pump speed, excore flux power, selected CEA positions, and CEA deviation penalty factors. Calculations performed by the CPC include reactor coolant system (RCS) flowrate, T power, axial power distribution, fuel rod radial peaking factors, DNBR, local power density, core average power, CEA deviation alarm, and calibrated excore power. Outputs from CPC available to the operator on a display and control panel include DNBR margin, local power density margin, and calibrated neutron flux. The operator can also monitor all calculators, including specific inputs or calculated functions.
The staff evaluations of the CPC system are addressed in Section 4.4 and Section 7.2 of this report.
15.1.2    Analytical Techniques The analysis methods used for postulated transients and accidents are normally reviewed on a generic basis. In this regard, the staff has received submittals from Combustion Engineering (CE) of the computer codes and methods used in the analysis of reactor transients as shown in Table 15.2. The mathematical model used in steam line break accident and the feedwater line break analyses is described in the Combustion Engineering Standard Safety Analysis Report (CESSAR) application, as discussed below. The CE topical reports associated with the thermal-hydraulic design of the Waterford 3 reactor cores are discussed in Section 4.4 of this report.
Generic topical report on methods of analysis of steam and feed line breaks have been submitted for staff approval by CE in appendices to the CESSAR System 80 FSAR. Information specific to Waterford 3 steam and feed line break analysis has been submitted by the applicants. NRC review of this information is not yet complete. However, the results of the review to date indicate that there is reasonable assurance that the conclusions based on these analyses will 15-3
 
Table 15.2 Topical reports for codes used in safety analyses Topics and topical report                                Status Large-Break LOCA Code CENPD-132                                            Approved CENPD-132, Supplement 1                              Approved CENPD-132, Supplement 2                              Approved LOCA Slowdown Code CENPD-133                                            Approved CENPD-133, Supplement 2                              Approved LOCA Refill/Reflood Code CENPD-134                                            Approved CENPD-134, Supplement 1                              Approved Fuel Rod Heat Transfer Code CENPD-135                                            Approved CENPD-135, Supplement 2                              Approved CENPD-135, Supplement 4                              Approved Reflood Code When Reflood at Less Than 1 Inch per Second CENPD-138                                            Approved CENPD-138, Supplement 1                              Approved Heat Transfer Coefficients for 16 x 16 Fuel Bundles Code CENPD-123                                            Approved Small-Break LOCA Evaluation Model Code CENPD-137                                            Approved CENPD-137, Supplement 1                              Approved Reactor Coolant Code for Flow During Coastdown Transient CENPD-98                                            Approved CEA Ejection Analysis Code CENPD-190                                            Approved Code Used To Simulate NSSS CENPD-107                                            Under review (approved CENPD-107, Supplement 1                              for Code application CENPD-107, Supplement 2                              to ATWS only)
CENPD-107, Supplement 3 CtNPU-1U7, Supp1ement 4 CENPD-107, Supplement 5 CENPD-107, Supplement 6 ATWS Analysis for CE Plants CENPD-158                                            Approved Loss of Flow Analysis Method CENPD-183                                            Approved with conditions Core Thermohydraulics Code CENPD-161                                            Approved CENPD-206                                            Approved CENPD-207                                            Under review 15*4
 
not be appreciably altered by completion of the analytical review. If the final approval of the analytical methods indicates that any revisions to the analyses are required, the applicant will be required to implement the results of such changes at Waterford 3.
The topical reports on the methods used in the analysis of reactor transients are under review by the staff. The status of the code reviews is listed below:
(1)  CENP0-107 CESEC--Digital Simulation of a Combustion Engineering Nuclear Steam Supply System, April 1974 The CESEC computer program is used for the analysis of various system transients and is currently under review by the staff. If final approval of CENP0-107 indicates that any revisions to the analyses are required, this information shall be included in the Waterford 3 review.
(2)  CENPD-207--Core Thermo-Hydraulics Code The CENP0-207 is used for the analysis of core thermo-hydraulics and is currently being reviewed by the staff. If final approval of CENPD-107 indicates that any revisions to the analyses are required, this information shall be included in a supplement to this SER.
There is reasonable assurance that the conclusions based on these analyses will not be appreciably altered by completion of the analytical review. If the final approval of the analytical methods indicates that any revisions to the analyses are required, Waterford 3 will be required to implement the results of such changes.
Based on previous acceptable analyses for CE plants, on a cornpar1s1on with other industry models, on independent staff audits calculations, and on previous startup testing experience, the staff concludes that, with the exception noted above, the analytical methods used are acceptable for the safety analyses performed for Waterford 3.
15.2 NORMAL OPERATION AND ANTICIPATED TRANSIENTS The applicant has analyzed several events expected to occur one time or more during the lifetime of the plant. It is demonstrated that all the transients are terminated without exceeding specified fuel design limits (ONBR remains at or above 1.19 using the CE-1 correlation) and that the reactor coolant pressure stays beiow the applicable ASME Code limits. For transients plus single failure events, core geometry is maintained in such a way that there is no loss of core cooling capability and control rod insertability is maintained. Radiological consequences must be a small fraction of 10 CFR Part 100 limits. Radiological consequences for various postu1ated events are given in Section 15.4 of this report.
15.2.1  Increase in Heat Removal by the Secondary System The applicants have analyzed the following events which produce increased primary system cooling:
(1)  Decrease in feedwater temperature, 15-5
 
(2)  Increase in feedwater flow, (3)  Increase in main steam flow, (4)  Inadvertent opening of steam generator atmospheric dump valve.
The most severe of these events is the increased main steam flow event. The inadvertent opening of a turbine bypass valve is the most severe of several postulated increased steam flow transients. The low DNBR trip limits the minimum DNBR to slightly above 1.19, the minimum DNBR limit. The emergency feedwater system in conjunction with the low steam generator water level trip signal will maintain adequate inventory in the steam generators. The closure of the main steam isolation valves following the low steam generator pressure signal will terminate the steam flow from the turbine bypass valve. The maximum reactor coolant system pressure and secondary pressure do not exceed 110% of the design pressure for these events. None of these events progresses to a more serious plant condition unless additional faults occur. Therefore, the staff finds the results of these events acceptable.
For transients with a concurrent single failure of an active component, the most limiting event with respect to DNBR and system pressure is the increase in main steam flow with a loss of all offsite power when a reactor trip condition exists.
Failure of all the condenser circulating water pumps was also considered but was less severe than loss of offsite power. The peak primary and secondary system pressures are less than 110% of the system design pressures. The decreas ing forced reactor coolant flow results in a minimum DNBR of 1.12. Approximately 0.34% of the fuel pins will have experienced DNBR. The results of the applicant's analysis for the events that cause an increase in heat removal by the secondary system with a concurrent single failure are acceptable, on condition that the concerns below are adequately addressed and support the conclusions listed above.
It is not clear why the stuck-open atmospheric dump valve event for Waterford 3 results in fuel damage whereas the steam line break event (more severe primary system cooldown) does not result in exceeding the minimum DNBR limit. Moreover, plants such as CESSAR do not experience DNB for the stuck-open dump valve transient. More information is needed regarding the reasons for these differ ences before NRC can make an acceptability finding.
15.2.2 Decrease in Heat Removal by the Secondary System The applicant analyzed the following events which cause a decrease in secondary side heat removal:
(1)  Loss of external load, (2)  Turbine trip, (3)  Loss of condenser vacuum, (4)  Loss of normal ac power, (5)  Loss of normal feedwater flow.
The most limiting transient with respect to DNBR is the loss of normal ac power where the calculated minimum DNBR is 1.19. A reactor trip occurs as a result of a low DNBR trip. The maximum calculated pressure for these events is also 15-6
 
achieved by the loss of normal ac power transient where peak RCS pressure reaches 2434 psia. These results are acceptable because the system pressure and fuel limits are not violated.
For transients coupled with a single failure, the most limiting event with respect to DNBR is the loss of normal ac power with a concurrent single failure.
The maximum calculated RCS pressure for these events is 2712 psia for the loss of condenser vacuum with failure of the pressurizer level management channel.
Another single failure considered for the loss of condenser vaccurn was loss of all ac power on turbine trip.
The applicant's calculations show that for transient events leading to decrease in heat removal by the secondary system (with and without single failure), at most a small fraction of the fuel rods in the reactor fail for transients with a single failure, core geometry, and control rod insertability are maintained with no loss of core cooling capability, and maximum RCS pressure remains below 110% of design. The results of these analyses are acceptable.
15.2.3  Decrease in Reactor Coolant Flow Rate The applicant analyzed the following events that lead to a decrease in reactor coolant flow.
(1)  Partial loss of forced reactor coolant flow, (2)  Total loss of forced reactor coolant flow.
The partial loss of forced reactor coolant flow is bounded by the total loss of forced reactor coolant flow.
A loss of power to all reactor coolant pumps produces a reduction of coolant flow through the reactor core. The reduction in coolant flow rate causes an increase in the average coolant temperature in the core and a decrease in the margin to DNB. A low DNBR reactor trip is generated by the core protection calculators to prevent the minimum DNBR calculated with the CE-1 correlation from decreasing to below 1.19 at any time during the transient. The maximum calculated RCS pressure is maintained below 110% of design pressure during these transients.
15.2.3.1 Single Reactor Coolant Pump Shaft Seizure During a reactor coolant pump shaft seizure accident, the following criteria must be met. Offsite doses at the exclusion boundary should be a small fraction of 10 CFR Part 100 guideline values. Core geometry should remain intact so that there is no loss of core cooling capability or control rod insertability.
If the DNBR for any fuel pin falls below the 1.19 minimum DNBR limit, release of all of the gaseous fission product inventory should be assumed. Loss of offsite power and the technical specification limit for steam generator tube leakage should also be assumed in the analysis for this event. Reactor coolant pressure should be maintained below the applicable ASME Code limits, and a rotor seizure, by itself, should not degenerate into a more serious condition or result in the loss of function of the RCS or containment barriers.
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The applicant 1 s analysis of this event as presented in the FSAR does not meet the above stated criteria. NRC requires that the applicant reanalyze this event using the above criteria. The resolution of this item will be reported in a supplement to this SER.
15.2.3.2 Single Reactor Coolant Pump Sheared Shaft During a reactor coolant pump sheared shaft event, the acceptance criteria are the same as the criteria stated in Section 15.2.3.1, for the reactor coolant pump shaft seizure event.
The analysis of this event has not been provided in the FSAR. However, the applicant, in Amendment 17 to the FSAR, has committed to provide a safety grade protection system for this postulated event and to submit an analysis of this event.
NRC's evaluation of the applicant's analysis will be reported in a supplement to this SER.
15.2.4 Reactivity and Power Distribution Anomalies 15.2.4.1 Uncontrolled CEA Withdrawal From a Subcritical or Low Power Condition The consequences of an uncontrolled CEA withdrawal at low power have been analyzed. Such a transient can be caused by a failure in the control element drive mechanism, control element drive mechanism control system, reactor regulating system, or by operator error. The analysis assumes a conservatively small (in absolute magnitude) negative Doppler coefficient and the most positive moderator coefficient. The reactivity insertion rate corresponds to approximately twice the largest insertion rate expected from the sequential withdrawal of the CEA groups with 40% overlap at the maximum speed of 30 in./min. The transient is terminated with a maximum DNBR of 1.19 in the hot channel. Fuel centerline temperatures do not exceed U0 2 melting and the highest RCS pressure produced is well below the emergency limit of 2750 psia.
The staff has reviewed the reactivity worths and reactivity coefficients used in the analysis and concludes that conservative values have been used. The calculated consequences of this design transient are acceptable.
The requirements of GDC 20, which requires that protection be automatically ini tiated, and GOC 25, which requires that single failure of the protection system does not result in violation of specified fuel design limits, have been satisfied.
15.2.4.2 Uncontrolled Withdrawal of Control Element Assembly at Power The consequences of uncontrolled CEA withdrawal in the power operating range have been analyzed. The effect of the resulting power transient causes an increasing temperature and pressure transient which, together with the power distribution shift to the top of the core, causes a rapid approach to the fuel design limits. The initial conditions assumed in the analysis include the lowest RCS pressure, a power level of 76% of full power, a bottom peaked core average axial power distribution, a conservatively sma11 Doppler coefficient, and the most positive moderator coefficient. The reactivity insertion rate is based 15-8
 
on calculated CEA worths (including 50% uncertainty) and on the maximum with drawal rate capability of the CEA drive system. The transient is terminated with a minimum DNBR of 1.19 in the hot channel and with fuel temperatures well below centerline melt.
The basis for acceptance in the staff review is that the applicant's analysis method has been reviewed and approved, the input parameters have been found to be suitably conservative, and the results show that no fuel damage occurs.
The staff concludes that the calculations contain sufficient conservatism with respect to input assumptions and models to assure that fuel damage will not result from control rod withdrawal errors. The staff further concludes that the requirements of GDC 20 and 25 have been met.
15.2.4.3 Misoperation of Control Element Assembly The CEA misoperation events analyzed by the applicant include individual full or part-length CEA drops and dropping of part-length CEA subgroups. A subgroup is defined as any one set of four symmetrical CEAs, which is controlled by the same control element drive mechanism control system.
The effect of any individually misoperated control element assembly on core power distribution will be evaluated by the CEA calculators, and an appropriate power distribution penalty factor will be transmitted to the core protection calculators. The CPCs will, themselves, assess other changes in core conditions (for example, changes in coolant temperature, axial power distribution, power level) and initiate a low DNBR or high local power density trip if required.
However, there are trip delay times associated with the CPC-generated DNBR and high local power density trips, and time is required to insert CEAs following scram. To ensure that the CPCs can accommodate all misoperation events, it must be demonstrated that the elapsed time between initiation of the event and the time the core approaches either the DNBR or local power density limit is sufficient to allow for CPC scram initiation and CEA insertion. Therefore, the misoperating events of most interest are those that result in a rapid decrease in margin to safety limit.
The worst full-length CEA drop incident is caused by the dropped CEA that produces the maximum increase in the radial peaking factor and the least nega tive reactivity insertion.
The drop of a single part-length CEA or subgroup results in either a negative or positive reactivity change depending on the initial part-length CEA position and the axial distribution of thermal neutron flux. Appropriate most negative Doppler and moderator temperature coefficients were used accordingly.
The analyses of the nuclear steam supply system (NSSS) response (tota1 power, coolant temperature, system pressure) were performed using the CESEC code.
The detailed response of the core (hot channel, power, heat flux, fuel and cladding temperatures, etc.) was calculated using the STRIKIN code. The thermal margin on DNBR in the core was calculated using the TORC computer program with the CE-1 critical heat flux correlation. Since the consequences of a single 15-9
 
CEA or bank drop are strongly dependent upon the axial power distribution that exists at the start of the transient, the analyses were performed using several different axial power distributions as initial conditions with each distribution characterized by an axial shape index (ASI)*.
The results of these analyses show that the most rapid approach to the DNB specified acceptable fuel design limits for a CEA misoperation is caused by either the single full-length CEA drop or the part-length CEA subgroup drop.
The single part-length drop causes the most rapid approach to the centerline melt specified acceptable fuel design limits. For each case studied, the DNBR assumed as an initial condition was varied until the minimum departure from nucleate boiling ratio reached during the transient was equal to 1.19.
The staff has reviewed the analysis of the misoperation events and finds acceptable the general approach used to establish that, during the most limiting events, no violations of the specified acceptable fuel design limits on ONBR, centerline fuel temperature, and RCS pressure occur.
15.2.4.4 Inadvertent Boron Dilution The applicant has identified a boron dilution event when in cold shutdown (mode 5) because of a chemical and volume control system (CVCS) malfunction, as the limiting boron dilution transient, since it results in the shortest availab1e time for detection and termination. The applicant has stated that there are various indications to an operator (that is, charging pump on, pressur izer level rising, low boron concentration alarm) concerning the occurrence of a boron dilution event. However, it is the staff's position that the applicant has not demonstrated that the plant is protected for postulated boron dilution events in all modes assuming the worst single active failure. The staff will require that the plant be appropriately protected against the failure of the first alarm as part of in the boron dilution analysis. The applicant must also demonstrate that the operator action times available between the receipt of the alarm and the time shutdown margin will be lost are consistant with the times listed in II.2.d of SRP Section 15.4.6. The analysis for Mode 5 must also consider the possibility of a partially drained hot leg.
In Amendment 19 to the FSAR, the applicant committed to provide additional alarms on the startup channel flux monitors, to protect against the failure of the first alarm. Additionally the applicant committed to provide the necessary anaiysis to demonstrate compliance with SRP Section 15.4.6, regarding times available for action following detection of a boron dilution event. The staff finds these committments acceptable, and will review and confirm the analysis results prior to fuel loading.
*ASI = pbot - ptOQ where      = power in the bottom half of the core, pbot PT            ptop
                              = power in the top half of the core, and PT  = total core power 15-10
 
The staff will report on the resolution of the above concerns in a supplement to this SER.
15.2.4.5  Inadvertent Loading of a Fuel Assembly Into the Improper Position The staff has evaluated the consequences of postulated fuel loading errors.
The two errors considered were (1) the erroneous loading of fuel pellets or fuel rods of different enrichment in a fuel assembly, and (2) the erroneous placement or orientation of fuel assemblies. The analyses provided by the applicant have shown for each case considered that either the error is detectable by the available instrumentation (and hence remediable) or the error is undetect able, but the offsite consequences of any core damage are only a small fraction of the 10 CFR Part 100 guideline.
15.2.4.6 Ejection of the Control Element Assembly The mechanical failure of a control rod mechanism pressure housing would result in the ejection of a CEA. For CEAs, initially inserted, the consequences would be a rapid reactivity insertion together with an adverse core power distribution, possibly leading to localized fuel rod damage. Although mechanical provisions have been made to make this accident extremely unlikely, the applicant has analyzed the consequences of such an event.
Methods used in the ana1ysis are reported in CENPD-190-A which has been reviewed and accepted by the staff. This report demonstrates that the model used in the accident analysis is conservative relative to a three-dimensional kinetics calculation.
Four cases were analyzed: beginning-of-cycle at 102% and at zero power, and end-of-cycle at 102% and at zero power. The calculated total average enthalpy of the hottest fuel pellet was well below the Regulatory Guide 1. 77 (Ref. 2) acceptance criterion of 280 ca1/gm. Analyses have been performed to show that the pressure pulse produced by the rod ejection will not stress the RCS boundary beyond faulted limits. Further analyses have shown that a cascade effect is not credible.
The ejected rod worths and reactivity coefficients used in the analysis have been reviewed and have been judged to be conservative. The assumptions and methods of analysis used by the applicant are also in accordance with those recommended in Regulatory Guide 1.77. Therefore, this analysis is acceptable.
15.2.5  Increase in Reactor Coolant System Inventory The applicant has evaluated the fo1lowing events which result in an increase in the RCS inventory:
(1)  eves  malfunction, (2)  CVCS malfunction with a concurrent single failure of an active component, (3)  Inadvertent operation of the emergency core cooling system (ECCS) during power operation.
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The maximum primary and secondary system pressures for these two CVCS malfunction events are less than 110% of the system design pressure. The DNBR remains well above 1.19 during these events.
Actuation of the safety injection system during power operations will not cause injection of coolant into the RCS. During power operation, the core protection calculators ensure that the RCS pressure is greater than 1785 psia. This pres sure exceeds the shutoff head of the safety injection pumps and the safety injection tank pressure.
The analysis assumes that the transient is terminated by the operator 1 s manual action at 30 min after the start of the transient, to turn off charging pumps and letdown flow.
The staff finds the results of the increase in RCS inventory events acceptable because fuel damage limits and the primary and secondary system presssure limits are not violated and these events do not generate more serious plant conditions unless other faults occur independently.
15.2.6 Startup of an Inactive Loop Power operation with an inactive coolant loop is not permitted by the Waterford 3 Technical Specifications. Therefore, this event need not be analyzed for Waterford 3.
15.2. 7 Conclusions The applicant has presented results for various anticipated operational occur rences (with and without assumed single failures). With the exceptions previously noted, the staff finds they meet NRC acceptance criteria with respect to fuel and primary system performance. Therefore, the applicant has provided adequate protection for anticipated operational occurrences (except as noted) and is considered in compliance with GDC 10, 15, and 26.
15.3 LIMITING ACCIDENTS The applicant has analyzed events, which, though not expected to occur during the lifetime of the plant, could have serious radiological consequences if not effectively mitigated. For accident conditions, the reactor coolant pressure should stay below the applicable ASME Code limits. The core geometry should be maintained so that there is no loss of core coolina caoabilitv and control rod insertability. Radiological consequences must be-weli within the 10 CFR Part 100 limits. Radiological consequences are discussed in detail in Section 15.4 of this report.
15.3.1 Steam Line Breaks During a steam line break (SLB) accident, the RCS pressure must remain blow the applicable ASME Code limits. Fuel failure is assumed if the minimum DNBR criteria are violated using appropriate design correlations. Radiological consequences of the SLB event are discussed in Section 15.4.
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Three SLB accidents are analyzed by the applicant: (1) a full power, double ended SLB (inside containment) with concurrent loss of offsite power; (2) a full power, double-ended SLB (inside containment) with no loss of offsite ac power; and (3) a hot zero power, double-ended SLB (outside containment) with concurrent loss of offsite ac power. These events are analyzed assuming various conservative parameter inputs including steam quality, Doppler reactivity, moderator reactivity, void reactivity feedback, core mixing, CEA worth and feed water flow.
In the analyses, moisture carryover was not permitted during steam generator blowdown, the moderator reactivity was chosen as a function of the lowest cold leg temperature, and there was no thermal mixing in the core lower plenum. A study of single failures was performed to determine which is most limiting.
Failures considered included failure of main feedwater isolation valve to close after a main steam isolation signal (MSIS), failure of one main steam isolation valve to close after MSIS, failure of turbine stop valves to close after reactor trip, failure of one diesel generator to start after loss of offsite ac power, and failure of one high pressure safety injection (HPSI) pump to start after a safety injection actuation signal (SIAS). This study showed that loss of one HPSI pump had the most adverse effect. Various assumptions regarding time of loss of offsite ac power and the location and size of the SLB inside and outside containment were analyzed. The worst break with respect to fuel damage was a loss of ac power coincident with the complete severance of a main steam line inside containment. For the limiting case (loss of offsite power with the break inside containment), a low DNBR trip trips the reactor and a low steam generator pressure trip initiates MSIS. Low primary system pressure initiates SIAS.
After 30 min, the operator initiates plant cooldown by manual control of the atmospheric steam dump valve associated with the intact steam generator.
For all three SLB events analyzed, the minimum DNBR never decreased below 1.19 and the maximum primary and secondary system pressures did not exceed 110% of design pressure.
In the submittal, the applicant has not addressed the outcome of losing offsite power during the transient (that is, other than time zero), nor has tripping of the reactor coolant pumps (RCPs) during the transient been evaluated for the limiting conditions. These evaluations are required as part of SRP Section 15.1.5 and the TMI requirements, which direct the operator to trip the RCPs upon ECCS initiation. NRC requires the applicant to address these concerns before a finding of acceptability is made.
The results of the applicant's analyses were performed utilizing the CESEC-II computer program. This program does not properly account for steam formation in the reactor vessel and in the primary system after the pressurizer empties.
Neglecting these effects results in the improper evaluation of the system pressure and hydraulic behavior.
The modeling deficiency in CESEC-II has the potential for providing unacceptable results for depressurizing transients. As such, for transients that empty the pressurizer or result in saturation at other locations in the primary system, the CESEC-II computer program must be verified to correctly calculate system thermal-hydraulic response. The staff requires the applicant to reanalyze these events with a suitable model in order to demonstrate the acceptability of the CESEC-II program to predict the thermal-hydraulic phenomena in question, and to demonstrate compliance with GDC 10, 15, and 26.
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15.3.2 Feedwater System Pipe Breaks Feedwater system pipe break acceptance criteria require that the peak reactor coolant system and main steam pressures during the analyzed accident be below the applicable ASME Code limits. Fuel damage that results from pipe break may be such that the calculated doses at the site boundary are a fraction of 10 CFR Part 100. The full spectrum of break areas is analyzed by the applicant, and the largest break is most limiting. System input parameters are chosen in order to maximize the RCS pressure and to maximize the mismatch between core power and steam generator heat removal capacity. The worst credible single active failure is considered the failure of one out of the three emergency feedwater pumps. Loss of normal electrical power is assumed at the time of turbine trip.
High pressurizer pressure initiates the reactor trip. The low water level in the steam generators actuates the emergency feedwater system. The emergency feedwater flow reaches the steam generator with the intact feedwater line 70 sec after the pipe break. The maximum RCS pressure during the accident is 2832 psia (110% of design is 2750 psia), the maximum steam generator pressure is 1138 psia (110% of design is 1210 psia), and the minimum DNBR is 1.20. The core geometry is maintained so that core cooling capacity is not impaired. The maximum RCS pressure during the accident of 2832 psia (approximately 113% of design pressure) exceeds the limit of acceptance criteria in the Standard Review Plan. However, the ASME Boiler and Pressure Vessel Code Section III, Division 1 contains a provision that permits, under emergency conditions, the stress in the RCS compo nents to reach 120% of design value. Since the feedwater pipe break accident does not cause the stress value in RCS components to exceed the above Code limit, is acceptable because the plant meets the ASME Code requirements.
However, based on review of the applicant 1 s methodology, the staff cannot yet conclude on the overall acceptability of the feedwater line break analysis.
It is the understanding of NRC that the methodology utilized for analyzing feed water line breaks is documented in Appendix 15B of CESSAR. However, the results documented in CESSAR differ from those in the Waterford 3 FSAR. Specifically, the CESSAR FSAR states that the limiting break size is in the small break range (that is, 0.02 ft2 ). The Waterford 3 FSAR, however, states that the limiting break is a double-ended guillotine break. The CESSAR FSAR states that the break flow is assumed to be saturated liquid. However, the Waterford 3 FSAR analyses predict two phase flow exiting the break (see Figure 15.2-51). Based on these described differences, the staff does not have adequate information to conclude on the acceptability of the feedwater line break methodology. Therefore the applicant is required to describe the differences between the feedwater line break methodology utilized for Waterford 3 and that documented in the CESSAR FSAR. In addition, the applicant should describe why the limiting feedwater line break for Waterford 3 is a double-ended guillotine break, but for CESSAR the limiting break is a smaller size break.
15.3.3  Loss-of-Coolant Accident The acceptance criteria for a LOCA as required by 10 CFR Section 50.46 are:
(1)  The calculated maximum fuel element cladding temperature shall. not exceed 2200 &deg; F, (2)  The calculated total oxidation of the cladding shall not exceed 17% of the total cladding thickness before oxidation, 15-14
 
(3) The calculated total amount of H2 generated from the chemical reaction of the cladding with water or steam shall not exceed 1% of the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react, (4) Calculated changes in core geometry are of such a nature that the core shall remain amenable to cooling, (5) After any calculated successful initial operation of the ECCS, the calcu lated core temperature shall be maintained at an acceptable low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity.
Details of the ECCS mitigating and long-term cooling systems for a LOCA are given in Section 6.3 of this report. The applicant analyzed a complete break spectrum for large breaks (1.0 ft2 , 0.8 ft2 , 0.6 ft2 , and 0.4 ft2 double-ended slot and guillotine and a 0.5 ft2 slot). These calculations are made using approved Code models which meet the requirements of Appendix K to 10 CFR Part 50.
During the LOCA calculation, offsite power is assumed lost. The time of ECCS flow delivery to the core includes a delay time for the startup of the diesel generators. In addition, all ECCS flow delivered to the broken cold leg is assumed to spill directly to containment. Studies show that the worst single failure for the large break spectrum is the failure of one low pressure safety injection pump to start. Containment parameters are chosen to minimize the calculated containment pressure so that core reflood calculations are conserva tively calculated. Fuel rod initial conditions are chosen to maximize clad temperature and oxidation. The applicant performed clad ballooning calculations which show that none of the LOCAs analyzed had core geometry changes of a magni tude large enough to significantly reduce core cooling capability. Calculations of core geometry are carried out past the point where temperatures are decreasing.
The most limiting break with respect to peak clad temperature is the 0.6 ft2 double-ended slot (DES)  break in the pump discharge (PD) leg. The peak clad temperature is 2137&deg; F, which is below the 2200&deg; F limit. The limiting local and core-wide clad oxidation values calculated by the applicants were 12.34%
local for the 0.6 ft2 DES/PD and 0.799% core-wide for the 1.0 ft2 DEG/PD (double-ended guillotine/pump discharge).
In the initial FSAR submittal, small-break LOCAs were not calculated for Waterford 3. The applicant submitted a comparison between CESSAR and Calvert Cliffs Unit One and Waterford 3 in order to assure that small break results for Waterford 3 are bounded by the submitted results of the other plants. This comparison indicated that small breaks were not limiting. This comparison was not sufficient and the staff requested that the applicant perform a small-break analysis for Waterford 3. The applicant submitted a small-break analysis for postulated break sizes of 1.0 ft2 , 0.1 ft 2 , 0.075 ft 2 , 0.05 ft 2 , and 0.01&deg; ft 2 .
This analysis showed that the maximum peak cladding temperature was 1732 F for the 0.05 ft 2 break. The high pressure safety injection (HPSI) is the primary source of coolant makeup for the small-break LOCA. The applicant is committed in Section 14.2.12 of the FSAR, to perform a preoperation test of the HPSI pumps to quantify the actual pump flow performance and verify that the flow performance utilized in the ECCS analyses are conservative with respect to the actual performance.
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The analysis for small breaks takes credit for the charging and borating portion of the eves, which is considered a part of the safety injection system. The review of these analyses indicated that the analytical assumptions used might not be compatible with the eves performance when specific single failures and injection points, with regard to the break locations are considered. The appli cant was requested to address these concerns. The applicant has responded to these concerns and has provided the requested information. The applicant has shown that the small-break assumptions and analyses are conservative with respect to the specific single failures. The applicant reanalyzed the double-ended guillotine break of the charging line downstream of the last check valve and, taking no credit for charging flow, found the result to be bounded by the previously submitted small break spectrum.
The applicant 1 s submittals for L0CA analyses do not address the effects of steam generator tube plugging. The effects of a decrease in steam generator flow area is an increase in the peak cladding temperature (when the peak occurs during the reflood portion of the transient). The applicant will be required to perform additional ECCS analyses prior to any operation with plugged generator tubes. The applicant is required to include an interface requirement on the validity of the LOCA analysis (acceptance criteria of 10 eFR 50.46) and the Technical Specification limit for the number (or percentage) of allowable plugged steam generator tubes.
15.3.4 Steam Generator Tube Rupture The applicant simulated the NSSS response to a steam generator tube rupture using the CESEC computer program, both with and without concurrent loss of offsite power. In light of recent operating experience (the St. Lucie Unit 1 natural circulation cooldown event of June 11, 1980, and reanalyses of SAR Chapter 15 design basis events by St. Lucie in February 1981) a potential model ing deficiency has been identified in the CESEC computer program and NSSS model.
As the pressurizer cools down and system pressure decreases, steam can form in the reactor vessel head as a result of flashing of hot coolant in a stagnant region of the upper head. The steam bubble in the reactor vessel head displaces coolant from the reactor vessel into the pressurizer, and the steam in the reactor vessel head will determine the system pressure.
It is expected that the RCS pressure will be at or near the saturation pressure equivalent to the reactor vessel upper head temperature during steady-state operation, once the pressurizer empties.
The current CESEC model does not properly account for steam formation in the reactor vessel upper head and, after the pressurizer empties, the RCS pressure is seen to decrease to a value consistent with the saturation pressure corre sponding to the RCS average temperature. CESEC treats the RCS at a uniform pressure.
The potential modeling deficiency present in CESEC, treatment of steam formation in the reactor vessel upper head, results in a potentially unacceptable analysis for steam generator tube rupture events. Further, any CESEC analysis which predicts either that the pressurizer will empty or that the RCS saturates does not appear to correctly calculate the system thermal-hydraulic response and is not justified for use.
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The staff will require the applicant to reanalyze these events with a suitable model or provide additional justification why the CESEC analyses properly account for steam formation in the primary system in order for the staff to accept the results of these analyses as demonstration of compliance with GDC 10, 15, and 26.
15.3.5 Inadvertent Opening of a Pressurizer Safety Valve The design of the Waterford 3 RCS includes two safety valves on the pressurizer.
The RCS does not have power-operated relief valves. The applicant analyzed the inadvertent opening of a pressurizer safety valve using its small-break LOCA model. A low pressurizer pressure signal initiates reactor trip and turbine trip. A loss of offsite power is assumed to occur simultaneously with reactor trip. The worst single failure was identified as failure of one diesel to start. Thus, only one HPSI and one LPSI pump are assumed to be available.
The results of the calculation  show that the core does not uncover and the peak cladding temperature is 928&deg; F.
The applicant has classified this event as a limitin fault. The staff is in agreement with the applicant on the classification since the safety valves are considered passive devices. The intent of SRP Section 15.6.1 is to address those valves which have control systems that may fail causing an inadvertent opening (for example, a pressurizer relief valve). The applicant has performed a probabilistic assessment of a PWR pressurizer safety valve to inadvertently open. Using the combined operating history for 43 PWRs, in more than 497 operating years no PWR pressurizer safety valve inadvertent opening event has occurred. The probability of occurrence is calculated to be 2.78 x 10-3 per year. The classification of this event as a limiting fault is therefore consist ent with the ANSI Nl8.2 definition of the limiting fault cateijory. Based on the above, the staff finds the analysis and conclusions of this event acceptable.
15.3.6 Anticipated Transients Without Scram A number of plant transients can be affected by a failure of the scram system to function. For a PWR, the most important transients affected inciude loss of normal feedwater, loss of electrical load, inadvertent control rod withdrawal, and loss of normal electrical power. In September 1973, the staff issued WASH-1270, 11 Technical Report on Anticipated Transients Without Scram for Water Cooled Power Reactors, 11 establishing acceptance criteria for anticipated transients without scram. In conformance with the requirements of Appendix A to WASH-1270, CE submitted an evaluation of anticipated transients without scram in Topical Report CENPD-158, 11 Topical Report Anticipated Transients Without Scram. 11 On December 9, 1975, the staff issued 11 Status Report on Anticipated Transients Without Scram for Combustion Engineering Reactors." In response, CE issued Revision 1 to CENPD-158 in May 1976. A reevaluation of the potential risks from anticipated transients without scram (ATWS) has been published in NUREG-0460, Volumes 1 through 4. The status of NUREG-0460 is described below:
(1)  In March 1980 the 4th volume of NUREG-0460 was issued by the NRC staff.
The recommendations included design criteria for plants such as Waterford 3, and rulemaking to establish such criteria.
(2) The NRC staff presented its recommendations on ATWS to the Commission, including those for rulemaking, in September 1980.
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(3) After deliberation, the Commission will act on the matter. If rulemaking is initiated by the Commission, the staff would expect that any rule adopted would include an implementation plan for all classes of plants.
The applicant would be required to provide plant modifications for Waterford 3 in conformance with ATWS criteria and schedule requirements provided in the rule or as adopted by the Commission. The following discussion presents the bases for operation of Waterford 3 before the adoption of a rule.
In NUREG-0460, Volume 3, the staff states: 11 The staff has maintained since 1973 (for example, see pages 69 and 70 of WASH-1270) and reaffirms today that the present likelihood of severe consequences arising from an ATWS event is acceptably small and presently there is no undue risk to the public from ATWS.
This conclusion is based on engineering judgment in view of: (a) the estimated arrival rate of anticipated transients with potentially severe consequences in the event of scram failure; (b) the favorable operating experience with current scram systems; (c) the limited number of operating reactors." In view of these considerations and staff expectation that the necessary plant modifications will be implemented in 1 to 4 years following a Commission decision on ATWS, NRC has generally concluded that pressurized water plants can continue to operate because the risk from ATWS events in this time period is acceptably small. As a prudent course, in order to further reduce the risk from ATWS events during the interim period before completing the plant modification determined by the Commission to be necessary, the staff has required that the following steps be taken:
(1) Develop emergency procedures to train operators to recognize ATWS event, including consideration of scram indicators, rod position indicators, flux monitors, pressurizer level and pressure indicator, and any other alarms annunciated in the control room with emphasis on alarms not processed through the electrical portion of the reactor scram system.
(2) Train operators to take actions in the event of an ATWS, including consid eration of manually scramming the reactor by using the manual scram button, prompt actuation of the auxiliary feedwater system to assure delivery to the full capacity of this system, and initiation of turbine trip. The operator should also be trained to initiate boration by actuation of the HPSI system to bring the facility to a safe shutdown condition.
These procedural requirements provide  an acceptable basis for interim operation of the facility based on the staff 1 s understanding of the plant response to postulated ATWS events.
The applicant has committed to develop emergency procedures for and train operators to respond to ATWS per requirements (1) and (2) above. This is acceptable.
15.3. 7 Conclusions The applicant has presented results for various accidents which meet NRC accept ance criteria as detailed in Section 15 in the Standard Review Plan. With the exceptions noted, the applicant has provided adequate protection systems to 15-18
 
mitigate accidents in compliance with the applicable General Design Criteria relating to core coolability, control rod insertability, and primary system pressure boundary integrity.
15.4 RADIOLOGICAL CONSEQUENCES OF ACCIDENTS The applicant calculated the offsite doses that could result from the occurrence of each of several1 design basis accidents, in order to demonstrate the effective ness of the plant s engineered safety features (ESFs). The staff has independently performed similar calculations, in order to confirm the effectiveness of these features and to investigate the dependence of the computed doses upon variable aspects of the accidents.
The computed doses of several representative postulated accidents are listed in Table 15.3. Where these doses are significantly dependent upon the primary coolant iodine concentrations, or arise through multiple leakage paths, separate doses for extreme conditions or separate dose contributions for individual leakage paths have been listed. Details of each postulated accident and leakage path are discussed in the following sections.
NRC review procedures and assumptions are consistent with the applicable Standard Review Plans and Regulatory Guides (except for the meteorological portions),
as noted in each of the following discussions, and are outlined in Tables 15.4 through 15.8. The computed doses are presented in such a form as to allow direct comparison with the dose guidelines in 10 CFR Section 100.11, and are expressed as rems of thyroid and whole-body dose, either for a 2-hr period at the exclusion area boundary (EAB, 914 m from the reactor centerline), or for a 30-day period at the outer boundary of the low population zone (LPZ, 3219 m from the reactor centerline).
The atmospheric diffusion parameters (X/Q's) used in all these computations are those presented and discussed in this SER, Section 2.3.4. The meteorological models described in the regulatory guides referred to in the following discus sions have been applied in these calculations using the modifications presented in Regulatory Guide 1.145 (see Section 2.3.4 of this report for a further description of this modification).
15.4.1 Steam Line Break Accident The staff and the applicant have both evaiuated the radiological consequences of a postuiated steam line break occurring outside primary containment and upstream of the main steam isolation valve for two particular cases. For the first case, the staff and the applicant assumed that the primary system has experienced a previous iodine spike and that the concentration is equal to the maximum primary coolant concentration permitted by the CE Standard Technical Specifications. During the course of this accident, the shell side of the affected steam generator was assumed to boil completely dry and to stay dry because of the blocking off of auxiliary feedwater flow to the affected steam generator under the accident conditions. Because of the assumed dry condition in the affected steam generator, all the iodine transported by the primary to secondary leakage (1 gal/min) was assumed to be released directly to the atmo sphere. Although the releases from the secondary side of both the affected and unaffected steam generators would be vented to the atmosphere as an elevated release, the staff has conservatively assumed that all releases for the duration of the accident occur at ground level.
15-19
 
Table 15.3 Summary of computed accident dose consequences Times and locations of doses Exclusion area        Low population zone boundary*                boundary**
Thyroid    Whole body  Thyroid    Whole body Postulated accident            (rem)        (rem)      (rem)        (rem)
Fuel handling                  1.1      <1.0        <LO        <LO Waste gas tank failure                    0.4                    0.05 Liquid waste system failure    0.4        0.001 Main steam line break Case 1                    13.0                    2.4 Case 2                    18.0                    4.6 Small line break Case 1                    5.3                    0.1 Case 2                    16.0                    0.25 Case 3                  265.0                    4.2 Control rod ejection Case 1                    33.0        0.6        44.0        0.02 Case 2                  195.0        3.0          5.0        0.6 Steam generator tube rupture Case 1                    8. 2      <1.0          Ll        <0.1 Case 2                    66.5      <LO          9.2      <LO Loss of coolant Bypass                  195.0        0.7        130.0        0.2 SBVS                      4.0        0.6          9.0        1.6 CVAS                      23.0        6.2        12.0        2.1 Total                    222.0        7.6        151.0        4.2 Total loss-of-coolant LPZ dose by time interval 0-8 hr                                            73.0        2.8 8-24 hr                                          32.0        1.0 1-4 day                                          27.0        0.3 4-30 day                                          19.0        0.1
* 0-2 hr period at 914 m from the reactor centerline.
**0-30 day period at 3219 m from the reactor centerline.
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Table 15.4 Assumptions used in the radiological consequences analysis of the steam line break outside containment Parameter and unit of measure                          Quantity Initial thermal power (MWt)                            3478 Primary coolant iodine concentration for case 1 (&#xb5;Ci/gm DE I-131)                              60 Secondary coolant iodine concentration for cases 1 and 2 (&#xb5;Ci/gm DE I-131)                        0.1 Initial primary coolant iodine concentration for case 2 (&#xb5;Ci/gm DE I-131)                              6.5 Primary to secondary leakage in affected steam generator (gal/min)                              1.0 Increase in iodine release rate from defective fuel beginning at time t=O                            500 Relative concentrations (sec/m 3 )
0-2 hr at the exclusion area boundary                5.1  X 10-4 0-8 hr at the low population zone boundary          6.9  X 10- 5 No offsite power is available All primary to secondary leakage occurs in the steam generator associated with the ruptured steam line Releases of primary to secondary leakage occurs for 13,564 sec (i.e., until RCS temperature drops below 212&deg; F) 15-21
 
Tab1e 15.5 Assumptions used to calculate fuel handling accident doses Parameter and unit of measure              Quantity Power level(MWt)                            3560 Total number of fuel rods in core          38,192 Number of fuel rods damaged                176 Power peaking factor                        1.65 Shutdown time(hr)                          72 Fraction of iodine and noble gas activity released to pool(%, except Kr-85)          10 Fraction of Kr-85 released to pool(%)      30 Pool decontamination factors:
Iodine                                    100 Noble gases                              1 Iodine fractions released from pool (%)
Elemental                                75 Organic                                  25 Filter efficiency, fuel handling building ventilation system(%)                      99 0-2 hr relative atmospheric concentration value at exclusion area boundary(sec/m 3 )  5.1 x 10- 4 15-22
 
Table 15.6 Assumptions used in accidents involving small line breaks outside the containment Parameter and unit of measure                Quantity Coolant released (lb)                        126,000 Fraction of coolant released flashed to steam(%)                          37 Coolant contaminant concentration (&#xb5;Ci/gm)
Case 1, normal operating limit              1.0 Case 2, coincident 11 iodine spike/'
500 times normal release rate, concentration varying with time    1. 0-5. 0 Case 3, maximum concentration limit, allowable less than 10% of time    50.0 15-23
 
Table 15.7 Assumptions and bases for steam generator tube failure doses Parameter and unit of measure                                        Quantity For case 1, no preaccident iodine spike Rupture location: top of tube bundle Length of tube for pressure drop calculation (ft)                    40 Velocity of water in ruptured tube, based on one phase, initial (ft/sec)                                                      150 Total mass flow rate of water out both sides of double-ended rupture, initial (lb/sec)                                            28.6 Fraction of iodine in leaked coolant that becomes airborne (flashed or as aerosol)                                              0.50 Decontamination factor for condenser                                  10 Concentration of iodine in coolant Initial {&#xb5;Ci/gm)                                                    1.0 Increasing during pressure-transient spike (&#xb5;Ci/gm-hr)              19.7 Secondary side initial concentration (&#xb5;Ci/gm)                        0.1 Fraction of iodine in primary coolant that mixes with secondary water that is converted to organic iodine                            0.01 Fraction of organic iodine released to environment                    1.0 Partition coefficient used in calculating iodine concentration of steam in equilibrium with secondary liquid                            100 Duration of leak, prior to scram {min)                                30 Time that safety valves are open in affected steam generator (sec)    320 Loss of offsite power at scram results in condenser unavailability Mass of steam released through affected steam generator's safety valves (lb)                                                    39,000 Mass of steam released from intact steam generator 1 s safety valves (lb)                                                    728,000 Mass of steam released from intact steam generator during first 2 hr (lb)                                                      430,000 For case 2, with a preaccident iodine spike As above, except:
Concentration of iodine in primary coolant Initial (&#xb5;Ci/gm)                                                    60 Increasing at (&#xb5;Ci/gm-hr)                                          19. 7 15-24
 
Table 15.8  Assumptions used in loss-of-coolant dose calculations Parameter and unit of measure                            Quantity Power (MWt)                                              3560 Fission product fractions released to containment(%)
Iodine                                                50 Noble gases                                            100 Iodine distribution(%)
Elemental CI 2 )                                      95.5 Organic(CH 3 I)                                        2.0 Particulate                                            2.5 Containment iodine removal coefficient(per hr)
Sprayed                                                1. 43 Unsprayed                                              1.18 ESF filter efficiencies(all forms) (%)                  99 Containment leak rate(%/day) 0-24 hr                                                0.5 After 24 hr                                            0.25 Containment leakage distribution(%)
Bypass                                                6 To shield building                                    41.0 To auxiliary building                                  53.0 Secondary containment inleakage(%/day)                  100 15-25
 
For the second case, the staff assumed that an iodine spike occurs as a result of the accident and that the iodine release rate from the fuel to the primary coolant following the accident is increased by a factor of 500. Further, before the accident, the plant was assumed to be operating at a primary coolant equi librium iodine technical specification activity limit of 6.5 &#xb5;Ci/gm. The assumed primary coolant activity value, although larger than that given in the vendor Standard Technical Specifications, has been proposed by the applicant as the plant-specific technical specification limit. All assumptions regarding the releases from the steam generators given in Case 1 above are also assumed for this case.
Staff assumptions are presented in Table 15.4 and calculated doses are presented in Table 15.3.
The staff concludes that the distances to the exclusion area and to the low population zone boundaries for the Waterford site are sufficient to provide reasonable assurance that the calculated radiological consequences of a postulated main steam line break accident outside containment do not exceed(1) a small fraction( 10%) of the exposure limits set forth in 10 CFR Part 100 paragraph 11, for the case of an iodine spike that results from the accident and (2) the exposure limits set forth in 10 CFR Part 100 paragraph 11 for the case of a preaccident spike or a control rod held out of the core.
The staff 1 s finding is based upon(1) its review of the applicant 1 s radiological consequence analysis; (2) the staff 1 s independent dose evaluation using the conservative regulatory assumptions identified in the Appendix to SRP Section 15.1.5 and the conservative atmospheric dispersion factors as discussed in this SER Section, 2.3.4; and (3) the assumed technical specifications provided in the applicant 1 s FSAR for primary and secondary coolant iodine concentrations and unidentified primary to secondary system leakage in the steam generators.
15.4.2 Fuel Handling Accident In the evaluation of the fuel handling accident, the assumptions used by the staff are based on Positions C.l.a through C.l.f of Regulatory Guide 1.25.
The staff assumed that a single fuel assembly is dropped in the spent fuel pool and that all the fuel rods in the assembly are damaged, releasing gap activity into the pool water. Instantaneous release of radioiodines and noble gases is assumed, with the activity released to the environment after filtration by the fuel handling building ventilation system. The iodine and particulate removal efficiency is conservativeiy assumed to be 99%, as discussed in Regulatory Guide 1.52 and in Section 6.5.1 in this report. The list of assumptions and parameters used in the analysis are given in Table 15.5. The offsite radio logical consequences are shown in Table 15.3. The potential offsite consequences are well within the guideline values given in 10 CFR Part 100. The staff, therefore, concludes that the fuel handling building ventilation system is suitable for mitigating the consequences of fuel handling accidents.
In the staff's review of the spent fuel cask drop accident, it was noted that potential vertical cask drop distances onto hard surfaces were less than 30 ft and the overhead handling system is designed to retain the maximum design load during safe shutdown earthquake (SSE) conditions. Also, the cask is not permitted to travel over spent fuel or safety-related equipment. Therefore, 15-26
 
the radiological consequences of a spent fuel cask drop accident have not been evaluated, in accordance with SRP Section 15. 7.5, since the most severe drop is within the designed strengths of the barriers to fission product release.
15.4.3 Failure of a Small Line Carrying Primary Coolant Outside Containment The applicant has provided an analysis of an accident involving a break in the 2-in. (Schedule 60) letdown line outside containment. Following such a break, reactor primary coolant would be released to the auxiliary building, causing RCS pressure to decrease. This drop in reactor vessel pressure would cause a reactor trip, after which low pressurizer level would result in an SIAS. This signal causes the letdown line to be isolated from the reactor coolant, terminat ing flow through the break. The time between the initial break and its automatic isolation is estimated by the applicant to be 7 min, during which time approxi mately 126,000 lb of primary coolant would be released into the auxiliary building.
The staff estimates that 37% of the hot reactor coolant would flash into steam upon entering the auxiliary building atmosphere, so that an equal fraction of the dissolved iodine fission products the coolant contained could be assumed to become airborne as gas and particulates. In the absence of ESFs designed to detect and mitigate the consequences of this release, it is further assumed that this airborne radioiodine can escape directly to the environment at ground level, without delay, dilution, or filtration.
The applicant has estimated the dose consequences of this accident at the exclu sion area boundary using an equilibrium technical specification limit of 6.5 &#xb5;Ci/gm dose equivalent I-131 coolant concentration. The applicant's estimate of 49 rem thyroid dose exceeds the guideline in SRP Section 15.6.2, which states that, for the case of the equilibrium technical specification limit, the calculated doses should not be greater than 10% of the dose guidelines in 10 CFR Part 100, or, in this instance, 30 rem. The Standard Technical Specifications suggested by the reactor vendor, CE, are 1.0 &#xb5;Ci/gm as the equilibrium technical specifi cation limit, and 60 &#xb5;Ci/gm not to be exceeded, with intermediate values allowable for less than 10% of the annual operation time.
Staff analysis of this accident indicates that neither the 6.5 &#xb5;Ci/gm limit proposed by the applicant for normal operation nor the 60 &#xb5;Ci/gm upper limit of the Standard Technical Specifications are permissible for this plant. The staff's computed doses for three coolant conditions during this accident are listed in Table 15.3. Case 1 assumes a constant coolant concentration of 1.0 &#xb5;Ci/gm. In case 2, the coolant concentration varies with time during the release, beginning at the equilibrium technical specification limit, and increas ing due to a 500-fold rise in the iodine release rate from the fuel. This increased release rate, or "iodine spike," is intended to model the response of small fuel cladding defects to the rapid change in coolant pressure expected to occur during this accident. Case 3 assumes that the plant is operating with a preexisting 11 iodine spike, 11 caused by an earlier transient, and that the coolant concentration is at an upper contaminant concentration limit of 50 &#xb5;Ci/gm.
Table 15.6 outlines NRC 1 s assumptions for this postulated accident.
The dose consequences NRC has calculated for these three cases are within the guidelines of 10 CFR Part 100, and also within the guidelines of staff practice contained in SRP Section 15.6.2. The staff will, therefore, require technical specifications for the plant to set the equilibrium technical specification limit at 1.0 &#xb5;Ci/gm dose equivalent I-131, and the spike limit at 50 &#xb5;Ci/gm.
15-27
 
15.4.4 Waste System Failures Various activities of plant operation generate gaseous and liquid wastes which are processed and stored within the auxiliary building. The predominant source of such wastes is the letdown and decontamination of reactor coolant, and the predominant inventories of iodine and noble gas inventories within the auxiliary building are the waste holding tanks, with much lesser amounts within the processing equipment itself.
The largest release of liquid wastes would occur from the simultaneous failure of all non-seismic-qualified tanks and equipment. The largest inventories of such tanks and equipment have been estimated by the applicant and listed in Table 15. 7-4 of the FSAR. The staff has computed doses which might result from the release of 1% of the iodine content of the entire non-seismic-qualified inventory, assuming that this fraction could become airborne and escape to the environment without delay, dilution, or filtration. These doses are listed in Table 15.3, are appropriately small fractions of the dose guidelines of 10 CFR Part 100, and are within the staff guidelines of SRP Section 15.7.2.
The largest release of noble gas waste would result from the failure of a waste gas decay tank while it held its maximum inventory. The applicant has computed a maximum inventory, and reported the results in Table 15.7-2 of the FSAR.
This computation assumed that all noble gas activities within the coolant at shutdown were instantaneously removed by the waste gas system and held in a single decay tank. The dose consequences computed for the release of this inventory, both by the applicant and by the staff, exceed the dose guidelines in SRP Section 15.7.1. The staff notes, however, that the waste gas system cannot instantaneously process the entire 200-ton coolant inventory, since its capacity is only 40 gal/min, or approximately 0.5%/hr. The staff has computed the doses for this accident, as listed in Table 15.3, by assuming operation at 3560 MWt with 1% failed fuel and the waste gas system operating at 100% efficiency and capacity, placing all of the waste gas in a single tank. The resulting doses, which are diminished because of the decay of the radioactive gases over the time required for their processing, are appropriately small fractions of the dose guidelines of 10 CFR Part 100, and are within the staff guidelines of SRP Section 15.7.1.
The staff concludes, therefore, that the waste systems are designed so that the most severe single failure will not cause dose consequences in excess of appropriately small fractions of 10 CFR Part 100 guidelines.
15.4.5 Control Rod Ejection Accident The consequences to the plant of the control rod ejection accident are discussed in Section 15.2.4.2, and the design of the plant has been found capable of assuring that the recovery from the accident is sufficiently rapid and effec tive to limit the release of radioactivity from the fuel. The radiological consequences of this release limit have been evaluated using the recommendations of Regulatory Guide 1. 77 and a conservative description of the plant response during the accident, and the calculated doses are listed in Tab1e 15.3. Two ieakage paths to the environment are possible: case 1 assumes the released radioactivity escapes into the containment building and leaks from there to the environment; case 2 assumes the radioactivity remains concentrated within 15-28
 
the pressure vessel and leaks through the steam generators and secondary system steam lines to the environment. Release in case 1 is slow, but of long duration; in case 2 a more rapid release is terminated by plant recovery from the accident, and any combination of leakage pathways would result in dose consequences inter mediate between those calculated for the two cases. Technical specification limits on primary-to-secondary leakage assure that the potential doses are within 10 CFR Part 100 exposure guidelines.
15.4.6 Steam Generator Tube Failure A steam generator tube rupture (SGTR) accident releases primary coolant to the secondary side of a steam generator, thus providing a pathway for iodine and noble gases from the primary coolant to be released to the environment. The staff evaluated the radiological consequences of the release to the environ ment, both with and without loss of offsite power, and both with a consequential iodine spike (that is, a temporary rapid increase in rate of fuel rod leakage) and with a preexisting iodine spike.
The applicant's description of the steam generator tube failure accident was reviewed, inc1uding the assumptions of the thermohydraulic transient, the sequence of events, the bases for operator actions in isolating the steam generator, and the effects of offsite power loss. The signals available to the operator are sufficient to ensure that the affected steam generator will be isolated within 30 min, thus limiting the release of radionuclides to the environment. The descriptions of the plant transients and sequence of events are sufficient to ensure that the most conservative type of SGTR was selected, namely, a continuous leak from the rupture for some time before a reactor scram, and loss of offsite power coincident with the scram.
The doses that the applicant calculated to result from this accident meet the guidelines of SRP Section 15.6.3 and 10 CFR Part 100. However, the staff independently calculated the thyroid dose from this accident (the whole-body dose calculated by the applicant was very small, and NRC accepted its value).
The staff determined that the rupture location which would result in the greatest releases would be the top of the tube bundle, where scrubbing of iodine by the secondary side liquid would be diminished. The staff has conservatively assumed that 50% of the iodine in the coolant would be released from the steam generator to the environment. The flow rate from the rupture was based on pressure drop from entrance and exit losses, and viscous pressure drop for both one- and two-phase flow. Other assumptions are listed in Tabie 15.7.
The calculated doses are summarized in Table 15.3, with case 1 entailing no preaccident iodine spike, and case 2 assuming a preaccident iodine spike. Both cases assumed loss of offsite power, with consequent loss of condenser cooling and release of steam to the atmosphere. For case 1, the dose is proportional to the plant technical specification for the equilibrium I-131 dose equivalent primary coolant activity 1imit. The applicant has proposed that this limit be 5.5 &#xb5;Ci/m dose equivalent I-131 (DE I-131), but the staff's calculated doses using this limit exceeded the SRP guideline values (10% of 10 CFR Part 100 dose guidelines). Therefore, the doses listed in Table 15.3 for case 1 were calcu lated using the CE Standard Technical Specification equilibrium 1imit of 1.0 &#xb5;Ci/gm dose equivalent I-131. Acceptance of the coolant activity limit is based on the adoption of the 1.0 &#xb5;Ci/gm limit by the applicant, which will limit 15-29
 
potential doses (for case 1) to small fractions of the 10 CFR Part 100 exposure guidelines. The potential doses are then within the 10 CFR Part 100 guidelines even if the accident were to occur with a preaccident iodine spike (case 2).
Additional fuel failure is not expected to occur as a result of this accident.
15.4.7 Radiological Considerations of Loss-of-Coolant Accident A design basis LOCA was postulated for Waterford 3 using evaluation methods described in the appendices to SRP Section 15.6.5. To mitigate the dose conse quences of this accident, the plant design includes three major active systems:
the containment spray system, discussed in Section 6.5.2 of this report; the shield building ventilation system (SBVS); and controlled area ventilation system (CVAS), discussed in Section 6.5.3. The first of these systems acts to reduce airborne radioiodine in the primary containment to reduce its leakage; the latter two act to collect and filter leakage from the primary containment.
Some of the lines penetrating the primary containment do not terminate within building volumes served by the SBVS and CVAS and the possibility exists of leakage through these lines directly to the environment. Unfiltered leakage to the environment is termed 11 bypass."
Leakage from the primary containment to the portion of the plant served by the CVAS may occur either as gas or liquid. During the accident, liquid used by certain ESPs is recirculated through pipes and equipment located in the auxiliary building, where leakage may occur.
Dose consequences for the LOCA have been calculated for each of four potential leakage paths; (1) bypass, (2) containment leakage treated by the CVAS, (3) leak age treated by the SBVS, and (4) ESF leakage into the auxiliary building. Doses from the first three sources and their sum are listed in Table 15.3. The assumptions used to compute these doses are outlined in Table 15.8, and are explained more fully in Positions 1.b through l.f of Regulatory Guide 1.4, 11 Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss-of-Coolant Accident for Pressurized Water Reactors," from which they were derived.
ESF equipment outside containment which would contain dissolved fission products from liquid piped from the containment, and which is required to operate during and following a LOCA, consists of components of the ECCS and containment spray recirculation system. The applicant states that this equipment is designed to remain operable without maintenance over the accident duration; however, any leaks that developed in these systems possibiy couid not be repaired, because of lack of access to a high radiation environment. The applicant has, therefore, provided for the collection of any such leakage in floor drain sumps. The applicant has estimated the largest single leak that might develop would be 500 cc/min, upon the failure of an ESF pump seal.
All ESF components and sumps subject to liquid leakage outside containment are located in areas served by the CVAS, which is itself an ESF-grade system. Under the criteria of SRP Section 15.6.5, Appendix B, the dose consequences of a passive failure in an ESF component need not be evaluated if the leakage is controlled by an ESF filtration system. The staff has evaluated the potential consequences of a 1000 cc/min liquid leak continuing throughout the duration of the accident. The computed doses to the thyroid are 0.02 and 0.3 rem, 15-30
 
respectively, at 2 hours at the EAB and 30 days at the LPZ. These doses do not contribute significantly to total potential doses, and are omitted from Table 15.3.
Consistent with Regulatory Guide 1.4, the staff has assumed the initial release of iodine fission product to be predominantly in the form of elemental vapor, an assumption which makes great demands upon the containment atmosphere cleanup system. This system, described in Section 6.5.3 of this SER, contains no design provision for chemical addition during the injection phase, and achieves neutralization of the containment spray acidity during recirculation by dissolu tion of trisodium phosphate stored in the containment sump. A large fraction of the computed thyroid doses may be attributed to the assumption of the chemical form of the initial iodine release, combined with the comparatively slow and inefficient method of iodine removal chosen by the applicant.
The staff has examined the dependence of the computed potential doses upon the rates of iodine removal mechanisms from the containment atmosphere, and has concluded that this time dependence is not a major factor in determining potential doses.
Computed potential doses are heavily dependent upon the assumed distribution of containment leakage between bypass and ESF-filtered pathways. This distribu tion is taken to be the same as the technical specification limits on leakage tests periodically required to be performed on containment penetrations. When applying for a CP, the applicant had proposed a bypass leakage fraction of 0.5%
of total containment loss. In the FSAR, however, a bypass leakage fraction of 8% was proposed. This much larger limit resulted in a computed potential dose that was 97% of the corresponding guideline dose in 10 CFR Part 100, and a control room thyroid dose in excess of staff criteria. As listed in Table 15.5, the staff has assumed a bypass fraction of 6%, which yields a computed potential control room dose of acceptable magnitude. The staff will require a technical specification limit of 6% maximum bypass leakage. In amendment 19 to the FSAR, the applicant has revised the proposed technical specifications to require a bypass leakage fraction of less than 6%.
The computed doses in Table 15.3 are well within the guidelines of 10 CFR Part 100, given the reduced technical specification limit discussed above, and we conclude, therefore, that the plant ESFs are acceptably efficient in mitigating the conse quences of a postulated LOCA.
15.4.8 Liquid Tank Failure Accident The staff evaluated the consequences of tank failures for tanks located outside the ractor containment which could result in releases of iiquids containing radioactive materials to the environs. Considered in the evaluation were (1) the radionuclide inventory in each tank assumin a one percent operating power fission product source term, (2) a tank liquid inventory equal to 80 percent of its design capacity, (3) the mitigating effects of plant design including overf1ow lines and the location of indoor storage tanks in curbed areas designed to retain spillage, and (4) the effects of site geoglogy and hydrology.
The applicant has incorporated provisions in the plant design to retain releases from the liquid overlow as discussed in Section 11.2.1 of this report. Failure 15-31
 
of tanks located within the reactor auxiliary building would not likely result in either surface or groundwater contamination sicne the hydrostatic pressure is against the reactor auxiliary building and since most tanks considered are located below the water table. An analysis was performed to estimate the offsite radionuclide concentration assuming that the entire inventory of the tank with the highest concentration was released. The groundwater concentrations at the site boundary were only a small part of 10 CFR Part 20 concentrations.
 
==15.5 REFERENCES==
American National Standards Institute:
ANSI NlB.2 American Society of Mechanical Engineers Boiler and Pressure Vesse1 Code:
ASME .Code, Section III, Division 1 Code of Federal Regulations:
10 CFR Part 50, Appendix K 10 CFR Section 50.46 10 CFR Part 100 10 CFR Section 100.11 10 CFR Part 100, paragraph 11 Combustion Engineering reports:
CE Standard Technical Specifications CENPD - 107 CENPD - 158 CENPD - 158, Revision 1 CENPD - 190-A CENPD - 207 CESSAR, Combustion Engineering Standard Safety Analysis Report General Design Criteria:
GDC 20 GDC 25 Louisiana Power and Light Company:
FSAR for Waterford 3, Amendment 17 FSAR for Waterford 3, Chapter 15 Regulatory Guides:
RG 1.4 RG 1. 25 RG 1. 45 RG 1.52 RG 1. 77 USNRC report:
NUREG-75/087 "Status Report on Anticipated Transients Without Scram for Combustion Engineering Reactors,u December 9, 1975.
*See Appendix 8, Bibliography, for complete citations and availability statements.
15-33
 
==15.5 REFERENCES==
FOR SECTION 15 (Continued)
SRP  Section 15.6.3 SRP  Section 15.6.5, Appendix B SRP  Section 15.7.1 SRP  Section 15.7.2 SRP  Section 15.7.5 USNRC report:
NUREG-75/087 11 Status Report on Anticipated Transients Without Scram for Combustion Engineering Reactors, 11 December 9, 1975.
15-34
 
16 TECHNICAL SPECIFICATIONS The technical specifications in a license define certain features, character istics, and conditions governing operation of a facility that cannot be changed without prior approval of the Commission. The finally approved technical speci fications will be made a part of the operating license. Included will be sections covering safety limits, limiting safety systems settings, -limiting conditions for operation, surveillance requirements, design features, and administrative controls.
The applicant has proposed that the technical specifications given in Section 16 of the Waterford 3 Final Safety Analysis Report be used. These technical speci fications are based upon NUREG-0212, "Standard Technical Specifications for Combustion Engineering Pressurized Water Reactors. 11 The NRC staff is currently working with the applicant to update the technical specifications proposed by the applicant for Waterford 3 to include the results of the NRC staff review. On the basis of the review to date, indications are that normal plant operation within the limits of the technical specifications will not result in potential offsite exposures in excess of the 10 CFR Part 20 limits. Furthermore, indications are that the limiting conditions for operation and surveillance requirements will assure that necessary engineered safety features will be available in the event of malfunctions within the plant. The staff 1 s final conclusions will be reported in a supplement to this SER.
16-1
 
REFERENCES*
: 1. 10 CFR Part 20.
: 2. Louisiana Power and Light Co.) FSAR for Waterford 3, Section 16.0.
: 3. USNRC report, NUREG-0212.
*See Appendix B, Bibliography, for complete citations and avai1ability statements.
 
17 QUALITY ASSURANCE 17.1 GENERAL The description of the quality assurance (QA) program for the operations phase of Waterford 3 is contained in Section 17.2 of the FSAR. Staff evaluation of this quality assurance program is based on a review of this information  and discussions with representatives of LP&L. NRC assessed LP&L 1 s quality assurance program for the operations phase to determine if it complies with the require ments of 10 CFR Part 50, Appendix 8, 11Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, 11 the applicable quality assurance found in related Regulatory Guides listed in Table 17.1, ANSI Standards, and the SRP, Section 17.2, Rev. 1, 11 Quality Assurance During the Operations Phase. 11 17.2 ORGANIZATION The structure of the organization responsible for the operation of Waterford 3 and for the establishment and execution of the operations phase quality assur ance program is shown in Figure 17.1.
The Vice President, Power Production has overall responsibility for the Water ford 3 station and establishes quality assurance policies, goals, and objec tives. Reporting to the Vice President, Power Production is the Quality Assurance Manager and staff who have responsibility for developing, coordinating, and assuring effective implementation of the Operational Quality Assurance Program.
The Quality Assurance Manager and staff assure effective implementation of the Operational Quality Assurance Program by performing audits  of onsite and offsite quality-related activities and evaluating vendor 1 s quality assurance programs and procedures. The Quality Assurance Manager submits quarterly audit result summaries to the Vice President, Power Production for review and assessment.
The Quality Assurance Organization is responsible for: (1) estabiishing indoctrination and training programs for offsite personnel performing quality affecting activities; (2) reviewing and approving the Operational Quality Assurance Program and the Operational Quality Assurance Procedures Manual that implements the program; (3) assuring that personnel qualifications are current and applicable to the work being performed; (4) assuring that offsite procure ment documents include applicable QA requirements; (5) performing preaward evaluation of suppliers and surveillance and inspection at the suppliers' facilities; and (6) conducting internal audits of maintenance, modification, and operations activities and external audits of suppliers.
The Nuclear Operations Quality Assurance group reports to the Quality Assur ance Manager and is located onsite during plant preoperational testing and plant operations. This group gives full attention to assuring that the Quality 17-1
 
Table 17.1 Regulatory Guide Applicable to Quality Assurance Program Reg.      Rev.
Guide    No.      Date          Title 1.28      1        March 1978    Quality Assurance Program Requirements (Design and Construction) 1.30      0        August 1972    Quality Assurance Requirements for Installation, Inspection, and Testing of Instrumentation and Electric Equipment 1.33      2        February 1978 Quality Assurance Program Requirements (Operation) 1.37      0        March 1973    Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants 1.38      2        May 1977      Quality Assurance Requirements for Packaging, Shipping, Receiving, Storage, and Handling of Items for Water-Cooled Nuclear Power Plants 1.39      2        September 1977 Housekeeping Requirements for Water-Cooled Nuclear Power Plants 1.58      1        September 1980 Qualifications of Nuclear Power Plant Inspection, Examination, and Test Personnel 1.64      2        June 1976      Quality Assurance Requirments for the Design of Nuclear Power Plants 1.74      0        February 1974 Quality Assurance Terms and Definitions 1.88      2        October 1976  Collection, Storage, and Maintenance of Nuclear Power Plant Quality Assurance Records 1.94      1        April 1976    Quality Assurance Requirements for Installation, Inspection, and Testing of Structural Concrete and Structural Steel During the Construction Phase of Nuclear Power Plants 1.116    0-R      June 1976      Quality Assurance Requirements for installation, Inspection, and Testing of Mechanical Equipment and Systems 1.123    1        July 1977      Quality Assurance Requirements for Control of Procurement of Items and Services for Nuclear Power Plants 1.144    1        September 1980 Auditing of Quality Assurance Programs for Nuclear Power Plants 1.146    0        August 1980    Qualification of Quality Assurance Program Personnel for Nuclear Power Plants 17-2
 
Pfl&#xa3;SIOEIH II, Clilf F EX(CUTIVE OHICEA SENIOR VICE PRESIOENT-OPlAATIONS
                                                  \IICE PRUIUENT POWER l'ROOUCTION    ----------------------7 I
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            ,-----------*-1,t----*-------.,
VENDOR ANO SUPPLIER
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                                                                                ------Asst. Vice
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:                                      :  1'1,AIIT 01'\"ATIOU I                                        lllY1lW ITTH I
1___ -      P lant Mgr.                                I r          Nuclear I
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Operations                                        QUAUTY CONTROl EIICIJIHR Quality Assurance Waterford Steam Electric Station
                                                                                          ,OSllCIAUIUTll!TY (NCINHR IOtf Unit No. 3 Quality Assurance for Operations Administrative                UCINIIRINQ l(CHICIANS (OCJ                                      Figure 17.1
                                          -----------Communicative
 
Assurance Program at the station is being effectively implemented and inter faces with the plant quality control staff, provides assistance to other plant organizations on matters related to quality assurance, and conducts audits and surveillances during plant startup and operations to verify compliance with applicable requirements.
Located onsite and reporting to the Plant Manager, Nuclear are the Quality Control Engineer, Associate/Utility Engineers, and engineering technicians.
The Quality Control Engineer and staff: (1) develop and maintain the Station Quality Control Procedures; (2) perform inspection of station safety-related activities; (3) review and concur in inspection plans; test, calibration, special process, maintenance, modification and repair procedures; and drawings and specifications; (4) review and concur in station-initiated procurement documents; and (5) report the effectiveness of the Operational Quality Assur ance Program to the Plant Manager, Nuclear. The Quality Control Engineer maintains a working interface with the Operations Quality Assurance Group and direct line of communication with the Quality Assurance Manager for proper direction of the Operational Quality Assurance Program and assistance in resolving quality assurance/quality control problems.
Both the Quality Assurance and Quality Control sections have the authority, delineated in writing to: (1) identify quality assurance problems; (2) ini tiate, recommend, or provide solutions through designated channels; (3) verify implementation of solutions; and (4) stop unsatisfactory work or control further processing, delivery, or installation of unsatisfactory material.
Also reporting to the Vice President, Power Production is the Assistant Vice President, Nuclear Operations who is responsible for execution of the admin istrative controls and quality assurance/quality control program to assure safe and reliable operation of Waterford 3. This function is accomplished through the Plant Manager, Nuclear whose responsibilities include providing station personnel with an adequate indoctrination and training program in the areas of quality assurance/ quality control and the performance of safety-related activities and the development of station safety-related implementing documents such as station operating, maintenance, repair, and inspection procedures.
Disputes involving quality, arising from a difference of opinion between the Quality Control Group and other station groups (Maintenance, Operations, etc.)
or external safety-related contractors/suppliers organizations shall be resolved through the Plant Manager, Nuclear. Disputes involving quality, arising from a difference of opinion between the offsite QA organization and the station organization shall be resolved through the Vice President, Power Production.
17.3 QUALITY ASSURANCE PROGRAM The QA program for the operation of Waterford 3 is presented in the Louisiana Power & Light Company Operational Quality Assurance Program which describes the QA policies, goals, objectives, and requirements to be implemented at the station in order to assure that safety-re1ated activities are performed in a controlled manner and documented to provide objective evidence of compliance with NRC regulations and guidance. The Operational Quality Assurance Program is implemented by the Operational Quality Assurance Procedures Manual that includes all related policies, procedures, and instructions. These documents 17-4
 
present the detailed techniques and methods by which the requirements of Appendix B to 10 CFR Part 50 and the provisions of the NRC regulatory guidance shown in Table 17.1 are satisfied. They are reviewed and concurred in by the Quality Assurance Manager.
The QA program requires that quality assurance documents encompass detailed controls for: (1) translating codes, standards, and regulatory requirements into specifications, procedures, and instructions; (2) developing, reviewing, and approving procurement documents, including changes; (3) prescribing all quality-affecting activities by documented instructions, procedures, or drawings; (4) issuing and distributing approved documents; (5) purchasing items and services; (6) identifying materials, parts, and components; (7) performing special processes; (8) inspecting and/or testing material, equipment, processes, or services; (9) calibrating and maintaining measuring and test equipment; (10) handling, storing, and shipping items; (11) identifying the inspection, test, and operating status of safety-related items; (12) identifying and dispositioning nonconforming items; (13) correcting conditions adverse to quality; (14) preparing and maintaining quality assurance records; and (15) auditing activities that affect quality.
The QA program requires the establishment and continuous implementation of the quality assurance indoctrination, training, and retraining program to assure that persons involved in safety-related activities are knowledgeable in QA instructions and implementing procedures, and demonstrate a high level of competence and skill in the performance of their quality-related activities.
Quality is verified through surveillance, inspection, testing, checking, and audit of work activities. The quality assurance program requires that quality verification and inspections be performed by qualified control inspectors who are not directly responsible for performing the actual work activity. Inspec tions are performed with procedures, instructions, and/or checklists by inspectors who have been qualified and certified in accordance with codes, standards, or company training programs.
The Quality Assurance Manager is responsible for the establishment and imple mentation of the audit program. Audits are performed with written procedures or checklists by qualified personnel not having direct responsibility in the areas being audited. The quality assurance program establishes a comprehensive audit system to ensure that the quality assurance program requirements and related supporting procedures are effective and properly implemented during operations. Audits will include an objective evaluation of quality assurance practices, procedures, and instructions; work areas, activities, processes, and items; the effectiveness of implementation of the quality assurance pro gram; and conformance with policy directives.
The quality assurance program requires documentation of audit results and review by management having responsibi1ity in the area audited to determine and take corrective action as required. Reaudits are performed to determin that nonconformances are effectively corrected and that the corrective action precludes repetitive occurrences. Audit findings, which indicate quality trends and the effectiveness of the quality assurance program, are reviewed by the Quality Assurance Manager and are reported to the Vice President, Power Production and the Plant Manager, Nuclear on a regular basis.
17-5
 
==17.4 CONCLUSION==
S The review of LP&L's quality assurance program description for the operations phase has verified that the criteria of Appendix 8 to 10 CFR Part 50 have been addressed in the Waterford 3 quality assurance program.
Based on the review and evaluation of the quality assurance program description contained in Section 17.2 of the Final Safety Analysis Report for Waterford 3, the staff concludes that:
(1) The quality assurance organization of LP&L provides: sufficient independence from cost and schedule (when opposed to safety considerations), authority to effectively carry out the operations quality assurance program, and access to management at a level necessary to perform their quality assurance functions.
(2) The quality assurance program describes requirements, procedures, and controls that, when properly implemented, comply with the requirements of Appendix B to 10 CFR Part 50 and with the acceptance criteria contained in Standard Review Plan Section 17.2.
Accordingly, the staff concludes that the applicant's description of the quality assurance program, with the exception of the outstanding issue noted below, is in compliance with applicable NRC regulations.
17.5 OUTSTANDING QUALITY ASSURANCE ISSUE FOR WATERFORD 3 STEAM ELECTRIC STATION The applicant has not yet responded to our request that additional safety-related items and activities be placed under the appropriate controls of the quality assurance program. The staff will address this issue in a supplement to this SER.
 
==17.6 REFERENCES==
Code of Federal Regulations 10 CFR, Part 50, Appendix B Louisiana Power and Light Co. reports:
FSAR for Waterford 3, Section 17.2 Operational Quality Assurance Procedures Manual Regulatory Guides:
1.28, Rev. 1 1.30, Rev. 0 1.33, Rev. 2 1.37, Rev. 0 1.38, Rev. 2
: 1. 39, Rev. 2 1.58, Rev. 1
: 1. 64, Rev. 2
: 1. 74, Rev. 0 1.88, Rev. 2
: 1. 94, Rev. 1 1.116, Rev. 0-R
: 1. 123 , Rev. 1
: 1. 144, Rev. 1 1.146, Rev. 0 Standard Review Plan
*See Appendix B, Bibliography, for complete citations and availability statements.
17-7
 
18 REPORT OF THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS The Waterford 3 app]ication for an operating 1icense is being reviewed by the Advisory Committee on Reactor Safeguards. The NRC staff will issue a supplement to this Safety Evaluation Report after the Committee report to the Commission is available. The supplement will append a copy of the Committee's report, will address comments made by the Committee, and will describe steps taken by the NRC staff to resolve any issues raised as a result of the Committee's review.
18-1
 
19 COMMON DEFENSE ANO SECURITY The application reflects that the activities to be conducted will be within the jurisdiction of the United States and that all of the directors and prin cipal officers of the applicant are United States citizens. The applicant is not owned, dominated, or controlled by an alien, a foreign corporation, or a foreign government. The activities to be conducted do not involve any restricted data, but the applicant agreed to safeguard any such data which might become involved in accordance with the requirements of 10 CFR Part 50. The applicant will rely upon obtaining fuel as it is needed from sources of supply available for civilian purposes, so that no diversion of special nuclear material for military purposes will be involved. For these reasons and in the absence of any information to the contrary, the staff finds that the activities to be performed will not be inimical to the common defense and security.
 
REFERENCE*
10 CFR Part 50
*See Appendix B, Bibliography, for complete citation and availability statement.
19-2
 
20 FINANCIAL QUALIFICATIONS The Nuclear Regulatory Commission's requirements for determining an applicant's financial qualifications for an operating license are stated in its regulations in 10 CFR Section 50.33(f) and Appendix C to 10 CFR Part 50. The former regula tion states 11 [i]f the application is for an operating license, such information shall show that the applicant possesses the funds necessary to cover estimated operating costs or that the applicant has reasonable assurance of obtaining the necessary funds, or a combination of the two. 11 [10 CFR 50.33(f)] The latter restates the former with the additional proviso that "For purposes of the latter requirement, it will ordinarily be sufficient to show at the time of filing of the app1ication, availability of resources sufficient to cover estimated operating costs for each of the first five years of operation plus the estimated costs of permanent shut-down and maintenance of the facility in a safe condition. 11 [10 CFR Part 50, Appendix C(I)(B)] This subsection concludes with the expectation that 11 in most cases the applicant's financial statements contained in its published annual reports will enable the Commission to eva1uate the applicant's financial capability to satisfy this requirement."
In response to a staff request submitted pursuant to Appendix C, Section (IV) to 10 CFR Part 50, the Louisiana Power and Light Company (the Company) submitted the necessary financial information. This information addresses the applicant's financial qualifications to operate and permanently shut down, if necessary, and maintain Waterford 3 in a safe condition. The financial information provided by the applicant states the required financial data of estimated facility operating expenses, permanent shutdown costs, and projected maintenance expenses to keep the facility in a safe shutdown condition.
The following anaiysis constitutes the NRC staff's evaluation of the applicant's submittal and addresses the financial qualifications of the applicant to operate the Waterford 3 facility, permanently shut it down, if necessary, and maintain it in a safe condition.
20.1 BUSINESS OF APPLICANT Louisiana Power and Light Company is a corporation organized and operating under the laws of the State of Louisiana. The Company is an electric public utility company engaged principally in the generation, purchase, transmission, distribu tion, and sale of electric energy for residential, commercial, industrial, and other purposes to the public in 46 of the 64 parishes (counties) in the State of Louisiana. Louisiana Power and Light Company serves electricity to over 500,000 customers. The Company's rates and operations are regulated by the Louisiana Public Service Commission. Middle South Utilities, Inc., a registered utility holding company under the Public Utility Holding Company Act of 1935, owns all the common stock of Louisiana Power and Light Company.
20-1
 
20.2 ESTIMATED OPERATING COSTS OF FACILITY For the purpose of estimating the facility's operating costs, the applicant has assumed that 1983 will be the first year of commercial operation. Estimates of the total annual costs of operating the Waterford plant for each of the first full five years are presented in Table 20.1, below. All operating estimates for Waterford's costs are based upon a peak net elec              y of 1,165 mega watts and total estimated construction costs of ((          )) . As an element of conservatism, operating costs are also presen              0.1 based upon alter native capacity factors of 50 and 60%, respectively. At the end of 1980 the Waterford facility was 82% complete in construction. Operating costs include all costs associated with the capital investment and operation and maintenance including nuclear fuel.
((
                                                                                ))
20.3 ESTIMATED COSTS TO DECOMMISSION FACILITY Although the applicant has not at this time made a final selection of its pro posed method of decommissioning the facility, it has supplied cost estimates for such expenses under various options of decommissioning methods. Such options include safe storage (mothballing), entombment, dismantlement, or a combination of either of the first two methods with dismantlement occurring on a deferred basis after completion of initial decommissioning activity. Based upon an Atomic 20-2
 
Industrial Forum study entitled 11 An Engineering Evaluation of Nuclear Power Reactor Decommissioning Alternatives,11 AIF/NESP - 009 AIF, Washington, D.C. (1976),
the            as estimated that costs in 1978 dollars for de              could be ((      ))  for  the lower level of decommissioning up to ((        )) for mot            h full security followed by complete removal a              ent.
Under contract for the NRC, the Battelle Pacific Northwest Laboratory issued its report "Technology, Safety, and Cost of Decommissioning a Reference Pres surized Water Reactor Power Station,'' NUREG/CR-0130 (June 1978). In both this report and its August 1979 Addendum the Battelle Laboratory estimated the costs of decommissioning various types of reference pressurized water reactors under various types of decommissioning methods. The maximum cost of decommissioning for            ate dismantlement method was estimated by Battelle as a total of ((                )) dollars. Accordingly, as an element of conservatism, Bat ((              )) maximum estimate of decommissioning expenses has been adopted her            basis in evaluating the Company's ability to finance such decommissioning.
20.4 REASONABLE ASSURANCE OF FUNDS 20.4.1 General The staff's evaluation of the financial qualifications of the applicant included consideration of the Commission's decision in Public Service Compan of New Hamp shire, et al., (Seabrook Station, Units 1 and 2), 7 NRC 1, 18 (1978), affirmed sub nom., New England Coalition on Nuclear Pollution vs. NRC, 582 F. 2d 87 (1st.
Cir. 1978), which states "the applicant must have a reasonable financing plan in light of relevant circumstances. 11 In consideration of the foregoing cost estimates, the following analysis will evaluate the reasonableness of the appli cant's financial plans in covering the various costs that will result from the operation of the facility.
In general, an evaluation of the financing plans of the applicant to meet opera tional expenses and decommissioning costs can only reasonably be considered in relation to the applicant's nature of business, its size in revenue, assets, net income, and overall financial strength. Because the applicant is an ongoing entity, such an evaluation requires a review of the financial results of its operation over a sustained period of time. Since capital is discounted propor tionate with time, emphasis is placed upon recent performance. The near-term financial outlook of the applicant is also given consideration.
Long-term financial considerations are also important in the financial review since some costs will occur over an extremely long time. However, as noted in Seabrook, the number of variables such as interest rates, the state of the stock and bond markets, inflation, and the cost of fuel and labor, among many others, make long-term financial forecasting inherently uncertain. Therefore, for long term forecasts, the staff places primary reliance on recent performance and current characteristics of the applicant's financial condition. In consideration of those relevant circumstances, the following evaluates the reasonableness of the applicant's financial plan.
20-3
 
20.4.2 Costs of Operation The applicant plans to recover all costs of operation through revenues derived from its customers in its systemwide sales of electricity. As stated earlier, by reason of rate regulation, LP&L's rates may only be increased upon approval by the Louisiana Public Service Commission.
The sole purpose of the operation of the Waterford facility will be the produc tion of electricity to serve the applicant's customers. Because such capability will qualify the facility as a productive asset, from an accountin viewpoint such property wi11 reasonably be expected to qualify as property used and useful in public utility service 11 for ratemaking purposes.
As a consequence of this, the facility's cost of construction, including amounts allowed for funds used during construction, will be included in LP&L's rate base for regulatory ratemaking purposes in the amount of its investments in it. Under Louisiana rate regulation, rate base inclusion of the facility will allow the Company to recover the capital costs associated with its construction which are interest on debt, and a reasonable return including dividends on preferred and common stock. The same regulatory treatment also allows recovery of all fixed and variable operation and maintenance expenses necessary for the production of power. Tax costs attributable to the facility would also be recovered through customer charges.
As would be expected, review of the applicant's long-term statement of operations shows consistent recovery of its historical costs of operation. This may be noted in Table 20.2. Since the Company is a wholly owned subsidiary of Middle South Utilities, Inc., Table 20.2 also states selected financial statistics for its parent corporation.
((
                                                                                  ))
20-4
 
Since the applicant has demonstrated the ability to historically achieve consistent recovery of capital and operating costs for all other facilities it has constructed and operated, it is reasonable to conclude that its plan to finance the facility's operation through revenues derived from rates charged to customers for utility service represents a reasonable financing plan in light of relevant circumstances.
20.4.3 Decommissioning Cost The Company believes that decommissioning costs of Waterford 3 will ultimately be allowed to be recovered in the rate process. Based on this assumption, the Company's intention is to build the collection of these funds into depreciation rates of the plant. This method is known as the 11 negative net salvage11 approach.
The premise behind using the negative net salvage approach is that the rate payers who receive the benefits of use of the nuclear facility over its service life should pay for its total cost (including the cost of decommissioning) and that future ratepayers should not be required to pay for facilities from which they derive little or no benefit. Based upon the maximum aggregate requirement of ((        ))for total estimated decommissioning expense and a 30-yr facility life, an annual payment by the applicant of ((          )) would be necessary to fund negative net salvage amounts. To adjust for inflation, periodic reviews of decommissioning costs are customarily made for any changes in economic condi tions and advances in technology, and such changes are usually incorporated into the annual negative net salvage charge for decommissioning costs.
The applicant has proposed that the collection of any decommissioning costs through depreciation rates would be accumulated in unfunded reserves by the Company. Since the Company is regulated by the Louisiana Public Service Commission, its authorization will be required for the method and collection process of the decommissioning costs.
The applicant maintains and the staff concurs that it has reasonable assurance of financing the decommissioning of Waterford 3 at the expiration of its service able life regardless of which plan of action is undertaken. This opinion is based upon the Company's nature of business in combination with its historical and present financial strength. During the past 10 years the Company has com pleted approximately ((        ))of external financing while its parent corporation, Middle South Utilities, Inc., financed well over ((        )) during the same period.
These financings for both companies were accomplished without restrictions during a period of chaotic market conditions with the Company maintaining its investment quality ratings on its debt obligations. Of particular importance is that during the last several years of this 10-yr period, the Company has been able to finance the construction of the Waterford 3 nuclear plant at an estimated cost to date of over ((      )). It is the opinion of the Company and the staff concurs, that if it is financially able to raise ((        )) to construct this plant in addition to its other construction requirements, there is reasonable assurance it will be able to finance the decommissioning of the nuclear plant at the end of its useful life, regardless of which of the three methods it may elect to use.
As of December 1980, LP&L had assets of over ((        )), operating revenues of
((          )), and common equity of ((            )). Annual decommissioning fund amounts will be less than (( )) of 1980 revenues for the Company. Clearly, this level of expense for decommissioning will not be prohibitive to finance, considering the size of the applicant's operations.
20-5
 
Additionally, since the NRC requires that any operating reactor be safely decom missioned when retired for the protection of the public health and safety, it is reasonable to assume that those amounts will be allowed in customer rate charges as necessary and reasonable expenses. Accordingly, the staff has con cluded that the applicant 1 s plan to finance these expenses from customer revenues constitutes a reasonable financing plan in light of relevant circumstances.
Moreover, although the NRC requires no specific plan to fund decommissioning expenses, the Company 1 s plan to fund such amounts provides the necessary element of assurance in that it constitutes a reasonable method for obtaining the neces sary amounts of proceeds to meet decommissioning costs. As stated earlier, utilities customarily adjust their annual charges for negative net salvage amounts to compensate for changes in the decommissioning cost estimates. This constitutes an additional level of assurance that decommissioning funds will be available when needed. Furthermore, should additional amounts be needed over and above those realized as negative net salvage, the applicant has two other traditional sources of funds available to meet any such amounts. The first source is the Company 1 s internal cash generation attributable to: (1) depreciation expenses for all utility plant; (2) retained earnings; and (3) normalized tax depreciation and levelized investment tax credits. The second source of funds is the external capital market. As public utilities constitute the most capital-intensive industry in the United States, they have long had access to funds in the public securities market. To gain access to such additional external funds the Company would issue debt in the form of bonds and would also issue additional preferred stock or sell additional common stock to its parent corporation, or perform a combination of each of these financing methods. As stated earlier, the applicant 1 s demonstrated ability in raising over ((          )) over the past 10 years leads one to reasonably conclude that it would have little difficulty in financing any additional amounts over the ((          )) estimate in cost required to decom mission the Waterford facility.
 
==20.5 CONCLUSION==
 
In accordance with the regulations cited herein, an applicant must demonstrate that it has reasonable assurance of obtaining the necessary funds to cover the estimated costs of the activities contemplated under the license. As stated earlier, the Commission has determined in Seabrook that the reasonable assurance requirement for financial qualifications is a reasonable financing plan in light of relevant circumstances. Based upon the preceding analyses of the applicant's proposed financing plans, the NRC staff concludes that LP&L has a reasonable financing plan in light of relevant circstances to operate, and permanently shut down, if necessary, and maintain the Waterford facility in a safe condition.
Accordingly, NRC staff has determined that the Company has reasonable assurance under 10 CFR Section 50.33(f) of obtaining the necessary funds to cover the estimated operating costs in the facility. In this respect, the applicant has demonstrated that it has available resources sufficient to cover estimated costs for each of the first 5 years of operation plus the estimated costs of permanent shutdown and maintenance of the facility in a safe condition (10 CFR Part 50, Appendix C(I)(B)). As a consequence of this, the staff finds that the applicant is financially qualified to operate and safely decommission Waterford 3. In summary, this conclusion is based upon the Company's status as a public utility, the size of its operations, its demonstrated ability to achieve revenues sufficient 20-6
 
to cover its operating and capital costs, and its successful history of obtaining capital in amounts both internally generated and in the external markets.
 
==20.6  REFERENCES==
Atomic Industrial Forum, AIF/NESP-009AIF Code of Federal Regulations:
10 CFR Part 50, Appendix C 10 CFR Section 50.33(f)
Public Utility Holding Company Act, 1935 USNRC report:
NUREG/CR-0130
*See Appendix 8, Bibliography, for complete citations and availability statements.
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21 FINANCIAL PROTECTION AND INDEMNITY REQUIREMENTS 21.1 GENERAL Pursuant to the financial protection and indemnification provisions of the Atomic Energy Act of 1954, as amended (Section 170 and related sections), the Commission has issued regulations on 10 CFR Part 140. These regulations set forth the Commission's requirements with regard to proof of financial protec tion by, and indemnification of, licensees for facilities such as power reac tors under 10 CFR Part 50.
21.2 PREOPERATIONAL STORAGE OF NUCLEAR FUEL The Commission's regulations in 10 CFR Part 140 require that each holder of a construction permit under 10 CFR Part 50, who is also the holder of a license under 10 CFR Part 70 authorizing the ownership and possession for storage only of special nuclear material at the reactor construction site for future use as fuel in the reactor (after issuance of an operating license under 10 CFR Part 50), shall, during the interim storage period prior to licensed operation, have and maintain financial protection in the amount of $1,000,000 and execute an indemnity agreement with the Commission. Proof of financial protection is to be furnished prior to, and the indemnity agreement executed as of, the effective date of the 10 CFR Part 70 license. Payment of an annual indemnity fee is required.
The applicant will furnish the Commission proof of financial protection in the amount of $1,000,000 in the form of a Nuclear Energy Liability Insurance Association Policy. Further, the applicant will execute an Indemnity Agreement with the Commission effective as of the date of its preoperational fuel storage license. The applicant will pay the annual indemnity fee applicable to preoper ational fuel storage.
21.3 OPERATING LICENSES Under the Commission 1 s regulations, 10 CFR Part 140; a license authorizing the operation of a reactor may not be issued until proof of financial protection in the amount required for such operation has been furnished, and an indemnity agreement covering such operation (as distinguished from preoperational fuel storage only) has been executed. The amount of financial protection which must be maintained for Waterford 3 (which has a rated capacity in excess of 100,000 electrical kilowatts), is the maximum amount available from private sources, i.e., the combined capacity of the two nuclear liability insurance pools, which amount is currently ((        )) .
Accordingly ) a license authorizing operation of Waterford 3 will not be issued until proof of financial protection in the requisite amount has been received and the requisite indemnity agreement executed.
21-1
 
The staff expects that, in accordance with the usual procedure, the nuclear liability insurance pools will provide, several days in advance of anticipated issuance of the operating license document, evidence in writing, on behalf of the applicant, that the present coverage has been appropriately amended so that the policy limits have been increased to meet the requirements of the Commission's regulations for reactor operation. Similarly, an operating license will not be issued until an appropriate amendment to the present indemnity agreement has been executed. The applicant will be required to pay an annual fee for operating license indemnity as provided in our regulations.
On the basis of the above considerations, the staff expects that the requirements of 10 CFR Part 140 will be satisfied. Prior to issuance of the operating license, the applicant will be required to comply with the provisions of 10 CFR Part 140 applicable to operating licenses, including those as to proof of financial protection in the requisite amount and as to execution of an appropriate indemnity agreement with the Commission. Final resolution of this item will be discussed in a supplement to this SER.
 
==21.4 REFERENCES==
Atomic Energy Act of 1954.
Code of Federal Regulations:
10 CFR Part 50 10 CFR Part 70 10 CFR Part 140
*See Appendix B, Bibliography, for complete citations and availability statements.
21-2
 
22 TMI-2 REQUIREMENTS
 
==22.1 INTRODUCTION==
 
The accident at Three Mile Island Unit 2 (TMI-2) resulted in requirements which were developed from the recommendations of several groups established to investi gate the accident. These groups include the Congress, the General Accounting Office, the President's Commission on the Accident at Three Mile Island, the NRC Special Inquiry Group, the NRC Advisory Committee on Reactor Safeguards, the Lessons Learned Task Force and the Bulletins and Orders Task Force of the NRC Office of Nuclear Reactor Regulation, the Special Review Group of the NRC Office of Inspection and Enforcement, the NRC Staff Siting Task Force and Emergency Preparedness Task Force, and the NRC Offices of Standards Development and Nuclear Regulatory Research. The report NUREG-0660, entitled "NRC Action Plan Developed as a Result of the TMI-2 Accident" (referred to as Action Plan),
was developed to provide a comprehensive and integrated plan for the actions now judged necessary by NRC to correct or improve the regulation and operation of nuclear facilities. The Action Plan was based on the experience from the TMI-2 accident and the recommendations of the investigating groups.
With the development of the Action Plan (NUREG-0660), NRC has transformed the recommendations of the investigating groups into discrete scheduled tasks that specify changes in its regulatory requirements, organization, or procedures.
Some actions to improve the safety of operating plants were judged to be neces sary before an action plan could be developed, although they were subsequently included in the Action Plan. Such actions came from the Bulletins and Orders issued by the Commission immediately after the accident, the first report of the Lessons Learned Task Force, and the recommendations of the Emergency Preparedness Task Force. Before these immediate actions were applied to operating plants, they were approved by the Commission.
NRC has identified a discrete set of licensing requirements related to TMI-2 in the Action Plan for plants that are scheduled to receive an operating license in the near future. The report NUREG-0737, entitled 11 Clarification of TMI Action Plan Requirements," was issued in November 1980. This report identifies the specific items from NUREG-0660 that have been approved by the Commission for implementation at nuclear power plants. It also includes additional informa tion about schedules, applicability, method of implementation review, submittal dates, and clarification of technical positions. This section summarizes the NRC staff review of Waterford 3 against the criteria of NUREG-0660, as clarified by NUREG-0737.
In the following sections, each requirement from NUREG-0737 related to TMI-2 that applies to Waterford 3 is addressed in sequence. Items required prior to fuel loading are not separated from items required for full power or from dated items. For each item, the staff requirements from NUREG-0660 and/or NUREG-0737 are defined under subsections labeled "Position" and 11 Clarification. 11 Following these, the staff evaluation of the applicant's compliance with NRC requirements 22-1
 
1s given in a subsection 11 labeled "Discussion and Conclusions. 11 All references to the 11 licensee in this section refer to the applicant.
22.2 DISCUSSION OF REQUIREMENTS I.A.1.1 Shift Technical Advisor Pasition Each licensee shall provide an on-shift technical advisor to the shift super visor. The shift technical advisor (STA) may serve more than one unit at a multiunit site if qualified to perform the advisor function for the various units.
The STA shall have a bachelor's degree or equivalent in a scientific or engi neering discipline and have received specific training in the response and analysis of the plant for transients and accidents. The STA shall also receive training in plant design and layout, including the capabilities of instrumenta tion and controls in the control room. The licensee shall assign normal duties to the STAs that pertain to the engineering aspects of assuring safe operations of the plant, including the review and evaluation of operating experience.
Clarification The staff letter of October 30, 1979 from H. R. Denton to All Operating Nuclear Power Plants clarified the short-term STA requirements. That letter indicated that the STAs must have completed all training by January 1, 1981. This paper confirms these requirements and requests additional information.
The need for the STA position may be eliminated when the qualifications of the shift supervisors and senior operators have been upgraded and the man-machine interface in the control room has been acceptably upgraded. However, until those long-term improvements are attained, the need for an STA program will continue.
The staff has not yet established the detailed elements of the academic and training requirements of the STA beyond the guidance given in its {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}}. Nor has the staff made a decision on the level of upgrading required for licensed operating personnel and the man-machine interface in the control room that would be acceptable for eliminating the need of an STA. Until these requirements for eliminating the STA position have been established, the staff continues to require that, in addition to the staffing requirements speci fied in its {{letter dated|date=July 31, 1980|text=July 31, 1980 letter}} (as revised by item I.A.1.3 of this report),
an STA be available for duty on each operating shift when a plant is being oper ated in Modes 1-4 for a PWR and Modes 1-3 for a BWR. At other times, an STA is not required to be on duty.
Since the {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}} was issued, several efforts have been made to establish, for the longer term, the minimum level of experience, education, and training for STAs. These efforts include work on the revision to ANS-3.1, work by the Institute of Nuclear Power Operations (INPO), and internal staff efforts.
22-2
 
INPO recently made available a document entitled 11 Nuclear Power Plant Shift Technical Advisor--Recommendations for Position Description, Qualifications, Education and Training. 11 A copy of Revision O of this document, dated April 30, 1980, is attached as Appendix C to NUREG-0737. Sections 5 and 6 of the INPO document describe the education, training, and experience requirements for STAs.
The NRC staff finds that the descriptions as set forth in Sections 5 and 6 of Revision Oto the INPO document are an acceptable approach for the selection and training of personnel to staff the STA positions. [Note: This should not be interpreted to mean that this is an NRC requirement at this time. The intent is to refer to the INPO document as acceptable for interim guidance for a utility in planning its STA program over the long term (i.e., beyond the January 1, 1981 requirement to have STAs in place  in accordance with the qualification requirements specified in the staff 1 s {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}}).]
No later than January 1, 1981, all licensees of operating reactors shall provide this office with a description of their STA training program and their plans for requalification training. This description shall indicate the level of training attained by STAs by January 1, 1981 and demonstrate conformance with the qualification and training requirements in the {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}}.
Applicants for operating licenses shall provide the same information in this application, or amendments thereto, on a schedule consistent with the NRC licensing review schedule.
No later than January 1, 1981, all licensees of operating reactors shall provide this office with a description of their long-term STA program, including qualifi cation, selection criteria, training plans, and plans, if any, for the eventual phaseout of the STA program. (Note: The description shall include a comparison of the licensee/applicant program with the above-mentioned INPO document. This request solicits industry views to assist NRC in establishing long-term improve ments in the STA program. Applicants for operating licenses shall provide the same information in their application, or amendments thereto, on a schedule consistent witb the NRC licensing review schedule.)
Discussion and Conclusions By {{letter dated|date=April 20, 1981|text=letter dated April 20, 1981}}, the applicant submitted its proposed STA program.
The program will consist of two phases, as stated by the applicant, as follows:
(1)  Prior to Fuel Load--Select and train six STAs who have had orevious operational nuclear plant experience. These STAs will be piaced on an 8-hour rotating shift schedule during integrated testing. Any shortcomings will be madeup by the use of contract personnel.
(2)  Prior to Commercial Operation--Select and train a minimum of nine addi tional STAs who may be entry-level engineers at the inception of training.
These STAs will complete formal training prior to fuel load and will be placed on shift rotation during integrated testing to gain operational experience. The goal is to provide 18 months of total training and expe rience with emphasis on plant-specific experience during startup integrated testing. Following commercial operation, the 15 or more STAs will be placed on a 24-hour duty-day rotation on a collateral duty basis.
22-3
 
In their collateral capacity, STAs will report to the STA Coordinator. The STA Coordinator reports to the Assistant Plant Manager, Operations and Maintenance.
The STA Coordinator position will require a B.S. degree with a minimum of 2 years operational nuclear power experience and a Senior Reactor Operator (SRO) license. It will be the responsibility of the STA Coordinator to assure that STAs are selected and trained to carry out the STA function in a manner consist ent with the importance of the STA position, and so as to command the respect of the operational shifts. The STA Coordinator will also serve as an advisor to the Operations Superintendent on matters concerning plant operations.
The program also describes the STA role in the control room, the STA shift routine and responsibilities during normal and off-normal plant operation, criteria for calling STAs to the control room, the career progression expecta tions for STAs, and plans for continuing STA coverage for  attrition, vacations and illnesses. It does not spe11 out in detail the STA 1 s duties when he is not on duty as an STA.
The proposed program appears to be acceptable. However, during our audit team visit (see Section 13.1 of this report), the staff will review in detail the proposed STA program, including personnel resumes, administrative procedures, the STA 1 s collateral duties, and the supervision chain of command. NRC staff wi11 report the results of the review in a supplement to this report.
I.A.1.2 Shift Supervisor Administrative Duties Position (1) The highest level of corporate management of each licensee shall issue and periodically reissue a management directive that emphasizes the primary management responsibility of the shift supervisor for safe operation of the plant under all conditions on his shift and that clearly establishes his command duties.
(2)  Plant procedures shall be reviewed to assure that the duties, responsibili ties, and authority of the shift supervisor and control room operators are properly defined to effect the establishment of a definite line of command and clear delineation of the command decision authority of the shift supervisor in the control room relative to other plant mangement personnel. Particular emphasis shall be placed on the following:
(a) The responsibility and authority of the shift supervisor shall be to maintain the broadest perspective of operational conditions affecting the safety of the plant as a matter of highest priority at all times when on duty in the control room. The principle shall be reinforced that the shift supervisor should not become totally involved in any single operation in times of emergency when multiple operations are required in the control room.
(b) The shift supervisor, until properly relieved, shall remain in the control room at all times during accident situations to direct the activities of control room operators. Persons authorized to re1ieve the shift supervisor shall be specified.
22-4
 
(c)  If the shift supervisor is temporarily absent from the control room during routine operations, a lead control room operator shall be designated to assume the control room command function. These temporary duties, responsibilities, and authority shall be clearly specified.
(3) Training programs for shift supervisors shall emphasize and reinforce the responsibility for safe operation and the management function the shift supervisor is to provide for assuring safety.
(4)  The administrative duties of the shift supervisor shall be reviewed by the senior officer of each utility responsible for plant operations.
Administrative functions that detract from or are subordinate to the management responsibility for assuring the safe operation of the plant shall be delegated to other operations personnel not on duty in the control room.
Discussion and Conclusions This item is covered in Section I.C.3, Shift Supervisor Responsibilities.
I.A.1.3 Shift Manning Position This position defines shift manning requirements for normal operation. The letter of July 31, 1980 from 0. G. Eisenhut to all power reactor licensees and applicants sets forth the interim criteria for shift staffing (to be effective pending general criteria that will be the subject of future rulemaking).
Overtime restrictions were also included in the {{letter dated|date=July 31, 1980|text=July 31, 1980 letter}}.
Clarification Page 3 of the {{letter dated|date=July 31, 1980|text=July 31, 1980 letter}} is superseded in its entirety by the following:
Licensees of operating plants and applicants for operating licenses shall include in their administrative procedures (required by license conditions) provisions governing required shift staffing and movement of key individuals about the plant. These provisions are required to assure that qualified plant personnel to man the operational shifts are readily available in the event of an abnormal or emergency situation.
These administrative procedures shall also set forth a policy, the objective of which is to operate the plant with the required staff and develop working schedules such that use of overtime is avoided, to the extent practicable, for the plant staff who perform safety-re1ated functions [e.g., senior reactor operators, reactor operators, health physicists, auxi1iary operators, instru mentation and control (I&C) technicians, and key maintenance personnel].
IE Circular No. 80-02, "Nuclear Power Plant Staff Work Hours/ 1 dated February 1, 1980, discusses the concern of overtime work for members of the plant staff who perform safety-related functions.
22-5
 
The staff recognizes that there are diverse opinions on the amount of overtime that would be considered permissib1e and that there is a lack of hard data on the effects of overtime beyond the generally recognized normal 8-hour working day, the effects of shift rotation, and other factors. NRC has initiated studies in this area. Until a firmer basis is developed on working hours, the administrative procedures shall include as an interim measure the following guidance, which generally follows that of IE Circular No. 80-02.
In the event that overtime must be used (excluding extended periods of shutdown for refueling, major maintenance, or major plant modifications), the following overtime restrictions should be followed:
(1) An individual should not be permitted to work more than 12 hours straight (not including shift turnover time).
(2) There should be a break of at least 12 hours (which can include shift turnover time) between all work periods.
(3) An individual should not work more than 72 hours in any 7-day period.
(4) An individual should not be required to work more than 14 consecutive days without having 2 consecutive days off.
However, recognizing that circumstances may arise requiring deviation from the above restrictions, such deviation shall be authorized by the plant manager or his deputy or higher levels of management in accordance with published proce dures and with appropriate documentation of the cause.
If a reactor operator or senior reactor operator has been working more than 12 hours during periods of extended shutdown (e.g., at duties away from the control board), such individuals shall not be assigned shift duty in the control room without at least a 12-hour break preceding such an assignment.
NRC encourages the development of a staffing policy that would permit the licensed reactor operators and senior reactor operators to be periodically assigned to other duties away from the control board during their normal tours of duty.
If a reactor operator is required to work in excess of 8 continuous hours, he shall be periodically relieved of primary duties at the control board, such that periods of duty at the board do not exceed about 4 hours at a time.
The guidelines on overtime do not apply to the shift technical advisor provided he or she is provided sleeping accommodations and a 10-minute availability is assured.
Operating license applicants shall complete these administrative procedures before fuel loading. Development and implementation of the administrative procedures at operating plants will be reviewed by the Office of Inspection and Enforcement beginning 90 days after July 31, 1980.
See section III.A.1.2 for minimum staffing and augment capabilities for emer gencies.
22-6
 
Discussion and Conclusions The applicant's proposed minimum shift crew composition conforms with NRC require ments given in NUREG-0737 for licensed and unlicensed plant operators. However, the NRC staff will examine the details of the upipeline" for assuring that adequate numbers of personnel will be available to staff all essential operations functions, including the presence on each shift of a health physics technician.
In FSAR Amendment 16, the applicant stated that administrative procedures will be adopted governing overtime limitations. NRC will review these procedures during the audit team visit (see Section 13.1 of this report). The results of the review will be discussed in a supplement to this report.
I.A.2.1 Position Effective December 1, 1980, an applicant for a senior reactor operator (SRO) license will be required to have been a licensed operator for 1 year.
Clarification Applicants for SRO either come through the operations chain (C operator to B operator to A operator, etc.) or are degree-holding staff engineers who obtain licenses for backup purposes.
In the past, many individuals who came through the operator ranks were admin istered SRO examinations without first being an operator. This was clearly a poor practice and the letter of March 28, 1980 requires reactor operator experience for SRO applicants.
However, NRC does not wish to discourage staff engineers from becoming licensed SROs. This effort is encouraged because it forces engineers to broaden their knowledge about the plant and its operation.
In addition, in order to attract degree-holding engineers to consider the shift supervisor's job as part of their career development, NRC should provide an alternate path to holding an operator's license for 1 year.
The track followed by a high school graduate (a non-degreed individual) to become an SRO would be 4 years as a control room operator, at least one of which would be as a licensed operator, and participation in an SRO training program that includes 3 months on shift as an extra person.
The track followed by a degree-holding engineer would be, at a minimum, 2 years of responsible nuclear power plant experience as a staff engineer, participation in an SRO training program equivalent to a cold applicant training program, and 3 months on shift as an extra person in training for an SRO position.
Holding these positions assures that individuals who will direct the licensed activities of licensed operators have had the necessary combination of educa tion, training, and actual operating experience prior to assuming a supervisory role at that faility.
22-7
 
The staff realizes that the necessary knowledge and experience can be gained in a variety of ways. Consequently, credit for equivalent experience should be given to applicants for SRO licenses.
Applicants for SRO licenses at a faciity may obtain their 1-year operating experience in a licensed capacity (operator or senior operator) at another nuclear power plant. In addition, actual operating experience in a position that is equivalent to a licensed operator or senior operator at military pro pulsion reactors will be acceptable on a one-for-one basis. Individual appli cants must document this experience in their individual applications in sufficient detail so that the staff can make a finding regarding equivalency.
Applicants for SRO licenses who possess a degree in engineering or applicable sciences are deemed to meet the above requirement, provided they meet the require ments set forth in sections A.1.a and A.2 in Enclosure 1 in the letter from H. R. Denton to all power reactor applicants and licensees, dated March 28, 1980, and have participated in a training program equivalent to that of a cold senior operator applicant.
NRC has not imposed the 1-year experience requirement on cold applicants for SRO licenses. Cold applicants are to work on a facility not yet in operation; their training programs are designed to supply the equivalent of the experience not available to them.
Discussion and Conclusions The applicant has established a program to assure that all reactor operator and senior reactor operator license candidates (beyond the initial complement required to start up Waterford 3) have the prescribed experience qualifi cations and training. Candidates will be prepared and certified in accordance with the applicant's Nuclear Plant Staff Training Program, under Section 13.1, "Development and Implementation of Staff Recruiting and Training Program," the process by which the qualifications of candidates for operations positions will be evaluated by the applicant in the future.
The initial startup crews will have completed extensive training devised in part to recognize the nonoperational status of the unit. This program includes real-time training on the CE PWR simulator located in Windsor, Connecticut, which is similar to the actual unit and thus in many respects equates to the experience requirements. Subsection 13.1.3 of FSAR describes the qualifications commitments for existing plant staff.
The staff concludes that LP&L has satisfied the requirements of this task of the action plan.
I.A.2.3 Administration of Training Programs Position Pending accreditation of training institutions, licensees and applicants for operating licenses will assure that training center and facility instructors who teach systems, integrated responses, transient, and simulator courses demon strate SRO qualifications and be enrolled in appropriate requalification programs.
22-8
 
Clarification The above position is a short-term position. In the future, accreditation of training institutions will include review of the procedure for certification of instructors. The certification of instructors may, or may not, include successful completion of an SRO examination.
The purpose of the examination is to provide NRC with reasonable assurance during the interim period that instructors are technically competent.
The requirement is directed to permanent members of training staff who teach the subjects listed above, including members of other organizations who rou tinely conduct training at the facility. There is no intention to require guest lecturers who are experts in particular subjects (reactor theory, instru mentation, thermodynamics, health physics, chemistry, etc.) to successfully complete an SRO examination. Nor is it intended to require a system expert, such as the instrument and control supervisor teaching the control rod drive system, to complete an SRO examination.
Discussion and Conclusions The applicant defines the uinstructors 11 referenced in this requirement as those individuals who teach systems specific to PWRs, integrated responses, transients, and simulator courses to licensed operators or licensed candidates.
Certification of instructors is described in Subsection 13.2.1 of the applicant's FSAR. This will be accomplished by either demonstrating their senior reactor operator qualifications and enrollment in appropriate requalification programs or successfully completing an instructor certification program accepted by NRC.
Based on the foregoing, the staff has concluded that LP&L has complied with the requirements of this task of the action plan.
IE will verify that all permanent members of the station staff who teach the topics outlined above have completed an SRO examination prior to fuel loading.
I.A.3.1              and Criteria for Licensin Examinations--Simulator Position Simulator examinations will be included as part of the licensing examinations.
Items 1 and 2 require that "Principles of Heat Transfer and Fluid Mechanics, 11 be added to the operator written examination and that the grade required for passing the examination be raised.
Clarification The clarification does not alter the staff's position regarding simulator examinations.
The clarification does provide additional preparation time for utility companies and NRC to meet examination requirements as stated. A study is under way to 22-9
 
consider how similar a nonidentical simulator should be for a valid examination.
In addition, present simulators are fully booked months in advance.
Application of this requirement was stated on June 1, 1980 to applicants where a simulator is located at the facility. Starting October 1, 1981, simulator examinations will be conducted for applicants of facilities that do not have simulators at the site.
NRC simulator examinations normally require 2 to 3 hours. Normally, two applicants are examined during this time period by two examiners.
Utility companies should make the necessary arrangements with an appropriate simulator training center to provide time for these examinations. Preferably, these examinations should be scheduled consecutively with the balance of the examination. However, they may be scheduled no sooner than 2 weeks prior to and no later than 2 weeks after the balance of the examination.
Discussion and Conclusions The applicant's reactor operator and SRO training program has been upgraded to include the subject material described in this requirement. Candidates will be prepared and certified in accordance with the applicant's Nuclear Plant Staff Training Program. The CE PWR simulator is available to the applicant for the simulator portions of the exams. Application package will include a release that permits the NRC to inform LP&L management of exam results.
Based on the foregoing, the staff has concluded that LP&L has complied with the requirements of this task of the action plan.
I.B.1.2 Independent Safety Engineering Group Position The licensee organization shall comply with the findings and requirements generated in an interoffice NRC review of licensee organization and management.
The review will be based, in part, on an NRC document entitled "Draft Criteria for Utility Management and Technical Competence." The first draft of this document was dated February 25, 1980. The current draft was issued for interim use and public comment in September 1980 as NUREG-0731, "Guidelines for Utility Management Structure and Technical Resources. 11 These draft guidelines address the organization, resources, training, and qualifications of plant staff and management (both onsite and offsite) for routine operations and the resources and activities (both onsite and offsite) for accident conditions.
The licensee shall establish a group that is independent of the plant staff but is assigned onsite to perform independent reviews of plant operational activities and a capability for evaluation of operating experiences and nuclear power plants.
Organizational changes are to be implemented on a schedule to be determined prior to fuel loading.
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Corporate management of the utility-owner of a nuclear power plant shall be sufficiently involved in the operational phase activities, including plant modifications, to assure a continual understanding of plant conditions and safety considerations. Corporate management shall establish safety standards for the operation and maintenance of the nuclear power plant. To these ends, each utility-owner shall establish an organization, parts of which shall be located onsite, to: perform independent reviews and audits of plant activi ties; provide technical support to the plant staff for maintenance, modifica tions, operational problems, and operational analysis; and aid in the establishment of programmatic requirements for plant activities.
The licensee shall establish an integrated organizational arrangement to provide for the overall management of nuclear power plant operations. This organization shall provide for clear management control and effective lines of authority and communication between the organizational units involved in the management, technical support, and operation of the nuclear unit.
The key characteristics of a typical organization arrangement are:
(1) Integration of all necessary functional responsibilities under a single responsible person.
(2) The assignment of responsibility for the safe operation of the nuclear power plant(s) to an upper level executive position.
Each applicant for an OL shall establish an onsite independent safety engineering group (ISEG) to perform independent reviews of plant operations.
The principal function of the ISEG is to examine plant operating characteristics, NRC issuances, Licensing Information Service advisories, and other appropriate sources of plant design and operating experience information that may indicate areas for improving plant safety. The ISEG is to perform independent review and audits of plant activities including maintenance, modifications, operational problems, operational analysis, and aid in the establishment of programmatic requirements for plant activities. Where useful improvements can be achieved, it is expected that this group will develop and present detailed recommendations to corporate management for such things as revised procedures or equipment modifications.
Another function of the ISEG is to maintain surveillance of plant operations and maintenance activities to provide independent verification that these activities are performed correctly and that human errors are reduced as far as practicable. ISEG will then be in a position to advise utility management on the overall quality and safety of operations. ISEG need not perform detailed audits of plant operations and shall not be responsible for sign-off functions such that it becomes involved in the operating organization.
Clarification The new ISEG shall not replace the plant  operations review committee (PORC) and the utility 1 s independent review and audit group as specified by current staff guidelines (SRP, RG 1.33, Standard  Technical Specifications). Rather, it is an additional independent group of  a minimum of five dedicated, full-time 22-11
 
engineers, located onsite, but reporting offsite to a corporate official who holds a high-level, technically oriented position that is not in the management chain for power production. The ISEG will increase the available technical expertise located onsite and will provide continuing, systematic, and independent assessment of plant activities. Integrating the STAs into the ISEG in some way would be desirable in that it could enhance the group 1 s contact with and knowledge of day-to-day plant operations and provide additional expertise.
However, the STA on shift is necessarily a member of the operating staff and cannot be independent of it.
It is expected that the ISEG may interface with the quality assurance (QA) organization, but preferably should not be an integral part of the QA organization.
The functions of the ISEG require daily contact with the operating personnel and continued access to plant facilities and records. The ISEG review func tions can, therefore, best be carried out by a group physically located onsite.
However, for utilities with multiple sites, it may be possible to perform portions of the independent safety assessment function in a centralized loca tion for all the utilities' plants. In such cases, an onsite group still is required, but it may be slightly smaller than would be the case if it were performing the entire independent safety assessment function. Such cases will be reviewed on a case-by-case basis.
At this time, the requirement for establishing an ISEG is being applied only to applicants for operating licenses in accordance with Action Plan Item I.8.1.2.
The staff intends to review this activity in about a year to determine its effectiveness and to ascertain whether changes are required. Applicability to operating plants will be considered in implementing long-term improvements in organization and management for operating plants (Action Plan Item I.B.1.1).
Discussion and Conclusions This item is discussed in Section 13.4 of this report.
I.C.l Guidance for the Evaluation and Development of Procedures for Transients and Accidents Position In letters of September 13 and 27, October 10 and 30, and November 9, 1979, the Office of Nuclear Reactor Regulation required licensees of operating plants, applicants for operating licenses, and licensees of plants under construction to perform analyses of transients and accidents, prepare emergency procedure guidelines, upgrade emergency procedures, including procedures for operating with natural circulation conditions, and to conduct operator retraining (also refer to Item I.A.2.1). Emergency procedures are required to be consistent with the actions necessary to cope with the transients and accidents analyzed. Analyses of transients and accidents were to be completed in early 1980 and implementation of procedures and retraining were to be completed 3 months after emergency procedure guidelines were established; however, some difficulty in completing these requirements has been experienced.
Clarification of the scope of the task and appropriate schedule revisions are 22-12
 
being developed. In the course of review of these matters on Babcock and Wilcox (B&W)-designed plants, the staff will follow up on the bulletin and orders matters relating to analysis methods and results, as listed in NUREG-0660, Appendix C (refer to Table C.1, items 3, 4, 16, 18, 24, 25, 26, 27; Table C.2, items 4, 12, 17, 18, 19, 20; and Table C.3, items 6, 35, 37, 38, 39, 41, 47, 55, 57).
Clarification The letters of September 13 and 27, October 10 and 30, November 8, 1979, required that procedures and operator training be developed for transients and accidents. The initiating events to be considered should include the events presented in the final safety analysis report (FSAR) loss of instrumentation buses, and natural phenomena such as earthquakes, floods, and tornadoes. The purpose of this paper is to clarify the requirements and add additional require ments for the reanalysis of transients and accidents and inadequate core cooling.
Based on staff reviews to date, there appear to be some recurring deficiencies in the uide1ines being developed. Specifically, the staff has found a lack of justification for the approach used (i.e., symptom-, event-, or function oriented) in developing diagnostic guidance for the operator and in procedural development. It has also been found that, although the guidelines take implicit credit for operation of many systems or components, they do not address the availability of these systems under expected plant conditions nor do they address corrective or alternative actions that should be performed to mitigate the event should these systems or components fail.
The analyses conducted to date for guideline and procedure development contain insufficient information to assess the extent to which multiple failures are considered. NUREG-0578 concluded that the single-failure criterion was not considered appropriate for guideline development and called for the considera tion of multiple failures and operator errors. Therefore, the analyses that support guideline and procedure development should consider the occurrences of multiple and consequential failures. In general, the sequence of events for the transients and accidents and inadequate core cooling analyzed should postu late multiple failures such that, if the failures were unmitigated, conditions of inadequate core cooling would result.
Examples of multiple faiiure events include:
(1)  Multiple tube ruptures in a single steam generator and tube rupture in more than one steam generator; (2) Failure of main and auxiliary feedwater; (3) Failure of high-pressure reactor coolant makeup system; (4) An anticipated transient without scram (ATWS) event following a loss of offsite power, stuck-open relief valve or safety/relief valve, or loss of main feedwater; and (5) Operator errors of omission or commission.
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The analyses should be carried out far enough into the event to assure that all relevant thermal/hydraulic/neutronic phenomena are identified (e.g., upper head voiding due to rapid cooldown, steam generator stratification). Failures and operator errors during the long-term cooldown period should also be addressed.
The analyses should support development of guidelines that define a logical transition from the emergency procedures into the inadequate core cooling procedure including the use of instrumentation to identify inadequate core cooling conditions. Rationale for this transition should be discussed.
Additional information that should be submitted includes:
(1) A detailed description of the methodology used to develop the guidelines; (2)  Associated control function diagrams, sequence-of-event diagrams, or others, if used; (3)  The bases for multiple and consequential failure considerations; (4) Supporting analysis, including a description of any computer codes used; and (5) A description of the applicability of any generic results to plant-specific applications.
Owners' group or vendor submittals may be referenced as appropriate to support this reanalysis. If owners' group or vendor submittals have already been forwarded to the staff for review, a brief description of the submittals and justification of their adequacy to support guideline development is all that is required.
Pending staff approval of the revised analysis and guidelines, the staff will continue the pilot monitoring of emergency procedures described in Task Action Plan Item I.C.8 (NUREG-0660). For PWRs, this will involve review of the loss of coolant, steam-generator tube rupture, loss of main feedwater, and inadequate core cooling procedures. The adequacy of each PWR vendor's guidelines will be identified to each NTOL during the emergency-procedure review. Since the analysis and guidelines submitted by the General Electric Company (G-E) owners' group that comply with the requirements stated above have been reviewed and approved for trial implementation on six plants with applications for operating licenses pending, the interim program for BWRs will consist of trial implementa tion on these six plants.
Following approval of analysis and guidelines and the pilot monitoring of emergency procedures, the staff will advise all licensees of the adequacy of the guidelines for application to their plants. Consideration will be given to human-factors engineering and system operational characteristics, such as information transfer under stress, compatibility with operator training and control-room design, the time required for component and system response, clarity of procedural actions, and control-room personnel interactions. When this determination has been made by the staff, a long-term plan for emergency procedure review, as described in Task Action Plan Item I.C.9, will be made available. At that time, the reviews currently being conducted on NTOLs under 22-14
 
Item I.C.8 will be discontinued, and the review required for applicants for operating licenses will be as described in the long-term plan. Depending on the information submitted to support development of emergency procedures for each reactor type or vendor, this transition may take place at different times. For example, if the GE guidelines are shown to be effective on the six plants chosen for pilot monitoring, the long-term plan for BWRs may be complete in early 1981. Operating plants and applicants will then have the option of implementing the long-term plan in a manner consistent with their operating schedule, provided they meet the final date required for implementation. This may require a plant that was reviewed for an operating license under Item I.C.8 to revise its emergency procedures again prior to the final implementation date for Item I.C.9. The extent to which the long-term program will include review and approval of plant-specific procedures for operating plants has not been established. Our objective, however, is to minimize the amount of plant-specific procedure review and approval required. The staff believes this objective can be acceptably accomplished by concentrating the staff review and approval on generic guidelines. A key element in meeting this objective is the use of staff approved generic guidelines and guideline revisions by licensees to develop procedures. For this approach to be effective, it is imperative that, once the staff has issued approval of a 9uideline, subsequent revisions of the guide line should not be implemented by l1censees until reviewed and approved by the staff. Any changes in plant-specific procedures based on unapproved guidelines could constitute an unreviewed safety issue under 10 CFR 50.59. Deviations from this approach on a plant-specific basis would be acceptable provided the basis is submitted by the licensee for staff review and approval. In this case, deviations from generic guidelines should not be implemented until staff approval is formally received in writing. Interim implementation of analysis and pro cedures for small-break loss-of-coolant accident and inadequate core cooling should remain on the schedule contained in NUREG-0578, Recommendation 2.1.9.
Pending staff approval of the revised analysis and guidelines, the staff will continue the pilot monitoring of emergency procedures described in Task Action Plan Item I.C.8 (NUREG-0660). For PWRs, this will involve review of the loss of-coolant acident, steam-generator tube rupture, loss of main feedwater, and inadequate core cooling procedures. The adequacy of each PWR vendor's guidelines will be identified for each near-term operating license (NTOL) during the emergency procedure review.
Discussion and Conclusions The Combustion Engineering (C-E) Owners; Group revised analysis and guidelines required by Task Action Plan item I.C.1(3), as clarified in NUREG-0737, have recently been submitted for staff review. Therefore, interim C-E Owners' Group guidelines that are under review by the staff will be used in the evaluation of selected emergency procedures. The C-E Owners' Group interim guidelines were submitted in CEN-117 (Inadequate Core Cooling, October 1979) and CEN-128 (Transients and Accidents). Review of the C-E Owners' Group guidelines has been performed in conjunction with the review for I.C.8 - Pilot Monitoring of Selected Emergency Procedures for NTOLs, and are adequate except for the CE Owners 1 Group inadequate core cooling guidelines. Guidelines prepared from the long-term reanalysis of transients and accidents, including inadequate core cooling, were submitted by the CE Owners' Group for staff review on June 8, 1981. Since the staff is currently reviewing these guidelines, CE has not expended resources 22-15
 
to address staff concerns on the interim guidelines. Since additional work on the interim guidelines was not performed by CE, the staff will conduct a review of the plant-specific Waterford 3 inadequate core cooling procedure. The review of the plant specific procedure to determine if it is technically adequate will be performed to the same depth as would be performed for a generic guideline.
A set of selected Emergency Operating Procedures has been received and the staff has initiated their review. Walk-throughs in a simulator and the Waterford 3 control room are scheduled to ensure that the guidelines have been adequately incorporated into the Emergency Operating Procedures. This review is expected to be completed by August 15, 1981, and we will report on the results in a supple ment to this SER.
i.C.2 Shift and Relief Turnover Procedures Position The licensee shall review and revise as necessary the plant procedure for shift and relief turnover to assure the following:
(1) A checklist shall be provided for the oncoming and offgoing control-room operators and the oncoming shift supervisor to complete and sign. The following items, as a minimum, shall be included in the checklist:
(a) Assurance that critical plant parameters are within allowable limits (parameters and allowable limits shall be listed on the checklist).
(b) Assurance of the availability and proper alignment of all systems essential to the prevention and mitigation of operational transients and accidents by a check of the control console. What to check and criteria for acceptable status shall be included on the checklist.
(c) Identification systems and components that are in a degraded mode of operation permitted by the Technical Specifications. For such systems and components, the length of time in the degraded mode sha11 be com pared with the Technical Specifications action statement. (This shall be recorded as a separate entry on the checklist.)
(2) Checklists or logs shall be provided for completion by the offgoing and oncoming auxiliary operators and technicians. Such checklists or logs shall include any equipment under maintenance or test that by itself could degrade a system critical to the prevention and mitigation of operational transients and accidents or initiate an operational transient (what to check and criteria for acceptable status shall be included on the checklist);
and (3) A system shall be established to evaluate the effectiveness of the shift and relief turnover procedures (for example, periodic independent verifi cation of system alignments).
Discussion and Conclusions Refer to discussion and conclusions in Section I.C.4, Control Room Access.
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I.C.3 Shift Supervisor Responsibilities This item is included in Section I.A.1.2, Shift Supervisor Duties.
Discussion and Conclusions Refer also to discussion and conclusions in Section I.C.4, Control Room Access.
I.C.4 Control Room Access Position The licensee shall make provisions for limiting access to the control room to those individuals responsible for the direct operation of the nuclear power plant (e.g., operations supervisor, shift supervisor, and control room operators),
to technical advisors who may be requested or required to support the operation, and the predesignated NRC personnel. Provisions shall include the following:
(1) Develop and implement an administrative procedure that establishes the authority and responsibility of the person in charge of the control room to limit access; and (2)  Develop and implement procedures that establish a clear line of authority and responsibility in the control room in the event of an emergency. The line of succession for the person in charge of the control room shall be established and limited to persons possessing a current senior reactor operator's license. The plan shall clearly define the lines of communi cation and authority for plant management personnel not in direct command of operations, including those who report to stations outside the control room.
Discussion and Conclusions In FSAR Amendment 16, the applicant stated that plant procedures will be reviewed to assure that (1) the oncoming shift is aware of the status of plant systems, (2) the duties, responsibilities, and authority of the Shift Supervisor and Control Room Operators are properly defined, and (3) a clear line of authority and responsibility is established in the control room.
During the NRC audit team visit (see Section 13.1 of this report), the staff wili review the applicant's procedures to assure that they cover adequately the matters of concern. The results of the review will be discussed in a supplement to this report.
I.C.5 Procedures for Feedback of Operating Experience to Plant Staff Position In accordance with Task Action Plan Item I.C.5, Procedures for Feedback of Operating Experience to Plant Staff (NUREG-0660), each applicant for an OL shall prepare procedures to assure that operating information pertinent to plant safety originating both within and outside the utility organization is continually supplied to operators and other personnel and is incorporated into training and retraining programs. These procedures shall:
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(1)  Clearly identify organizational responsibilities for review of operating experience, the feedback of pertinent information to operators and other personnel I and the incorporation of such information into training and retraining programs; (2)  Identify the administrative and technical review steps necessary in translating recommendations by the operating experience assessment group into p1ant actions (e.g., changes to procedures; operating orders);
(3) Identify the recipients of various categories of information from operating experience (i.e., supervisory personnel, shift technical advisors, operators s maintenance personnel, health physics technicians) or otherwise provide means through which such information can be readily related to the job functions of the recipients; (4) Provide means to assure that affected personnel become aware of and understand information of sufficient importance that should not wait for emphasis through routine training and retraining programs; (5) Assure that plant personnel do not routinely receive extraneous and unimportant information on operating experience in such volume that it would obscure priority information or otherwise detract from overall job performance and proficiency; (6) Provide suitable checks to assure that conflicting or contradictory information is not conveyed to operators and other personnel until resolution is reached; and (7) Provide periodic internal audit to assure that the feedback program functions effectively at all levels.
Clarification Each utility shall carry out an operating experience assessment function that will involve utility personnel having collective competence in all areas important to plant safety. In connection with this assessment function, it is important that procedures exist to assure that important information on operating experience originating both within and outside the organization is continually provided to operators and other personnel and that it is incorporated into plant operating procedures, training, and retraining program.
Those involved in the assessment of operating experience will review information from a variety of sources. These include operating information from the licensee's own plant(s), publications such as IE Bulletins, Circulars, Notices, and pertinent NRC or industrial assessments of operating experience. In some cases, information may be of sufficient importance that it must be dealt with promptly (through instructions, changes to operating and emergency procedures, issuance of special changes to operating and emergency procedures, issuance of specia1 precautions, etc.) and must be handled in such a manner to assure that operations management personnel would be directly involved in the process. In many other cases, however, important information will become available that should be brought to the attention of operators and other personnel for their general information to assure continued safe plant operation. Since the total volume of information handled by the 22-18
 
assessment group may be large, it is important that assurance be provided so that high-priority matters are dealt with promptly and that discrimination is used in the feedback of other information so that personnel are not deluged with unimportant and extraneous information to the detriment of their overall proficiency. It is important, also, that technical reviews be conducted to preclude premature dissemination of conflicting or contradictory information.
Discussion and Conclusions In FSAR Amendment 16, the applicant committed to providing administrative procedures to assure that operating experience from within and outside the LP&L organization will be provided to operators and other operating personnel and incorporated into training programs.
During the NRC audit team visit (see Section 13.1 of this report), the staff will review these procedures to assure that appropriate steps have been taken to provide operating experience information not only to licensed operators but also to unlicensed personnel, including those in technical support positions both onsite and offsite. The results of the review will be discussed in a supplement to this report.
I.C.6 Guidance on Procedures for Verifying Correct Performance of Operating Activities Position It is required (from NUREG-0660) that licensees' procedures be reviewed and revised, as necessary, to assure that an effective system of verifying the cor rect performance of operating activities is provided as a means of reducing human errors and improving the quality of normal operations. This will reduce the frequency of occurrence of situations that could result in or contribute to accidents. Such a verification system may include automatic system status monitoring, human verification of operations and maintenance activities inde pendent of the people performing the activity (see NUREG-0585, Recommendation 5),
or both.
Implementation of automatic status monitoring, if required, will reduce the extent of human verification of operations and maintenance activities but will not eliminate the need for such verification in all instances. The procedures adopted by the licensees may consist of two phases--one before and one after installation of automatic status monitoring equipment, if required, in accord ance with Item I.D.3 of NUREG-0660.
Clarification Item 1.C.6 of the NRC Task Action Plan (NUREG-0660) and Recommendation 5 of NUREG-0585 propose requiring that licensees' procedures be reviewed and revised, as necessary, to assure that an effective system of verifying the correct performance of operating activities is provided. An acceptable program for verification of operating activities is described below.
The American Nuclear Society had prepared a draft revision to ANSI Standard NlB.7-1972 (ANS 3.2), 11 Administrative Controls and Quality Assurance for the 22-19
 
Operational Phase of Nuclear Power Plants. 11 A second proposed revision to Regulatory Guide 1. 33, "Qua 1 ity Assurance Program Requirements (Operation),U which is to be issued for public comment in the near future, wi11 endorse the latest draft revision to ANS 3.2 subject to the following supplemental provisions:
(1) Applicability of the guidance of Section 5.2.6 should be extended to cover surveillance testing in addition to maintenance.
(2) In lieu of any designated senior reactor operator (SRO), the authority to release systems and equipment for maintenance or surveillance testing or return-to-service may be delegated to an on-shift SRO, provided provisions are made to ensure that the shift supervisor is kept fully informed of system status.
(3) Except in cases of significant radiation exposure, a second qualified person should verify correct implementation of equipment control measures such as tagging of equipment.
(4) Equipment control procedures should include assurance that control-room operators are informed of changes in equipment status and the effects of such changes.
(5) For the return-to-service of equipment important to safety, a second qualified operator should verify proper systems alignment unless functional testing can be performed without compromising plant safety, and can prove that all equipment, valves, and switches involved in the activity are correctly aligned.
Note: A licensed operator possessing knowledge of the systems involved and the relationship of the systems to plant safety would be a "qualified" person. The staff is investigating the level of qualification necessary for other operators to perform these functions.
For plants that have or will have automatic system status monitoring as dis cussed in Task Action Plan Item I.D.3, NUREG-0660, the extent of human verifica tion of operations and maintenance activities will be reduced. However, the need for such verification will not be eliminated in all instances.
Discussion and Conclusions In FSAR Amendment 16, the applicant stated that procedures will be reviewed and revised as necessary to assure that an effective system of verifying the correct performance of operating activities is in place. The applicant also stated that Waterford 3 Plant Operating Procedure entitled 11 Conduct of Operations, 11 defines the responsibilities and methods to be used by the Operations Group to ensure that plant operations are conducted in conformance with applicable legal require ments, regulations, and dictates of good operating practices.
During the staff 1 s audit team visit (see Section 13.1 of this report), we will review the applicant 1 s procedures to assure that they cover adequately the matters of concern. We will report the results of our review in a supplement to this report.
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I.C.7 NSSS Vendor Review of Procedures Position Operating license applicants are required to obtain reactor vendor review of their low-power, power-ascension, and emergency procedures as a further veri fication of the adequacy of the procedures.
Discussion and Conclusions The vendor, Combustion Engineering, will review the startup tests and Emergency Operating Procedures. The startup tests encompass the low power testing and the power ascension testing phases. The applicant has committed to ensuring these reviews are complete prior to fuel load. The staff will review the final revision of the procedures selected for I.C.7 to verify that the vendor review has been implemented acceptably, and will report our findings in a supplement to this SER.
I.C.8 Pilot Monitoring of Selected Emergency Procedures for Near-Term Operating License Applicants Position The NRC will conduct an interdisciplinary and interoffice audit of selected plant emergency operating procedures (e.g., small-break LOCA, loss of feedwater, restart of engineered safety features following a loss of ac power, steamline break, or steam-generator tube rupture).
The licensee should correct, before full-power operation, any deficiencies in the emergency procedures, as necessary, based on the NRC audit.
Discussion and Conclusions The selected Emergency Operating Procedures were received on May 19, 1981.
The staff has initiated a review of these procedures. A meeting to discuss staff comments was held for June 24, 1981. A walk-through of the Emergency Operating Procedures on the Palo Verde simulator and in the Waterford Unit 3 control room is scheduled for the week of July 27, 1981. The staff review of I.C.8 is expected to be completed by August 15, 1981, and will be reported in a supplement to this SER.
I.D.1 Control-Room Design Reviews Position In accordance with Task Action Plan I.0.1, Control Room Design Reviews (NUREG-0660), all licensees and applicants for operating licenses will be required to conduct a detailed control-room design review to identify and correct design deficiencies. This detailed control-room design review is expected to take about a year. Therefore, the Office of Nuclear Reactor Regulation (NRR) requires that those applicants for operating licenses who are unable to complete this review prior to issuance of a license make preliminary assessments of their control rooms to identify significant human-factors and 22-21
 
instrumentation problems and establish a schedule approved by NRC for correcting deficiencies. These applicants will be required to complete the more detailed control-room reviews on the same schedule as licensees with operating plants.
Clarification NRR is presently developing human-engineering guidelines to assist each licensee and applicant in performing detailed control-room review. A draft of the guide lines has been published for public comment as NUREG/CR-1580, "Human Engineering Guide to Control Room Evaluation. 11 The due date for comments on this draft document was September 29, 1980. NRR will issue the final version of the guide lines as NUREG-0700 in September 1981, after receiving, reviewing, and incorpo rating substantive public comments from operating reactor licensees, applicants for operating licenses, human-factors engineering experts, and other interested parties. NRR will issue evaluation criteria, by September 1981, which will be used to judge the acceptibility of the detailed reviews performed and the design modifications implemented.
Applicants for operating licenses who will be unable to complete the detailed control-room design review prior to issuance of a license are required to perform a preliminary control-room design assessment to identify significant human-factors problems. Applicants will find it of value to refer to the draft of NUREG/CR-1580 in performing the preliminary assessment. NRR will evaluate the applicants' preliminary assessments including the performance by NRR of onsite review/audit.
The NRR onsite review/audit will be on a schedule consistent with licensing needs and will emphasize the following aspects of the control room:
(1) The adequacy of information presented to the operator to reflect plant status for normal operation, anticipated operational occurrences, and accident conditions; (2) The groupings of displays and the layout of panels; (3)  Improvements in the safety monitoring and human-factors enhancement of controls and control displays; (4)  The communications from the control room to points outside the control room, such as the onsite technical support center, remote shutdown panel, offsite telephone lines, and to other areas within the plant for normal and emergency operation; (5)  The use of direct rather than derived signals for the presentation of process and safety information to the operator; (6)  The operability of the plant from the control room with multiple failures of nonsafety-grade and nonseismic systems; (7) The adequacy of operating procedures and operator training with respect to limitations of instrumentation displays in the control room; (8)  The categorization of alarms, with unique definition of safety alarms; and 22-22
 
(9) The physical location of the shift supervisor's officer either adjacent to or within the control-room complex.
Prior to the onsite review/audit, NRR will require a copy of the applicant's preliminary assessment and additional information which will be used in formu lating the details of the onsite review/audit.
Discussion and Conclusions As part of the NRC staff actions following the TMI-2 accident (Item I.D.1 of NUREG-0660, Vol. 1, May 1980 and NUREG-0737 November 1980), all licensees and applicants for operating licenses are required to conduct a detailed control room design review (DCRDR) to identify and correct human engineering discre ri1 ancies (HEDs). These DCRDRs will be initiated after issuance of NUREG-0700, Guidelines for Control Room Design Reviews," and will be completed within one year. NRC expects to publish the NUREG-0700 documents by the fall of 1981.
Applicants for operating licenses who are unable to complete this DCRDR prior to fuel loading are required to conduct a preliminary design assessment of their control rooms, identify HEDs, and establish a schedule (approved by the NRC) for correcting discrepancies.
Louisiana Power and Light Company (LP&L) performed a preliminary control room assessment (PCRA) of the Waterford 3 control room and submitted its findings to NRC in a report dated April 15, 1981 for review and evaluation. The Human Factors Engineering Branch (HFEB) and its consultants have reviewed the 11 Pre liminary Control Room Assessment in Louisiana Power and Light Company's Waterford SES Unit No. 3.u However, NRC was unable to complete its review because the state of construction of the control room did not permit a meaningful onsite audit. The applicant plans to complete its detailed control room design review and submit a report to NRC prior to fuel loading.
The applicant's PCRA showed an appreciation for the consideration of human factors standards and principles contained in NUREG/CR-1580 and MIL-STD 14728.
The applicant's PCRA, althouh acceptable for staff review, did not include commitments to correct most identified HEDs. The staff will require the appli cant to implement measures to correct significant HEDs before loading fuel.
In addition, the staff recommends that LP&L plan to implement physical changes, where necessary, that would significantly improve human factors interfaces between the control boards and the operators, since LP&L has at least a year before the scheduled date for loading fuel.
NRC evaluation of the applicant 1 s preliminary control room assessment, contained in Appendix E, should be factored into the applicant's detailed control room design review (DCRDR). This DCROR will include a more detailed control room evaluation than was performed for the preliminary assessment. Louisiana*Power and Light stated its intent to perform this DCRDR in the PCRA. Some discrepancies identified during the DCRDR must be corrected before fuel loading and others may be reported on and scheduled in the longer term acceptable to NRC. The final evaluation of the Waterford 3 control room will be reported in a later supplement to the SER prior to issuance of an operating license. NRC requires that a report be submitted 120 days prior to the scheduled date for loading fuel so that the staff may complete its evaluation of the control room.
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Appropriate correction of the discrepancies identified in Appendix E and those identified in the DCRDR will enhance the operators' detection and response capability and lessen the probability of operator error during stressful operating conditions. Based on the review of the applicant's PCRA submittal, the staff concludes that the Waterford 3 control room features can be sufficiently upgraded using human factors standards and principles to allow safe operation of the plant.
1.0.2 Plant Safety Parameter Display Console Position In accordance with Task Action Plan Item I.D.2, Plant Safety Parameter Display Console, each applicant and licensee shall install a safety parameter display system (SPDS) that will display to operating personnel a minimum set of parameters which define the safety status of the plant. This can be attained through continuous indication of direct and derived variables as necessary to assess plant safety status.
Discussion and Conclusions Although this is not yet an NRC requirement, the staff has included a discussion of the SPDS in Section 7.5.4 of this report.
I.G.l Training During Low-Power Testing Position NUREG-0694, "TMI-Related Requirements for New Operating Licenses," requires applicants for a new operating license to define and commit to a special low-power testing program approved by the NRC staff, to be conducted at power levels no greater than 5 percent for the purposes of providing meaningful technical information beyond that obtained in the normal startup test program and to provide supplemental training. This requirement must be met before fuel loading.
Clarification The staff position was stated in a letter to the applicants dated November 14, 1980. This letter stated that the program should provide for the following:
    "Each licensed reactor operator (RO or SRO who performs RO or SRO duties, respectively) should experience the initiation, maintenance and recovery from natural circulation mode, using nuclear heat to simulate decay heat.
Operators should be able to recognize when natural circulation has stabi lized, and should be able to control saturation margin, RCS pressure, and heat removal rate without exceeding specified operating limits.
These tests should demonstrate the following plant characteristics:
length of time required to stablize natural circulation, core flow dis tribution, ability to establish and maintain natural circulation with or 22-24
 
without onsite and offsite power, and the ability to uniformly borate and cool down to hot shutdown conditions using natural circulation. The latter demonstration may be performed using decay heat following power ascension and vendor acceptance tests, and need only be performed at those plants for which the tests has not been demonstrated at a compar able prototype plant. 11 Discussion and Conclusions This item is discussed in Section 14 of this report.
II.B.1 Reactor Coolant System Vents Position Each applicant and licensee shall install reactor coolant system (RCS) and reactor vessel head high point vents remotely operated from the control room.
Although the purpose of the system is to vent noncondensible gases from the RCS which may inhibit core cooling during natural circulation, the vents must not lead to an unacceptable increase in the probability of a loss-of-coolant accident (LOCA) or a challenge to containment integrity. Since these vents form a part of the reactor coolant pressure boundary, the design of the vents shall conform to the requirements of Appendix A to 10 CFR Part 50, 11 General Design Criteria. 11 The vent system shall be designed with sufficient redundancy that assures a low probability of inadvertent or irreversible actuation.
Each licensee shall provide the following information concerning the design and operation of the high point vent system:*
(1) Submit a description of the design, location, size, and power supply for the vent system along with results of analyses for loss-of-coolant accidents initiated by a break in the vent pipe. The results of the analyses should demonstrate compliance with the acceptance criteria of 10 CFR 50.46.
(2) Submit procedures and supporting analysis for operator use of the vents that also include the information availabie to the operator for initiating or terminating vent usage.
Clarification A. Gener-a 1 (1) The important safety function enhanced by this venting capability is core cooling. For events beyond the present design basis, this venting capability will substantially increase the plant 1 s ability to deal with large quanti ties of noncondensible gas which could interfere with core cooling.
*It was the intent of the {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}} to delete the requirement to meet the criteria of 10 CFR 50.44 and SRP 6.2.5 for beyond-design-basis events. The analysis requirements of Position 2 in the {{letter dated|date=September 13, 1979|text=September 13, 1979 letter}} are therefore unnecessary.
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(2) Procedures addressing the use of the reactor coolant system vents should define the conditions under which the vents should be used as well as the conditions under which the vents should not be used. The procedures should be directed toward achieving a substantial increase in the plant being able to maintain core cooling without loss of containment integrity for events beyond the design basis. The use of vents for accidents within the normal design basis must not result in a violation of the requirements of 10 CFR 50.44 or 10 CFR 50.46.
(3) The size of the reactor coolant vents is not a critical issue. The desired venting capability can be achieved with vents in a fairly broad spectrum of sizes. The criteria for sizing a vent can be developed in several ways. One approach, which may be considered, is to specify a volume of noncondensible gas to be vented and in a specific venting time.
For containments particularly vulnerable to failure from large hydrogen releases over a short period of time, the necessity and desirability for contained venting outside the containment must be considered (e.g., into a decay gas collection and storage system).
(4) Where practical, the reactor coolant system vents should be kept smaller than the size corresponding to the definition of LOCA (10 CFR 50, Appendix A).
This will minimize the challenges to the emergency core cooling system (ECCS) since the inadvertent opening of a vent smaller than the LOCA definition would not require ECCS actuation, although it may result in leakage beyond technical specification limits. On PWRs, the use of new or existing lines whose smallest orifice is larger than the LOCA definition will require a valve in series with the vent valve that can be closed from the control room to terminate the LOCA that would result if an open vent valve could not be rec1osed.
(5) A positive indication of valve position should be provided in the control room.
(6) The reactor coolant vent system shall be operable from the control room.
(7) Since the reactor coolant system vent will be part of the reactor coolant system pressure boundary, all requirements for the reactor pressure boundary must be met, and, in addition, sufficient redundancy should be incorporated into the design to minimize the probability of an inadvertent actuation of the system. Administrative procedures may be a viable option to meet the single-failure criterion. For vents larger than the LOCA definition, an analysis is required to demonstrate compliance with 10 CFR 50.46.
(8) The probability of a vent path failing to close, once opened, should be minimized; this is a new requirement. Each vent must have its power supplied from an emergency bus. A single failure within the power and control aspects of the reactor coolant vent system should not prevent isolation of the entire vent system when required. On BWRs, block valves are not required in lines with safety valves that are used for venting.
(9) Vent paths from the primary system to within containment should go to those areas that provide good mixing with containment air.
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(10) The reactor coolant vent system (i.e., vent valves, block valves, position indication devices, cable terminations, and piping) shall be seismically and environmentally qualified in accordance with IEEE 344-1975 as supple mented by RG 1.100, 1.92 and SRP Sections 3.9.2, 3.9.3, and 3.10.
Environmental qualifications are in accordance with the May 27, 1980 Commission Order and Memorandum (CLI-80-21).
(11) Provisions to test for operability of the reactor coolant vent system should be a part of the design. Testing should be performed in accordance with subsection IWV of Section XI of the ASME Code for Category B valves.
(12) It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human-factor analysis should be performed taking into consideration:
(a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritization of alarms.
B. BWR Vent Design Considerations--These considerations are not applicable.
C. PWR Vent Design Considerations (1) Each PWR licensee should provide the capability to vent the reactor vessel head. The reactor vessel head vent should be capable of venting non condensible gas from the reactor vessel hot legs (to the elevation of the top of the outlet nozzle) and cold legs (through head jets and other leakage paths).
(2) Additional venting capability is required for those portions of each hot leg that cannot be vented through the reactor vessel head vent or pressurizer.
It is impractical to vent each of the many thousands of tubes in a U-tube steam generator; however, the staff believes that a procedure can be devel oped that assures sufficient liquid or steam can enter the U-tube region so that decay heat can be effectively removed from the RCS. Such operating procedures should incorporate this consideration.
(3) Venting of the pressurizer is required to assure its availability for system pressure and volume control. These are important considerations, especially during natural circulation.
Discussion and Conclusions The applicant has responded in Amendments 14, 15, and 16 to the NRC requirements for reactor coolant system (RCS) vents. These requirements are described and clarified in NUREG-0737, Item II.B.l. The implementation date for RCS vents is the latter date of July 1982 or the operating license issuance date. The OL issuance for Waterford 3 is beyond July 1982.
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The Waterford 3 RCS vent design consists of twin parallel trains of vent valves connected to the vessel head and pressurizer and feeding into a common header.
This header has two remotely operated valves which permit venting into the quench tank or the containment atmosphere. All valves are operated from the control room and position indication is provided for each. Orifices limit the flow of liquid to less than the capacity of the valve trains. All equipment is classified as seismic Category I. Piping upstream of the orifices and the orifices them selves are safety Class I, whereas all equipment downstream of the orifices are safety Class I I.
Several features are provided to meet the requirements to provide redundancy and minimize inadvertent actuation. Each of the parallel vent paths on the vessel head, pressurizer, and common header are powered from alternate emergency power sources. This assures venting capability with a single active failure.
The instrumentation is also supplied from emergency sources. Inadvertent opera tion is minimized by using key-locked control switches with the power locked out during normal operation. The potential for irreversible operation is reduced by having fail-closed solenoid valves.
The discharge areas of the vent paths offer adequate ventilation and the capability to handle liquid discharge. The valves have been located to minimize potential missile hazards from the solenoid-operated valves. Leak detection for the system has been provided. The applicant has committed to develop procedures for operation of the vent system and to develop testing procedures for the valves. In addition, a human factors analysis will be performed as part of Item I.D.1.
The design features of the Waterford 3 RCS vent system discussed above meet the requirements of NUREG-0737 and are therefore acceptable. The operating procedures, test procedures, and human factors analysis must be successfully completed and reviewed before operation of the vents under power conditions is permitted.
II.B.2 Desi n Review of Plant Shieldin and Environmental ualification of gu1pmen or                        ay                          perations Position With the assumption of a post-accident release of radioactivity equivalent to that described in Regulatory Guide 1.3 and 1.4 (i.e., the equivalent of 50% of the core radioiodine, 100% of the core noble gas inventory, and 1% of the core solids are contained in the primary coolant), each licensee shall perform a radiation and shielding-design review of the spaces around systems that may, as a result of an accident, contain highly radioactive materials. The design review should identify the location of vital areas and equipment, such as the control room, radwaste control stations, emergency power supplies, motor control centers, and instrument areas, in which personnel occupancy may be unduly limited or safety equipment may be unduly degraded by the radiation fields during post accident operations of these systems.
Each licensee shall provide for adequate access to vital areas of protection of safety equipment by design changes, increased permanent or temporary shielding, or post-accident procedural controls. The design review shall determine which types of corrective actions are needed for vital areas throughout the facility.
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Clarification The purpose of this item is to ensure that licensees examine their plants to determine what actions can be taken over the short-term to reduce radiation levels and increase the capability of operators to control and mitigate the consequences of an accident. The actions should be taken pending conclusions resulting in the long-term degraded core rulemaking, which may result in a need to consider additional sources.
Any area that will or may require occupancy to permit an operator to aid in the mitigation of or recovery from an accident is designated as a vital area.
For the purposes of this evaluation, vital areas and equipment are not neces sarily the same vital areas or equipment defined in 10 CFR 73.2 for security purposes. The security center is listed as an area to be considered as poten tially vital, since access to this area may be necessary to take action to give access to other areas in the plant.
The control room, technical support center (TSC), sampling station and sample analysis area must be included among those areas where access is considered vital after an accident. [Refer to Section III.A.1.2 for discussion of the TSC and emergency operations facility.] The evaluation to determine the necessary vital areas should also include, but not.be limited to, consideration of the post-LOCA hydrogen control system, containment isolation reset control area, manual ECCS alignment area (if any), motor control centers, instrument panels, emergency power supplies, security center, and radwaste control panels. Dose rate determinations need not be for these areas if they are determined not to be vital.
As a minimum, necessary modification must be sufficient to provide for vital system operation and for occupancy of the control room, TSC, sampling station, and sample analysis area.
In order to assure that personnel can perform necessary post-accident opera tions in the vital areas, the following guidance is to be used by licensees to evaluate the adequacy of radiation protection to the operators:
(1) Source Term The minimum radioactive source term should be equivalent to the source terms recommended in RG 1.3, 1.4, 1.7 and SRP Section 15.6.5 with appropriate decay times based on plant design (i.e., assuming the radioactive decay that occurs before fission products can be transported to various systems).
(a)  Liguid-Containinr $*stems: 100% of the core equilibrium noble gas inventory, So% o te core equilibrium halogen inventory, and 1% of all others are assumed to be mixed in the reactor coolant and liquids recirculated by residual heat remova1 (RHR), high-pressure coolant injection (HPCI), and low-pressure coolant injection (LPCI), or the equivalent of these systems. In determining the source term for recirculated, depressurized cooling water, assume that the water contains no noble gases.
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(b)                  1 Gas-Containing s stems: 100% of the core equilibrium noble gas inven tory and 25% of he core equilibrium halogen activity are assumed to be mixed in the containment atmosphere. For vapor-containing lines connected to the primary system (e.g., BWR steam lines), the concentra tion of radioactivity shall be determined assuming the activity is contained in the vapor space in the primary coolant system.
(2) Systems Containing the Source Systems assumed in your analysis to contain high levels of radioactivity in a post-accident situation should include, but not be limited to, contain ment, residual heat removal system, safety injection systems, chemical and volume control system (CVCS), containment spray recirculation system, sample lines, gaseous radwaste systems, and standby gas treatment systems (or equivalent of these systems). If any of these systems or others that could contain high levels of radioactivity were excluded, you should explain why such systems were excluded. Radiation from leakage of systems located outside of containment need not be considered for this analysis. Leakage measurement and reduction is treated (in NUREG-0660) under Item III.0.1.1, "Integrity of Systems Outside Containment Likely to Contain Radioactive Material for PWRs and BWRs. 11 Liquid waste systems need not be included in this analysis. Modifications to liquid waste systems will be considered after completion of Item III.D.1.4, 11 Radwaste System Design Features To Aid in Accident Recovery and Decontamination. 11 (3) Dose Rate Criteria The design dose rate for personnel in a vital area should be such that the guidelines of GDC 19 will not be exceeded during the course of the accident. GDC 19 requires that adequate radiation protection be provided such that the dose to personnel should not be in excess of 5 rem whole-body, or its equivalent, to any part of the body for the duration of the accident.
When determining the dose to an operator, care must be taken to determine the necessary occupancy times in a specific area. For example, areas requiring containuous occupancy will require much lower dose rates than areas where minimal occupancy is required. Therefore, allowable dose rates will be based upon expected occupancy, as well as the radioactive source terms and shielding. However, in order to provide a general design objec tive, we are providing the following dose rate criteria with alternatives to be documented on a case-by-case basis. The recommended dose rates are average rates in the area. Local hot spots may exceed the dose rate guide lines. These doses are design objectives and are -  not to be used to limit access in the event of an accident.
(a) Areas Re uirin Continuous Occu anc: <15 mrem/hr (averaged over ese areas w, require full-time occupancy during the course of the accident. The control room and onsite technical support center are areas where continuous occupancy will be required. The dose rate for these areas is based on the control room occupancy factors contained in Standard Review Plan 6.4.
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(b)  Areas Requiring Infrequent Access: GDC 19. These areas may require access on an irregular basis, not continuous occupancy. Shielding should be provided to allow access at a frequency and duration estimated by the licensee. The plant radiochemical/chemical analysis laboratory, radwaste panel, motor control center, instrumentation locations, and reactor coolant and containment gas sample stations are examples of sites where occupancy may be needed often, but not continuously.
(4)  Radiation Qualification of Safety-Related Equipment The review of safety-related equipment which may be unduly degraded by radiation during post-accident operation of this equipment relates to equipment inside and outside of the primary containment. Radiation source terms calculated to deter mine environmental qualification of safety-related equipment consider the following:
(a) LOCA events which completely depressurize the primary system should consider releases of the source term (100% noble gases, 50% iodines, and 1% particulates) to the containment atmosphere.
(b) LOCA events in which the primary system may not depressurize should consider the source term (100% noble gases, 50% iodines, and 1% partic ulates) to remain in the primary coolant. This method is used to determine the qualification doses for equipment in close proximity to recirculating fluid systems inside and outside of containment.
Non-LOCA events both inside and outside of containment should use 10% noble gases, 10% iodines, and 0% particulate as a source term.
The following table summarizes these considerations.
LOCA Source Term                        Non-LOCA (Noble Gas/Iodine/        High-Energy Line Break Source Term Containment          Particulate)            (Noble Gas/Iodine/Particulate)
Outside                  %                                  %
(100/50/1)                        (10/10/0) in RCS                            in RCS Inside              Larger of                          (10/10/0)
(10 /50/1)                        In RCS in containment or (100/50/1) in RCS Discussion and Conclusions The applicant reviewed shielding design to evaluate the ability to have access to vital areas necessary to operate essential systems required after a LOCA with significant core damage.
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The systems analyzed as sources of radiation that would be designed to function after an accident included; reactor containment, the safety injection system; the shutdown cooling system; the containment spray system; the sampling system; controlled ventilation area system; shield building ventilation system; and control room emergency ventilation system. Dose rate calculations were performed for the areas of these systems by placing piping diagram transparencies over general arrangement drawings to determine the source term for each area. Using a SPAN-4 computer code with rectangular, cylindrical and spherical geometries available in libraries of materials densities, cross sections, energy buildup factors etc, the calculations were performed to determine dose rates from the contained sources. Dose rate zone maps, as a function of time following an accident, were provided for each relevant area.
Vital areas requiring accessibility following an accident are identified with respect to location, occupancy requirements and maximum dose levels. Problems associated with unacceptable dose rates have been resolved to make them accept able in accordance with the requirements of NUREG-0737 (i.e., less than 15 mrem/hr averaged over 30 days), and GDC-19. Areas excluded as sources of radiation were the chemical and volume control systems and waste management, and boron management which are not necessary for post LOCA operation. Although the sampling room is a vital area, the applicant has not addressed its resolution for making it acceptable as described above. LP&L plans on providing a new location to make the area acceptable for continuous operation. This is an open item and additional information will be required in order to complete our review.
On the basis of the staff review, we have concluded that, with the exception of post accident sampling and analysis area description, the applicant has performed a radiation and shielding design review for vital area access in accordance with Item II.B.2 of NUREG-0737.
II.B.3 Postaccident Sampling Capability Position A design and operational review of the reactor coolant and containment atmosphere samp1ing line systems shall be performed to determine the capability of personnel to promptly obtain (within 1 hr) a sample under accident conditions without incurring a radiation exposure to any individual in excess of 3 and 18-3/4 rem to the whole body or extremities, respectively. Accident calculations shall be based on Regulatory Guide 1.3 or 1.4 release of fission products. If the review indicates that personnel could not promptly and safely obtain the sampies, additional design features or shielding shall be provided to meet the criteria.
A design and operational review of the radiological spectrum analysis facilities shall be performed to determine the capability to promptly quantify (in less than 2 hrs) certain radionuclides that are indicators of the degree of core damage. Such radionuclides are noble gases (which indicate cladding failure),
iodines and cesiums (which indicate high fuel temperatures), and nonvolatile isotopes (which indicate fuel melting). The initial reactor coolant spectrum should correspond to Regulatory Guide 1.3 or 1.4 release. The review should also consider the effects of direct radiation from piping and components in the auxiliary building and possible contamination and direct radiation from airborne effluents. If the review indicates that the analyses required cannot be performed in a prompt manner with existing equipment, then design modifications or equipment procurement shall be undertaken to meet the criteria.
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In addition to the radiologica1 ana1yses, certain chemical analyses are neces sary for monitoring reactor conditions. Procedures shall be provided to perform boron and chloride chemical analyses assuming a highly radioactive initial sample (Regulatory Guide 1.3 or 1.4 source term). Both analyses shall be capable of being completed promptly (i.e., the boron sample analysis within an hour and the chloride sample analysis within a shift).
Clarification The following items are clarifications of requirements identified in NUREG-0578, NUREG-0660, or the September 13, 1979, October 30, 1979, September 5, 1980 and October 31, 1980 clarification letters.
(1)  The licensee shall have the capability to promptly obtain reactor coolant samples and containment atmosphere samples. The combined time allotted for sampling and analysis should be 3 hr or less from the time a decision is made to take a sample.
(2) The licensee shall establish an onsite radiological and chemical analysis capability to provide, within the 3-hr time frame established above, quantification of the following:
(a) certain radionuclides in the reactor coolant and containment atmosphere that may be indicators of the degree of core damage (e.g., noble gases; iodines and cesiums, and nonvolatile isotopes);
(b) hydrogen levels in the containment atmosphere; (c) dissolved gases (e.g., H 2 ), chloride (time allotted for analysis subject to discussion below), and boron concentration of liquids; and (d) alternatively, have inline monitoring capabilities to perform all or part of the above analyses.
(3) Reactor coolant and containment atmosphere sampling during postaccident conditions shall not require an isolated auxiliary system; e.g., the letdown system, reactor water cleanup system (RWCUS) to be placed in operation in order to use the sampling system.
(4) Pressurized reactor coolant samples are not required if the licensee can quantify the amount of dissolved gases with unpressurized reactor coolant samples. The measurement of either total dissolved gases or H 2 gas in reactor coolant samples is considered adequate. Measuring the 0 2 concen tration is recommended, but is not mandatory.
(5) The time for a chloride analysis to be performed is dependent upon two factors: (a) if the plant's coolant water is seawater or brackish water and (b) if there is only a single barrier between primary containment systems and the cooling water. Under both of the above conditions the licensee shall provide for a chloride analysis within 24 hours of the sample being taken. For all other cases, the licensee shall provide for the analysis to be completed within 4 days. The chloride analysis does not have to be done onsite.
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(6) The design basis for plant equipment for reactor coolant and containment atmosphere sampling and analysis must assume that is is possible to obtain and analyze a sample without radiation exposures to any individual exceeding the criteria of GDC 19 (Appendix A, 10 CFR Part 50) (i.e., 5 rem whole-body, 75 rem extremities). [Note that the design and operationa1 review criterion was changed from the operational limits of 10 CFR Part 20 (NUREG-0578) to the GDC 19 criterion ({{letter dated|date=October 30, 1979|text=October 30, 1979 letter}} from D. G. Eisenhut to all licensees).]
(7) The analysis of primary coolant samples for boron is required for PWRs.
(Note that Revision 2 of Regulatory Guide 1.97, when issued, will likely specify the need for primary coolant boron analysis capability at BWR plants.)
(8) If inline monitoring is used for any sampling and analytical capability specified herein, the licensee shall provide backup sampling through grab samples, and shall demonstrate the capability of analyzing the samples.
Established planning for analysis at offsite facilities is acceptable.
Equipment provided for backup sampling shall be capable of providing at least one sample per day for 7 days following onset of the accident and at least one sample per week until the accident condition no longer exists.
(9) The licensee's radiological and chemical sample analysis capability shall include provisions to:
(a) Identify and quantify the isotopes of the nuclide categories discussed above to levels corresponding to the source terms given in Regulatory Guide 1.3 or 1.4, and 1.7. Where necessary and practicable, the ability to dilute samples to provide capability for measurement and reduction of personnel exposure should be provided. Sensitivity of onsite liquid sample analysis capability should be such as to permit measurement of nuclide concentration in the range from approximately 1 &#xb5;Ci/g to 10 Ci/g.
(b) Restrict background levels of radiation in the radiological and chemical analysis facility from sources such that the sample analysis will provide results with an acceptably small error (approximately a factor of 2). This can be accomplished through the use of sufficient shielding around samples and outside sources, and by the use of ventilation system design which will control the presence of airborne radioactivity.
(10) Accuracy, range, and sensitivity shall be adequate to provide pertinent data to the operator in order to describe radiological and chemical status of the reactor coolant systems.
(11) In the design of the postaccident sampling and analysis capability, consideration should be given to the following items:
(a) Provisions for purging sample lines, for reducing plateout in sample lines, for minimizing sample loss or distortion, for preventing block age of sample lines by loose material in the RCS or containment for appropriate disposal of the samples, and for flow restrictions to 22-34
 
limit reactor coolant loss from a rupture of the sample line. The post-accident reactor coolant and containment atmosphere samples should be representative of the reactor coolant in the core area and the containment atmosphere following a transient or accident. The sample lines should be as short as possible to minimize the volume of fluid to be taken from containment. The residues of sample collection should be returned to containment or to a closed system.
(b) The ventilation exhaust from the sampling station should be filtered with charcoal adsorbers and high efficiency particulate air (HEPA) filters.
Discussion and Conclusions The applicant has committed to a postaccident sampling system that meets the requirements of NUREG-0737, Item Il.B.3 in Amendment 16, but has not provided the technical information required by NUREG-0737 for our evaluation. Implementation of the requirement is not necessary prior to low power operation because only small quantities of radionuclide inventory will exist in the reactor coolant system and therefore will not affect the health and safety of the public. Prior to exceeding 5% power operation, the applicant must demonstrate the capability to promptly obtain reactor coolant samples in the event of an accident in which there is core damage consistent with the conditions stated below.
: 1. Demonstrate compliance with all requirements of NUREG-0737, II.8.3, for sampling, chemical and radionuclide analysis capability, under accident conditions.
: 2. Provide sufficient shielding to meet the requirements of GDC-19, assuming Regulatory Guide 1.3 or 1.4 source terms.
: 3. Commit to meet the sampling and analysis requirements of Regulatory Guide 1.97, Revision 2.
: 4. Verify that all electrically*powered components associated with postaccident sampling are capable of being supplied with power and operated, within thirty minutes of an accident in which there is core degradation, assuming loss of offsite power.
: 5. Verify that valves which are not accessible for repair after an accident are environmentally qualified for the conditions in which they must operate.
: 6. Provide a procedure for relating radionuclide gaseous and ionic species to estimated core damage,
: 7. State the design or operational prov1s1ons to prevent high pressure carrier gas from entering the reactor coolant system from online gas analysis equipment, if it is used.
: 8. Provide a method for verifying that reactor coolant dissolved oxygen is at <0.1 ppm if reactor coolant chlorides are determined to be >0.15 ppm.
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: 9. Provide information on (a) testing frequency and type of testing to ensure long-term operability of the post system accident sampling system and (b) operator training requirements for postaccident sampling.
In addition to the above licensing conditions, the staff is conducting a generic review of accuracy and sensitivity for analytical procedures and online instru mentation to be used for postaccident analysis. The staff will require that the applicant submit data supporting the applicability of each selected analytical chemistry procedure or online instrument along with documentation demonstrating compliance with the licensing conditions four months prior to exceeding 5% power operation, but review and approval of these procedures will not be a condition for full power operation. In the event the staff's generic review determines a specific procedure is unacceptable, the applicant will be required to make modifications as determined by the generic review.
The operating license should be conditioned for the items stated above.
II.B.4 Training for Mitigating Core Damage Position The staff requires that the applicants develop a program to ensure that all operating personnel are trained in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged. The training program shall include the following topics:
A. Incore Instrumentation (1)  Use of fixed or movable incore detectors to determine extent of core damage and geometry changes.
(2)  Use of thermocouples in determining peak temperatures; methods for extended range readings; methods for direct readings at terminal junctions.
B. Excore Nuclear Instrumentation (NIS)
(1) Use of NIS for determination of void formation; void location basis for NIS response as a function of core temperatures and density changes.
C. Vital Instrumentation (1) Instrumentation response in an accident environment; failure sequence (time to failure, method of failure); indication reliability (actual vs indicated level).
(2) Alternative methods for measuring flows, pressures, levels, and temperatures.
(a)  Determination of pressurizer level if all level transmitters fail.
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(b) Determination of letdown flow with a clogged filter (low flow).
(c) Determination of other reactor coolant system parameters if the primary method of measurement has failed.
D. Primary Chemistry (1)  Expected chemistry results with severe core damage; consequences of transferring small quantities of liquid outside containment; importance of using leaktight systems.
(2)  Expected isotopic breakdown for core damage; for clad damage.
(3) Corrosion effects of extended immersion in primary water; time to failure.
E. Radiation Monitoring (1)  Response of process and area monitors to severe damages; behavior of detectors when saturated; method for detecting radiation readings by direct measurement at detector output (over ranged detector); expected accuracy of detectors at different locations; use of detectors to determine extent of core damage.
(2)  Methods of determining dose rate inside containment from measurements taken outside containment.
F. Gas Generation (1) Methods of H 2 generation during an accident; other sources of gas (Xe, Kr); techniques for venting or disposal of noncondensibles.
(2)  H 2 flammability and explosive limit; sources of 0 2 in containment or reactor coolant system.
Discussion and Conclusions A training program covering the above requirements has been developed by the applicant and the training will be completed prior to fuel loading. This training will address the upgraded emergency procedures and contingencies presently being developed.
Based on the foregoing, the staff concludes that the LP&L training and requalifi cation program will meet NRC requirements for training personnel in the use of installed plant systems to control or mitigate an accident in which the core is severely damaged. The applicant has committed to complete the training of all operating personnel in the use of installed systems to monitor and control accidents in which the core may be severely damaged. This training must be completed before the issuance of a full-power license.
The Office of Inspection and Enforcement will verify completion of the (1) training program prior to fuel loading and (2) training of all operational personnel prior to full-power operations.
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II.D.1 Performance Testing of Boiling Water Reactor and Pressurized Water Reactor Relief and Safety Valves Position Pressurized water reactor and boiling water reactor licensees and applicants shall conduct testing to qualify the reactor coolant system relief and safety valves under expected operating conditions for design-basis transients and accidents.
Clarification Licensees and applicants shall determine the expected valve operating conditions through the use of analyses of accidents and anticipated operational occurrences referenced in Regulatory Guide 1.70, Revision 2. The single failures applied to these analyses shall be chosen so that the dynamic forces on the safety and relief valves are maximized. Test pressures shall be the highest predicted by conventional safety analysis procedures. Reactor coolant system relief and safety valve qualification shall include qualification of associated control circuitry, piping, and supports, as well as the valves themselves.
A. Performance Testing of Relief and Safety Valves--The following information must be provided in report form by October 1, 1981:
(1) Evidence supported by test of safety and relief valve functionability for expected operating and accident (non-ATWS) conditions must be provided to NRC. The testing should demonstrate that the valves will open and reclose under the expected flow conditions.
(2)  Since it is not planned to test all valves on all plants, each licensee must submit to NRC a correlation or other evidence to substantiate that the valves tested in the Electric Power Research Institute (EPRI) or other generic test program demonstrate the functionability of as installed primary relief and safety valves. This correlation must show that the test conditions used are equivalent to expected operating and accident conditions as prescribed in the final safety analysis report (FSAR). The effect of as-built relief and safety valve dis charge piping on valve operability must also be accounted for, if it is different from the generic test loop piping.
(3) Test data including criteria for success and failure of valves tested must be provided for NRC staff review and evaluation. These test data should include data that would permit plant-specific evaluation of discharge piping and supports that are not directly tested.
B. Qualification of PWR Block Valves--Although not specifically listed as a short-term lessons-learned requirement in NUREG-0578, qualification of PWR block valves is required by the NRC Task Action Plan NUREG-0660 under task Item II.D.1. It is the understanding of the NRC that testing of several commonly used block valve designs is already included in the generic EPRI PWR safety and relief valve testing program to be completed by July 1, 1981. NUREG-0737 established July 1, 1982 as the date for verification of block valve functionability. By July 1, 1982, each PWR licensee, for plants so equipped, should provide evidence supported by test that the 22-38
 
block or isolation valves between the pressurizer and each power-operated relief valve can be operated, closed, and opened for all fluid conditions expected under operating and accident conditions.
C.      ATWS Testing--Although ATWS testing need not be completed by July 1, 1981, the test facility should be desiQned to accommodate ATWS conditions of approximately 3200 to 3500 (Service Level C pressure limit) psi and 700&deg; F with sufficient capacity to enable testing of relief and safety valves of the size and type used on operating pressurized water reactors.
Discussion and Conclusions The applicant has stated that it will participate in the EPRI/NSAC program to conduct performance testing of PWR relief and safety valves and associated piping and supports. The applicant has referenced the proposed EPRI program ( 11 Program Plan for the Performance Verification of PWR Safety/Relief Valves and Systems, 11 dated December 13, 1979) for the performance testing of these valves. Additionally, by {{letter dated|date=December 15, 1981|text=letter dated December 15, 1981}}, the applicant has responded to the clarification requirements of NUREG-0737.
A description of the EPRI/NSAC program was provided to the NRC in December 1979 and an updated revision to the program was submitted in July 1980. The staff has reviewed these program descriptions and is generally in agreement that the NUREG-0737 technical requirements for relief and safety valves and associated piping and supports can be met, subject to receipt of additional information which was requested by letter of November 26, 1980 to Russel C. Youngdahl.
By letter of December 15, 1980 from R. C. Youngdahl to 0. Eisenhut, EPRI has responded to both the November 26, 1980 staff letter and NUREG-0737. The staff has not completed its review of the EPRI {{letter dated|date=December 15, 1980|text=December 15, 1980 letter}}. However, in that response, EPRI has taken exception to the documentation submittal dates specified in NUREG-0737.
On completion of the review of the EPRI December 15, 1980 submittal, the staff will arrive at a generic resolution regarding the NUREG-0737 required documenta tion submittal dates which will be applicable to all operating reactors. We will require that Louisiana Power & light (LP&L) provide documentation in accord ance with this schedule for the Waterford Unit 3 relief valves, safety valves and associated piping and supports.
Louisiana Power and Light has committed to the requirements of this item to the extend possible at this time. The applicant is participating in the EPRI/NSAC PWR safety and relief valve performance verification test program and is moni toring this program to insure that the test results apply to the Waterford 3 plant specific valves and associated piping and supports. The staff believes that this commitment provides adequate assurance that the requirements for perform ance testing of relief valves, safety valves and associated piping and supports will be satisfied.
The basis for accepting this commitment is our review of the EPRI/NSAC test rogram to date and our continued review to confirm that the test results are 0
Ptab1e for the Waterford 3 plant specific design. We will report the final of our review in a supplement to this evaluation.
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II.0.3 Direct Indication of Relief and Safety Valve Position Position Reactor system relief and safety valves shall be provided with a positive indica tion in the control room derived from a reliable valve position detection device or a reliable indication of flow in the discharge pipe.
Clarification (1) The basic requirement is to provide the operator with unambiguous indica tion of valve position (open or closed) so that appropriate operator actions can be taken.
(2) The valve position should be indicated in the control room. An alarm should be provided in conjunction with this indication.
(3) The valve position indication may be safety grade. If the position indication is not safety grade, a reliable single channel direct indication, powered from a vital instrument bus, may be provided if backup methods of determining valve position are available and are discussed in the emergency procedures as an aid to operator diagnosis of an action.
(4) The valve position indication should be seismically qualified consistent with the component or system to which it is attached.
(5) The position indication should be qualified for its appropriate environment (any transient or accident which would cause the relief or safety valve to lift) and in accordance with Commission Order of May 27, 1980 (CLI-80-21).
(6) It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human-factor analysis should be performed taking into consideration (a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training; and (d) other alarms during emergency and need for prioritization of alarms.
Discussion and Conclusions This item will be addressed in a supplement to this SER.
II.E.1.1 Auxiliary Feedwater System Evaluation Position The Office of Nuclear Reactor Regulation is requiring reevaluation of the auxiliary feedwater (AFW) systems for all PWR operating plant licensees and operating license applications. This action includes:
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(1) Perform a simplified AFW system reliability analysis that uses event-tree and fault-tree logic techniques to determine the potential for AFW system failure under various loss-of-main-feedwater-transient conditions. Partic ular emphasis is given to determining potential failures that could result from human errors, common causes, single-point vulnerabilities, and test and maintenance outages; (2)  Perform a deterministic review of the AFW system using the acceptance criteria of SRP Section 10.4.9 and associated Branch Technical Position ASB 10-1 as principal guidance; and (3)  Reevaluate the AFW system flowrate design bases and criteria.
Clarification Operating Plant Licenses--Items 1 and 2 above have been completed for Westinghouse(),
Combustion Engineering (C-E), and two Babcock and Wilcox (B&W) operating plants (Rancho Seco, short-term only, and TMI-1). As a result of staff review of items 1 and 2, letters were issued to these plants that required the implementation of certain short- and long-term AFW system upgrade requirements. Included in these letters was a request for additional information re9arding item 3 above. The staff is now in the process of evaluating licensees responses and commitments to these letters.
The remaining B&W operating plants(Oconee 1-3, Crystal River 3, AN0-1, and Davis-Besse 1) have submitted the analysis described in item 1 above. The analysis is presently undergoing staff review. When the results of the staff reviews are complete, each of the remaining B&W plants will receive a letter specifying the short- and long-term AFW system upgrade requirements based on item 1 above. Included in these letters will be a request for additional information regarding items 2 and 3 above.
Operating License Applicants--Operating license applicants have been requested to respond to staff letters of March 10, 1980(W and C-E) and April 24, 1980 (B&W). These responses will be reviewed during-the normal review process for these applications.
Discussion and Conclusions This item is discussed in Section 10.4.9 of this SER.
II.E.1.2 Auxiliary Feedwater System Automatic Initiation and Flow Indication PART 1:  Auxiliary Feedwater System Automatic Initiation Position Consistent with satisfying the requirements of General Design Criterion 20 of Appendix A to 10 CFR Part 50 with respect to the timely initiation of the uxiliary feedwater system (AFWS), the following requirements shall be imple-ted in the short term:
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(1) The design shall provide for the automatic initiation of the AFWS.
(2) The automatic initiation signals and circuits shall be designed so that a single failure will not result in the loss of AFWS function.
(3) Testability of the initiating signals and circuits shall be a feature of the design.
(4) The initiating signals and circuits shall be powered from the emergency buses.
(5) Manual capability to initiate the AFWS from the control room shall be retained and shall be implemented so that a single failure in the manual circuits will not result in the loss of system function.
(6) The ac motor-driven pumps and valves in the AFWS shall be included in the automatic actuation (simultaneous and/or sequential) of the loads onto the emergency buses.
(7) The automatic initiating signals and circuits shall be desined so that their failure will not result in the loss of manual capability to initiate the AFWS from the control room.
In the long term, the automatic initiation signals and circuits shall be upgraded in accordance with safety-grade requirements.
Clarification The intent of this recommendation is to assure a reliable automatic initiation system. This objective can be met by providing a system which meets all the requirements of IEEE Standard 279-1971.
The staff has determined that the following salient paragraphs of IEEE 279-1971 should be addressed as a minimum:
IEEE 279-1971, Paragraph 4.1                General Functional Requirements 4.2                Single Failure 4.3, & 4.4          Qualification 4.6                Channel Independence 4.7                Control and Protection System Interaction 4.9 & 4.10          Capability for Testing 4.11                Channel Bypass 4.12                Operating Bypass 4.13                Indication of Bypass 4.17                Manual Initiation PART 2:  Auxiliary Feedwater System Flowrate Indication Position Consistent with satisfying the requirements set forth in GDC 13 to provide the capability in the control room to ascertain the actual performance of the AFWS 22-42
 
when it is called to perform its intended function, the following requirements shall be implemented:
(1)  Safety-grade indication of auxiliary feedwater flow to each steam generator shall be provided in the control room.
(2) The auxiliary feedwater flow instrument channels shall be powered from the emergency buses consistent with satisfying the emergency power diversity requirements of the auxiliary feedwater system set forth in Auxiliary Systems Branch Technical Position 10-1 of the Standard Review Plan, Section 10.4.9.
Clarification The intent of this recommendation is to assure a reliable indication of AFWS performance. This objective can be met by providing an overall indication system that meets the following appropriate design principles:
(1) For Babcock and Wilcox Plants (a) To satisfy these requirements, B&W plants must provide as a minimum two auxiiairy feedwater flowrate indicators for each steam generator.
(b) The flow indication system should conform to the following salient paragraphs of IEEE 279-1971:
IEEE 279-1971, Paragraph 4.1            General Functional Requirements 4.2            Single Failure 4.3 & 4.4      Qua 1 ification 4.6            Channel Independence
: 4. 7            Control and Protection System Interaction
: 4. 9 & 4.10    Capability for Testing (2) For Westinghouse and Combustion Engineering Plants (a) To satisfy these requirements, W and C-E plants must provide as a minimum one auxiliary feedwater-flowrate indicator and one wide-range steam-generator level indicator for each steam generator or two flowrate indicators.
(b) The flow indication system should be:
(i) environmentally qualified (ii)  powered from highly reliable, battery-backed non-Class IE power source (iii) periodica lly testable (iv)  part of plant quality assurance program (v)  capable of display on demand 22-43
 
It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human-factor analysis should be performed taking into consideration:
The use of this information by an operator during both normal and abnormal plant conditions, Integration into emergency procedures, Integration into operator training, and Other alarms during emergency and need for prioritization of alarms.
Discussion and Conclusions This item is discussed in Sections 7.3.4 and 10.4.9 of this SER.
II.E.3.1 Emergency Power Supply for Pressurizer Heaters Position Consistent with satisfying the requirements of GDC 10, 14, 15, 17, and 20 of Appendix A to 10 CFR Part 50 for the event of loss-of-offsite power, the following positions shall be implemented:
(1) The pressurizer heater power supply design shall provide the capability to supply, from either the offsite power source or the emergency power source (when offsite power is not available), a predetermined number of pressurizer heaters and associated controls necessary to establish and maintain natural circulation at hot standby conditions. The required heaters and their controls shall be connected to the emergency buses in a manner that will provide redundant power supply capability.
(2) Procedures and training shall be established to make the operator aware of when and how the required pressurizer heaters shall be connected to the emergency buses. If required, the procedures shall identify under what conditions selected emergency loads can be shed from the emergency power source to provide sufficient capacity for the connection of the pressurizer heaters.
(3) The time required to accomplish the connection of the preselected pressu rizer heater to the emergency buses shall be consistent with the timely initiation and maintenance of nautral circulation conditions.
(4) Pressurizer heater motive and control power interfaces with the emergency buses shall be accomplished through devices that have been qualified in accordance with safety-grade requirements.
Clarification (1)  Redundant heater capacity must be provided, and each redundant heater or group of heaters should have access to only one Class lE division power supply.
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(2)  The number of heaters required to have access to each emergency power source is that number required to maintain natural circulation in the hot standby condition.
(3) The power sources need not necessarily have the capacity to provide power to the heaters concurrent with the loads required for LOCA.
(4) Any changeover of the heaters from normal offsite power to emergency onsite power is to be accomplished manually in the control room.
(5) In establishing procedures to manually reload the pressurizer heaters onto the emergency power sources, careful consideration must be given to (a) which ESF loads may be appropriately shed for a given situation; (b) reset of the safety injection actuation signal to permit the operation of the heaters; and (c) instrumentation and criteria for operator use to prevent overloading a diesel generator.
(6) The Class IE interfaces for main power and control power are to be protected by safety-grade circuit breakers (see also Regulatory Guide 1.75).
(7) Being non-Class IE loads, the pressurizer heaters must be automatically shed from the emergency power sources upon the occurrence of a safety injection actuation signal (see item 5.b. above).
Discussion and Conclusions Consistent with satisfying the requirements of GDC 10, 14, 15, 17, and 20 of Appendix A to 10 CFR for the event of loss of offsite power, the Waterford 3 pressurizer heater power supply design will provide the capability to supply, from either the offsite power source or the emergency power source (when offsite power is not available), a redundant group of pressurizer proportional heaters and associated controls necessary to establish and maintain natural circulation at hot standby conditions. Each group of heaters has access to only one Class lE division power supply. The Class lE interfaces for main power and control power will be protected by safety-grade circuit breakers. Being non-Class lE loads, the pressurizer heaters will be automatically shed from the emergency power source upon the occurrence of a safety injection actuation signal.
The emergency operation procedures will be developed for loading the pressurizer heaters onto the emergency power supply. These procedures will provide operator guidance on instrumentation and criteria to ensure that (1) the diesel generator is not overloaded when manually loading the heaters, (2) pressurizer level indicates that all heaters are covered, and (3) safety injection has not been actuated.
  *ining in the use of these procedures will be incorporated in the operation
    'iing program. Technical specifications reflecting Waterford 3 compliance is requirement wi11 be developed and submitted approximately six months the scheduled fuel 1oading date.
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The NRC staff finds the Waterford design to be in conformance with the preceding requirements and to be acceptable.
II.E.4.1 Dedicated Hydrogen Penetrations Position Plants using external recombiners or purge systems for postaccident combustible gas control of the containment atmosphere should provide containment penetration systems for external recombiner or purge systems that are dedicated to that service only, that meet the redundancy and single-failure requirements of GDC 54 and 56 of Appendix A to 10 CFR 50, and that are sized to satisfy the flow require ments of the recombiner or purge system.
The procedures for the use of combustible gas control systems following an accident that results in a degraded core and release of radioactivity to the containment must be reviewed and revised, if necessary.
Changes to Previous Requirements and Guidance Changes in the implementation date have been made because of equipment procurement problems and to minimize the number of plant shutdowns necessary to install equipment related to the TMI Action Plan.
Clarification (1) An acceptable alternative to the dedicated penetration is a combined design that is single-failure proof ,for containment isolation purposes and single-failure proof for operation of the recombiner or purge system.
(2)  The deciated penetration or the combined single-failure proof alternative shall be sized such that the flow requirements for the use of the recombiner or purge system are satisfied. The design shall be based on 10 CFR 50.44 requirements.
(3) Components furnished to satisfy these requirements shall be safety grade.
(4)  Licensees that rely on purge systems as the primary means of controlling combustible gases following a loss-of-coolant accident should be aware of the positions taken in SECY-80-399 ) Proposed Interim Amendments to 10 CFR 11 Part 50 Related to Hydrogen Control and Certain Degraded Core Considerations. 11 This proposed rule, published in the Federal Register on October 2, 1980, would require plants that do not have recombiners to have the capacity to install external recombiners by January 1, 1982. (Installed internal recombiners are an acceptable alternative to the above.)
(5) Containment atmosphere dilution (CAO) systems are considered to be purge systems for the purpose of implementing the requirements of this TMI Task Action item.
Discussion and Conclusions The Waterford 3 combustible gas control system uses two redundant hydrogen recombiners permanently installed inside containment to control and reduce the 22-46
 
hydrogen gas concentration within containment following a LOCA. Therefore, the requirement for dedicated containment penetrations for postaccident combustible gas control of the containment atmosphere is not applicable to Waterford 3.
The applicant has committed (FSAR Section 1.9.27) to review and revise as necessary prior to the fuel load date all plant procedures concerning the use of the combustible gas control system following an accident that results in a degraded core and release of radioactivity to the containment. Therefore, the staff concludes that the applicant has complied with the provisions of Item II.E.4.1 of NUREG-0737.
II.E.4.2 Containment Isolation Dependability Position (1) Containment isolation system designs shall comply with the recommendations of SRP 6.2.4; i.e., that there be diversity in the parameters sensed for the initiation of containment isolation.
(2)  All plant personnel shall give careful reconsideration to the definition of essential and nonessential systems, identify each system determined to be essential, identify each system determined to be nonessential, describe the basis for selection of each essential system, modify their containment isolation designs accordingly, and report the results of the reevaluation to NRC.
(3) All nonessential systems shall be automatically isolated by the containment isolation signal.
(4)  The design of control systems for automatic containment isolation valves shall be such that resetting the isolation signal will not result in the automatic reopening of containment isolation valves. Reopening of contain ment isolation valves shall require deliberate operator action.
(5) The containment setpoint pressure that initiates containment isolation for nonessential penetrations must be reduced to the minimum compatible with normal operating conditions.
(6) Containment purge valves that do not satisfy the operability criteria set forth in Branch Technical Position CSB 6-4 or the Staff Interim Position of October 23, 1979 must be sealed closed as defined in SRP Section 6.2.4, item II.3.f during operational conditions 1, 2, 3, and 4. Furthermore, these valves must be verified to be closed at least every 31 days.
(7)  Containment purge and vent isolation valves must close on a high radiation signal.
Changes to Previous Requirements and Guidance
'lthough there has been no change in the requirements since NUREG-0660 was issued,
    !ions 5, 6, and 7 have not been previously transmitted to licensees. These 0sitions were not part of the original NUREG-0578 requirements of
          *tion 2.1.4; however, they were added to Item II.E.4.1 of NUREG-0660 22-47
 
as a result of further staff evaluation of features needed to improve containment isolation dependability. The schedule for implementing positions 5, 6, and 7 on operating plants has been changed from NUREG-0660. The design position 5 shall be completed by January 1, 1981, with modifications completed by July 1, 1981. Position 6 shall be implemented by January 1, 1981 or during the following outage of sufficient duration, but no later than January 1, 1982.
Clarification (1) The reference to SRP Section 6.2.4 in position 1 is only to the diversity requirements set forth in that document.
(2)  For postaccident situations, each nonessential penetration (except instrument lines) is required to have two isolation barriers in series that meet the requirements of GDC 54, 55, 56, and 57, as clarified by SRP Section 6.2.4.
Isolation must be performed automatically (i.e., no credit can be given for operator action). Manual valves must be sealed closed, as defined by SRP Section 6.2.4, to qualify as an isolation barrier. Each automatic isolation valve in a nonessential penetration must receive the diverse isolation signals.
(3) Revision 2 to RG 1.141 will contain guidance on the classification of essential versus nonessential systems and is due to be issued by June 1981.
Requirements for operating plants to review their list of essential and nonessential systems will be issued in conjunction with this guide including an appropriate time schedule for completion.
(4) Administrative provisions to close all isolation valves manually before resetting the isolation signals is not an acceptable method of meeting position 4.
(5)  Ganged reopening of containment isolation valves is not acceptable. Reopening of isolation valves must be performed on a valve-by-valve basis, or on a line-by-line basis, provided that electrical independence and other single-failure criteria continue to be satisfied.
(6) The containment pressure history during normal operation should be used as a basis for arriving at an appropriate minimum pressure setpoint for initiating containment isolation. The pressure setpoint selected should be far enough above the maximum observed (or expected) pressure inside containment during normal operation so that inadvertent containment isolation does not occur during normal operation from instrument drift or fluctuations due to the accuracy of the pressure sensor. A margin of 1 psi above the maximum expected containment pressure should be adequate to account for instrument error. Any proposed values greater than 1 psi will require detailed justification. Applicants for an operating license and operating plant licensees that have operated less than one year should use pressure history data from similar plants that have operated more than 1 year, if possible, to arrive at a minimum containment setpoint pressure.
(7) Sealed-closed purge isolation valves shall be under administrative con trol to assure that they cannot be inadvertently opened. Administrative control includes mechanical devices to seal or lock the valve closed, or to prevent power from being supplied to the valve operator. Checking 22-48
 
the valve position light in the control room is an adequate method for verifying every 31 days that the purge valves are closed.
Discussion and Conclusions The applicant has stated that each fluid system penetrating the Waterford 3 primary containment vessel is automatically isolated by one or some combination of four actuation signals except those systems that are considered essential or considered acceptable on some other defined basis. The four actuation signals are (1) containment isolation actuation signal (CIAS), which occurs on either high containment pressure or low pressurizer pressure; (2) safety injection actuation signal (SIAS), which occurs on either high containment pressure or low pressurizer pressure (identical to CIAS but utilizing different circuitry and relays); (3) main steam isolation signal (MSIS), which is generated by low steam generator pressure or high containment pressure; and (4) containment purge isolation signal (CPIS), which is generated by high containment radiation.
The staff concludes that the containment isolation system complies with the provisions of SRP Section 6.2.4 regarding diversity of parameters sensed for containment isolation.
The applicant has designated the following fluid system lines that are not auto matically isolated or sealed closed as essential: the steam lines to the emergency feedwater pump turbine, the atmospheric steam dump lines, the emergency feedwater lines, the component cooling water lines to and from the fan coolers, the safety injection system (SIS sump, LPSI, and HPSI) lines, the containment spray lines, the containment vacuum relief lines, the chemical and volume control charging line, and the actuating instrument lines of the containment vacuum relief system.
The staff finds the applicant 1 s designation of these system lines as essential to be acceptable.
The staff also finds that all nonessential systems use either sealed-closed isolation valves or else the valves are automatically isolated following an accident.
The applicant has stated that the resetting of the isolation actuation signals will not result in the automatic reopening of any containment isolation valves.
Furthermore, the applicant has stated that reopening of isolation valves can only be effected by deliberate operator action after reset of the actuating signal and that each valve must then be opened individually by the operator.
This is in compliance with the requirements of Position 4.
In compliance with the requirement to provide automatic isolation of the contain ment purge and vent isolation valves on a high radiation signal, the containment atmosphere purge system isolation valves are closed on CPIS (high radiation) in addition to CIAS.
The applicant has indicated in the FSAR that the required containment pressure setpoint study of position 5 to determine the minimum containment setpoint ressure compatible with normal operating conditions has not been completed.
  - the applicant intends to use purge valves during operating modes 1, 2, 3
* the applicant must first satisfactorily demonstrate that these valves
      *,, the operability criteria set forth in BTP CSB 6-4 and our Guidelines stration of Operability of Purge and Vent Valves Appendix G).
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The staff concludes that the applicant has met all the requirements of positions 1, 2, 3, 4, 6 and 7. Although the applicant has stated that position 5 will be complied with, it will remain an open item until additional information is provided and reviewed, and will be discussed in a supplement to the SER.
II.F.l, Additional Accident-Monitoring Instrumentation Introduction Item II.F.1 of NUREG-0660 contains the following subparts:
(1) Noble gas effluent radiological monitor; (2) Provisions for continuous sampling of plant effluents for postaccident releases of radioactive iodines and particulates and onsite laboratory capabilities (this requirement was inadvertently omitted from NUREG-0660; see Attachment 2 that follows for position);
(3)  Containment high-range radiation monitor; (4)  Containment pressure monitor; (5) Containment water level monitor; and (6) Containment hydrogen concentration monitor.
NUREG-0578 provided the basic requirements associated with items 1 through 3 above. NRC staff letters issued to all operating nuclear power plants dated September 13, 1979 and October 30, 1979 provided clarification of staff require ments associated with items 1 through 6 above. Attachments 1 through 6 present the staff position on these matters.
The requirements associated with the recommendations of this section should be considered as advanced implementation of certain requirements to be included in Regulatory Guide 1.97, Rev. 2, "Instrumentation to Follow the Course of an Accident, 11 which was issued for comment in November 1980.
It is important that the displays and controls added to the control room as a result of this requirement not increase the potential for operator error. A human-factor analysis has been performed (see Section II.0.2) taking into consideration:
(a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training,    and (d) other alarms during emergency and need for prioritization of alarms.
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11.F.1, Attachment 1, Noble Gas Effluent Monitor Position Noble gas effluent monitors shall be installed with an extended range designed to function during accident conditions as well as during normal operating conditions. Multiple monitors are considered necessary to cover the ranges of interest.
(1) Noble gas effluent monitors with an upper range capacity of 105 mCi/cc (Xe-133) are considered to be practical and should be installed in all operating plants.
(2)  Noble gas effluent monitoring shall be provided for the total range of concentration extending from normal condition [as low as reasonably achievable (ALARA)] concentrations to a maximum of 105 mCi/cc (Xe-133).
Multiple monitors are considered to be necessary to cover the ranges of interest. The range capacity of individual monitors should overlap by a factor of ten.
Clarification (1) Licensees shall provide    continuous monitoring of high-level, post-accident releases of radioactive  noble gases from the plant. Gaseous effluent monitors shall meet the  requirements specified in Table II.F.1-1. Typical plant effluent pathways  to be monitored are also given in the table.
TABLE II. F.1-1 HIGH-RANGE NOBLE GAS EFFLUENT MONITORS REQUIREMENT          Capability to detect and measure concentrations of noble gas fission products in plant gaseous effluents during and following an accident. All potential accident release paths shall be monitored.
PURPOSE              To provide the plant operator and emergency planning agencies with information on plant releases of noble gases during and following an accident.
DESIGN BASIS MAXIMUM RANGE Design range values may be expressed in Xe-133 equivalent values for monitors using gamma radiation detectors or in microcuries per cubic centimeter of air at standard temperature and pressure (STP) for monitors employing beta radiation detector (Note: lR/hr at 1 ft= 6. 7 Ci Xe-133 equivalent for point source).
Calibrations with a higher energy source are acceptable. The decay of radionuclide noble gases after an accident (i.e., the distribution of noble gases changes) should be taken into account.
10 5 &#xb5;Ci/cc          Undiluted containment exhaust gases (e.g., PWR reactor building purge, BWR drywell purge through the standby gas treatment system).
 
TABLE II.F.1-1 (Continued)
Undiluted PWR condenser air removal system exhaust.
104 &#xb5;Ci/cc      Diluted containment exhaust gases (e.g., >  10:l dilution, as with auxiliary building exhaust air).
BWR reactor building (secondary containment) exhaust air.
PWR secondary containment exhaust air.
103 &#xb5;Ci/cc      Buildings with systems containing primary coolant or primary coolant offgases (e.g., PWR auxiliary building, BWR turbine buildings).
PWR steam safety valvetdischarge, atmospheric steam dump valve discharge.
102 &#xb5;Ci/cc      Other release points (e.g., radwaste building, fuel handling/
storage buildings).
REDUNDANCY      Not required; monitoring the final release point of several discharge inputs is acceptable.
SPECIFICATIONS - (None) Sampling design criteria per ANSI Nl3.l.
POWER SUPPLY    Vital instrument bus or dependable backup power supply to normal ac.
CALIBRATION      Calibrate monitors using gamma detectors to Xe-133 equivalent (1 R/hr@ 1 ft= 6. 7 Ci Xe-133 equivalent for point source).
Calibrate monitors using beta detectors to Sr-90 or similar long-lived beta isotope of at least 0.2 MeV.
DISPLAY          Continuous and recording as equivalent Xe-133 concentrations or &#xb5;Ci/cc or actual noble gases.
QUALIFICATION -  The instruments shall provide sufficiently accurate responses to perform the intended function in the environment to which they will be exposed during accidents.
DESIGN          Offline monitoring is acceptable for all ranges of noble CONSIDERATIONS  gas concentrations.
Inline (induct) sensors are acceptable for 102 &#xb5;Ci/cc to 10 5 &#xb5;Ci/cc noble gases. For less than 10 2 &#xb5;Ci/cc, offline monitoring is recommended.
Upstream filtration (prefiltering to remove radioactive iodines and particulates) is not required; however, design should consider all alternatives with respect to capability to monitor effluents following an accident.
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TABLE II.F.1-1 (Continued)
For external mounted monitors (e.g., PWR main steam line),
the thickness of the pipe should be taken into account in accounting for low-energy gamma radiation.
(2) The monitors shall be capable of functioning both during and following an accident. System designs shall accommodate a design-basis release and then be capable of following decreasing concentrations of noble gases.
(3) Offline monitors are not required for the PWR secondary side main steam safety valve and dump valve discharge lines. For this application, externally mounted monitors viewing the main steam line upstream of the valves are acceptable with procedures to correct for the low-energy gammas the external monitors would not detect. Isotopic identification is not required.
(4) Instrumentation ranges shall overlap to cover the entire range of effluents from normal (ALARA) through accident conditions.
(5) The design description shall include the following information:
(a) System description, including (i) instrumentation to be used, including range or sensitivity, energy dependence or response, calibration frequency and tech nique, and vendor 1 s model number, if applicable; (ii) monitoring locations (or points of sampling), including description of methods used to assure representative measurements and background correction; (iii)  location of instrument readout(s) and method of recording, includ ing description of the method or procedure for transmitting or disseminating the information or data; (iv)  assurance of the capability to obtain readings at least every 15 minutes during and following an accident; and (v)  the source of power to be used.
(b) Description of procedures or calculational methods to be used for converting instrument readings to release rate per unit time, based on exhaust air flow and considering radionuclide spectrum distribution as a function of time after shutdown.
Discussion and Conclusions High-range noble gas effluent radiation monitors will be located on the plant stack, the condenser vacuum pump effluent line and the fuel handling building emergency exhaust effluent line. In addition, an external monitor is located on each of the main steam lines to detect activity that may be released during actuation of the safety relief valves.
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The noble gas accident monitors conform to the requirements of items (1), (2) and (4) under the discussion and clarification with the exception that the applicant has not addressed the calibration of the monitors. Such a discussion is required and will be reviewed when the information is submitted together with the final design description.
The noble gas accident monitors conform to item 5 of the discussion and clarifi cation listed above with the following exceptions:
(1) The instrumentation 1 s energy dependence or response has not been indicated nor has its calibration frequency or technique.
(2)  Monitoring locations or points of sampling have not been indicated.
(3)  Methods of recording the data has not been indicated.
This information is required before the noble gas monitoring system can be judged to be in complete compliance with this TMI requirement. This information will be reviewed when the information is submitted.
The main steam line monitors conform to the requirements listed under discussion and clarification with the following exceptions:
Under item 5:
(1) the range or sensitivity energy dependence or response, calibration frequency and technique and vendor's model number are not indicated; and (2)  the location of instrument readouts is not indicated.
The applicant has indicated that plant personnel will record the times at which various safety relief valves are actuated. This information and curves of flowrate through the valves as a function of pressure will be used to estimate the integrated release which would have occurred during the accident. It is our position that it is impractical to rely upon plant personnel to record the times at which the safety relief valves open and close. Therefore, it is our position that times of closure and opening of the safety relief valves should be recorded automatically or that an alternative means for calculating releases from the safety relief valves be utilized. The applicant has indicated that he will propose an alternative method of calculating the release from the safety relief valves. Upon receipt of the description of this methodology and our review, the acceptability of the method will be determined.
The applicant has not provided for review the final design description of the as-built system including piping and instrument drawings and either a description of procedures for system operation and calibration or copies of procedures for system operation and calibration. Such information is required no less tan .
4 months prior to issuance of an OL and the approval of the noble gas on1tor1ryg system is contingent upon the resu1ts of the review of this and other 1nformat1on.
22-54
 
II.F.l, Attachment 2, Sampling and Analysis of Plant Effluents Position Because iodine gaseous effluent monitors for the accident condition are not considered to be practical at this time, capability for effluent monitoring of radioiodines for the accident condition shall be provided with sampling conducted by adsorption on charcoal or other media, followed by onsite laboratory analysis.
Clarification (1)  Licensees shall provide continuous sampling of plant gaseous effluent for postaccident releases of radioactive iodines and particulates to meet the requirements of the enclosed Table II.F.1-2. Licensees shall also provide onsite laboratory capabilities to analyze or measure these samples. This requirement should not be construed to prohibit design and development of radioiodine and particulate monitors to provide online sampling and analysis for the accident condition. If gross gamma radiation measurement techniques are used, then provisions shall be made to minimize noble gas interference.
(2) The shielding design basis is given in Table II.F.1-2. The sampling system design shall be such that plant personnel could remove samples, replace sampling media and transport the samples to the onsite analysis facility with radiation exposures that,are not in excess of the criteria of GDC 19 of 5 rem whole-body exposure and 75 rem to the extremities during the duration of the accident.
(3) The design of the systems for the sampling of particulates and iodines should provide for sample nozzle entry velocities which are approximately isokinetic (same velocity) with expected induct or instack air velocities.
TABLE II.F.1-2 SAMPLING AND ANALYSIS OR MEASUREMENT OF HIGH-RANGE RADIOIODINE AND PARTICULATE EFFLUENTS IN GASEOUS EFFLUENT STREAMS EQUIPMENT            Capability to collect and analyze or measure representative samples of radioactive iodines and particulates in plant gaseous effluents during and following an accident. The capability to sample and analyze for radioiodine and particulate effluents is not required for PWR secondary main steam safety valve and dump valve discharge lines.
PURPOSE              To determine quantitative release of radioiodines and particulates for dose calculation and assessment.
DESIGN BASIS        10 2 &#xb5;Ci/cc of gaseous radioiodine and particulates, SHIELDING            deposited on sampling media; 30 minutes sampling time, average gamma energy (E) of 0.5 MeV.
SAMPLING            Iodine> 90% effective adsorption for all forms of gaseous MEDIA                iodine.
22-55
 
TABLE II.F.1.2(Continued)
Particulates> 90% effective retention for 0.3 micron(&#xb5;)
diameter particulates.
SAMPLING            Representative sampling per ANSI Nl3.l-1969.
CONSIDERATION Entrained moisture in effluent stream should not degrade adsorber.
Continuous collection required whenever exhaust flow occurs.
Provisions for limiting occupational dose to personnel incorporated in sampling systems, in sample handling and transport, and in analysis of samples.
ANALYSIS            Design of analytical facilities and preparation of analytical procedures shall consider the design basis sample.
Highly radioactive samples may not be compatible with generally accepted analytical procedures; in such cases, measurement of emissive gamma radiations and the use of shielding and distance factors should be considered in design.
For accident conditions, sampling may be complicated by a reduction in stack or vent effluent velocities to below design levels, making it necessary to substantially reduce sampler intake flow rates to achieve the isokinetic conditions; therefore, the staff will accept flow control devices which have the capability of maintaining isokinetic conditions with variations in stack or duct design flow velocity of +/-20%. Further departure from the isokinetic condition need not be considered in design. Corrections for non-isokinetic sampling conditions, as provided in Appendix C of ANSI 13.1-1969 may be considered on an ad hoc basis.
(4)  Effluent streams which may contain air with entrained water (e.g., air ejector discharge) shall have provisions to ensure that the adsorber is not degraded while providing a representative sample (e.g., heaters).
Discussion and Conclusions Radioactive iodines and particulates will be Sfu11pled prior to the plant vent stack monitor and the fuel handling buiiding emergency exhaust effluent monitor.
The applicant has indicated that continuous sampling of plant gaseous effluent for postaccident releases of radioiodines and particulates will be provided.
A sampling media that will ensure greater than 90% retnetion of all forms of gaseous iodine and greater than 90% retention for 0.3 micron diameter particles will be used. Sampling wi11 be performed per ANSI N13.l-1969.
Moisture is not anticipated to be a problem. Samples will be continuously collected during the time exhaust flow occurs. The applicant has determined that occupational exposures to personne1 who handle the sampling systems 1 trans port them for analysis 1 and analyze the samples will be within the requirements of General Design Criterion 19 of Appendix A of 10 CFR Part 50. Analysis will 22-56
 
be performed as discussed in TMI Item III.D.3.3, 11 Improved Inplant Iodine Instrumentation Under Accident Conditions. 11 The staff finds that the radioiodine and particulate sampling and analysis system to be installed can meet the intent of the II.F.l requirement, however a post implementation review of the installed system detailed drawings and the procedures for sampling will be performed, and an evaluation provided in a supplement to the SER.
II.F.1, Attachment 3, Containment High-Range Radiation Monitor Position In-containment radiation-level monitors with a maximum range of 108 rad/hr shall be installed. A minimum of two such monitors that are physically separated shall be provided. Monitors shall be developed and qualified to function in an accident environment.
Clarification (1)  Provide two radiation monitor systems in containment which are documented to meet the requirements of Table II.F.1-3.
TABLE II.F.1-3 CONTAINMENT HIGH-RANGE RADIATION MONITOR REQUIREMENT          The capability to detect and measure the radiation level within the reactor containment during and following an accident.
RANGE                1 rad/hr to 10 8 rads/hr (beta and gamma) or alternatively 1 R/hr to 107 R/hr (gamma only).
RESPONSE            60 keV to 3 MeV photons, with linear energy response+/- 20%
for photons of 0.1 MeV to 3 MeV. Instruments must be accurate enough to provide usable information.
REDUNDANT            A minimum of two physically separated monitors (i.e.,
monitoring widely separated spaces within containment).
DESIGN AND          Category 1 instruments as described in Appendix B, except QUALIFICATION        as listed below.
SPECIAL              In-situ calibration by electronic signal substitution is CALIBRATION          acceptable for all range decades above 10 R/hr. In-situ calibration for at least one decade below 10 R/hr shall be by means of calibrated radiation source. The original laboratory calibration is not an acceptable position due to the possible differences after in-situ installation.
For high-range calibration, no adequate sources exist, so an alternate was provided.
22-57
 
IABLE II.F.1-3 (Continued)
SPECIAL            Calibrate and type-test respresentative specimens of ENVIRONMENTAL      detectors at sufficient points to demonstrate linearity QUALIFICATION      throtigh all scales up to 10 6 R/hr. Prior to initial use, certify calibration of each detector for at least one point per decade or range between 1 R/hr and 10 3 R/hr.
(2) The specification of 10 8 rad/hr in the above position was based on a calculation of post3ccident containment radiation levels that included both particulate (beta) and photon (gamma) radiation. A radiation detector that responds to both beta and gamma radiation cannot be qualified to post-LOCA (loss-of-coolant accident) containment environments but gamma sensitive instruments can be so qualified. In order to follow the course of an accident, a containment monitor that measures only gamma radiation is adequate. The requirement was revised in the {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}} to provide for a photon-only measurement with an upper range of 10 7 R/hr.
(3)  The monitors shall be located in containment(s) in a manner as to provide a reasonable assessment of area radiation conditions inside containment.
The monitors shall be widely 11 separated so as to provide independent measurements and shall 11 view a large fraction of the containment volume.
Monitors should not be placed in areas which are protected by massive shielding and should be reasonably accessible for replacement, maintenance, or calibration. Placement high in a reactor building dome is not recommended because of potential maintenance difficulties.
(4) For BWR Mark III containments, two such monitoring systems should be inside both the primary containment (drywell) and the secondary containment.
(5)  The monitors are required to respond to gamma photons with energies as low as 60 keV and to provide an essentially flat response for gamma energies between 100 keV and 3 MeV, as specified in Tab1e II.F.1-3. Monitors that use thick shielding to increase the upper range will underestimate post accident radiation levels in containment by several orders of magnitude because of their insensitivity to low-energy gammas and are not acceptable.
Discussion and Conclusions The applicant has on site and will install two    11 High Range Containment Monitors u in containment. These monitors meet the specifications of Table II.F.1-3 of NUREG-0737 and will have separate read-out via safety related remote display/
control devices mounted on a safety related radiation monitoring cabinet in the control room. They will be unshielded and physically separated on opposite sides of the reactor pressure vessel. The exact position of the monitors has not been specified by the applicant, but drawings indicating the locations of the monitors will be provided to the staff prior to fuel loading.
Subject to receipt of these drawings showing the exact location of the monitors, Waterford 3 meets the position of Item II.F.l Attachment 3 of NUREG-0737.
22-58
 
II.F.1, Attachment 4, Containment Pressure Monitor Position A continuous indication of containment pressure shall be provided in the control room of each operating reactor. Measurement and indication capability shall include three times the design pressure of the containment for concrete, four times the design pressure for steel, and -5 psig for all containments.
Changes to Previous Requirements and Guidance Regulatory Guide 1.97, Rev. 2, has been referenced since the {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}} as the guide for the design and qualification criteria for the containment pressure monitor. However, there have been many changes made to this proposed revision and it has not yet been made final. Therefore, the appropriate sections of the latest version of RG 1.97 have been added to this letter (Appendix 8) and this is to be considered a new requirement.
The implementation date has been changed because of the new requirements and because of equipment procurement problems. The new implementation schedule is intended to allow licensees enough time to complete design modifications with a minimum number of plant shutdowns.
Clarification (1) Design and qualification criteria are outlined in Appendix 8.
(2)  Measurement and indication capability shall extend to 5 psia for subatmospheric containments.
(3) Two or more instruments may be used to meet requirements. However, instruments that need to be switched from one scale to another scale to meet the range requirements are not acceptable.
(4)  Continuous display and recording of the containment pressure over the specified range in the control room is required.
(5)  The accuracy and response time specifications of the pressure monitor shall be provided and justified to be adequate for their intended function.
Discussion and Conclusions The applicant has provided two redundant Class lE channels of instrumentation to measure and continuously indicate/record containment wide range (0-200 psia) pressure. The instrument range of 0-200 psia meets the requirement of extending from -5 psig to four times the design pressure of te steel containment (44 psig).
The accuracy and response time of the containment pressure instrumentation has been reviewed and found adequate for the intended function. The applicant has stated the containment wide range pressure instrumentation shall meet the design and qualification criteria of Appendix 8 to NUREG-0737. With the applicant's commitment, the staff finds that this item is satisfied.
Based on staff review, NRC concludes that Waterford 3 is in full compliance with the requirements of NUREG-0737, Item II.F.1, Attachment 4, 11 Containment Pressure Monitor. 11 22-59
 
II.F.1, Attachment 5, Containment Water Level Monitor Position A continuous indication of containment water level shall be provided in the control room for all plants. A narrow-range instrument shall be provided for PWRs and cover the range from the bottom to the top of the containment sump.
A wide-range instrument shall also be provided for PWRs and shall cover the range from the bottom of the containment to the elevation equivalent to a 600,000-gallon capacity. For BWRs, a wide-range instrument shall be provided and cover the range from the bottom to 5 feet above the normal water level of the suppression pool.
Clarification (1) The containment wide-range water level indication channels shall meet the design and qualification criteria as outlined in Appendix B to NUREG-0737.
The narrow-range channel shall meet the requirements of RG 1.89.
(2) The measurement capability of 600,000 gallons is based on recent plant designs. For older plants with small water capacities, licensees may propose deviations from this requirement based on the available water supply capability at their plant.
(3) Narrow-range water level monitors are required for all sizes of sumps but are not required in those plants that do not contain sumps inside the containment.
(4) For BWR pressure-suppression containments, the emergency core cooling system (ECCS) suction line inlets may be used as a starting reference point for the narrow-range and wide-range water level monitors, instead of the bottom of the suppression pool.
(5) The accuracy requirements of the water level monitors shall be provided and justified to be adequate for their intended function.
Discussion and Conclusions The applicant has provided instrumentation to continuously monitor the containment water level. Redundant Class lE instrumentation channels (narrow range) will measure the containment sump level from 0.5 feet from the bottom of the sump to the top of the sump and display it in the control room on a recorder/ indicator.
Containment flood level (wide range) measurement capability in excess of a level equivalent to 600,000 gallons is provided by two redundant channels of instru mentation with readout in the control room on a recorder/ indicator. The accuracy of the containment narrow and wide range water level instrumentation from trans mitter to recorder/indicator is +4% of the calibrated rane. The applicant has stated the containment wide-range water level indication channels shall meet the design and qualification criteria of Appendix 8 to NUREG-0737 and the narrow-range channels shall meet the requirements of Regulatorr. Guide 1.89, "Qualification of Class lE Equipment for Nuclear Power Plants. 1 Based on staff review, NRC concludes that Waterford 3 is in full compliance with the requirements of NUREG-0737, Item II.F.1, Attachment 5, 11 Containment Water Level Monitor."
22-60
 
II.F.l, Attachment 6, Containment Hydrogen Monitor Position A continuous indication of hydrogen concentration in the containment atmosphere shall be provided in the control room. Measurement capability shall be provided over the range of Oto 10% hydrogen concentration under both positive and negative ambient pressure.
Changes to Previous Requirements and Guidance Regulatory Guide 1.97, Rev. 2, was referenced in the {{letter dated|date=October 30, 1979|text=October 30, 1979 letter}} as the guide for the design and qualification criteria for the containment hydrogen monitor. However, there have been many changes made to this proposed revision and it has not yet been made final. Therefore, the appropriate sections of the latest version of Regulatory Guide 1.97 have been added to this letter (Appendix B) and, therefore, this is to be considered a new requirement.
The implementation date has been changed due to equipment procurement problems.
The new implementation schedule is intended to allow licensees enough time to complete design modifications with a minimum number of plant shutdowns.
Clarification (1) Design and qualification criteria are outlined in Appendix B.
(2)  The continous indication of hydrogen concentration is not required during normal operation.
If an indication is not available at all times, continuous indication and recording shall be functioning within 30 minutes of the initiation of safety injection.
(3)  The accuracy and placement of the hydrogen monitors shall be provided and justified to be adequate for their intended function.
Discussion and Conclusions The Waterford 3 combustible gas control system includes a hydrogen analyzer system consisting of two identical, independent, and redundant hydrogen analyzer systems. Each hydrogen monitoring system can take samples from six separate and distinct locations within containment and can also sample the shield building annulus atmosphere. The hydrogen analyzer systems are located on local control panels in the reactor auxiliary building. Remote control panels are located in the main control room from which the hydrogen analyzer systems can be activated and controlled. Activation of the hydrogen analyzers can be accomplished within 30 minutes of initiation of safety injection. The measured percentage of hydrogen is indicated on recorders in the main control room. The hydrogen analyzers have a range of Oto 10% hydrogen with an accuracy of+ 2.0% of full scale and a rninumurn sensitivity of 0.2% hydrogen by volume and can operate under both positive and negative containment pressures.
The applicant has stated that the hydrogen analyzer system will conform to the design and qualification criteria outlined in Appendix B of NUREG-0737.
 
Based on staff review, NRC concludes that Waterford 3 is in full compliance with the requirements of NUREG-0737, Item II.F.1, Attachment 6, Containment Hydrogen Monitor.
II.F.2 Instrumentation for Detection of Inadequate Core Cooling A. Introduction General Design Criterion 13, 11 Instrumentation and Control, 11 of Appendix A to 10 CFR 50, requires instrumentation to monitor variables 11 * *
* for accident conditions as appropriate to assure adequate safety. 11 In the past, GDC 13 was not interpreted to require instrumentation to directly monitor water level in the reactor vessel as an indicator of the adequacy of core cooling. The instru mentation available on some operating reactors that could indicate inadequate core cooling (ICC) was generally included in the reactor design to perform other functions.
During the TMI-2 accident, a condition of low water level in the reactor vessel and inadequate core cooling existed and was not recognized for a long period of time. This problem was the result of a combination of factors including an insufficient range of existing instrumentation, inadequate emergency procedures, inadequate operator training, unfavorable instrument location (scattered informa tion), and perhaps insufficient instrumentation.
The purpose of this review is to evaluate the implementation at Waterford 3 of the post-TMI ICC indication requirements described in NUREG-0578 as follows:
(1)  Licensees shall develop procedures to be used by the operator to recognize inadequate core cooling with currently available instrumentation. The licensee shall provide a description of the existing instrumentation for the operators to use to recognize these conditions. A detailed description of the analyses needed to form the basis for operator training and procedure development shall be provided pursuant to another short-term11 requirement, 11 Analysis and Design of Off-Normal Transients and Accidents    (see Section 2.1.9 of NUREG-0578).
In addition, each PWR shall install a primary coolant saturation meter to provide online indication of coolant saturation condition. Operator instruction as to use of this meter shall include consideration that it is not to be used exclusive of other related plant parameters.
(2) Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement those devices cited in the preceding section giving an unambiguous, easy-to interpret indication of inadequate core cooling. A description of the functional design requirements for the system shall also be included. A description of the procedures to be used with the proposed equipment, the ana1ysis used in developing these procedures, and a schedule for insta11ing the equipment shall be provided (see Section II.F.2 of NUREG-0737).
22-62
 
B. Existing ICC Instrumentation (II.F.2)
Clarification of Requirements for Existing ICC Instrumentation A clarification of requirement for ICC instrumentation, which is to be installed and operational prior to fuel load, was provided in a letter from H. Denton to all operating nuclear power plants on "Discussion of Lessons Learned Short-Term Requirements," dated October 30, 1979. The letter included the following requirements.
(1)  The analysis and procedures addressed in paragraph A.1., above, will be reviewed and should be submitted to the NRC staff for review.
(2) The purpose of the subcooling meter is to provide a continuous indication of margin to saturated conditions. This is an important diagnostic tool for the reactor operators.
(3) Redundant safety-grade temperature input from each hot leg (or use of multiple core exit in T/Cs) are required.
(4)  Redundant safety-grade system pressure measures should be provided.
(5)  Continuous display of the primary coolant saturation conditions should be provided.
(6) Each PWR should have (a) safety-grade calculational devices and display (minimum of two meters), or (b) a highly reliable single channel, environ mentally qualified, and testable system plus a backup procedure for use of steam tables. If the plant computer is to be used, its availability must be documented.
(7) In the long term, the instrumentation qualifications must be required to be upgraded to meet the requirements of Revision 2 to Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," which was issued for comment in November 1980.
(8) In all cases, appropriate steps (electrical, isolation, etc.) must be taken to assure that the addition of the subcooling meter does not adversely impact the reactor protection of engineered safety features systems.
(9) Table II.F.2-1 of this report provides a definition of information required on the subcooling meter. (Note that this table has been completed by the applicant to provide information applicable to Waterford 3.
Discussion and Conclusions Refer to discussion at end of Item II.F.2.
22-63
 
Staff Evaluation of II.F.2.8 (Existing ICC Instrumentation)
C. Additional ICC Instrumentation (II.F.2)
Position on Additional ICC Instrumentation Licensees shall provide a description of any additional instrumentation or controls (primary or backup) proposed for the plant to supplement existing instrumentation (including primary coolant saturation monitors) in order to provide an unambiguous, easy-to-interpret indication of inadequate core cooling (ICC). A description of the functional design requirements for the system shall also be included.
A description of the procedures to be used with the proposed equipment, the analysis used in developing these procedures, and a schedule for installing the equipment shall be provided.
Clarification, Additional ICC Instrumentation Requirements (1) Design of new instrumentation should provide an unambiguous indication of ICC. This may require new measurements or a synthesis of existing measurements that meet design criteria item 7, below.
(2) The evaluation is to include reactor-water-level indication.
(3)  Licensees and applicants are required to provide the necessary design analy sis to support the proposed final instrumentation system for inadequate core cooling and to evaluate the merits of various instruments to monitor water level and to monitor other parameters indicative of core-cooling conditions.
(4) The indication of ICC must be unambiguous in that it should have the following properties:
(a) It must indicate the existence of inadequate core cooling caused by various phenomena (i.e., high-void-fraction pumped flow as well as stagnant boiloff); and (b) It must not erroneously indicate ICC because of the presence of an unrelated phenomenon.
(5) The indication must give advanced warning of the approach of ICC.
(6) The indication must cover the full range from normal operation to complete core uncovery. For example, water-level instrumentation may be chosen to provide advanced warning of two-phase level drop to the top of the core and could be supplemented by other indicators such as incore and core-exit thermo couples, provided that the indicated temperatures can be correlated to provide indication of the existence of ICC and to infer the extent of core uncovery.
Alternatively, full-range level instrumentation to the bottom of the core may be employed in conjunction with other diverse indicators such as core exit thermocouples to prec1ude misinterpretation due to any inherent deficiencies or inaccuracies in the measurement system selected.
(7) All instrumentation in the final ICC system must be evaluated for conformance to Appendix B to NUREG-0737, "Design and Qua 1 ification Criteria for Accident Monitoring Instrumentation," as clarified or modified by the provision of items (8) and (9) that follow. This is a new requirement.
22-64
 
TABLE II.F.2-1 SUBCOOLED MARGIN MONITOR DATA FOR WATERFORD 3 Display Information Displayed(T-Tsat, Tsat, Press, etc.)                                      Selectable
: 1. Pressure or temperature margin
: 2. Tsat or Psat Display type(analog, digital, CRT)                Digital meter Continuous or on demand                          Continuous Single or redundant display                      Redundant Location of display                              Main control board Alarms(include setpoints)                        30&deg; F reset at 35 &deg; F Overall uncertainty( &deg; F, psi)                    Not available Range of display                                  0-3000 psi 0-710&deg; F Qualifications (seismic, environmental,          IEEE 323-1975 Seismic IEEE 323)                                        IEEE 323-1974 Environment Calculator Type(process computer, dedicated digital or      Dedicated digital analog calc.)                                    Microprocessor If process computer is used, specify              NA availability(% of time)
Single or redundant calculators                  Redundant Selection logic(highest T., lowest press.)        Highest Temp. RCS hot leg Lowest Pressurizer Pressurizer 22-65
 
TABLE II.F.2-1 (Continued)
Display Information Displayed (T-Tsat, Tsat, Press, Etc.)                                      Selectable Qualifications (seismic, environmental,          IEEE 344-1975 Seismic IEEE 323)                                        IEEE 323-1974 Environment Calculational technique (steam tables,            Steam tables functional fit, ranges)
Input Temperature (RTDs or T/Cs)
Temperature (number of sensors and locations)                          TE-0915-2 TE-0911Yl TE-0925-1 TE-0921Y2 Thot:                TE-0911Xl TE-0921X2 Range of temperature sensors                      0-710&deg;F Uncertainty of temperature sensors ( &deg;Fat 1)      Not available Qualifications (seismic, environmental,          IEEE 344-1975 Seismic IEEE 323)                                        IEEE 323-1971 Environmental Pressure (specify instrument used)                Diaphragm type electronic transmitter Pressure (number of sensors and locations)        ') '"'rn.r L
l"' I IY".; -YnY\
t,J <::.:>.::>UI IL<:!
1'"'\V\es t,JI IC
                                                                                            -'* sensors PT-0102-1, PT-0102-2 Range of pressure sensors                        0-3000 psi Uncertainty* of pressure sensors (psi at 1)      Not available*
Qualifications (seismic, environmental,          IEEE-344-1971 Seismic IEEE 323)                                        IEEE-323-1971 Environmental To be completed prior to fuel load.
22-66
 
TABLE II.F.2-1 (Continued)
Display Information Displayed (T-Tsat, Tsat, Press, Etc.)                                                                Selectable Backup Capability Availability of temperature and pressure                                    Temperatures - all hot and cold legs indicated, both hot recorded, one cold leg per steam generator recorded.
Pressure - four channels of pressurizer pressure indication in addition to indication of the two channels which provide input to the SMM.
Availability of steam tables, etc.
Training of operators Procedures
*These items will be completed prior to fuel load.
(8)  If a computer is provided to process liquid-level signals for display, seismic qualification is not required for the computer and associated hard ware beyond the isolator or input buffer at a location accessible for main tenance following an accident. The single-failure criteria of item 2, A---n..J1'** I'\ ... 0 u11nr-r fl"'7'l"'7 ___ ... -        ___ ,,, - *h -h----1 ""- --..1  h-l'IUl'\Cl.l U/.J/ ! llt:t:U IIot OfJtJ IJ L,U L, Ie I.. IQllllt: I Ut: y UIIU 1,11c
                                      =
liJJjJt! IU X D l, isolation device if it is designed to provide 99% availability with respect to functional capability for liquid-level display. The display and associated hardware beyond the isolation device need not be Class lE, but should be energized from a high-reliability power source that is battery-backed.
The quality assurance provisions cited in Appendix B, item 5, need not apply to this portion of the instrumentation system. This is a new requirement.
(9) Incore thermocouples located at the core exit or at discrete axial levels of the ICC monitoring system that are part of the monitoring system should be evaluated for conformity with Attachment 1 to Item II.F.2 in NUREG-0737, 11 Design and Qualification Criteria for PWR Incore Thermocouples, which                              11 is a new requirement.
                                                      "'"' r-,
 
(10) The types and locations of displays and alarms should be*determined by performing a human-factors analysis taking into consideration (a) the use of this information by an operator during both normal and abnormal plant conditions, (b) integration into emergency procedures, (c) integration into operator training, and (d) other alarms during emergency and need for prioritization of alarms.
Discussion and Conclusions The applicant has responded to the NUREG-0737 Section II.F.2 requirement in FSAR Amendment 17 dated April 1981. The applicant has stated in Amendment 17 that they will submit a later amendment to (1) address the reactor vessel level monitoring system (RVLMS) requirement and (2) provide an evaluation of additional instrumentation to indicate the approach to inadequate core cooling (ICC),
including core thermocouples, against the requirements of NUREG-0737.
The staff has reviewed the applicant 1 s submittal and has found that their commit ment is incomplete with respect to the itemized documentation requirements of NUREG-0737. Therefore, the staff will require the applicant to provide acceptable documentation of their ICC system prior to issuance of an operating license.
II.G.1 Emergency Power for Pressurizer Equipment Position Consistent with satisfying the requirements of General Design Criteria 10, 14, 15, 17, and 20 of Appendix A to 10 CFR Part 50 for the event of loss-of-offsite power, the following positions shall be implemented:
Power Supply for Pressurizer Relief and Block Valves and Pressurizer Level Indicators:
(1)  Motive and control components of the Power-Operated Relief Valves (PORVs) shall be capable of being supplied from either the offsite power source or the amergsncy power source when the offsite power is not avai1ab1e.
(2) Motive and control components associated with the PORV block valves shall be capable of being supplied from either the offsite power or the emergency power source when offsite power is not available.
(3)  Motive and control power connections to the emergency buses for the PORVs and their associated block valves shall be through devices that have been qualified in accordance with safety-grade requirements.
(4)  The pressurizer level indication instrument channels shall be powered from the vital instrument buses. The buses shall have the capability of being supplied from either the offsite power source or the emergency power source when offsite power is not available.
22-68
 
TABLE II. F. 2-2 Definition of Intervals in ICC Event Progression Interval No. ICC Phase            Bounding Parameter                    Description 1        Approach to          Reduction in RCS subcooling          Depressurization of RCS to saturation until saturation occurs.              pressure at hot leg temperature or heatup to saturation temperature at safety valve pressure.
2        Approach to          Falling two-phase mixture level      Net loss of coolant mass from RCS N                                      in upper plenum, down to top of      accompanied by boiling from con N
I                                    active fuel.                          tinued depressurization and/or 0)
I.O                                                                          decay power.
3        Approach to and/or    Two-phase level falls from top        Two-phase level drops in core Existence of          of active fuel until minimum          causing clad heatup and producing level during event progression        superheated steam at core exit.
occurs or until 2200&deg; F clad temperature occurs.
4        Recovery from        Two-phase level rises above          Coolant addition by ECCS raises level top of core.                          and quenches fuel. ICC progression is defined to terminate when vessel is full or when stable, controllable conditions exist.
 
TABLE II. F. 2-3 Instruments Included in Evaluations For ICC Instrumentation Sstem Post-Accident                                          Non-      Portion of Development Qua1ification                                          ambiguity ICC Event Instruments                Status      Status          Indication Provided by Instrument      of Signal Indicated Subcooled Margin Monitor  Exists      Qualified      Degree of Subcooling in RCS            Good      Approach Reactor Vessel Level      Under      Wi11 be        (1) Liquid inventory in upper head    Good      Approach Monitor                  Development Qualified      (2) Liquid inventory in upper plenum  Good      Recovery (3) Axial temperature distribution    Good in head and plenum Core Exit Thermocouples    Exists      Can be done    (1) Liquid temperature at core exit    Good      Approach N                                                          (2) Infer with synthesis N
I                                                            (a) Calculated mixture level incore Fair      Existence
'-J 0                                                            (b) Calculated clad temperature    Uncertain Recovery Incore Thermocouples      Concept    Can be done    (1) Metal temperature inside guide    Good      Approach (HJCT)                  Stage                          tube when RCP off                            Existence (2) Infer:
(a) Effective mixture level incore  Uncertain Recovery (b) Clad temperature Self-Powered Neutron      Ex*i sts    Can be done    Indirect measure of mixture level      Poor      Approach Detectors                                            (low-pressure uncovery)                          Only Hot Leg RTD (5 each)      Ex*i sts    Qualified      Fluid temperature in hot log          Good      Approach Infer calculated mixture 1 evel and    Fair      Existence clad temperature                      Uncertain Recovery Excore Neutron Detector    Ex*i sts    Can be done    Indirect measure of gross voiding      Fair      Approach (One, Source range)                                    Indirect indication of mixture                  Existence level incore RCP off                            Recovery Excore Neutron Detector    Concept    Can be done    Same as one excore detector, but      Fair      Approach (Stack of 5, Source range) Stage                      more axial resolution                            Existence Recovery
 
Clarification (1)  Although the primary concern resulting from lessons learned from the accident at TMI is that the PORV block valves must be closable, the design should retain, to the extent practical, the capability to also open these valves.
(2) The motive and control power for the block valve should be supplied from an emergency power bus different from the source supplying the PORV.
(3) Any changeover of the PORV and block valve motive and control power from the normal offsite power to the emergency onsite power is to be accomplished manually in the control room.
(4) For those designs in which instrument air is needed for operation, the electrical power supply should be required to have the capability to be manually connected to the emergency power sources.
Discussion and Conclusions (1)  Waterford 3 has sprinQ loaded pressurizer safety valves; therefore, this position requirement 1s not applicable.
(2) Waterford 3 has no pressurizer block valves; therefore this position is not applicable.
(3) See  (1)  and (2) above.
(4) Waterford 3 pressurizer level indication instrument channels are powered from the Class lE uninterruptible 120V ac power source or the standby power supply (Emergency Diesel Generators).
Technical Specification revisions reflecting Waterford 3 compliance to this requirement will be developed and submitted approximately six months prior to scheduled Operating License.
Based on NRC review, the staff concludes that the existing design for emergency power for pressurizer level indications meets the requirements of NUREG-0737 and is acceptable.
II.K.1 IE Bulletins on Measures to Miti ate Small-Break LOCAs and Loss of ee wa ...er .. cc, en .. s Position NRR will require all operating license applicants to evaluate their plants against the requirements specified in applicable IE Bulletins and not otherwise addressed in the Action Plan, and to take corrective actions as necessary prior to fuel loading. Ultimately, these requirements will be modified by NRR and SD, as appropriate, and required of all plants as preconditions for receipt of an operating license.
NUREG-0694, "TMI-Related Requirements for New Operating Licenses, lists the 11 following two IE Bulletin requirements (item numbers from Table C.1 of NUREG-0660) applicable to Combustion Engineering plants:
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C.1.5      Review all valve positions, positioning requirement, positive controls, and related test and maintenance procedures to assure proper emergency safety features (ESF) functioning.
C.1.10    Review and modify, as required, procedures for removing safety related systems from service (and restoring to service) to assure operability status is known.
Discussion and Conclusions In response to the above requirement, the applicant has stated, in Amendment 17 to the FSAR, that a review of all ESF valve positions, controls, and test and maintenance procedures is conducted during procedure preparation to ensure proper ESF functioning. This review assures normal lineup in the mode required for ESF operation.
Procedures dealin with all safety-related systems and components will require independent verification of all valve operations and breaker positions both for operational safeguards readiness and for realignment while performing maintenance or tests. When maintenance or tests are completed, the same independent verification will be performed for the restoration portion of the procedure to assure the operability status. Periodic tests and checks are performed to verify continued operability status. Review of all procedures concerning ECCS valve operations will be completed and documented prior to fuel loading. The staff finds that the applicant's commitment meets the technical and schedule requirements of NUREG-0737 and is, therefore, acceptable.
II.K.2.13 Thermal Mechanical Report--Effect of High-Pressure Intection Vessel Inte rity for Small-Break Loss-of-Coolant Accident Auxi&#xa5;iary Feedwater w, h No Position A detailed analysis shall be performed of the thermal-mechanical conditions in the reactor vessel during recovery from small breaks with an extended loss of all feedwater.
Clarification The position deals with the potential for thermal shock of reactor vessels resulting from cold safety injection flow. One aspect that bears heaviiy on the effects of safety injection flow is the mixing of safety injection water with reactor coolant in the reactor vessel. B&W provided a report on July 30, 1980 that discussed the mixing question and the basis for a conservative analysis of the potential for thermal shock to the reactor vessel. Other PWR vendors are also required to address this issue with regard to recovery from small breaks with an extended loss of all feedwater. In particular, demonstration shall be provided that sufficient mixing wou1d occur of the cold high-pressure injection (HP!) water with reactor coolant so that significant thermal shock effects to the vessel are precluded.
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Discussion and Conclusions, II.K.2.13 A program which completely addresses the NRC requirements of detailed analysis of the thermal-mechanical conditions in the reactor vessel during recovery from small breaks with an extended loss of all feedwater will be completed, documented, and submitted to NRC by January 1, 1982. This program will consist of analyses for generic Combustion Engineering PWR plant groupings. If required, additional plant specific analyses will be determined based on the results of the generic analyses.
Based on the above, we conclude that the Waterford Unit 3 meets the schedular requirements of this item and is acceptable.
II.K.2.17 Potential for Voiding in the Reactor Coolant System During Transients Position Analyze the potential for voiding in the reactor coolant system (RCS) during anticipated transients.
Clarification The background for this concern and a request for this analysis was originally sent to the Babcock and Wilcox (B&W) licensees in a letter from R. W. Reid, NRC, to all B&W operating plants, dated January 9, 1980.
The results of this evaluation have been submitted by the B&W licensees and is presently undergoing staff review. NUREG-0737 requires that all PWR applicants provide this information.
Discussion and Conclusions In response to the above requirement, the applicant has stated in Amendment 17 to the FSAR that he is participating in a Combustion Engineering Owners' Group evaluation of the generic applicability of these requirements. The applicant has committed to provide the results of this analysis by Janaury 1, 1982. The staff concludes that this commitment meets the implementation schedule of this item in NUREG-0737 and is therefore acceptable. NRC will condition the operating license, if necessary, to require compliance with this implementation schedule.
II.K.2.19  Sen11en+ ,* "1
              ':fU I \.t U.l Auxiliary Feedwater Flow Analysis Position Provide a benchmark analysis of sequential auxiliary feedwater (AFW) flow to the steam generators following a loss of main feedwater.
Clarification This requirement was originally sent to the Babcock and Wilcox (B&W) licensees in a letter from 0. F. Ross, Jr., NRC, to all B&W operating plants, dated August 21, 1979.
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The results of this analysis have been submitted by the B&W licensees and are presently undergoing staff review. NUREG-0737 requires that all PWR applicants provide this information.
Discussion and Conclusions Sequential auxiliary feedwater flow analytical requirements is only of concern to once-through steam generator designs. Since CE uses inverted U-tube steam generator designs, requirements set forth by Item Il.K.2.19 are not applicable to CE designs. As such, the applicant is not required to address the item.
II.K.3.1 Installation and Testing of Automatic Power-Operated Relief Valve Isolation System This item is not applicable to Waterford 3 because PORVs are not part of the plant design.
II.K.3.2 Report on Overall Safety Effect of Power-Operated Relief Valve Isolation System This item is not applicable to Waterford 3 because PORVs are not part of the plant design.
II.K.3.3 Reporting of Safety Valve and Relief Valve Failure and Challenges Position Any faiiure of a PORV or safety valve to close will be reported to the NRC promptly. All challenges to the PORVs or safety valves should be documented in the annual report.
Discussion and Conclusions In response to the above requirements, the applicant has stated in Amendment 15 to the FSAR that the failures of the spring-loaded pressurizer safety valves will be reported to NRC promptly. All challenges to the safety valves will be documented in the annual report. The staff concludes that this commitment meets the requirements of this item and is acceptable.
II.K.3.5 Automatic Trip of Reactor Coolant Pumps During Loss-of-Coolant Accident Position Tripping of the reactor coolant pumps (RCPs) in case of a loss-of-coolant accident (LOCA) is not an ideal solution. Licensees should consider other solutions to the small-break LOCA problem (for example, an increase in safety injection flow rate). In the meantime, until a better solution is found, the reactor coolant pumps should be tripped automatically in case of a small-break LOCA. The signals designated to initiate the pump trip are discussed in NUREG-0623.
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Clarification This action item has been revised in the May 1980 version of NUREG-0660 to provide for continued study of criteria for early reactor coolant pump trip. Implementa tion, if any is required, will be delayed accordingly. As part of the continued study, all holders of approved emergency core cooling (ECC) models have been required to analyze the forthcoming LOFT test (L3-6). The capability of the industry models to correctly predict the  experimental behavior of this test will have a strong input on the staff 1 s determination of when and how the reactor coolant pumps should be tripped.
Discussion and Conclusions In response to the above requirement, the applicant has stated in Amendment 15 to the FSAR that, through their participation in the Combustion Engineering Owners 1 Group, they are continuing to study the effects of RCPs on small-break LOCAs and the possible need for automatic RCP trip.
A report (CEN-115) that contains the results of a generic study of the influence of RCPs on 1 small-break LOCA transients has been provided to the staff by the C-E Owners Group. Following model verification through comparison with integral test data, the need for an automatic RCP trip will be reassessed. Based on the above, the staff concludes that the applicant has met the requirements of this item.
II.K.3.17 Report on Outages of Emergenc Core Cooling Systems, Licensee Report, and Proposed Technical Speciffcation Changes Position Several components of the emergency core cooling (ECC) systems are permitted by Technical Specifications to have substantial outage time (e.g., 72 hours for one diesel generator, 14 days for the HPCI system). In addition, there are no cumulative outage time limitations for ECC systems. Licensees should submit a report detailing outage date and lengths of outages for all ECC systems for the last 5 years of operation. The report should also include the causes of the outages (i.e., controller failure, spurious isolation).
Clarification The present Technical Specifications contain limits on allowable outage time for ECC systems and components. However, there are no cumulative outage time limitations on these same systems. It is possible that ECC equipment could meet present Technical Specification requirements but have a high unavailability because of frequent outages within the allowable Technical Specifications.
The licensee should submit a report detailing outage dates and length of outages for all ECC systems for the last 5 years of operation, including causes of the outages. This report will provide the staff with a quantification of historical unreliability due to test and maintenance outages, which will be used to determine if a need exists for cumulative outage requirements in the technical specifications.
Based on the above guidance and clarification, a detailed report should be sub mitted. The report should contain (1) outage dates and duration of outages; 22-75
 
(2) cause of the outage; (3) ECC systems or components involved in the outage; and (4) corrective action taken. Test and maintenance outages should be included in the above listings which are to cover the last 5 years of operation. The licensee should propose changes to improve the availability of ECC equipment, if needed.
Each applicant for an operating license shall establish a plan to meet these requirements.
Discussion and Conclusions In response to the above requirements, the applicant has stated in Amendment 17 to the FSAR that Waterford 3 will establish a program prior to fuel loading for data collection on information regarding ECC system outages. The information will contain (1) outage dates and duration of outages; (2) cause of the outage; (3) ECC systems or components involved in the outage; and (4) corrective action taken. The staff has reviewed the applicant 1 s commitment and finds that it meets the requirements of Item II.K.3.17 of NUREG-0737 and is acceptable.
II.K.3.25 Effect of Loss of Alternating-Current Power on Pump Seals Position The licensees should determine, on a plant-specific basis, by analysis or experi ment, the consequences of a loss of cooling water to the reactor recirculation pump seal coolers. The pump seals should be designed to withstand a complete loss of alternating-current (ac) power for at least 2 hours. Adequacy of the seal design should be demonstrated.
Clarification The intent of this position is to prevent excessive loss of reactor coolant system (RCS) inventory following an anticipated operational occurrence. Loss of ac power for this case is construed to be loss of offsite power. If seal failure is the consequence of loss of cooling water to the reactor coolant pump (RCP) seal coolers for 2 hours, due to loss of offsite power, one acceptable solution would be to supply emergency power to the component cooling water pump.
This topic is addressed for Babcock and Wilcox (B&W) reactors in Section II.K.2.lF of NUREG-0737.
Discussion and Conclusions In response to the above requirements, the applicant has stated in Amendment 16 to the FSAR that Waterford 3 complies with this position by supplying emergency power to the component cooling water pump. Although the component cooling water lines to the reactor coolant pump seal coolers are isolated on a CIAS, the isolation valves on these lines are provided with manual override capability.
Based on the preceding, the staff concludes that the Waterford 3 design meets the requirements of this item and is therefore acceptable.
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II.K.3.30 Revised Small-Break Loss-of-Coolant Accident Methods to Show Compliance with 10 CFR 50, Appendix K Position The analysis methods used by nuclear steam supply system (NSSS) vendors and/or fuel suppliers for small-break loss-of-coolant accident (LOCA) analysis for compliance with Appendix K to 10 CFR Part 50 should be revised, documented, and submitted for NRC approval. The revision should account for comparisons with experimental data, including data from the LOFT Test and Semiscale Test facilities.
Clarification As a result of the accident at TMI-2, the Bulletins and Orders Task Force was formed within the Office of Nuclear Reactor Regulation. This task force was charged, in part, to review the analytical predictions of feedwater transients and small-break LOCAs for the purpose of assuring the continued safe operation of all operating reactors, including a determination of acceptability of emergency guidelines for operators.
As a result of the task force reviews, a number of concerns were identified regarding the adequacy of certain features of small-break LOCA models, particu larly the need to confirm specific model features (e.g., condensation heat transfer rates) against applicable experimental data. These concerns; as they applied to each light-water reactor (LWR) vendor's models, were documented in the task force reports for each LWR vendor. In addition to the modeling concerns identified, the task force also concluded that, in light of the TMI-2 accident, additional systems verification of the small-break LOCA model as required by II.4 of Appendix K to 10 CFR 50 was needed. This included providing predictions of Semiscale Test S-07-108, LOFT Test (L3-1), and providing experimental verifi cation of the various modes of single-phase and two-phase natural circulation predicted to occur in each vendor's reactor during small-break LOCAs.
Based on the cumulative staff requirements for additional small-break LOCA model verification, including both integral system and separate effects verification, the staff considered model revision as the appropriate method for reflecting any potential upgrading of the analysis methods.
ihe purpose of the verification was to provide the necessary assurance that the small-break LOCA models were acceptable to calculate the behavior and con sequences of small primary system breaks. The staff believes that this assurance can alternatively be provided, as appropriate, by additional justification of the acceptability of present small-break LOCA models with regard to specific staff concerns and recent test data. Such justification could supplement or supersede the need for model revision.
The specific staff concerns regarding small break LOCA models are provided in the analysis sections of the B&O Task Force reports for each LWR vendor, (NUREG-0635 ) -0555 ) -0626, -0611, and -0623). These concerns should be reviewed in total by each holder of an approved emergency core cooling system (ECCS) model and addressed in the evaluation as appropriate.
                                    ??-77
 
The recent tests include the entire Semiscale small-break test series and LOFT Tests (L3-l) and (L3-2). The staff believes that the present small-break LOCA models can be both qualitatively and quantitatively assessed against these tests.
Other separate effects tests (e.g., ORNL core uncovery tests) and futute tests, as appropriate, should also be factored into this assessment.
Based on the preceding information, a detailed outline of the proposed program to address this issue should be submitted. In particular, this submittal should identify (1) which areas of the models, if any, the licensee intends to upgrade, (2) which areas the licensee intends to address by further justification/upgrade effort, (3) test data to be used as part of the overall verification/upgrade effort, and (4) the estimated schedule for performing the necessary work and submitting this information for staff review and approval.
Discussion and Conclusions In response to the above requirements, the applicant has committed, in his {{letter dated|date=May 7, 1981|text=letter dated May 7, 1981}}, to submit the final report to justify the adequacy of the present small-break LOCA model by January 1, 1982. The staff will condition the operating license, if necessary, to require this. The staff concludes that this commitment meets the implementation schedule requirements of NUREG-0737 and, therefore, is acceptable.
II.K.3.31 Plant-Specific Calculations to Show Compliance with 10 CFR 50.46 Position Plant-specific calculations using NRC approved models for small-break loss-of coolant accidents (LOCAs) as described in item II.K.3.30 to show compliance with 10 CFR 50.46 should be submitted for NRC approval by all licenses.
Clarification See "Clarification" for item II.K.3.30.
Discussion and Conclusions In response to the above requirements, the applicant has committed in Amendment 17 to the FSAR to submit, within one year after staff approval of the small-break LOCA models, revised small-break LOCA ECCS analyses. The staff will condition the operating license, if necessary, to require this. The staff concludes that this commitment meets the implementation schedule requirements of NUREG-0737 and is therefore acceptable.
III.A.1.1 Upgrade Emergency Preparedness Position All licensees should comply with Appendix E, "Emergency Facilities,'' to 10 CFR Part 50, RG 1.101, 11 Emergency Planning for Nuclear Power Plants," and, for the offsite plans, meet essential elements of NUREG-75/111 or have a favorable finding from FEMA. This requirement shall be met before fuel loading.
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All licensees should provide an emergency response plan in substantial compliance with NUREG-0654, 11 Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," except that only a description of and completion schedule for the means for providing prompt notification to the population (Appendix 3), the staffing for emergencies in addition to that already required (Table B.1), and an upgraded meteorological program (Appendix 2) need be provided. NRC will give substantial weight to FEMA findings on offsite plans in judging the adequacy against NUREG-0654. An emergency response exercise should take place to test the integrated capability and a major portion of the basic elements existing within emergency preparedness plans and organizations. This requirement shall be met before issuance of a full-power license.
Discussion and Conclusions This Item is discussed in Section 13.3 of this SER.
III.A.1.2 Upgrade Licensee Emergency Support Facilities A. Onsite Technical Support Center (NUREG-0578, Item 2.2.2.b)
Position Each operating nuclear power plant shall maintain an onsite technical support center (TSC) separate from and in close proximity to the control room that has the capability to display and transmit plant status to those individuals who are knowledgeable of and responsible for engineering and management support of reactor operations in the event of an accident. The center shall be habitable to the same degree as the control room for postulated accident conditions.
The licensee shall revise his emergency plans as necessary to incorporate the role and location of the technical support center. Records that pertain to the as-built conditions and layout of structures, systems, and components shall be readily available to personnnel in the TSC.
Clarification (NRC Letter Dated November 9, 1979)
(1) By January 1, 1980, each licensee should meet items a through g that follow.
Each licensee is encouraged to provide additional upgrading of the TSC (items 2 through 10) as soon as practical, but no later than January 1, 1981.
(a) Establish a TSC and provide a complete description.
(b) Provide plans and procedures for engineering/management support and staffing of the TSC.
(c) Install dedicated communications between the TSC and the control room, near-site emergency operations center, and the NRC.
(d) Provide monitoring (either portable or permanent) for both direct radiation and airborne radioactive contaminants. The monitors should provide warning if the radiation levels in the support center are reaching potentially dangerous levels. The licensee should designate action levels to define when protective measures should be taken (such
                                    ??-7Q
 
as using breathing apparatus and potassium iodide tablets or evacuation to the control room).
(e) Assimilate or ensure access to technical data, including the licen see's best effort to have direct display of plant parameters necessary for assessment in the TSC.
(f) Develop procedures for performing this accident assessment function from the control room should the TSC become uninhabitable.
(g) Submit to the NRC a longer range plan for upgrading the TSC to meet all requirements.
(2) Location It is recommended that the TSC be located in close proximity to the control room to ease communications and access to technical information during an emergency. The center should be located onsite, i.e., within the plant security boundary. The greater the distance from the control room, the more sophisticated and complete should be the communications and avail ability of technical information. Consideration should be given to providing key TSC personnel with a means for gaining access to the control room.
(3) Physical Size and Staffing The TSC should be large enough to house 25 persons, necessary engineering data and information displays (TV monitors, recorders, etc.). Each licensee should specify staffing levels and disciplines reporting to the TSC for emergencies of varying severity.
(4) Activation The center should be activated in accordance with the 1 1 Alert 11 level as defined in the NRC document 11 Draft Emergency Action Level Guidelines 11 (NUREG-0610), dated September 1979, which is currently out for public comment.
Instrumentation in the TSC should be capable of providing displays of vital plant parameters from the time the accident began (t = o defined as either reactor or turbine trip). The shift technical advisor should be consulted on the 1 1 Not i fication of Unusua 1 Event. 11 However, the activation of the TSC is discretionary for that class of event.
(5) Instrumentation The instrumentation to be located in the TSC need not meet safety-grade requirements but should be qualitatively comparable (with regard to accuracy and-reliability) to that in the control room. The TSC should have the capability to access and display plant parameters independent from actions in the control room. Careful consideration should be given to the design of the interface of the TSC instrumentation to assure that addition of the TSC will not result in any degradation of the control room or other plant functions.
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(6) Instrumentation Power Supply The power supply to the TSC instrumentation need not meet safety-grade requirements, but should be reliable and of a quality compatible with the TSC instrumentation requirements. To insure continuity of information at the TSC, the power supply provided should be continuous once the TSC is activated. Consideration should be given to avoid loss of stored data (e.g., plant computer) due to momentary loss of power or switching tran sients. If the power supply is provided from a plant safety-related power source, careful attention should be given to assure that the capability and reliability of the safety-related power source is not degraded as a result of this modification.
(7) Technical Data Each licensee should establish the technical data requirements for the TSC, keeping in mind the accident assessment function that has been estab lished for those persons reporting to the TSC during an emergency. As a minimum, data (historical in addition to current status) should be available to permit the assessment of the following:
(a) Plant Safety Systems Parameters for:
(i)  Reactor coolant system (ii)  Secondary system (PWRs)
(iii)  ECC svstems (iv)  Feedwater and makeup systems (v)  Containment (b) In-Plant Radiological Parameters for:
(i) Reactor coolant system (ii) Containment (iii) Effluent treatment (iv) Release paths (c) Offsite radiological (i) Meteorology (ii) Offsite radiation levels (8) Data Transmission In addition to providing a data transmission link between the TSC and the control room, each licensee should review current technology with regard to transmission of those parameters identified for TSC display. Although there is no requirement at the present time, each licensee should investigate the capability to transmit plant data offsite to the emergency operations center, NRC, the reactor vendor, etc.
(9) Structural Integrity (a) The TSC need not be designed to meet seismic Category I requirements.
The center should be well built in accordance with sound engineering 22-81
 
practice with due consideration to the effects of natural phenomena that may occur at the site.
(b) Since the center need not be designed to the same stringent require ments as the control room, each licensee should prepare a backup plan for responding to an emergency from the control room.
(10) Habitability The licensee should provide protection for the technical support center personnel from radiological hazards including direct radiation and air borne contaminants as required in GDC 19 and SRP 6.4.
(a) Licensee should assure that personnel inside the  TSC will not receive doses in excess of those specified in GDC 19 and  SRP 6.4 (i.e., 5 rem whole-body and 30 rem to the thyroid for the  duration of the accident). Major sources of radiation should be  considered.
(b) Permanent monitoring systems should be provided to continuously indicate radiation dose rates and airborne radioactivity concentrations inside the TSC. The monitoring systems should include local alarms to warn personnel of adverse conditions. Procedures must be provided that will specify appropriate protective actions to be taken in the event that high dose rates or airborne radioactive concentrations exist.
(c) Permanent ventilation systems that include particulate and charcoal filters should be provided. The ventilation systems need not be qualified as ESF systems. The design and testing guidance of Regulatory Guide 1.52 should be followed except that the systems do not have to be redundant, seismic, instrumented in the control room, or automatically activated. In addition, the HEPA filters need not be tested as specified in Regulatory Guide 1.52 and the HEPAs do not have to meet the QA _requirements of Appendix B to 10 CFR 50. How ever, spare parts should be readily available and procedures in place for replacing failed components during an accident. The systems should be designed to operate from the emergency power supply.
(d) Dose-reduction measures, such as breathing apparatus and potassium iodide tablets, cannot be used as a design basis for the TSC in lieu of ventilation systems with charcoal filters. However, potassium iodide and breathing apparatus should be available.
Discussion and Conclusions This Item is discussed in Section 13.3 of this SER.
B. Onsite Operational Support Center (NUREG-0578, Item 2.2.2.c)
Position An area to be designated as the onsite operational support center shall be established. It shall be separate from the control room and shall be the place to which the operations support personnel will report in an emergency situation.
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Communications with the control room shall be provided. The emergency plan shall be revised to reflect the existence of the center and to establish the methods and lines of communication and management.
Discussion and Conclusions (C) Near-Site Emergency Operation Facility (NUREG-0694)
Position Designate a near-site emergency operations facility (EOF) with communications with the plant to provide evaluation of radiation releases and coordination of all onsite and offsite activities during an accident.
Provide shielding against direct radiation, ventilation isolation capability, dedicated communications with the onsite technical support center, and direct display of radiological and meteorological parameters.
Discussion and Conclusions This Item is discussed in Section 13.3 of this SER.
III.A.2 Improving Licensee Emergency Preparedness-Long Term Position Each nuclear facility shall upgrade its emergency plans to provide reasonable assurance that adequate protective measures can and will be taken in the event of a radiological emergency. Specific criteria to meet this requirement are delineated in NUREG-0654 (FEMA-REP-1), "Criteria for Preparation and Evalua tion of Radiological Emergency Response Plans and Preparation in Support of Nuclear Power Plants."
Clarification In accordance with Task Action Plan item III.A.1.1, "Upgrade Emergency Preparedness, 11 each nuclear power facility was required to immediately upgrade its emergency plans with criteria provided October 10, 1979, as revised by NUREG-0654 (FEMA-REP-1, issued for interim use and comment, January 1980).
New plans were submitted by January 1, 1980 using the October 10, 1979 criteria.
Reviews were started on the upgraded p1ans using NUREG-0654. Concomitant to these actions, amendments were developed to 10 CFR Part 50 and Appendix E to 10 CFR Part 50 to provide the long-term implementation requirements. These new rules were published in the Federal Re ister on August 19, 1980, with an effective date of November 3, 1980. The revise rules delineate requirements for emergency preparedness at nuclear reactor facilities.
NUREG-0654 (FEMA-REP-1), 11 Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, 11 provides detailed items to be included in the upgraded emergency plans and, along with the revised rules, provides for meteorological criteria, means for providing for a prompt notification to the population, and the need for emergency response facilities (see Item III.A.1.2).
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Implementation of the new rules levied the requirement for the licensee to provide procedures implementing the upgraded emergency plans to the NRC for review. Publication of Revision 1 to NUREG-0654 (FEMA-REP-1), which incorporates the many public comments received, is expected in October 1980. This is the document that will be used by NRC and FEMA in their evaluation of emergency plans submitted in accordance with the new NRC rules.
NUREG-0654, Revision 1; NUREG-0696, "Functional Criteria for Emergency Response Facilities; 11 and the amendments to 10 CFR Part 50 and Appendix E to 10 CFR Part 50 regarding emergency preparedness provide more detailed criteria for emergency plans, design, and functional criteria for emergency response facilities, and establish firm dates for submission of upgraded emergency plans and for instal lation of prompt notification systems. These revised criteria and rules supersede previous Commission guidance for the upgrading of emergency preparedness at nuclear power facilities.
Revision 1 to NUREG-0654 provides meteorological criteria to fulfill, in part, the standard, that 11 Adequate methods, systems, and equipment for assessing and monitoring actual or potential offsite consequences of a radiological emergency condition are in use 11 (see 10 CFR &sect;50.47). The position in Appendix 2 to NUREG-0654 outlines four essential elements that can be categorized into three functions: measurements, assessment, and communications.
Proposed Revision 1 to RG 1.23, "Meteorological Measurements Programs in Support of Nuclear Power Plants,1' has been adopted to provide guidance criteria for the primary meteorological measurements program consisting of a primary system and secondary system(s), where necessary, and a backup system. Data collected from these systems are intended for use in the assessment of the offsite consequences of a radiological emergency condition.
Appendix 2 to NUREG-0654 delineates two classes of assessment capabilities to provide input for the evaluation of offsite consequences of a radiological emergency condition. Both classes of capabilities provide input to decisions regarding emergency actions. The Class A capability should provide informa-tion to determine the necessity for notification, sheltering, evacuation, and, during the initial phase of a radiological emergency, making confirmatory radio logical measurements. The Class B capability should provide information regarding the placement of supplemental meteorological monitoring equipment, and the need to make additional confirmatory radiological measurements. The Class 8 capability shall identify the areas of contaminated property and foodstuff requiring protective measures and may also provide information to determine the necessity for sheltering and evacuation.
Proposed Revision 1 to RG 1.23 outlines the set of meteorological measurements that should be accessible from a system that can be interrogated; the meteoro logical data should be presented in th prescribed format. The results of the assessments should be accessible from this system: This information should incorporate human-factors engineering in its display to convey the essential information to the initial decisionmakers and subsequent management team. An integrated system should allow the eventual incorporation of effluent monitoring and radiological monitoring information with the environmental transport to provide direct-dose consequence assessments.
22-84
 
Requirements of the new emergency-preparedness rules under paragraphs 50.47 and 50.54 and the revised Appendix E to 10 CFR 50 taken together with NUREG-0654 Revision 1 and NUREG-0696, when approved for issuance, go beyond the previous requirements for meteorological programs. To provide a realistic time frame for implementation, a staged schedule has been established with compensating actions provided for interim measures.
Discussion and Conclusions This Item is discussed in Section 13.3 of this SER.
1 III.D.1.1 Integrit of s stems Outside Containment Likely to Contain Radioactive Ma erial for Pressurized-Water Reactors and Boiling-Water Reactors Posit ion Applicants shall implement a program to reduce leakage from systems outside containment that would or could contain highly radioactive fluids during a serious transient or accident to as-low-as-practical levels. This program shall include the following:
(1) Immediate leak reduction (a) Implement all practical leak reduction measures for all systems that could carry radioactive fluid outside of containment.
(b) Measure actual leakage rates with system in operation and report them to the NRC.
(2) Continuing leak reduction--Establish and implement a program of preventive maintenance to reduce leakage to as-low-as-practical levels. This program shall include periodic integrated leak tests at intervals not to exceed each refueling cycle.
Clarification Applicants shall provide a summary description, together with initial leak-test results, of their program to reduce leakage from systems outside containment that would or could contain primary coolant or other highly radioactive fluids or gases during or following a serious transient or accident.
(1) Systems that should be leak tested follow (any other plant system that has similar functions of post-accident characteristics, even though not specified herein, should be included):
      '  Residual heat removal (RHR)
      **  Containment spray recirculation High-pressure injection recirculation 22-85
 
Containment and primary coolant sampling Reactor core isolation cooling Makeup and letdown (PWRs only)
Waste gas (includes headers and cover gas system outside of contain ment in addition to decay or storage system).
Include a list of systems containing radioactive materials which are excluded from program and provide justification for exclusion.
(2) Testing of gaseous systems should include helium leak detection or equivalent testing methods.
(3) Should consider program to reduce leakage potential release paths due to design and operator deficiencies as discussed in NRC letter to all opera ting nuclear power plants regarding North Anna and related incidents, dated October 17, 1979.
Discussion and Conclusions The applicant has committed to developing procedures and a scheduled maintenance program to monitor leakage and to reduce detected leakage to as low as practical levels for systems outside the containment which could contain radioactivity.
For liquid systems leakage detection will be performed by visual inspection of all potential leak sources (e.g., valves, pump seals, etc.). Upon detection of a leak, the leak rate will be determined. Those liquid systems which will be tested are those containing radioactive liquids, the High Pressure Safety Injection System, the Low Pressure Safety Injection System, including Shutdown Cooling System, the Containment Spray System, and Chemical Volume and Control System.
The gaseous radwaste system will be leak tested by pressurizing the system with an inert gas or nitrogen and visually inspecting potential leak sources with a soapy water solution.
The applicant has committed to recording all sources of leaks and their asso ciated leak rates. Those leakage sources which cannot be reduced to as low as practical will be reported to the Plant Manager or his designee for resolution.
The above program is considered acceptable, and will satisfy this TM! require ment when the initial leak rate test results are provided.
III.0.3.3 Improved In-Plant Iodine Instrumentation Under Accident Conditions Position (1) Each licensee shall provide equipment and associated training and procedures for accurately determining the airborne iodine concentration in areas within the facility where plant personnel may be present during an accident.
22-86
 
(2) Each applicant for a fuel-loading license to be issued prior to January 1, 1981 shall provide the equipment, training, and procedures necessary to accurately determine the presence of airborne radioiodine in areas within the plant where plant personnel may be present during an accident.
Clarification Effective monitoring of increasing iodine levels in the buildings under acci dent conditions must include the use of portable instruments using sample media that will collect iodine selectively over xenon (e.g., silver zeolite) for the following reasons:
(1) The physical size of the auxiliary/fuel handling building precludes locating stationary monitoring instrumentation at all areas where airborne iodine concentration data might be required.
(2)  Unanticipated isolated 11 hot spots11 may occur in locations where no stationary monitoring instrumentation is located.
(3) Unexpectedly high background radiation levels near stationary monitoring instrumentation after an accident may interfere with filter radiation readings.
(4) The time required to retrieve samples after an accident may result in high personnel exposures if these filters are located in high dose rate areas.
After January 1, 1981, each applicant and licensee shall have the capability to remove the sampling cartridge to a low-background, low-contamination area for further analysis. Normally, counting rooms in auxiliary buildings will not have sufficiently low backgrounds for such analyses following an accident.
In the low background area, the sample should first be purged of any entrapped noble gases using nitrogen gas or clean air free of noble gases. The licensee shall have the capability to measure accurately the iodine concentrations present in these samples under accident conditions. There should be sufficient samplers to sample all vital areas.
For applicants with fuel-loading dates prior to January 1, 1981, provide by fuel loading (until January 1, 1981) the capability to accurately detect the presence of iodine in the region of interest fo1lowing an accident. This can be accomplished by using a portable or cart-mounted iodine sampler with attached single-channel analyzer (SCA). The SCA window should be calibrated to the 365 KeV of iodine-131 using the SCA. This will give an initial conservative estimate of presence of iodine and can be used to determine if respiratory protection is required. Care must be taken to assure that the counting system is not saturated as a result of too much activity collected on the sampling cartridge.
Discussion and Conclusions In Amendments 15 and 16 to the FSAR, the applicant has addressed the surveil lance program for inplant airborne iodine monitoring, and has identified the specific methods used to determine potentially high airborne iodine concentra tions and the manner in which resolution of iodine from high concentrations of noble gases can be achieved during accident conditions. Waterford 3 will have the capability to use nitrogen purginQ of the silver zeolite sampling cartridge to remove residual noble gases. Provisions shall be made to insure against 22-87
 
the spreading of contamination into clean areas during purging, by use of a hood. Use of the (Geli) spectroscopy system with a multichannel analyzer, which can accurately analyze the iodine content in a silver zeolite sample filter, is described. A computer is used with a software program for spectrum smoothing, peak search, nuclide identification and data storage. To minimize the effects of background in the counting room, the (Geli) detector is mounted in a six inch lead shield. Utilizing the information obtained from the analysis of the samples health physics personnel can accurately determine whether the use of respirators is required. Therefore, the provision for performing iodine analysis under accident conditions described by the applicant meets our position of item III.D.3.3 of NUREG-0737 and is acceptable.
III.0.3.4 Control Room Habitability Requirements Requirement Identify and evaluate potential hazards in the vicinity of the site as described in SRP Sections 2.2.1, 2.2.2, and 2.2.3. Confirm that operators in the control room are adequately protected from these hazards and the release of radioactive gases as described in SRP Section 6.4, and, if necessary, provide the schedule for modifications to achieve compliance with SRP Section 6.4.
This requirement shall be met by issuance of a full-power license (see NUREG-0694).
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II licensees shall assure that control room operators will be adequately protected against the effects of accidental release of toxic and radioactive gases and that the nuclear power plant can be safely operated or shut down under design basis accident conditions (GDC 19, "Control Room;' of Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR 50).
Clarification (1) All licensees must make a submittal to the NRC regardless of whether or not they meet the criteria of the referenced Standard Review Plan (SRP) sections. The new clarification specifies that licensees meeting the criteria of the SRPs should provide the basis for their conclusions that SRP Section 6.4 requirements are met. Licensees may establish this basis by referencing past submittals to the NRC and/or providing new or additional information to supplement past submittals.
(2) All licensees with control rooms that meet the criteria of the following sections of the Standard Review Plan 2.2.1-2.2.2                      Identification of Potential Hazards in Site Vicinity 2.2.3                            Evaluation of Potential Accidents 6.4                              Habitability Systems, shall report their findings regarding the specific SRP sections as explained below. The following documents should be used for guidance:
22-88
 
(a) Regulatory Guide 1.78, 11 Assumptions for Evaluating the Habitability of Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release; 11 (b)  Regulatory Guide 1.95, "Protection of Nuclear Power Plant  Control Room Operators Against an Accident Chlorine Release; 11 and (c) K. G. Murphy and K. M. Campe, 11 Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion 19,1' 13th AEC Air Cleaning Conference, August 1974.
Licensees shall submit the results of their findings as well as the basis for those findings by January 1, 1981. In providing the basis for the habitability finding, licensees may reference their past submittals. Licensees should, however, ensure that these submitta1s reflect the current facility design and that the information requested in Attachment 1 is provided.
(3)  All licensees with control rooms that do not meet the criteria of the above listed references, Standard Review Plans, Regulatory Guides, and other references shall perform the necessary evaluations and identify appropriate modifications.
Each licensee submittal shall include the results of the analyses of control room concentrations from postulated accidental release of toxic gases and control room operator radiation exposures from airborne radioactive material and direct radiation resulting from design-basis accidents. The toxic gas accident analysis should be performed for all potential hazardous chemical releases occurring either on the site or within 5 miles of the plant-site boundary. Regulatory Guide 1.78 lists the chemicals most commonly encountered in the evaluation of control room habitability, but it is not all inclusive.
The design-basis-accident (OBA) radiation source term should be for the loss-of coo1ant accident (LOCA) containment leakage and engineered safety feature (ESF) leakage contribution outside containment as described in Appendix A and B of SRP Section 15.6.5. In addition, boiling water reactor (BWR) facility evaluations should add any leakage from the main steam isolation valves (MSIV) (i.e., valve stem leakage, valve seat leakage, main steam isolation valve leakage control system release) to the containment leakage and ESF leakage following a LOCA.
This should not be construed as altering the staff recommendations in Section D of RG 1.96 (Rev. 2) regarding MSIV leakage-control systems. Other DBAs should be reviewed to determine whether they might constitute a more-severe control-room hazard than the LOCA.
In addition to the accjdent-analysis results, which should either identify the possible need for control-room modifications or provide assurance that the habi tability systems will operate under all postulated conditions to permit the control-room operators to remain in the control room to take appropriate actions required by GDC 19, the licensee should submit sufficient information needed for an independent evaluation of the adequacy of the habitability systems. lists the information that should be provided along with the licensee's evaluation.
22-89
 
Discussion and Conclusions The staff has advised the applicant of the ful1-power requirements for control room habitability as set forth in NUREG-0660 (May 1980), 11 NRC Action Plan Developed as a Result of TMI-2 Accident," in NUREG-0694 (June 1980), 11 TMI-Related Requirements for New Operating Licneses 0 and, finally, NUREG-0737 "Clarification of TMI Action Plan Requirements" issued in November 1980.
In Amendment 14 to the FSAR, the applicant states conformance with the requirements of SRP Sections 2.2.1, 2.2.2, 2.2.3, and 6.4 in accordance with the requirements of Task Action Plan item III.D.3.4. Conformance with RG 1.78 and chlorine hazards is discussed in FSAR Section 6.4.4.2.
Should further staff review confirm the applicant 1 s findings, as recorded in the FSAR with respect to toxic gas hazards, the staff will conc1ude in SER Section 6.4 that the control room of Waterford 3 meets the habitability requirements of GDC 19 of 10 CFR 50 Appendix A and the guidelines of Regulatory Guides 1.78 and 1.95.
Subject to the SAB concurrence mentioned above, the staff concludes that the applicant has satisfied the requirements of NUREG-0737 for a full-power license with respect to control room habitability systems.
III.D.3.4 ATTACHMENT 1, Information Required for Control Room Habitability Evaluation (1) Controi-room mode of operation (i.e., pressurization and filter recirculation for radiological accident isolation or chlorine release).
(2) Control-room characteristics:
(a) Air volume control room.
(b) Control-room emergency zone (control room, critical files, kitchen, washroom, computer room, etc.).
(c) Control-room ventilation system schematic with normal and emergency air-flow rates.
(d) Infiltration leakage rate.
(e) High-efficiency particulate air (HEPA) filter and charcoal adsorber efficiencies.
(f) Closest distance between containment and air intake.
(g) 'Layout of control room, air intakes, containment building, and chlorine, or other chemical storage facility with dimensions.
(h) Control-room shielding including radiation streaming from penetra tions, doors, ducts, stairways, etc.
(i) Automatic isolation capability-damper closing time, damper leakage and area.
22-90
 
(j)  Chlorine detectors or toxic gas (local or remote).
(k) Self-contained breathing apparatus availability (number).
(1) Bottled air supply (hours of supply).
(m) Emergency food and potable water supply (how many days and how many people).
(n) Control-room personnel capacity (normal and emergency).
(o) Potassium iodide drug supply.
(3) Onsite storage of chlorine and other hazardous chemicals:
(a) Total amount and size of container.
(b) Closest distance from control-room air intake.
22-91
 
23 CONCLUSIONS Based on the staff evaluation of the application as set forth above, it is the staff's position that, subject to favorable resolution of the outstanding matters described herein, the staff will be able to conclude that:
(1) The application for facility licenses filed by the applicant dated September 23, 1978, as amended, complies with the requirements of the Atomic Energy Act of 1954, as amended (Act), and the Commissioner's regulations set forth in 10 CFR Chapter 1; and (2) Construction of Waterford Steam Electric Station, Unit No. 3, proceeded and there is reasonable assurance that it will be substantially completed, in cornformity with Construction Permit No. CPPR-103, the application as amended, the provisions of the Act, and the rules and regulations of the Commission; and (3) The facility will operate in conformity with the application as amended, the provisions of the Act, and the rules and regulations of the Commission; and (4) There is reasonable assurance (a) that the activities authorized by the operating licenses can be conducted without endangering the health and safety of the public, and (b) that such activities will be conducted in compliance with the regulations of the Commission set forth in 10 CFR Chapter 1; and (5) The applicant is technically and financially qualified to engage in the activities authorized by this license, in accordance with the regulations of the Commission set forth in 10 CFR Chapter 1; and (6) The issuance of this license will not be inimical to the common defense and security or to the health and safety of the public.
Before an operating license will be issued to the applicant for operation of Waterford Steam Electric Station Unit No. 3, the unit must be completed in conformity with the provisional construction permits, the application, the Act, and the rules and regulations of the Commission. Such completeness of construction as is required for safe operation at the authorized power levels must be verified by the Commission's Office of Inspection and Enforcement prior to issuance of the license.
Further, before an operating license is issued, the applicant will be required to satisfy the applicable provisions of 10 CFR Part 140.
23-1
 
APPENDIX A CHRONOLOGY OF RADIOLOGICAL REVIEW September 28, 1978  Letter from applicant submitting operating license application with FSAR for acceptance review.
September 29, 1978  Letter to applicant advising of receipt of application and advising that acceptance review has begun.
{{letter dated|date=October 3, 1978|text=October 3, 1978      letter}} from applicant forwarding memorandum of under standing between applicant and State government that provides for implementation of protective actions on behalf of the general public in the event of a radio logical emergency at the site.
October 25, 1978    Applicant meeting with NRC to discuss Security Plan, 10 CFR 50.55a, Preoperationa1 Testing, Environmental Review, and FSAR Questions from the NRC staff.
October 31, 1978    Letter to applicant requesting further information for antitrust review. Questions pertain to applicant interconnection agreements with neighboring towns.
November 10, 1978    Letter from applicant forwarding 11 WSES 3, Fracture Toughness Test and Evaluations, Supplement 1 (November 1978) >> providing discussion and comparisons of 10 CFR 55a requirements.
November 21, 1978    Letter to applicant forwarding amendment to 10 CFR 21 which may eliminate applicant 1 s need for exemption.
Processing of OL application suspended to allow applicant to reassess current needs.
November 21, 1978    Letter to app1icant giving notice that application is acceptable for docketing, and forwarding first set of requests for additional information.
November 29, 1978    Letter from applicant informing NRC of schedule for responding to requests for additional information.
December 5, 1978    Letter from applicant responding to requests for additional information to support antitrust review.
Letter also addresses request for service from appli cant by the City of Placquemine.
A-1
 
APPENDIX A (Continued)
December 11, 1978 Letter from applicant forwarding schedule for responding to NRC requests for additional information. States that Chapter 14 requests will be discussed at future meeting with NRC.
December 13, 1978 NRC forwards to applicant the revised Entry Control System Handbook (SAND 77-1033), Intrusion Detection System Handbook (SAND 76-0554), and Barrier Penetration Database (NUREG/CR-0181).
December 18, 1978 Operating license application docketed.
December 19, 1978 Letter to applicant forwarding Federal Re ister notices regarding December 18, 1978 docke{ ing of license application.
December 21, 1978 Letter to applicant requesting copy of operating agreements in regard to obtaining antitrust information.
December 22, 1978 Applicant forwards affidavit informing NRC that required distribution of OL application documents has been made.
January 10, 1979  Letter from applicant forwarding FSAR Amendment 1 in partial response to NRC {{letter dated|date=November 21, 1978|text=letter dated November 21, 1978}} and also provides other updated information for several chapters of the FSAR.
January 12, 1979  Letter from applicant forwarding operating agreement for Homer, LA.
February 16, 1979 Applicant forwards physical security plan to NRC.
February 21, 1979 Applicant forwards FSAR Amendment 2 which responds to NRC {{letter dated|date=November 21, 1978|text=letter dated November 21, 1978}} and also provides other updated information for several chapters of the FSAR.
March 2, 1979    Letter to applicant forwarding NUREG-0523, Summary 11 of Operating Experience with Recirculating Steam Generators," which focuses on recent problems with degradation.
March 6, 1979    Applicant meeting with NRC to discuss tentative FSAR review schedule.
March 7, 1979    NRC inspection of meteorological tower at the site.
A-2
 
APPENDIX A (Continued)
March 15, 1979 Letter to applicant requesting additional information regarding the capability of the nuclear steam supply system to respond to ATWS transients.
March 23, 1979 Letter to applicant forwarding NUREG-0531, 11 Investi gation and Evaluation of Stress Corrosion Cracking in Piping of LWR Plants. 11 April 19, 1979 Letter to applicant forwarding summary of major milestones of Ol application safety review.
April 26, 1979 Letter to applicant requesting additional information for FSAR review.
April 30, 1979 Applicant forwards "Annual Financial Report 1978 11 to NRC.
May 10, 1979  Applicant forwards FSAR Amendment 3.
May 22, 1979  NRC meeting with applicant at the site to review site geology.
May 23, 1979  NRC meeting with applicant at the site to review site hydrology.
June 7, 1979  Applicant forwards FSAR Amendment 4 to NRC in additional response to NRC {{letter dated|date=November 21, 1978|text=letter dated November 21, 1978}} and also provides other updated information for several chapters of the FSAR.
June 7, 1979  Letter from applicant discussing testing of mechanical draft cooling towers in component cooling water system.
June 9, 1979  Site tour by NRR Director (Denton).
June 13, 1979  Applicant meeting with NRC to discuss current applica tion review policies and criteria for establishing review priorities.
July 17, 1979  Letter from applicant summarizing evaluation of effect of TMI incident. Letter included review of correspondence, evaluation of sequence of events, and design comparisons.
July 18, 1979  Letter to applicant discussing status of program to upgrade bases section of STS and fee exemption approval.
A-3
 
APPENDIX A (Continued)
July 19, 1979      Letter from applicant forwarding Amendment 5 to the FSAR.
July 19, 1979      Letter from applicant forwarding responses to questions and comments regarding physical security plan.
July 19, 1979      Letter to applicant forwarding NUREG-0576, 11 Nuclear Power Reactor Security Personnel Training and Qualifi cation Plan Reviewer Workbook. 11 July 19, 1979      Letter to applicant forwarding order extending con struction completion date to October 1982.
July 23, 1979      Letter from Ebasco forwarding documentation for FSAR Amendment 5 including revised electrical drawings and a geological mapping report.
July 28, 1979      Letter from applicant with comments on proposed rules in 10 CFR Parts 02, 21, 31, 34, 35, 40, and 70. Requests partial exemption from requirements of 10 CFR 21 based on financial hardship.
August 2, 1979    Letter to applicant requesting additional information regarding power systems and conduct of operations.
August 7, 1979    Letter from applicant responding to NRC request for reexamination of petition for partial exemption to 10 CFR 21. Partial exemption is no longer required for terminal blocks in nine safety-related panels.
August 21, 1979    Letter from applicant forwarding FSAR Amendment 6 and schedule for submittal of Amendment 7.
August 24, 1979    Letter from applicant forwarding drawings: 11 Site Grading and Drainage, 11 "Reactor Containment Building Penetrations,i 1 and "Reactor Building Fuel Transfer Tube Shielding. 11 September 13, 1979 Letter to applicant containing short-term measures to be taken with emergency and operating procedures.
Measures were results of review of TMI-2 accident.
September 19, 1979 Letter from applicant forwarding FSAR Amendment 7.
September 24, 1979 Letter from Ebasco forwarding updated I&C drawings per FSAR Table 1.7-1.
A-4
 
APPENDIX A (Continued)
September 25, 1979 NRC Caseload Forecast Panel meeting with applicant at the site.
October 10, 1979  Letter to applicant discussing schedule for upgrading emergency plans.
October 12, 1979  Letter from Ebasco discussing uLoss Prevention and Safety Promotion in Process Industries. 11 Discussion supports FSAR review in determining area of fluid flowing under force of gravity.
October 17, 1979  Letter to applicant discussing NRC plans to use generic analysis for early verification program to resolve ATWS issue.
October 31, 1979  NRC meeting with applicant to discuss possible ways to expedite licensing review. TMI-2 also discussed.
November 9, 1979  Letter from applicant forwarding list of unresolved items from meeting with NRC on October 31, 1979.
November 9, 1979  Letter to applicant forwarding "Discussions of TMI Lessons Learned Short-Term Requirements, 11 providing additional clarification of NRC requirements.
November 17, 1979  Letter from Ebasco containing information on hydrologic engineering aspects of the Waterford site.
November 21, 1979  Letter to applicant concerning upgrading of emergency plans. Contains requirements for certain emergency arrangements with State and local organizations.
November 30, 1979  Applicant forwards report discussing verification of ATWS-related parameters.
December 17, 1979  Letter from applicant informing NRC that ATWS early verfication report dated November 30, 1979 was the response to NRC {{letter dated|date=October 17, 1979|text=letter dated October 17, 1979}}.
December 21, 1979  Letter to applicant forwarding Revision 1 to Branch Technical Position on radiological environmental monitoring.
December 21, 1979  Letter to applicant announcing regional workshop to discuss regulation on radiological emergency response plans.
A-5
 
APPENDIX A (Continued)
December 26, 1979 Letter to applicant requesting evacuation time estimates for areas near the plant.
December 27, 1979 Letter from applicant requesting immediate attention be given to action items submitted on November 9, 1979. Also requests specific data for OL review schedule.
January 7, 1980  Letter to applicant stating that Oak Ridge National Laboratory wi11 perform independent confirmatory piping analysis to verify compliance with ASME Code stress criteria.
January 29, 1980  Letter from applicant forwarding safeguards contin gency and security training and qualification plans.
February 5, 1980  Letter to applicant with review of response to Question 211.2 of NUREG-0588, and requesting additional hydrology and quality assurance information.
February 5, 1980  Meeting with applicant, Ebasco t Savannah River Labora tory, and Combustion Engineering at the site to review update of I&C and electrical design.
February 7, 1980  Letter to applicant requesting additional information on conformance of Quality Group C components to requirements in ASME Code, Section III, Class 3.
February 7, 1980  Letter from applicant forwarding FSAR Amendment 8.
February 11, 1980 Letter from Ebasco forwarding drawings for FSAR Amendment 8. Submitted as update of Table 1.7.
February 14, 1980 Meeting with applicant, Ebasco, and Oak Ridge National Laboratory at the site to discuss main steam line stress analysis.
February 21, 1980 Letter to applicant containing additional guidance on NUREG-0588 and request for review of equipment qualifi cation records to determine extent of compliance.
March 10, 1980    Letter to app1icant with guidance concerning additional information on the auxiliary feedwater system and review of the TMI-2 acccident.
March 11, 1980    Letter to applicant advising that submittal date for evacuation time estimates has been postponed pending GAO clearance under the Federal Reports Act.
A-6
 
APPENDIX A (Continued)
April 1, 1980  Letter from applicant confirming arrangements for meeting on April 11, 1980 to discuss licensing schedules.
April 11, 1980 Meeting with NRR Director (Denton) and applicant senior management to review application review progress.
Established new SER issuance date of May 1981.
April 21, 1980 Letter to applicant discussing ability of piping supports attached to masonry walls to carry loads.
Requests information regarding acceptance criteria for analysis, design, and quality control of Category I masonry walls.
April 22, 1980 Letter from applicant forwarding Annual Financial Report for 1979.
April 25, 1980 Letter to applicant with clarification of NRC require ments for emergency response facilities.
May 1, 1980    Applicant announces new fuel load date of October 1982.
May 2, 1980    Letter from applicant forwarding copy of press release that addresses revised construction schedule and projects commercial operation in late 1982.
May 20, 1980  Letter to applicant advising of NRC discussion regarding Section 4 of NUREG-0577. (Potential for Low Fracture Toughness and lamellar Tearing on PWR Steam Generator and Reactor Coolant Pump Supports.)
May 30, 1980  Letter to applicant forwarding Round One requests for additional information regarding reactor systems.
June 2, 1980  Letter from applicant containing information to clarify conformance with inspection requirements of ASME Code, Section III, in response to NRC {{letter dated|date=February 7, 1980|text=letter dated February 7, 1980}}.
June 9, 1980  Letter to applicant requesting additional information for NRC review of January 29, 1980 safeguards contin gency plan.
June 10, 1980  Letter from applicant forwarding FSAR Amendment 9, which describes small-break LOCA analysis, responses to Hydrology Branch and Quality Assurance Branch questions, changes Section 2.2.3.1.3.2 and updates Table 1. 7-1.
A-7
 
APPENDIX A (Continued)
June 10, 1980 Letter to applicant with request for additional information on power instrumentation and control system for FSAR.
June 13, 1980 Letter to applicant forwarding Office of Nuclear Reactor Regulation reorganization chart.
June 25, 1980 Letter from applicant with evacuation time estimates for State and local officia1s involved in emergency planning for the area around the facility, per NRC request dated December 26, 1979.
June 25, 1980 Forwards Commission memorandum and order containing decisions on reconsideration of earlier memorandum and order regarding fire protection for electrical cables.
June 26, 1980 Letter to applicant forwarding statement of policy on requirements to be met for current OL applications in compliance with NUREG-0660 and NUREG-0694.
{{letter dated|date=June 27, 1980|text=June 27, 1980 letter}} from applicant forwarding FSAR Amendment 10 containing the upgraded Emergency Response Plan required by NRC {{letter dated|date=November 21, 1979|text=letter dated November 21, 1979}}.
Letter states Radiological Response Plan is under review and will be forwarded at a later date.
June 30, 1980 Letter to applicant with notice of regional meeting to address Commission memorandum and order rearding environmental qualification of electrical equipment installed in safety systems.
July 2, 1980  Letter to all CP and OL applicants requesting infor mation on vicinity evacuation estimates.
July 3, 1980  Letter from applicant responding to NRC request for additional information. Requests information to be included in FSAR amendment. Responds to NRC requests dated May 30, June 9, and June 10, 1980.
July 11, 1980 Letter to all applicants for Ols and holders of CPs requesting updated construction completion schedules and fuel load target dates to provide basis estab lishing NRC licensing priorties.
July 15, 1980 Letter from applicant in response to NRC request dated June 9, 1980. Forwards revision to safeguards contingency plan.
A-8
 
APPENDIX A (Continued)
July 21, 1980      Letter from applicant forwarding response to NRC request dated July 2, 1980.
July 30, 1980      Letter from applicant forwarding FSAR Amendment 11, which responds to NRC requests for additional infor mation from Power Systems Branch, Reactor Systems Branch, and I&C Branch.
Ju1y 31, 1980      Letter to all OL and CP licensees and applicants forwarding interim criteria for shift staffing.
Discusses administrative provisions for emergency and overtime work.
August 1, 1980    Letter to applicant forwarding draft of NUREG-0696, 11 Functional Criteria for Emergency Response Facilities, 11 and proposed implementation schedule.
August 6, 1980    Letter from applicant requesting extension of June 1, 1982 construction completion data to October 1983.
Summarizes impact of safety review schedule, con struction progress, and financial considerations.
August 11, 1980    Meeting with applicant to clarify criteria for shift staffing. Applicant expects to submit plans by mid-September 1980.
August 13, 1980    Meeting with applicant to discuss status of OL review and identify potential problem areas.
August 15, 1980    Letter to applicant forwarding requests for additional information required by Auxiliary Systems Branch.
August 22, 1980    Letter from applicant responding to NRC request dated April 21, 1980 for information on the use of Category I masonry walls to support seismic Category I piping and equipment.
September 4, 1980  Letter to applicant forwarding status of Mechanicai Engineering Branch and Oak Ridge National Laboratory reviews, and includes request for additional information.
September 5, 1980  Letter to all holders of CPs and Ols and applicants for Ols regarding preliminary clarification of TMI action plan requirements. Provides summary listing of all approved TMI-2 related requirements.
September 14, 1980 NRC meeting with applicant at the site to discuss FSAR Chapter 14.
A-9
 
APPENDIX A (Continued)
September 16, 1980 Letter from applicant forwarding organizational changes, new organization chart, and related press release.
September 19, 1980 Letter to all holders of CPs and Ols and applicants for OLs with errata sheets amending {{letter dated|date=September 5, 1980|text=September 5, 1980 letter}}. Corrected table of implementation schedule enclosed.
September 19, 1980 Letter from applicant forwarding revised construction milestones and activities list and informing NRC that construction is 83% complete.
September 26, 1980 Letter from applicant forwarding FSAR Amendment 12 which includes additional responses to questions from Power Systems Branch, Reactor Systems Branch, I&C Branch, and Auxiliary Systems Branch. Also includes miscellaneous internally generated changes.
September 30 -    Meeting with applicant, Oak Ridge National laboratory, October 3, 1980    Combustion Engineering, and Ebasco in New York to discuss NRC Mechanical Engineering Branch SER review.
October l, 1980    Letter to all holders of OLs and CPs and applicants far CPs requesting information concerning environmental qualification tests of safety-related equipment scheduled during the next two years.
October 6, 1980    Letter to all power reactor licensees and applicants forwarding summary of meeting on Unresolved Safety Issue A-12, "Potential for Low Fracture Toughness and Lamellar Tearing on Component Supports."
October 8, 1980    Letter from applicant advising that methodology used in MSS-NAl-P, 11 Qualification of Reactor Physics Methods for Application to PWRs in Middle South Utilities Systems," will be used to support facility supplemental safety evaluation.
October 24, 1980  Letter from applicant forwarding action items from meeting September 30, 1980 to October 3, 1980.
Information addresses piping preoperational vibration test program and asymmetric loads presention.
October 31, 1980  Letter to holders of Ols and CPs and OL applicants forwarding NUREG-0737 and requests confirmation that implementation dates will be met.
A-10
 
APPENDIX A (Continued)
November 3, 1980  Letter from applicant advising of intent to use safety evaluation status report in lieu of formal question and response approach for review of Sections 3.6.2 through 3.9.6 of the FSAR. Open items to be addressed by amendment to FSAR.
November 13, 1980 Letter to all holders of Ols and CPs and OL applicants advising of requirement to submit revised radiological emergency response p1ans.
November 14, 1980 Letter to applicant containing clarification of minimum TMI-related requirements for new operator licenses. Discusses low power testing and natural circulation training requirements.
November 14, 1980 Letter from applicant forwarding "Response to FSAR Question 11.1, Asymmetric Loads. 11 November 17, 1980 Letter to applicant requesting additional information on inservice inspection of pressure isolation valves.
November 18, 1980 Applicant forwards Amendment 13 to FSAR, including responses to additional information requested by Auxiliary Systems Branch, I&C Branch, Reactor Systems Branch, and information on emergency feedwater system.
Also responds to numerous open items developed during previous meetings.
November 19, 1980 Letter to applicant requesting additional information to complete OL review by Auxiliary Systems Branch.
November 26, 1980 Letter to all power reactor licensees and applicants forwarding summary of meeting on implementation of guidance for Unresolved Safety Issue A-12, "Potential for low Fracture Toughness and Lamellar Tearing of Component Supports."
November 26, 1980 Letter to a11 holders of Ols and CPs and OL applicants providing generic clarification of NRC orders on environmental qualification of safety-related electrical equipment.
December 5, 1980  Letter to applicant providing schedule for OL applica tion review, as requested by applicant.
December 5, 1980  Letter from applicant confirming commitment to October 1982 fuel load date.
A-11
 
APPENDIX A (Continued)
December 9, 1980  Letter to all holders of Ols and CPs and OL applicants forwarding Revision 1 of NUREG-0654/FEMA-REP-1 and summary of evacuation time estimate ratings.
December 15, 1980 Letter from applicant forwarding FSAR Amendment 14 which includes responses to questions from Accident Analysis Branch and Mechanical Engineering Branch open items. Also includes partial response to NUREG-0737 requirements.
December 15, 1980 Applicant forwards information requested by NRC on November 17, 1980. Information requested also included in FSAR Amendment 13 submitted November 21, 1980 (revised Section 5.2.5.7, Table 5.2-11, and response to Question 211.67).
December 19, 1980 Letter from Ebasco forwarding control room panel and general arrangement drawings.
December 22, 1980 Letter to holders of Ols and CPs and OL applicants discussing control of heavy loads. Requests review per NUREG-0612, forwards NRC position on interim actions, and requests additional information.
December 23, 1980 Core Performance Branch meeting with applicant and Combustion Engineering to discuss demonstration fuel assemblies.
December 26, 1980 Letter from applicant responding to NRC request dated October 1, 1980 concerning environmental qualification of safety-related equipment.
January 7, 1981  Applicant meetings with NRC to discuss training and physical security plan.
January 8,_ 1981  Ultimate heat sink presentation to NRC Auxiliary Systems Branch.
January 9, 1981  Letter from applicant stating Special Nuclear Material license application will be submitted by June 1981.
January 9, 1981  Applicant meeting with NRC to discuss ultimate heat sink.
January 9, 1981  NRC letter to Federal Energy Regulatory Commission requesting that files on applicant be made available to NRC for antitrust review.
A-12
 
APPENDIX A (Continued)
January 13-15, 1981 Caseload Forecast Panel site visit. Meeting resulted in Panel concurring with October 1982 construction completion date.
January 19, 1981    Letter to all holders of OLs and CPs and OL applicants regarding environmental qualification of safety related electric equipment. Items addressed involve cold shutdown, replacement parts, and NUREG-0737.
January 19, 1981    Letter from applicant concurring with October 1982 fuel load date.
January 22, 1981    Meeting with applicant, Ebasco, and Middle South Services to discuss LOCA asymmetric load analysis.
January 23, 1981    Letter to applicant giving notification of acceptance of facilities safeguards contingency plan.
January 30, 1981    Letter from applicant forwarding FSAR Amendment 15 which contains responses to miscellaneous questions, open items, and TMI-related requirements. Also includes revised Chapter 14 and Section 13.3.
February 3, 1981    Letter to applicant forwarding Auxiliary Systems Branch questions. Information requested concerns containment polar crane, nonseismic Category I piping, and isolation dampers.
February 5, 1981    Letter to applicant requesting additional financial information to enable NRC to complete review of OL application.
February 11, 1981  Letter to applicant advising that preservice inspection and test requirements for snubbers will be included in the licensing process. Includes requirements.
February 20, 1981  Letter to applicant requesting additional information for OL application review.
February 20, 1981  Letter to all power reactor licensees and applicants that discusses NUREG-0619 criteria.
February 25, 1981  Letter to applicant forwarding request for additional information on fire protection for OL review.
February 25, 1981  Letter to all licensees of operating power plants and OL applicants (except St. Lucie 1 and 2) requesting review of station blackout procedures and emergency procedure implementation.
A-13
 
APPENDIX A (Continued)
February 26, 1981 Letter to applicant forwarding requests for additional information for Radiological Assessment Branch.
February 26, 1981 Letter to applicant forwarding request for additional information regarding fire protection.
February 26, 1981 Letter to all CP holders and OL applicants discussing periodic updating of FSARs. Letter forwarded infor mation on FSAR legal status, format, and content.
February 26, 1981 Letter from applicant responding to NRC {{letter dated|date=November 25, 1980|text=letter dated November 25, 1980}}. Requested information will be forwarded by April 1, 1982, or approximately 6 months prior to license issue date.
February 27, 1981 Letter from applicant forwarding annual report for 1979 and additional financial information per NRC request dated February 5, 1981.
February 27, 1981 Letter to applicant forwarding additional requests for more information for OL review by Chemical Engineering Branch.
February 27, 1981 Letter from applicant forwarding package of diesel generator control wiring diagrams.
February 28, 1981 Letter to applicant forwarding additional requests for more information for OL review by I&C Systems Branch.
February 28, 1981 Letter to applicant requesting cooperation in acceler ated review of facility with plan for publishing SER in May.
March 3, 1981    Letter to applicant with additional questions for OL review.
March 5, 1981    Letter from applicant forwarding FSAR Amendment 16 which includes responses to questions from Core Performance Branch, Auxiliary Systems Branch, Mechanical Engineering Branch, Utility Finance Branch, and responds to numerous NUREG-0737 Action Items.
March 5, 1981    Letter to applicant forwarding Round Two questions for OL review (questions from Geosciences Branch).
March 5, 1981    Letter to licensees of operating plants and CP holders forwarding NUREG-0696, 11 Functiona1 Criteria for Emergency Response Facilities. 11 A-14
 
APPENDIX A (Continued)
March 10, 1981 Letter from applicant stating that emergency operating procedures for LOCA, inadequate core cooling, steam generator tube rupture, and loss of feedwater will be submitted by July 31, 1981. Additional time needed to address issues being discussed by Combustion Engineering owners group.
March 10, 1981 Letter to applicant forwarding revised request for additional information on fire protection.
March 10, 1981 Letter to all holders of OLs and CPs and OL applicants forwarding information necessary to establish environ mental qualification of safety-related electrical equipment.
March 12, 1981 Letter from Ebasco forwarding preservice examination bid packages.
March 13, 1981 Letter to applicant discussing the timely submission of information for review prior to publishing SER and SSER.
March 17, 1981 Letter from applicant forwarding drawings for fire protection review.
March 17, 1981 Letter from applicant forwarding flow diagrams and instrument drawings in support of NRC containment isolation system review.
March 19, 1981 Letter from Ebasco forwarding information regarding CEDMs in reply to NRC comments.
March 20, 1981 Letter to applicant forwarding Seismic Qualification Review Team request for additional information regarding equipment qualification for seismic and hydrodynamic loads.
March 23, 1981 Letter from applicant forwarding response to FSAR Question 110.1, Asymmetric Loads. Responds to questions and requests discussed during meeting with NRC on January 22, 1981.
March 23, 1981 Letter to applicant forwarding checklist for use in preparing for April 6, 1981 structural design audit for O L review.
March 25, 1981 Letter to applicant requesting estimate of the cost of construction delays.
A-15
 
APPENDIX A (Continued)
March 26, 1981      Meeting with applicant, Combustion Engineering, and Ebasco at the site to discuss emergency feedwater system reliability.
March 30, 1981      Letter from applicant confirming that emergency planning guidance will be met by October 1982 or prior to OL receipt.
March 30, 1981      Letter to applicant forwarding request for additional information on radiation emergency plan to determine compliance with NUREG-0654/FEMA-REP-l.
March 31, 1981      Letters to applicant forwarding requests for additional information for Core Performance Branch and Reactor Systems Branch.
April 3, 1981      Letter from applicant containing an estimate of the cost of construction delays. Responds to NRC {{letter dated|date=March 25, 1981|text=letter dated March 25, 1981}}.
April 10, 1981      Letter to applicant forwarding agenda and guidance for power systems drawing review and facility tour.
April 14, 1981      Letter from applicant forwarding conceptual design of operating phase meteorological monitoring system.
Comments requested.
April 14, 1981      Letter from applicant informing that preservice inspection program contract will be awarded by June 15, 1981.
April 14, 1981      Letter from applicant stating they will be unable to submit data on equipment qualification for seismic and hydrodynamic loads on July 30, 1981. Date for seismic qualification review team visit requested.
April 15,  -,nn'"1
          .L::10.L Letter from applicant forwarding "Preliminary Control Room Assessment. 11 April 16, *1981    Letter to applicant forwarding request for additional information for OL review by Effluent Treatment Systems Branch.
April 16, 1981      Letter to applicant forwarding request for additional information for OL review (information requested by Materials Engineering Branch and Chemical Engineering Branch).
A-16
 
APPENDIX A (Continued)
April 16, 1981 Memorandum from applicant forwarding draft of FSAR Amendment 17, and advising that formal issuance of Amendment 17 will be on April 30, 1981.
April 23, 1981 Letter from applicant forwarding additional information on the physical security plan, security force training and qualification plan, as requested by NRC.
April 23, 1981 Letter from applicant forwarding testimony and data related to financial matters as requested by telephone by NRC on April 21, 1981.
April 23, 1981 Letter to applicant requesting additional information for OL review.
April 27, 1981 Letter from applicant forwarding Amendment 17 to FSAR. The Amendment includes responses to questions from the following branches: Auxiliary Systems, I&C Systems, Power Systems, Structural Engineering i Chemical Engineering. Radiological Assessment, Geosciences, Core Performance, Effluent Treatment, Containment Systems, Reactor Systems, and Licensee Qualification.
April 29, 1981 Letter from applicant forwarding chart  of new organiza tion of plant management.
April 29, 1981 Applicant forwards itemized review of the compliance of the facility with the particularly significant rules and regulations of Title 10 CFR.
April 29, 1981 Letter from applicant forwarding itemized list of compliances with various sections of 10 CFR.
April 29, 1981 Letter from applicant discussing emergency procedures and training for blackout events.
{{letter dated|date=April 29, 1981|text=April 29, 1981 letter}} to applicant forwarding Instrumentation and Control Systems Branch Round 2 questions.
April 29, 1981 Letter to applicant forwarding Round 2 requests for additional information. Also discusses periodic inservice testing of secondary safety valves.
April 29, 1981 Meeting with the applicant at Bethesda to discuss applicant's response to Chapter 14 questions.
A-17
 
APPENDIX A (Continued)
{{letter dated|date=April 30, 1981|text=April 30, 1981 letter}} to applicant forwarding a list of criteria for determining when the control room will be ready for design review and NRC staff visit.
May 4, 1981    Letter to all licensees of operating plants and holders of construction permits regarding qualification of inspection, examination, and testing personnel.
Regulatory Guide 1.46 enclosed.
May 5, 1981    Letter from Ebasco forwarding Revision 2 to 11 Seismic Analysis of Waterford SES Spent Fuel Storage Racks 11 design calculations for reinforced concrete walls.
May 5, 1981    Letter to all licensees of operating plants and holders of construction permits regarding evaluation of H. B. Robinson plant coolant leak.
May 6, 1981    Letter from applicant forwarding draft implementing procedures for emergency plan.
May 7, 1981    Letter from applicant advising of current participation in CE owners group activities addressing NUREG*0737 item II. K. 3. 30.
May 7, 1981    Letter from applicant discussing plans for answering selected requests for additional information.
May 11, 1981  Letter from applicant forwarding proprietary and nonproprietary versions of 11 Preliminary Assessment of Waterford 3 Fuel Structural Integrity Under Faulted Conditions. 11 May 11, 1981  Meeting with the applicant at Bethesda to discuss applicant's management capabilities and staffing.
May 11, 1981  Letter from applicant with revised response to selected requests for additional information. Some information supersedes FSAR Amendment 17.
May 11, 1981  Letter from applicant forwarding information requested during a Structural Engineering Branch audit.
May 12, 1981  Letter from applicant discussing closing of switchboard breakers without de control power.
May 12, 1981  Letter from applicant forwarding updated FSAR figures ref1ecting more current geological information.
A-18
 
APPENDIX A (Continued)
May 13, 1981    Letter from applicant forwarding list of pumps, valves, and hangers subject to inservice inspection.
May 13, 1981    Letter to applicant requesting additional information for OL review.
May 14, 1981    Letter from applicant forwarding proprietary and nonproprietary versions of "Calculational Method for Critical Crack Size. 11 May 14, 1981    Letter from applicant forwarding FSAR Amendment 18, which includes information regarding structural engineering, TMI action items, procedures and test review, geosciences, effluent treatment, containment systems, and reactor systems.
May 14-15, 1981 Meeting with the applicant and Ebasco at the site for a site tour and discussion of industrial hazards and exclusion area control.
May 15, 1981    Letter from applicant forwarding three drawings and information regarding control of heavy loads and preliminary safe load paths.
May 15, 1981    Letter to applicant forwarding list of items requ1r1ng additional information for completion of SER.
May 15, 1981    Letter from applicant forwarding response to NRC concerns raised at May 11, 1981 meeting on applicant management and technical capability.
May 19-21, 1981 Meeting with the applicant, Ebasco, and Argonne National Laboratory at the site for a plant tour, discussion of open issues, and review of drawings.
May 20, 1981    Letter from applicant forwarding status of SER open items in response to NRC letter dated May 15; 1981.
May 21, 1981    Letter from applicant forwarding response to Effluent Treatment Systems Branch questions.
May 21, 1981    Letter to applicant forwarding updated list of open items. Requests schedule for providing information by May 22, 1981.
May 26, 1981    Letter from applicant forwarding information requested by Reactor Systems Branch.
A-19
 
APPENDIX A (Continued)
May 26, 1981  Letter to counsel to parties in NRC proceedings and other interested persons requesting comments on Federal Register notice regarding licensing requirements.
May 27, 1981  Letter from applicant forwarding nonproprietary version of "LP Turbine Disc Information."
May 27, 1981  Letter from applicant referring NRC to applicant {{letter dated|date=May 20, 1981|text=letter dated May 20, 1981}} for schedule of submitting information requested in NRC {{letter dated|date=May 21, 1981|text=letter dated May 21, 1981}}.
May 27, 1981  Meeting with the applicant, Ebasco, and Energy, Incorporated, at Bethesda to discuss outstanding issues in the containment systems review.
May 27, 1981  Letter from applicant forwarding response to Instru mentation and Control Systems Branch questions.
May 28, 1981  Meeting with the applicant and Ebasco at Bethesda to discuss site hazards affecting plant operations and safety.
June 1-3, 1981 Meeting with app1icant at the site for physical security site visit and discussion.
June 4, 1981  Meeting with the applicant, Ebasco, and Gage-Babcock at Bethesda to discuss fire protection.
June 4, 1981  Letter from applicant forwarding information requested by Reactor Systems Branch.
June 4, 1981  Letter from applicant forwarding information requested by Containment Systems Branch.
June 4, 1981  Letter to applicant forwarding summary of May 28, 1981 meeting with applicant regarding status of SER.
Agreement reached that delay of SER publication until July 6, 1981 is necessary.
June 9, 1981  Letter from applicant requesting that quality assurance correspondence be addressed to L. V. Maurin.
June 10, 1981  Letter from applicant forwarding more information requested by Reactor Systems Branch that concerns postirradiation fuel surveillance program and rod bow penalty.
A-20
 
APPENDIX A (Continued)
June 11, 1981    Letter from applicant forwarding physical security plan.
June 11-12, 1981 Meeting with applicant at the site for effluent treatment systems site visit and discussion of open items.
June 12, 1981    Letter from applicant forwarding responses to Structural Engineering Branch questions regarding evaluation of local stresses in steel containment shell.
June 12, 1981    Letter from applicant informing NRC that the applicant owns the surface access to property at the edge of the exclusion area, in response to NRC {{letter dated|date=May 15, 1981|text=letter dated May 15, 1981}}.
June 12, 1981    Letter from applicant regarding disagreement that safety injection tank discharge valve controls should be modified.
June 12, 1981    Letter from applicant forwarding response to SER open item in draft SER Section 4.2.2.
June 12, 1981    Letter from applicant forwarding response to SER open items in draft SER Section 2.4.2.3.
June 12, 1981    Letter from applicant forwarding additional information needed for SER input. Information pertains to descrip tion of changes to emergency feedwater system controls.
June 12, 1981    Letter to applicant providing additional guidance on TMI-2 Action Plan Item I.G.1 special low power testing.
June 15, 1981    Letter from applicant forwarding proposals for preservice inspection program piping and steam generator tubing.
June 15, 1981    Letter from applicant forwarding information regarding commitment to provide startup channel alarm to back up boron meter alarm for dilution event. Also discusses effects of steam generator tube plugging on LOCA analyses.
June 17, 1981    Letter from applicant forwarding FSAR Amendment 19, which includes additional information required to address open items that appear in draft SER.
June 17, 1981    Letter from applicant discussing revision to FSAR Amendment 18 response to NRC question.
A-21
 
APPENDIX A (Continued)
June 24-25, 1981 Applicant meeting with NRC to review emergency operating procedures.
A-22
 
APPENDIX B BIBLIOGRAPHY BOOKS, PAPERS, AND JOURNAL ARTICLES Coffman, J. L., and C. A. Von Hake, "Earthquake History of the United States,"
National Oceanic and Atmospheric Administration - U.S. Department of Commerce Publication 41-1, 1973.
Docekal, J., 11 Earthquakes of the Stable Interior, With Emphasis on the Mid-continent," Ph.D. Thesis, University of Nebraska, 1970.
((
                                                                                  ))
Gupta, I. W., and 0. W. Nuttli, 11 Spatial Attenuation of Intensities for Central U.S. Earthquakes, 11 Seismol. Soc. Amer. Bull. 66, pp. 227-248, 1976.
Holzworth, G. C., 11 Mixing Heights, Wind Speeds, and Potential for Urban Air Pollution Throughout the Contiguous United States," AP-101, EPA, Office of Air Programs, North Carolina, January 1972.
((
                                                                                  ))
Kao, H. S., C. D. Moran, and M. B. Parker, "Prediction of Flow Oscillation in Reactor Core Channel,' ANS Transactions, Vol 16, p. 212, 1973.
King, P. B., "The Tectonics of North America--A Discussion To Accompany the Tectonic Map of North America, Scale 1:5,000,000, 11 U.S. Geol. Survey Prof.
Paper 628, Washington, 0.C. 1969.
Kolb, C. R., F. L. Smith, and R. C. Silva, "Pleistocene Sediments of the New Orleans-Lake Pontchartrain Area," U.S. Waterways Expt. Sta. Tech. Rept.
S-75-6, Vicksburg, Miss., 1975.
Milne, J., Catalogue of Destructive Earthquakes, British Assoc. for the Adv.
Sci., Appendix 1, pp. 649-740, 1911.
Nuttli, 0. W., and K. G. Brill, Jr., Earthquake Source Zones in the Central United States Determined from Historical Seismicity, Preprint from Saint Louis University, 1981.
Nuttli, 0. W., and R. B. Herrmann, 11 State-of-the-Art for Assessing Earthquake Hazards in the United States: Credible Earthquakes for the Central United States, 11 Misc. Paper-S-73-1, Report No. 12, U.S. Army Waterways Experiment Station, Vicksburg, Miss., 1978.
Saucier, R. T., "Quaternary Geology of the Lower Mississippi Valley: Arkansas Archeological Survey, "Research Series No. 6, Fayetteville, Ark., 1974.
8-1
 
Smith, 0. A., 11 Sealing and Nonsealing Faults in Louisiana Gulf Coast Salt Basin, 11 Amer. Assoc. Petrol. Geologists Bull. 64(2), 145-172, 1980.
Thom, H. C. S., 11 New Distribution of Extreme Winds in the United States, 11 Proceedings of the ASCE, Journal of the Structural Division, July 1968.
Thom, H. C. 5., "Tornado Probabilities Monthly Weather Review," U. S. Weather Bureau, Washington, D.C., October-December 1973, pp., 730-736, 1963.
Trifunac, M. D., and A. G. Brady, On the Correlation of Seismic Intensity Scales With Peaks of Recorded Strong Ground Motion," Seismal. Soc. Amer. Bull.
65, 1975.
U.S. Department of Commerce, "Local Climatological Data Annual Summary With Comparative Data for New Orleans, Louisiana," National Ocenaic and Atmospheric Administration, Environmental Data Service, 1972.
Veziroglu, T. N., and S. S. Lee, "Boiling-Flow Instabilities in a Cross-Connected Parallel-Channel or Flow System," ASME Paper 71-HT-12, August 1971.
Wong, H. L., and M. D. Trifunac, 11 Synthesizing Realistic Ground Motion Accelero grams,11 Los Angeles: University of Southern California, Department of Civil Engineering, 1978.
Zoback, M. D., R. M. Hamilton, A. J. Crone, D. P. Russ, F. A. McKeown, and S.
R. Brockman, Recurrent Intra late Tectonism in the New Madrid Seismic Zone, Science, 209, pp. 971-976, 180.
B-2
 
CODE OF FEDERAL REGULATIONS*
10 CFR Part 20, 11 Standards for Protection Against Radiation 11 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities" 10 CFR Part 70, 11 Domestic Licensing of Special Nuclear Materials" 10 CFR Part 100, "Reactor Site Criteria" 10 CFR Part 140, 11 Financial Protection Requirements" 49 CFR Part 171, "General Information Regulations, and Definitions" 49 CFR Part 172, "Hazardous Materials Table u and Hazardous Materials Communications Regulations 49 CFR Part 173, Shippers--General Requirements for Shipments and Packagings" 11 49 CFR Part 174, 11 Carriage by Rail 11 11 49 CFR Part 175, "Carriage by Aircraft 49 CFR Part 176, "Carriage by Vessel" 49 CFR Part 177, "Carriage by Public Highway" 49 CFR Part 178, "Shipping Container Specifications
*Available in public libraries.
B-3
 
CONTRACTOR AND UTILITY REPORTS*
Arkansas 11 Power and Light Co. report                                                                                11 Arkansas Nuclear One, Unit 2, Final Safety Analysis:                                                Report,                May 25, 1977.
Carolina Power & Light report Study on Shearon Harris Nodalization Sensitivity Studies Combustion Engineering reports CEN-39(a)-P Rev. 2, 11 CPC Protective Algorithm Software Change Procedure 11 CEN-50, "CE Burnable Poison Irraidation Test Program, 11 March 1977 CEN-77(M)-P, Cladding Damage Analysis of Maine Yankee Core II 11 CENPD-107 11 CESEC--Digital Simulation of a Combustion Engineering Nuclear Steam Sur.ply System,11 April 1974 CENPD-118 'Densification of Combustion Engineering Fuel, 11 June 1974 CENPD-139-A "Fuel Evaluation Model, July 1974 CENPD-158 "Anticipated Transients Without Scram,"
CENPD-158, Rev. 1 CENPD-162-P-A "Critical Heat Flux Correlation for CE Fuel Assemblies With Standard Spacer Grids, Part 1 Uniform Axial Power Distribution."
CENPD-168 "Design Basis Pipe Breaks" CENPD-169-P 11 COLSS--Assessment of the Accuracy of PWR Operating                                                            Limits as Determined by the Core Operating Limit Supervisory Systems 11 CENPD-178 "Structural Analysis of Fuel Assemblies for Combined Seismic and Loss-of-Coolant Accident Loading," August 1976 CENPD-187-A "CEPAN Method of Analyzing Creep Collapse of Oral Cladding," March 1976 CENPD-190-A 11 CEA Ejection," January 1976 CENPD-198 (Suppl. 1) 11 Zircaloy Growth Application of Zircaloy Irradiation Growth Correlations for the Calculation of Fuel Assembly and Fuel Rod Growth Allowances,11 December 1977 CENPD-198 (Suppl. 2-P) "Resr.onse to Request for Additional Information on CENPD-198-P, Supplement 1, 'November 1, 1978 CENPD-207, "Core Thermo-Hydraulics Code" CENPD-225, "Fuel and Poison Rod Burning," October 1976 CE Standard Technical Specifications CESSAR, Combustion Engineering Standard Safety Analysis Report Idaho National Engineering Laboratories report HJl='I
  **'lt...L..
Donnv-t t...\,,,IU
              '"'-t-''-'' Y i:r.r.-J:M-"..11"..1 1 11 VtJ..J IIOe.,;e'*'
I\ YI n UI r.4' +hn    c:,.+ ..... +;,...., r.4' +
                                                                    \.oll'= Ll.,IIIIQl,fVJI VJ h - T, ..., 0nc:*v't:i"',
1,1 1t:i        ..., - ...,_
C:tl Charpy V-Notch Shelf Value From the Longitudinal Value 11
                                                  )
Louisiana Power and Light Co. reports Excerpt from Board of Directors meeting, April 14, 1981 Final Safety Analysis Report, Waterford 3 Steam Electric Station, Unit No. 3 B-4
 
Operational Quality Assurance Procedures Manual Preliminary Safety Analysis Report for the Construction Permit, Waterford 3 Waterford Unit 3 Fire Protection Program Reevaluation Westinghouse report:
WCAP-7820 WCAP-7820, Supplements
*Available for inspection and copying for a fee in the NRC Public Document Room, 1717 H Street, NW, Washington, D.C.
B-5
 
GENERAL DESIGN CRITERIA (10 CFR PART 50, APPENDIX A)*
: 1. Quality Standards and Records
: 2. Design Gases for Protection Against Natural Phenomena
: 3. Fire Protection
: 4. Environmental and Missile Design Bases
: 5. Sharing of Structures, Systems, and Components
: 10. Reactor Design
: 11. Reactor Inherent Protection
: 12. Suppression of Reactor Power Oscillations
: 13. Instrumentation and Control
: 14. Reactor Coolant Pressure Boundary
: 15. Reactor Coolant System Design
: 16. Containment Design
: 17. Electric Power Systems
: 18. Inspection and Testing of Electric Power Systems
: 19. Control Room
: 20. Protection System Functions
: 21. Protection System Reliability and Testability
: 22. Protection System Independence
: 23. Protection system Failure Modes
: 24. Separation of Protection and Control Systems
: 25. Protection System Requirements for Reactivity Control Malfunctions
: 26. Reactivity Control System Redundancy and Capability
: 27. Combined Reactivity Control Systems Capability
: 28. Reactivity Limits
: 29. Protection Against Anticipated Operational Occurrences
: 30. Quality of Reactor Coolant Pressure Boundary
: 31. Fracture Prevention of Reactor Coolant Pressure Boundary
: 32. Inspection of Reactor Coolant Pressure Boundary
: 33. Reactor Coolant Makeup
: 34. Residual Heat Removal
: 35. Emergency Core Cooling
: 36. Inspection of Emergency Core Cooling System
: 37. Testing of Emergency Core Cooling System
: 39. Inspection of Containment Heat Removal System
: 40. Testing of Containment Heat Removal System
: 41. Containment Atmosphere Cleanup
: 42. Inspection of Containment Atmosphere Cleanup Systems
: 43. Testing of Containment Atmosphere Cleanup Systems
: 44. Cooling Water
: 45. Inspection of Cooling Water System
: 46. Testing of Cooling Water System
: 50. Containment Design Basis
: 51. Fracture Prevention of Containment Pressure Boundary
: 52. Capabaility for Containment Leakage Rate Testing
: 53. Provisions for Containment Testing and Inspection
: 54. Systems Penetrating Containment
: 55. Reactor Coolant Pressure Boundary Penetrating Containment
: 56. Primary Contaiment Isolation
: 57. Closed System Isolation Valves.
B-6
: 60. Control Releases of Radioactive Materials to the Environment
: 61. Fuel Storage and Handling and Radioactivity Control
: 62. Prevention of Criticality in Fuel Storage and Handling
: 63. Monitoring Fuel and Waste Storage
: 64. Monitoring Radioactivity Releases
*The Code of Federal Regulations is available in public libraries.
B-7
 
LETTERS*
July 1, 1977        From LP&L submitting Waterford Unit 3 Fire Protection Program Reevaluation December*23, 1977 From A. E. Sherer, C-E, to V. Stello, NRC February 14, 1978 From W. P. Johnson, MYAP Co., to V. Stello, NRC February 14, 1978 From A. E. Lundvall, BG&E Co., to V. Stello, NRC April 14, 1978      From NRC to Carolina Power & Light May 19, 1978        From J. F. Stolz, NRC, to T. M. Anderson, November 1, 1978    Argeement letter with the Missouri Pacific Railroad Co.
August 21, 1978    From R. L. Baer, NRC, to A. E. Scherer, C-E November 9, 1979    From D. G. Eisenhut, NRC, to All Operating Light Water Reactors March 28, 1980      From H. R. Denton, NRC, to All Power Reactor Applicants and Licensees May 19, (20), 1980 From NRC to All Applicants and Licensees August 22, 1980    From LP&L to NRC October 17, 1980    Agreement letter between USCG and Louisiana Office of Emergency Preparedness November 12, 1980 From NRC to LP&L December 22, 1980 From NRC to Holders of OL 1 s and CP 1 s and OL Applicants February 25, 1981 From D. Eisenhut, NRC, to LP&L March 23, 1981      From L. V. Maurin, LP&L, to A. Schwencer, NRC April 14, 1981      From LP&L to NRC April 20, 1981      From LP&L to NRC May 11, 1981        From L.V. Maurin, LP&L, to R. L. Tedesco, NRC May 15, 1981        From LP&L to NRC
*Ava1lable for inspection and copying, for a fee in the NRC Public Document Room, 1717 H Street, NW., Washington, D.C.
B-8
 
MEMORANDA*
December 8, 1976    From D. F. Ross and D. G. Eisenhut, NRC, to 0. B. Vassallo and K. R. Go 11 er.
February 16, 1977  From D. F. Ross and D. G. Eisenhut, NRC, to D. B. Vassallo and K. R. Go 11er November 20, 1979  From R. P. Denise, NRC, to R. J. Mattson November 26, 1979  From H. R. Denton, NRC to Commissioners June 23, 1980      From R. E. Jackson, NRC, to D. Crutchfield May 5, 1981        From R. W. Macek, EG&G, to D. F. Obenchain, EG&G Available for inspection and copying for a fee in the NRC Public Document Room, 1717 H Street, NW., Washington, D.C.
B-9
 
MISCELLANEOUS REPORTS Atomic Industrial Forum:
ALFINESP-009 AIF, "An Engineering Evaluation of Nuclear Power Reactor Decommissioning Alternatives/ Washington, D.C., 1976.
Atomic Safety and Licensing Board, NRC:*
ALAB-444, November 23, 1977 ALAB-491 ALAB-603 Coastal Engineering Research Center (U.S. Army):
CERC Shore Protection Manual, 1973 Department of Defense:
MIL-STD-14728 Environmental Protection Agency:
EPA Emergency Workers and Lifesaving Activity Protective Action Guides Federal Register Vol. 40, p. 19442, May 5, 1975, October 2, 1980 (2 Notices)
*Available for inspection and copying for a fee in the NRC Public Document Room, 1717 H Street, NW., Washington, D.C.
B-10
 
TECHNICAL CODES, ANO STANDARDS*
American Concrete Institute American Institute of Steel Construction American National Standards Institute American Nuclear Society American Society of Civil Engineers American Society of Mechanica1 Engineers American Society of Testing Materials:
Institute of Electrical and Electronics Engineers National Electrical Manufacturers Association National Fire Protection Association Welding Research Council
*Available from public technical libraries.
B-11
 
USNRC REGULATORY GUIDES*
1.1  11  Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps 11 1.3  11 Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Boiling Water Reactors11 1
1.4  1  Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Pressurized Water Reactors 11 1.6  11 Independence Between Redundant Standby (Onsite) Power Sources and Between Their Distribution Systems11 1
1.7    1 Control of Combustible Gas Concentrations in Containment Following a Loss of Coolant Accident, Rev 2 11 1.8 "Personnel Selection and Training" 1
1.9    1 Selection, Design, and Qualification of Diesel-Generator Units Used as Standby (Onsite) Electric Power Systems at Nuclear Power Plants11 1
1.11    1  Instrument Lines Penetrating Primary Reactor Containment" 11 1.12        Instrumentation for Earthquakes" 1.13 "Spent Fuel Stored Facility Design Basis" 1.14    11 Reactor Coolant Pump Flywheel Integrity11 1.141 1 1 Containment Isolation Provisions for Fluid Systems" 1.16 "Reporting of Operating Information--Appendix A Technical Specifications11 1.20 "Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing" 1.21    11 Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Release of Radioactivity in Liquid and Gaseous Effluents From Light Water-Cooled Nuclear Power Plants" 1.23    11 0nsite Meteorological Programs, Rev. 1, Sept 1980 11 1.25    11  Assumptions Used for Evaluating the Potential Radological Consequences of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors" 1.26    11 Quality Group Classifications and Standards for Water-, Steam-, and Radio-Waste-Containing Components of Nuclear Power Plants''
1.27 "Ultimate Heat Sink for Nuclear Power Plants" B-12
 
1.28 "Quality Assurance Program Requirements (Design and Construction)"
1.29 11  Seismic Design Classification 11 1.30 11 Quality Assurance Requirements for the Installation, Inspection, and Testing of Instrumentation and Electric Equipment" 1.31 "Control of Ferrite Content in Stainless Steel Weld Metal 11 1.32 11 Criteria for Safety-Related Electric Power Systems for Nuclear Power Plants 11 1.33 "Quality Assurance Program Requirements (Operational), Rev. 2 11 1.36 "Nonmetallic Thermal Insulation for Austenitic Stainless Steel" 11 1.37      Quality Assurance Requirements for Cleaning of Fluid Systems and Associated Components of Water-Cooled Nuclear Power Plants" 1.38 11  Quality Assurance Requirements for Packaging, Shipping, Receiving, Storage, and Handling      of Items for Water-Cooled Nuclear Power Plants, Rev. 2 11 1.39 11  Housekeeping Requirements for Water-Cooled Nuclear Power Plants, Rev. 2 11 1.40 11 Qualfication Tests of Continuous-Duty Motors Installed Inside the Containment of Water-Cooled Nuclear Power. Plants" 1
1.41  1 Preoperational Testing of Redundant Onsite Electric Power Systems To Verify Proper Load Group Assignments" 1.43 11  Control Stainless Steel Weld Cladding of Low-Alloy Steel Components" 1.44 "Control of the Use of Sensitized Stainless Steel" 1.45 "Reactor Coolant Pressure Boundary Leakage Detection Systems 11 1.46 "Protection Against Pipe Whip Inside Containment" 1.47 11 Bypassed and Inoperable Status Indication for Nuclear Power Plant
    .:::,are"Ly .:::,ys"Lems**
    ,..  ,. 1  r      1    II 1.48 "Design Limits and Loading Combinations for Seismic Category I Fluid System Components" 1.50 "Control of Preheat Temperature for Welding of Low-Alloy Steel" 1.52 "Design, Testing, and Maintenance Criteria for Postaccident Engineered Safety-Feature Atmosphere Cleanup System Air Filtration and Absorption Units of Light-Water-Cooled Nuclear Power Plants 11 1.58 11 Qualification of Nuclear Power Plant Inspection, Examination, and Testing Personne1, Rev. 1 u 8-13
 
1.59 "Design Basis Floods for Nuclear Power Plants''
1.60  11  Design Response Spectra for Seismic Design of Nuclear Power Plants 11 1.61 "Damping Values for Seismic Design of Nuclear Power Plants' 1 1
1.62  1  Manual Initiation of Protective Actions 11 1.63  11 Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Power Plants11 1.64 "Quality Assurance Requirements for the Design of Nuclear Power Plants, Rev. 2 11 1.67 "Installation of Overpressure Protective Devices11 1.68 "Initial Test Programs for Water-Cooled Nuclear Power Plants11 1.68.2 11 Initial Startup Test Program to Demonstrate Remote Shutdown Capability for Water-Cooled Nuclear Power Plants" 1.69 "Concrete Radiation Shields for Nuclear Power Plants"
: 1. 70 "Standard Format and Content of Safety Analysis Reports for Nuclear Power Plants, Rev. 2 11 1.71 "Welder Qualification for Areas of Limited Accessibility"
: 1. 74 "Quality Assurance Terms and Definitions 1 1
: 1. 75 1 1
Physical Independence of Electric Systems 11 1.76 "Design Basis Tornado for Nuclear Power Plants 11 1.77 "Assumptions Used for Evaluating a Control Rod Ejection Accident for Pressurized Water Reactors" 1.79 "Preoperational Testing of Emergency Core Cooling Systems for Pressurized Water Reactors" 1.80 "Preoperational Testing of Instrument Air Systems 11 1.82  11  Sumps for Emergency Core Cooling and Containment Spray Systems" 1.83 "Inservice Inspection of Pressurized Water Reactor Steam Generator Tubes'  1 11 1.84      Design and Fabrication Code Case Acceptability--ASME Section III, Division 1 11 1.85 "Materials Code Case Acceptability--ASME Section III, Division 1" B-14
 
1.88 "Collection, Storage, and Maintenance of Nuclear Power Plant Quality Assurance Records, Rev 2 11 1.94 "Quality Assurance Requirements for Installation, Inspection, and Testing of Structural Concrete and Structural Steel11 During the Construction Phase of Nuclear Power Plants, Rev. 1 1.95 "Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release11 11 1.97    Instrumentation for Light-Water-Cooled Nuclear Power Plants To Assess Plant and 11 Environs Conditions During and Following an Accident, Rev. 2 1.102 "Flood Protection for Nuclear Power Plants" 1.106 "Thermal  1 Overload Protection for Electric Motors on Motor-Operated Valves 1 1.108** "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants" 1.109 "Calculation of Annual Doses to Man From Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50, Appendix 1 11 1.111 "Methods for Estimating Atmospheric Transport and Dispersion of Gaseous Effluents in Routine Releases from Light-Water-Cooled Reactors, Rev 111 1.115 "Protection Against Low Trajectory Turbine Missiles11 1.116 "Quality Assurance Requirements for Installation, Inspection, and Testing of Mechanical Equipment and Systems, Rev. O-R 11 1.117 urornado Design Classification" 1.118 "Periodic Testing of Electric Power and Protection Systems11 1
1.123    1  Quality Assurance Requirements for Control of Procurement of Items and Services for Nuclear Power Plants, Rev 1" 1.26    "An Acceptable Model and Related Statistical Methods for the Analysis of Fuel Densification1 1 1.32    11  Site Inventigations for Foundations of Nuclear Power Plants"
**Errata sheet available by writing to the Director, Division of Document Control, USNRC, Washington, D.C. 20555 B-15
 
1 1.33  1  Loose-Part Detection Program for the Primary System of Light-Water Cooled Reactors 11              ...
1.37 11 Fuel-Oil Systems for Standby Diesel Generators 11 1.43  1 1 Design Guidnce for Radioactive Waste Management Systems, Structures, and Components Installed in Light-Water-Cooled Nuclear Power Plants 11 1.145 11 Atmospheric Dispersion Models for Potential Accident Consequence Assessment at Nuclear Power Plants 11 1.146 11 Qualification  of Quality Assurance Program Audit Personnel for Nuclear Power Plants 11
: 4. 7  1 1
General Site Suitability Criteria for Nuclear Power Stations 11 11 8.2      Administrative Practices in Radiation Monitoring 11 8.3  11 Film Badge Performance Criteria 11 8.4  11  Direct-Reading and Indirect-Reading Pocket Dosimeters 11 1
: 8. 7  1  0ccupational Radiation Exposure Records Systems11 1
8.8    1 Information Relevant To Ensuring That Occupational Radiation Exposures at Nuclear Power Stations Will Be as Low as Is Reasonably Achievable11 8.10  1 1
0perating Philosophy for Maintaining Occupational Radiation Exposures as Low as Is Reasonably Achievable (Nuclear Power Reactors) 11 1
8.19    1 0ccupational Radiation Dose Assessment in Light-Water Reactor Power Plants--Design Stage Man-Rem Estimates11
*Available for purchase from Superintendent of Documents, U.S. Nuclear Regulatory Commission, ATTN: Sales Manager, Washington, D.C. 20555.
B-16
 
USNRC REPORTS*
WASH-1270      11 Technical Report on Anticipated Transients Without Scram for Water-Cooled Power Reactors," September 1973.
11 Safety Evaluation of the Comanche Peak Steam Electric Station, Units 1 and 2, 11 Docket Nos. 50-445 and 50-446, 1974.
              "Safety Evaluation Report Related to Construction of the South Texas Project, Units 1 and 2, 11 Docket Nos. STN 50-498 and 50-499, 1975.
NUREG-75/087** "Standard Review Plan for Review of Safety Analysis Reports for Nuclear Power Plants--LWR Edition" December 1975 NUREG-75/112  "Safety Evaluation Report for the Preliminary Design Approval of the Combustion Engineering Standard Safety Analysis Report--CESSAR System 80,11 December 1975 NUREG-0017    11 Calculations of Releases of Radioactive Materials in Gaseous and Liquid Effluents for Pressurized Water Reactors (PWR-GALE Code),11 April 1976 NUREG-0085    11 The Analysis of Fuel Densification, 11 July 1976 NUREG-0131    11 Early Site Review of Blue Hills Site by the Office of Nuclear Reactor Regulation in the Matter of Gulf States Utilities Company,' Docket Nos. 50-510 and 50-511, 1977 NUREG-0212,    11 Standard Technical Specifications for Combustion Engineering Pressurized Water Reactors," December 1980 NUREG-0224    11 Final Report on Reactor Vessel Pressure Transient Protection for Pressurized Water Reactors,' September 1978 NUREG-0303    "Evaluation of the Behavior of Water Logged Fuel Rod Failures in LWRs, 11 March 1978 NUREG-0308,    "Safety Evaluation Report Related to Operation of Arkansas Nuclear One, Unit 2, 11 September 1978 NUREG-0347    "Safety Evaluation Report Related to Construction of the Yellow Creek Nuclear Plant," Docket Nos. STN 50-566 and STN 50-567, December 1977 NUREG-0410    11 NRC Program for the Resolution of Generic Issues Related to Nuclear Power Plants, Report to Congress," December 1977 NUREG-0418    11 Fission Gas Release From Fuel at High Burnup, 11 March 1978 NUREG-0460    "Anticipated Transients Without Scram for Light Water Reactors, 11 April 1978 B-17
 
NUREG-0510    "Identification of Unresolved Safetri Issues Relating to Nuclear 1
Power Plants--A Report to Congress, January 1979 NUREG-0515    11 Safety Evaluation of the Allens Creek Nuclear Generating Station, Units 1 and 2, March 1979 11 NUREG-0577    "Potential for Low Fracture Toughness and Lamellar Tearing on PWR Steam Generator and Reactor Coolant Pump Supports, 11 September 1979 NUREG-0578    11 TMI ..: 2 Lessons Learned Task Force:  Status Report and Short-Term Recommendations/' July 1979 NUREG-0582    "Water Hammer in Nuclea,r Power Plants," April 1979 NUREG-0588    "Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment, 11 November 1979 NUREG-0609    "Asymmetric Slowdown Loads on PWR Primary Systems, Resolution of Generic Task Action Plan A-2, 11 January 1981 NUREG-0611    "Generic Evaluation of Feedwsater Transients and Small-Break Loss-of-Coolant Accidents in Pressurized Water Reactors,"
November 1979 NUREG-0612    "Control of Heavy Loads at Nuclear Power Plants, Resolution of Generic Technical Activity A-36, 11 July 1980 NUREG-0630    "Cladding Swelling and Rupture Models for LOCA Analysis,"
November 1979.
NUREG-0635    11 Generic Assessment of Sma 11-Break Loss-of-Coo 1 ant Accidents in Combustion Engineering Designed Operating Plants," January 1980 NUREG-0649    "Task Action Plan for Unresolved Safety Issues Related to Nuclear Power Plants,'1 February 1980 NUREG-0654/  "Criteria for Preparation and Evaluation of Radiological FENA-REP-1,  Emergency Response Plans and Preparedness in Support of Nuclear Nov. 1980    Power Plants," January 1980 NUREG-0660,  11 NRC Action Plan Developed as a Resuit of the TMI-2 Accident,"
Vols. 1 and 2 May 1980; Revision 1, August 1980 NUREG-0696    "Functional Criteria for Emergency Response Facilities," July 1980 (Draft Report)
NUREG-0696    "Functional Criteria for Emergency Response Facilities," February 1981 (Final Report)
NUREG-0700    "Guidelines for the Design Review of Nuclear Power Plant Control Rooms,jj to be printed B-18
 
NUREG-0705      11 Identification of New Unresolved Safety Issues Relating to Nuclear Power Plants," March 1981 NUREG-0712      11 Safety Evaluation Report Related to the Operation of San Onofre, Nuclear Generating Station, Units 2 and 3,U February 1981 NUREG-0731      "Guidelines for Utility Management Structure and Technical (Draft)***      Resources," September 1980 NUREG-0737      "Clarification of TMI Action Plan Requirements/ November 1980 NUREG-0779*** "Draft Environmental Statement Related to the Operation of Waterford Steam Electric Station, Unit No. 3,11 April 1981 NUREG-0797      11 Safety Evaluation Report of the Comanche Peak Electric Station, Units 1 and 2,11 to be printed NUREG-0800      11 Standard Review Plan for the Review of Safety Analysis Reports (Formerly      for Nuclear Power Plants--LWR Edition,'1 to be printed NUREG-75/087)
NUREG/CR-0130 Battelle Pacific Northwest Lab., 11 Technology, Safety, and Vol. 1          Costs of Decommissioning a Reference Pressurized Water Reactor Power Station, 11 June 1978 NUREG/CR-0130 "Addendum," August 1979 NUREG/CR-0660 University of Dayton Research Institute, "Enhancement of Onsite Emergency Diesel Generator Reliability, 11 February 1979 NUREG/CR-0672, Battelle Pacific Northwest Lab., "Technology, Safety, and Costs Vol. 1 and      of Decommissioning a Reference Boiling Water Reactor Power Vo 1. 2                Station, 11 June 1980 NUREG/CR-1580 Essex Corporation, "Human Engineering Guide for Control (Draft)***      Regulation,11 July 1980
  *Available for purchase from GPO Sales Program, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555 and/or National Technical Information Service, Springfield, Virginia 22161.
**Now NUREG-0800.
***Available free upon written request to TIDC, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555.
B-19
 
Documents with the following types of designation and other miscellaneous documents are available for inspection and copying for a fee in the NRC Public Document Room at 1717 H. Street, NW., Washington, D.C.:
Commission Order Inspection and Enforcement documents Regulatory Guides Standard Review Plan Branch Technical Positions
 
APPENDIX C NUCLEAR REGULATORY COMMISSION (NRC)
UNRESOLVED SAFETY ISSUES C.l UNRESOLVED SAFETY ISSUES The NRC staff continuously evaluates the safety requirements used in its reviews against new information as it becomes available. Information related to the safety of nuclear power plants comes from a variety of sources including experience from operating reactors; research results; NRC staff and Advisory Committee on Reactor Safeguards (ACRS) safety reviews; and vendor, architect/
engineer and utility design reviews. Each time a new concern or safety issue is identified from one or more of these sources, the need for immediate action to assure safe operation is assessed. This assessment includes consideration of the generic implications of the issue.
In some cases, immediate action is taken to assure safety, for example, the derating of boiling water reactors as a result of the channel box wear problems in 1975. In other cases, interim measures, such as modifications to operating procedures, may be sufficient to a11ow further study of the issue before making licensing decisions. In most cases, however, the initial assessment indicates that immediate licensing actions or changes in licensing criteria are not necessary. In any event, further study may be deemed appropriate to make judgments as to whether existing NRC requirements should be modified to address the issue for new plants or if backfitting is appropriate for the long-term operation of plants already under construction or in operation.
These issues are sometimes called "generic safety issues11 because they are related to a particular class or type of nuclear facility rather than a specific plant. These issues have also been referred to as "unresolved safety issues, 11 (NUREG-0410, "NRC Program for the Resolution of Generic Issues Related to Nuclear Power Plants, 11 dated January 1, 1978). However, as discussed above, such issues are considered on a generic basis only after the staff has made an initial determination that the safety significance of the issue does not prohibit continued operation or require licensing actions while the longer-term generic review is underway.
C.2 ALAB-444 REQUIREMENTS These longer-term generic studies were the subject of a decision by the Atomic Safety and Licensing Appeal Board of the Nuclear Regulatory Commission. The Decision was issued on November 23, 1977 (ALAB-444) in connection with the Appeal Board's consideration of the Gulf States Utility Company application for the River Bend Station, Unit Nos. 1 and 2.
C-1
 
In the view of the Appeal Board, (pp. 25-29)
    "The responsibilities of a licensing board in the radiological health and safety sphere are not confined to the consideration and disposition of those issues which may have been presented to it by a party or an
      'Interested State' with the required degree of specificity. To the contrary, irrespective of what matters may or may not have been properly placed in controversy, prior to authorizing the issuance of a construction permit the board must make the finding, inter alia, that there is 'reason able assurance 1 that 1 the proposed facility can be constructed and operated at the proposed location without undue risk to the health and safety of the public.' Of necessity, this 10 CFR 50.35(a) determination will entail an inquiry into whether the staff review satisfactorily has come to grips with any unresolved generic safety problems which might have an impact upon operation of the nuclear facility under consideration.
11 The SER is, of course, the principal document before the licensing board which reflects the content and outcome of the staff's safety review. The board should therefore be able to look to that document to ascertain the extent to which generic unresolved safety problems which have been pre viously identified in an FSAR item, a Task Action Plan, an ACRS report or elsewhere have been factored into the staff's analysis for the particular reactor--and with what result. To this end, in our view, each SER should contain a summary description of those generic problems under continuing study which have both relevance to facilities of the type under review and potentially significant public safety implications.
11 This summary description should include information of the kind now contained in most Task Action Plans. More specifically, there should be an indication of the investigative program which has been or will be undertaken with regard to the problem, the program's anticipated time span, whether (and if so, what) interim measures have been devised for dealing with the problem pending the completion of the investigation, and what alternative courses of action might be available should the program not produce the envisaged result.
11 In short, the board (and the public as well) should be in a position to ascertain from the SER itself--without the need to resort to extrinsic documents--the staff's perception of the nature and extent of the relation ship between each significant unresolved generic safety question and the eventual operation of the reactor under scrutiny. Once again; this assessment might well have a direct bearing upon the ability of the licensing board to make the safety findings required of it on the construc tion permit level even though the generic answer to the question remains in the offing. Among other things, the furnished information would likely shed light on such alternatively important considerations as whether: (1) the problem has already been resolved for the reactor under study; (2) there is a reasonable basis for concluding that a satisfactory solution will be obtained before the reactor is put in operation; or (3) the problem would have no safety implications until after several years of reactor operation and, should it not be resolved by then, alter native means will be available to insure that continued operation (if permitted at all) would not pose an undue risk to the public. 11 C-2
 
This appendix is specifically included to respond to the decision of the Atomic Safety and Licensing Appeal Board as enunciated in ALAB-444, and as applied to an operating license proceeding in Virginia Electric and Power Comany (North Anna Nuclear Power Station, Unit Nos 1 and 2), ALAB-491, nRrm (19 8).
C.3 UNRESOLVED SAFETY ISSUES In a related matter, as a result of Congressional action on the Nuclear Regulatory Commission budget for Fiscal Year 1978, the Energy Reorganization Act of 1974 was amended (PL 95-209) on December 13, 1977 to include, among other things, a new Section 210 as follows:
uUNRESOLVED SAFETY ISSUES PLAN" 11 SEC. 210. The Commission shall develop a plan providing for specification and analysis of unresolved safety issues relating to nuclear reactors and shall take such action as may be necessary to implement corrective measures with respect to such issues. Such plan shall be submitted to the Congress on or before January 1, 1978 and progress reports shall be included in the annual report of the Commission thereafter."
The Joint Explanatory Statement of the House-Senate Conference Committee for the Fiscal Year 1978 Appropriations Bill (Bill 1 S.1131) provided the following additional information regarding the Committee s deliberations on this portion of the bill:
11 SECTION 3 - UNRESOLVED SAFETY ISSUES 11 The House amendment required development of a plan to resolve generic safety issues. The conferees agreed to a requirement that the plan be sub mitted to the Congress on or before January 1, 1978. The conferees also expressed the intent that this plan should identify and describe those safety issues, relating to nuclear power reactors, which are unresolved on the date of enactment. It should set forth: (1) Commission actions taken directly or indirectly to develop and implement corrective measures; (2) further actions planned concerning such measures; and (3) timetables and cost estimates of such actions. The Commission should indicate the priority it has assigned to each issue, and the basis on which priorities have been assigned.11 In response to the reporting requirements of the new Section 210, the NRC staff submitted to Congress on January 1, 1978, a report, NUREG-0410, entitled uNRC Program for the Resolution of Generic Issues Related to Nuclear Power Plants, 11 describing the NRC generic issues program. The NRC program was already in place when PL 95-209 was enacted and    is of considerably broader scope than the 11 Unresolved Safety Issues Plan 11 required by Section 210. In the letter transmitting NUREG-0410 to the Congress on December 30, 1977, the Commission indicated that 11 the progress reports, which are required by Section 210 to be included in future NRC annual reports, may be more    useful to Congress if they focus on the specific Section 210 safety items. 11 It is the NRC 1 s view that the intent of Section 210 was to assure that plans were developed and implemented on issues with potentially significant public C-3
 
safety implications. In 1978, the NRC undertook a review of over 130 generic issues addressed in the NRC program to determine      which issues fit this description and qualify as "Unresolved Safety Issues 11 for reporting to the Congress. The NRC review included the development of proposals by the NRC Staff and review and final approval by the NRC Commissioners.
This review is described in a report NUREG-0510, 11 Identification of Unresolved Safety Issues Relating to Nuclear Power Plants - A Report to Congress," dated January 1979. 11 The report provides the following definition of an 11 Unresolved Safety Issue:
11 An Unresolved Safety Issue is a matter affecting a number of nuclear power plants that poses important questions concerning the adequacy of existing safety requirements for which a final resolution has not yet been developed and that involves conditions not likely to be accepable over the lifetime of the plants it affects. 11 Further the report indicates that in applying this definition, matters that pose 11 important questions concerning the adequacy of existing safety requirements11 were judged to be those for which resolution is necessary to (1) compensate for a possible major reduction in the degree of protection of the public health and safety, or (2) provide a potentially significant decrease in the risk to  the public health and safety. Quite simply, an "Unresolved Safety Issue 11 is potentially significant from a public safety standpoint and its resolution is likely to result in NRC action on the affected plants.
All of the issues addressed in the NRC program were systematically evaluated against this definition 11 as described in NUREG-0510. As a result, 17 11 Unresolved Safety Issues addressed by 22 tasks in the NRC program were identified. The issues are listed below. Progress on these issues was first discussed in the 1978 NRC Annual Report. The number(s) of the generic task(s) (e.g., A-1) in the NRC program addressing each issue is indicated in parentheses following the title.
11 UNRESOLVED SAFETY ISSUES 11 (APPLICABLE TASK NOS.)
: 1. Waterhammer - (A-1)
: 2. Asymmetric Slowdown Loads on the Reactor Coolant System - (A-2)
: 3. Pressurized Water Reactor Steam Generator Tube Integrity - (A-3, A-4, A-5)
: 4. BWR Mark I and Mark II Pressure Suppression Containments - (A-6, A-7, A-8, A-39)
: 5. Anticipated Transients Without Scram - (A-9)
: 6. BWR Nozzle Cracking - (A-10)
: 7. Reactor Vessel Materials Toughness - (A-11)
: 8. Fracture Toughness of Steam Generator and Reactor Coolant Pump Supports - (A-12)
: 9. Systems Interaction in Nuclear Power Plants - (A-17)
: 10. Environmental Qualification of Safety-Related Electrical Equipment -
(A-24)
: 11. Reactor Vessel Pressure Transient Protection - (A-26)
: 12. Residual Heat Removal Requirements - (A-31)
: 13. Control of Heavy Loads Near Spent Fuel - (A-36)
C-4
: 14. Seismic Design Criteria - (A-40)
: 15. Pipe Cracks at Boiling Water Reactors - (A-42)
: 16. Containment Emergency Sump Reliability - (A-43)
: 17. Station Blackout - (A-44)
In the view of the staff, the "Unresolved Safety Issues" listed above are the substantive safety issues referred to by the Appeal Board in ALAB-444 when it spoke of 11 * *
* those generic problems under continuing study which have....
potentially significant public safety implications." Eight of the 22 tasks identified with the "Unresolved Safety Issues 11 are not applicable to Waterford 3 and six of these eight tasks (A-6, A-7, A-8, A-39, A-10 and A-42) are peculiar to boiling water reactors. Tasks A-3 and A-5 address steam generator tube prob lems in Westinghouse and Babcock and Wilcox plants. With regard to the remaining 14 tasks that are applicable to this facility, the NRC staff has issued NUREG reports providing its proposed resolution of five of these issues. Each of these has been addressed in this Safety Evaluation Report or will be addressed in a future supplement. The table below lists those issues and the section of this Safety Evaluation Report in which they are discussed.
Safety Evaluation Task Number            NUREG Report and Title              Report Section A-2                NUREG-0609, 11 Asymmetric              3.9.2.2 Slowdown Loads on PWR                  4.2.2.9 Primary Systems" A-24                NUREG-0588, "Interim Staff              3.11 Position on Environmental Qualification of Safety Related Electrical Equipment11 A-26                NUREG-0224, 11 Reactor Vessel          5.2.2 Pressure Transient Protection for Pressurized Water Reactors 11 and RSB BTP 5-2 A-31                SRP 5.4.7 and BTP 5-1                  5.4.3 1
1 Residual Heat Removal Systems 1 1
incorporate requirements of US! A-31.
A-36                NUREG-0612, "Control of                9.1. 4 Heavy Loads at Nuclear Power Plants 11 The remaining issues applicable to this facility are listed in the following table:
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GENERIC TASKS ADDRESSING UNRESOLVED SAFETY ISSUES THAT ARE APPLICABLE TO THE WATERFORD STEAM ELECTRIC STATION, UNIT 3
: 1. A-1    Waterhammer
: 2. A-4    Combustion Engineering Steam Generator Tube Integrity
: 3. A-9    Anticipated Transients Without Scram
: 4. A-11  Reactor Vessel Materials Toughness
: 5. A-12  Potential for Low Fracture Toughness and Lamellar Tearing on PWR Steam Generator and Reactor Coolant Pump Supports
: 6. A-17  Systems Interactions in Nuclear Power Plants
: 7. A-40  Seismic Design Criteria
: 8. A-43  Containment Emergency Sump Reliability
: 9. A-44  Station Blackout With the exception of Tasks A-9, A-43, and A-44, Task Action Plans for the generic tasks above are included in NUREG-0649, 11 Task Action Plans for Unresolved Safety Issues Related to Nuclear Power Plants.11 A technical resolution for Task A-9 has been proposed by the NRC staff in Volume 4 of NUREG-0460, issued for comment. This served as a basis for the staff's proposal for rulemaking on this issue. The Task Action Plan for Task A-43 was issued in January 1981, and the Task Action Plan for A-44 was issued in July 1980. Draft NUREG-0577 which represents staff resolution of USI A-12 was issued for comment in November 1979. The Draft NUREG contained the Task Action Plan for A-12. The information provided in NUREG-0649 meets most of the informational requirements of ALAB-444.
Each Task Action Plan provides a description of the problem; the staff's approaches to its resolution; a general discussion of the bases upon which continued plant licensing or operation can proceed pending completion of the task; the technical organizations involved in the task and estimates of the manpower required; a description of the interactions with other NRC offices, the Advisory Committee on Reactor Safeguards and outside organizations; estimates of funding required for contractor supplied technical assistance; prospective dates for completing the task; and a description of potential problems that could alter the planned approach on schedule.
In addition to the Task Action Plans, the staff issues the "Office of Nuclear Reactor Regulation Unresolved Safety Issues Summary, Aqua Book 11 (NUREG-0606) on a ouarterlv basis which orovides current schedule information for each of the unresolved safety issues. It also includes information relative to the implementation status of each unresolved safety issue for which technical resolution is complete.
The NRC staff has reviewed the nine unresolved safety issues listed above as they relate to Waterford 3. Discussion of each of these issues including references to related discussions in the Safety Evaluation Report are provided below in Section C.5. Based on our review of these items, we have concluded, for the reasons set forth in Section C-5, that, with the exception of task A-40, 11 Seismic Design Criteria," there is reasonable assurance that Waterford, Unit 3 can be operated prior to the ultimate resolution of these generic issues without endangering the health and safety of the public. This determination for task A-40 is still under review and shall be included in a supplement to this SER.
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C.4 NEW "UNRESOLVED SAFETY ISSUES 11 An in-depth and systematic review of generic safety concerns identified since January 1979 has been performed by the staff to determine if any of these issues should be designated as new unresolved safety issues. The candidate issues originated from concerns identified in NUREG-0660, "NRC Action Plan as a Result of the TMI-2 Accident; 11 ACRS recommendations; abnormal occurrence reports and other operating experience. The staff's proposed list was reviewed and commented on by the ACRS, the Office of Analysis and Evaluation of Operational Data (AEOD) and the Office of Policy Evaluation. The ACRS and AEOD also proposed that several additional unresolved safety issues be considered by the Commission. The Commission considered the above information and approved the following four new unresolved safety issues:
A-45 Shutdown Decay Heat Removal Requirements A-46 Seismic Qualification of Equipment in Operating Plants A-47 Safety Implications of Control Systems A-48 Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment A description of the review process for candidate issues, together with a list of the issues considered is presented in NUREG-0705, "Identification of New Unresolved Safety Issues Relating to Nuclear Power Plants, Special Report to Congress," dated March 1981. An expanded discussion of each of the new unresolved safety issues is also contained in NUREG-0705.
Based on our review of these new 11 Unresolved Safety Issues, 11 we have concluded, for the reasons set forth in Section C-5, that, with the exception of task A-46, 11 Seismic Qualification of Equipment in Operating Plants," there is reasonable assurance that Waterford, Unit 3 can be operated prior to the ultimate resolution of these generic issues without endangering the health and safety of the public. This determination for task A-46 is still under review and shall be included in a supplement to this SER.
C.5 DISCUSSION OF TASKS AS THEY RELATE TO WATERFORD STEAM ELECTRIC STATION, UNIT 3 A-1 Waterhammer: Waterhammer events are intense pressure pulses in fluid systems caused by any one of a number of mechanisms and system conditions.
Since 1971 there have been over 100 incidents involving waterhammer in pressurized water reactors and boiling water reactors. The waterhammers have involved steam generator feedrings and piping, decay heat removal systems, emergency core cooling systems, containment spray lines, service water lines, feedwater lines and steam lines. However, the systems most frequently affected by waterhammer effects are the feedwater systems. The most serious waterhammer events have occurred in the steam generator feedrings of pressurized water reactors. These types of waterhammer events are addressed in Sections 10.4.7 and 10.4.9 of this Safety Evaluation Report.
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Under Generic Task A-1, the potential for waterhammer in various systems is being evaluated and appropriate requirements and systematic review procedures are being developed to ensure that waterhammer is given appropriate considera tion in al1 areas of licensing review. A technical report, NUREG-0582, 11 Water hammer in Nuclear Power Plants" (July 1979), provides the results of an NRC staff review of waterhammer events in nuclear power plants and states current staff licensing positions, completing a major subtask of Generic Task A-1.
With regard to protection against other potential waterhammer events currently provided in plants, piping design codes require consideration of impact loads.
Approaches used at the design stage include: (1) increasing valve closure times, (2) piping layout to preclude water slugs in steam lines and vapor formation in water lines, (3) use of snubbers and pipe hangers, and (4) use of vents and drains. In addition, NRC requires, that the applicant conduct a preoperational vibration dynamic effects test program in accordance with Section III of the ASME Code for all ASME Class 1 and Class 2 piping systems and piping restraints during startup and initial operation. These tests will provide adequate assurance that the piping and piping restraints have been designed to withstand dynamic effects resulting from valve closures, pump trips, and other operating modes associated with the design operational transients.
Nonetheless, in the unlikely event that a large pipe break did result from a severe waterhammer event, core cooling is assured by the emergency core cooling systems and protection against the dynamic effects of such pipe breaks inside and outside of containment is provided.
In the event that Task A-1 identifies some potentially significant waterhammer scenarios which have not explicitly been accounted for in the design and operation of Waterford 3, corrective measures will be required at that time.
The task has not as yet identified the need for requiring any additional measures beyond those already implemented.
Based on the foregoing, the staff has concluded that Waterford can be operated before ultimate resolution of this generic issue without undue risk to the health and safety of the public.
A-4 Combustion Engineering Steam Generator Tube Integrity: The primary concern is the capability of steam generator tubes to maintain their integrity during normal operation and postulated accident conditions.
In addition, the requirements for increased steam generator tube inspections and repairs have resulted in significant increases in occupational exposures to workers. Corrosion resulting in steam generator tube wall thinning (wastage) has been observed in several Westinghouse and Combustion Engineering plants for a number of years. Major changes in their secondary water treatment process essentially eliminated this form of degradation. Another major corrosion related phenomenon has also been observed in a number of plants in recent years, resulting from a buildup of support plate corrosion products in the annulus between the tubes and the support plates. This buildup eventually causes a diametral reduction of the tubes, called denting, and deformation 11        11 of the tube support plates. This phenomenon has led to other problems, including stress corrosion cracking, leaks at the tube/support plate intersections, and U-bend section cracking of tubes which were highly stressed because of support plate deformation.
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Specific measures, such as steam generator design features, a secondary water chemistry control and monitoring program, condensate demineralization and condenser tubing material selection, that the applicant has employed to minimize the onset of steam generator tube problems are described in Section 5.4.2.1 this report. In addition, Section 5.4.2.2 of this report discusses the inservice inspection requirements for steam generator tubes. As described in these sections, the applicant has met all current requirements regarding steam generator tube integrity. The technical specifications will include requirements for actions to be taken in the event that steam generator tube leakage occurs during plant operation.
Task A-4 is expected to result in improvements in our current requirements for inservice inspection of steam generator tubes. These improvements will include a better statistical basis for inservice inspection program requirements and consideration of the cost/benefit of increased inspection. Pending completion of Task A-4, the measures taken at Waterford 3 should minimize the steam generator tube problems encountered. Further the inservice inspection and technical specification requirements will assure that the applicants and the NRC staff are alerted to tube degradation should it occur. Appropriate actions such as tube plugging, increased and more frequent inspections, and power derating could be taken if necessary. Since the improvements that will result from Task A-4 will be procedural, that is, an improved inservice inspection program, they can be implemented by the applicant at Waterford 3 after operation begins, if necessary.
Based on the foregoing, the staff has concluded that Waterford can be operated before ultimate resolution of this generic issue without undue risk to the health and safety of the public.
A-9 Anticipated Transients Without Scram: Nuclear plants have safety and control systems to limit the consequences of temporary abnormal operating conditions or 11 anticipated transients. 11 Some deviations from normal operating conditions may be minor; others, occurring less frequently, may impose signifi cant demands on plant equipment. In some anticipated transients, rapidly shutting down the nuclear reaction (initiating a 11 scram11 ), and thus rapidly reducing the generation of heat in the reactor core, is an important safety measure. If a reactor shutdown system did not 11 scram11 as desired, then an "anticipated transient without scram," or ATWS, would have occurred.
The anticipated transient without scram issue and the requirements that must be met by the applicant before operation of the facility are discussed in Section 15.3.6 of this Safety Evaluation Reporto The ATWS issue is currently scheduled for rulemaking in mid-summer 1981. The applicant will be required to comply with any further requirements on ATWS which may be imposed as a result of the rulemaking.
Based on staff review, there is reasonable assurance that Waterford 3 can be operated before ultimate resolution of this generic issue without endangering the health and safety of the public.
A-11 Reactor Vessel Materials Toughness: Resistance to brittle fracture, a rapidly propagating catastrophic failure mode for a component containing flaws, is described quantitatively by a material property generally denoted as C-9
 
11 fracture toughness." Fracture toughness has different values and character istics depending upon the material being considered. For steels used in a nuclear reactor pressure vessel, three considerations are important. First, fracture toughness increases with increasing temperature; second, fracture toughness decreases with increasing load rates; and third, fracture toughness decreases with neutron irradiation.
In recognition of these considerations, power reactors are operated within restrictions imposed by the technical specifications on the pressure during heatup and cooldown operations. These restrictions assure that the reactor vessel will not be subjected to a combination of pressure and temperature that could cause brittle fracture of the vessel if there were significant flaws in the vessel materials. The effect of neutron radiation on the fracture toughness of the vessel material is accounted for in developing and revising these technical specification limitations.
For the service times and operating conditions typical of current operating plants, reactor vessel fracture toughness for most plants provides adequate margins of safety against vessel failure under operating, testing, maintenance, and anticipated transient conditions, and accident conditions over the life of the plant. However, results from a reactor vessel surveillance program and analyses performed for up to 20 older operating pressurized water reactors and those for some more recent vintage plants show that such vessels will have marginal toughness, relative to required margins at normal full power after comparatively short periods of operation. In addition, results from analyses performed by pressurized water reactor manufacturers indicate that the integrity of some reactor vessels may not be maintained in the event that a main steam line break or a loss-of-coolant accident occurs after approximately 20 years of operation. The principal objective of Task A-11 is to develop an improved engineering method and safety criteria to allow a more precise assessment of the safety margins that are available during normal operation and transients in older reactor vessels with marginal fracture toughness and of the safety margins available during accident conditions for all plants.
The NRC's evaluation of this facility's reactor vessel materials toughness and the requirements that must be met by the applicant before operation of the facility are discussed in Section 5.3 of this Safety Evaluation Report. Since Task A-11 is projected to be completed well in advance of this facility's reactor vessel reaching a fluence level which would noticably reduce fracture resistance, acceptable vessel integrity for the postulated accident conditions will be assured at least until the reactor vessel is reevaluated for long-term acceptability.
In addition, the surveillance program required by 10 CFR Part 50, Appendix H will afford an opportunity to reevaluate the fracture toughness periodically during the first half of design 1ife.
Therefore, based upon the foregoing, the staff has concluded that this facility can be operated before this generic issue is resolved without undue risk to the health and safety of the public.
A-12 Potential for Low Fracture Tou hness and Lamellar Tearin on PWR Steam Generator and eactor Coolant Pump Supports: During the course of the licensing action for North Anna Power Station Units No. 1 and 2 a number of questions C-10
 
were raised as to the potential for lamellar tearing and low fracture toughness of the steam generator and reactor coolant pump support materials for those facilities. Two different steel specifications (ASTM A36-70a and ASTM A572-70a) covered most of the material used for these supports. Toughness tests, not originally specified and not in the relevant ASTM specifications, were made on those heats for which excess material was available. The toughness of the A36 steel was adequate, but the toghness of the A572 steel was relatively poor at an operating temperature of 80 F.
Since similar materials and designs have been used on other nuclear plants, the concerns regarding the supports for the North Anna facilities are applicable to other PWR plants. It was, therefore, necessary to reassess the fracture toughness of the steam generator and reactor coolant pump support materials for all operating PWR plants and those in CP and OL review.
NUREG-0577, "Potential for Low Fracture Toughness and Lamellar Tearing on PWR Steam Generator and Reactor Coolant Pump Supports,'' was issued for comment in November 1979. This report summarizes work performed by the NRC staff and its contractor, Sandia Laboratories, in the resolution of this generic activity.
The report describes the technical issues, the technical studies performed by Sandia Laboratories, the NRC staff's technical positions based on these studies, and the NRC staff's plan for implementing its technical positions. As a part of initiating the implementation of the findings in this report, letters were sent to all applicants and licensees on May 19 and 20, 1980. In these letters a revised proposed implementation plan was presented and specific criteria for material qualifications were defined.
Many comments on both the draft of NUREG-0577 and the letters of May 19 and 20 have been received by the NRC staff and detailed consideration is presently being given to these comments. After completing its review and analysis of the comments provided, the staff will issue the final revision of NUREG-0577 which will include a full discussion and resolution of the comments and a final plan for implementation.
The staff estimates that its implementation review will require approximately 2 years. Since many factors (initiating event, low fracture toughness in a critical support member in tension, low operating temperature, large flaw) must be simultaneously present for the support system to fail, the staff has determined that licensing for pressurized water reactors should continue durinq the implementation phase. NRC conclusions reoardinq licensina and subsequent operation are not sensitive to the estimated length of time required for this work.
With regard to the lamellar tearing issue, the results of an extensive literature survey by Sandia revealed that, although lamellar tearing is a common occurrence in structural steel construction, virtually no documentation exists describing inservice failures resulting from lamellar tearing. Nonetheless, additional research is recommended to provide a more definitive and complete evaluation of the importance of lamellar tearing to the structural integrity of nuclear power plant support systems.
Based on NRC 1 s review, the staff has concluded that there is reasonable assurance that Waterford can be operated before this generic issue is ultimately resolved without endangering the health and safety of the public.
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A-17 Systems Interaction in Nuclear Power Plants: Current licensing require ments are founded on the principle of defense-in-depth. Adherence to this principle results in requirements such as physical separation and independence of redundant safety systems, and protection against hazards such as high energy line ruptures, missiles, high winds, flooding, seismic events, fires, human factors, and sabotage. These design provisions are subject to review against the Standard Review Plan (NUREG-75/087) which requires interdisciplinary reviews and addresses many different types of potential systems interactions.
The quality assurance program which is followed during the design, construction, and operational phases for each plant is expected to provide added assurance against the potential for adverse systems interactions. Thus, the current licensing requirements and procedures provide for a degree of plant safety with respect to such interactions.
In November 1974, the Advisory Committee on Reactor Safeguards requested that the NRC staff give attention to the need to increase safety by separately evaluating the plant from a multidisciplinary point of view, in order to identify potentially undesirable interactions between plant systems. The concern arises because the design, analysis and installation of systems is frequently the responsibility of teams of engineers with functional specialties-such as civil, electrical, mechanical, or nuclear. Experience at operating plants led the ACRS to question whether the work of these functional specialists is sufficiently integrated to enable them to minimize adverse interactions among systems. Such adverse events have occurred because the teams did not assure by adequate coordination that the required independence of safety systems was provided under all conditions of operation.
In mid-1977, Task A-17 was initiated to assure that present review procedures and safety criteria provide an acceptable level of redundancy and independence for safety functions. The task proceeded by evaluating the potential for undesirable interactions between systems at a sample plant.
The NRC staff's current procedures assign primary responsibility for review of various technical areas to specific organizational units and assign secondary responsibility to other units where there is a functional interface. Designers follow somewhat similar procedures and provide the analyses of systems and interface reviews. Task A-17 provided an independent study of methods that could identify important systems interactions adversely impacting safety, and which were not considered by current review procedures. The first phase of
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                                                                                                          ...)QllUIQ Laboratories under contract to the NRC staff.
The Phase I investigation was structured to identify areas where interactions are possible between systems and have the potential of negating or seriously degrading the performance of safety functions. The study concentrated on commonly caused or linked failures among systems that could violate a safety function. The investigation was to then identify where NRC review procedures may not have properly accounted for these interactions.
The Sandia Laboratories used fault-tree methods to identify component failure combinations (cut-sets) that could result in loss of a safety function. The cut-sets were further reduced by incorporating six common or linking systems failures into the analysis. The results of the Phase I effort indicate that, within the scope of the study, only a few areas of the staff's review procedures C-12
 
need improvement regarding systems interaction. However, the level of detail needed to identify all examples of potential system interaction candidates observed in some operating plants were not within the Phase I scope of the Sandia study.
The 11 NRC Action Plan Developed as a Result of the TMI-2 Accident, 11 NUREG-0660, provides for a systems interaction follow-on study, Section II.C.3, 11 Systems Interactions. 11 Since April 1980, the Office of Nuclear Reactor Regulation has intensified the effort both by broadening the study of methods to identify potential systems interactions and by performing audit reviews of two plants for selected systems interactions.
Recent experience provides a basis from which NRC is developing an improved, systematic review process for potential systems interactions. The process will provide for a resolution of USI A-17, assimilate operating reactor experience, and rank identified systems interactions by their relative importance to safety.
It is expected that the development of systematic ways to identify, rank, and evaluate systems interactions will go further to reduce the likelihood of intersystem failures resulting in the loss of plant safety functions. However, the studies to date indicate that current review procedures and criteria supplemented by the application of post-TM! findings and risk studies provide reasonable assurance that the effects of potential systems interactions on public safety will be within the effects on public safety previously evaluated.
Therefore, the staff concludes that there is reasonable assurance that Waterford 3 can be operated before the final resolution of this generic issue without endangering the health and safety of the public.
A-40 Seismic Design Criteria--Short-Term Program: NRC regulations require that nuclear power structures, systems, and components important to safety be designed to withstand the effects of natural phenomena such as earthquakes.
Detailed requirements and guidance regarding the seismic design of nuclear plants are provided in the NRC regulations and in Regulatory Guides issued by the Commission. However, there are a number of plants with construction permits and operating licenses issued before the NRC's current regulations and regulatory guidance were in place. For this reason, rereviews of the seismic design of various plants are being undertaken to assure that these plants do not present an undue risk to the public. Task A-40 is, in effect, a compendium of short-term efforts to support such reevaluation efforts of the NRC staff, especially those related to older operating plants. In addition, some revisions to the Standard Review Plan sections and Regulatory Guides to bring them more in line with the state of the art will result.
As discussed in Sections 3. 7.1 through 3.7.4 of this Safety Evaluation Report the seismic design basis and seismic design of the facility have been evaluated at the operating license stage and have been found acceptable pending confirma tory analyses discussed in Section 3. 7.
A-43 Containment Erner                          Following a postulated loss-of-coo ant acc1 ent t at 1s, a break 1n t e reactor coolant system piping), the water flowing from the break would be collected in the emergency sump at the low point in the containment. This water would be recirculated through the C-13
 
reactor system by the emergency core cooling pumps to maintain core cooling.
This water would also be circulated through the containment spray system to remove heat and fission products from the containment. Loss of the ability to draw water from the emergency sump could disable the emergency core cooling and containment spray systems.
One postulated means of losing the ability to draw water from the emergency sump could be blockage by debris. A principal source of such debris could be the thermal insulation on the reactor coolant system piping. In the event of a piping break, the subsequent violent release of the high pressure water in the reactor coolant system could rip off the insulation in the area of the break. This debris could then be swept into the sump, potentially causing blockage.
Currently, regulatory positions regarding sump design are presented in Regulatory Guide 1. 82, 11 Sumps for Emergency Core Cooling and Containment Spray Systems, 11 which addresses debris (insulation). Regulatory Guide 1.82 recommends, in addition to providing redundant separated sumps, that two protective screens be provided. A low approach velocity in the vicinity of the sump is required to allow insulation to settle out before reaching the sump screening; and it is required that the sump remain functional assuming that one-half of the screen surface area is blocked. Staff review of the sump design against the regulatory guide is found in Section 6.3 of this Safety Evaluation Report.
A second postulated means of losing the ability to draw water from the emergency sump could be abnormal conditions in the sump or at the pump inlet such as air entrainment, vortices, or excessive pressure drops. These conditions could result in pump cavitation, reduced flow and possible damage to the pumps.
Currently, regulatory positions regarding sump testing are contained in Regulatory Guide 1.79, 11 Preoperational Testing of Emergency Core Cooling Systems for Pressurized Water Reactors, 11 which addresses the testing of the recirculation function. Both inplant and scale model tests have been performed by applicants to demonstrate that circulation through the sump can be reliably accomplished.
As indicated in Section 6.3 of this Safety Evaluation Report, the applicant will perform out-of-plant scale model tests of the containment sump design.
The applicant will be required to demonstrate that there is reasonable assurance that the sump design will perform as expected following a loss-of-coolant accident.
The near term implementation of Task A-43 for Waterford is expected to be procedural in nature and assure adequate housekeeping and emergency procedures to supplement the sump tests discussed above. Accordingly, the staff has concluded that this facility can be operated before ultimate resolution of this generic issue without endangering the health and safety of the public.
A-44 Station Blackout: Electrical power for safety systems at nuclear power plants must be supplied by at least two redundant and independent divisions.
The systems used to remove decay heat to cool the reactor core following a reactor shutdown are included among the safety systems that must meet these requirements. Each electrical division for safety systems includes an offsite C-14
 
ac power connection, a standby emergency diesel generator ac power supply, and de sources.
Task A-44 involves a study of whether or not nuclear power plants should be designed to accommodate a complete loss of all alternating current power, that is, loss of both the offsite and the emergency diesel generator alternating current power supplies. This issue arose because of operating experience regarding the reliability of ac power supplies. A number of operating plants have experienced a total loss of offsite electrical power, and more such losses are expected in the future. During each of these loss-of-offsite-power events, the onsite emergency ac power supplies were available to supply the power needed by vital safety equipment. However, in some instances, one of the redundant emergency power supplies has been unavailable. In addition, there have been numerous reports of emergency diesel generators failing to start and run in operating plants during periodic surveillance tests.
A loss of all ac power was not a design basis event for the Waterford 3 facility.
Nonetheless, a combination of design, operation, and testing requirements that have been imposed on the applicant will assure that this unit will have substantial resistance to a loss of all alternating current and that, even if a loss of all alternating current should occur, there is reasonable assurance that the core will be cooled. These are discussed below.
A loss of offsite ac power involves a loss of both the preferred and backup sources of offsite power. NRC review and basis for acceptance of the design, inspection, and testing provisions for the offsite power system are described in Sections 8.1 and 8.2 of the Safety Evaluation Report.
If offsite power is lost, diesel generators and their associated distribution systems will deliver emergency power to safety-related equipment. NRC review of the design, testing, surveillance, and maintenance provisions for the onsite emergency diesels is described in Section 8.3 of the SER. Staff require ments include preoperational testing to assure the reliability of the installed diesel generators is in accordance with our requirements discussed in the SER. In addition, the applicant has been requested to implement a program for enhancement of diesel generator reliability to better assure the long-term reliability of the diesel generators. This program resulted from recommendations of NUREG/CR-0660, 11 Enhancement of Onsite Emergency Generator Reliability. 11 Even if both offsite and onsite ac power are lost, cooling water can still be provided to the steam generators by the auxiliary feedwater system by employing a steam turbine driven pump that does not rely on alternating current power for operation. Staff review of the auxiliary feedwater system design and operation is described in Section 10.4.9 of the Safety Evaluation Report.
The issue of station blackout was also considered by the Atomic Safety and Licensing Appeal Board (ALAB-603) for the St. Lucie Unit No. 2 facility. In addition, in view of the completion schedule for Task A-44 (October 1982), the Appeal Board recommended that the Commission take expeditious action to ensure that other plants and their operators are equipped to accommodate a station blackout event. The Commission has reviewed this recommendation and determined that some interim measures should be taken at all facilities including Waterford 3 while Task A-44 is being conducted. Consequently, interim emergency procedures and operator training for safe operation of the facility and restoration of ac C-15
 
power will be required. The staff notified the applicant of these requirements in a letter from D. Eisenhut, NRC, dated February 25, 1981.
Based on the above, we have concluded that there is reasonable assurance that Waterford 3 can be operated before the ultimate resolution of this generic issue without endangering the health and safety of the public.
A-45 Shutdown Decay Heat Removal Requirements: Under normal operating conditions, power generated within a reactor is removed as steam to produce electricity via a turbine generator. Following a reactor shutdown, a reactor produces insufficient power to operate the turbine; however, the radioactive decay of fission products continues to produce heat (so-called 1 1 decay heat 11 ). Therefore, when reactor shutdown occurs, other measures must be available to remove decay heat from the reactor to ensure that high temperatures and pressures do not develop which could jeopardize the reactor and the reactor coolant system. It is evident, therefore, that all light water reactors (LWRs) share two common decay heat removal functional requirements: {1) to provide a means of trans ferring decay heat from the reactor coolant system to an ultimate heat sink and (2) maintain sufficient water inventory inside the reactor vessel to ensure adequate cooling of the reactor fuel. The reliability of a particular power plant to perform these functions depends on the frequency of initiating events that require or jeopardize decay heat removal operations and the prob ability that required systems will respond to remove the decay heat.
This unresolved safety issue will evaluate the benefit of providing alternate means of decay heat removal which could substantially increase the plants' capability to handle a broader spectrum of transients and accidents. The study will consist of a generic system evaluation and will result in recommenda tions regarding the desirability of and possible design requirements for improvements in existing systems or an alternative decay heat removal method if the improvements or alternative can significantly reduce the overall risk to the public.
The primary method for removal of decay heat from pressurized water reactors is via the steam generators to the secondary system. This energy is transferred on the secondary side to either the main feedwater or auxiliary feedwater systems, and it is rejected to either the turbine condenser or the atmosphere via the steamline 5afety/relief valves. Following the TMI-2 accident, the importance of the auxiliary feedwater system was highlighted and a number of steps were taken to improve the reliability of the auxiliary feedwater system.
The staff 1 s review of these items is contained in Section 10.4.9 of this Safety Evaluation Report. It was also stipulated that plants must be capable of providing the required auxiliary feedwater flow for at least 2 hours from one auxiliary feedwater pump train, independent of any alternating current power source (that is, if both offsite and onsite ac power sources are lost).
Pressurized water reactors also have alternate means of removing decay heat if an extended loss of feedwater is postulated. This method is known as "feed and bleedu and uses the high pressure injection system to add water coolant (feed) at high pressure to the primary system. The decay heat increases the system pressure and energy is removed through the power-operated relief valves and/or the safety valves (bleed), if necessary.
C-16
 
At low primary system pressure (below about 200 psi), the long-term decay heat is removed by the residual heat removal system to achieve cold shutdown conditions.
Based on the foregoing, the staff has concluded that Waterford 3 can be operated before ultimate resolution of this generic issue without endangering the health and safety of the public.
A-46 Seismic Qualification of Equipment in Operating Plants: The design criteria and methods for the seismic qualification of mechanical and electrical equipment in nuclear power plants have undergone significant change during the course of the commercial nuclear power program. Consequently, the margins of safety provided in existing equipment to resist seismically induced loads and perform the intended safety functions may vary considerably. The seismic qualification of the equipment in operating plants must, therefore, be reassessed to ensure the ability to bring the plant to a safe shutdown condition when subject to a seismic event. The objective of this unresolved safety issue is to establish an explicit set of guidelines that could be used to judge the adequacy of the seismic qualification of mechanical and electrical equipment at all operating plants in lieu of attempting to backfit current design criteria for new plants. This guidance will concern equipment required to safely shut down the plant, as well as equipment whose function is not required for safe shutdown, but whose failure could result in adverse conditions which might impair shutdown functions.
Staff review of Waterford 3 against current seismic criteria is incomplete at this time. The staff will report on the results of its evaluation in a supple ment to this report.
A-47 Safety Implications of Control Systems: This issue concerns the potential for transients or accidents being made more severe as a result of control system failures or malfunctions. These failures or malfunctions may occur independently or as a result of the accident or transient under consideration.
One concern is the potential for a single failure such as a loss of a power supply, short circuit, open circuit, or sensor failure to cause simultaneous malfunction of several control features. Such an occurrence could conceivably result in a transient more severe than those transients analyzed as anticipated operational occurrences. A second concern is for a postulated accident to cause control system failures which could make the accident more severe than analyzed. Accidents could conceivably cause control system failures by creating a harsh environment in the area of the control equipment or by physically damaging the control equipment. It is generally believed by the staff that such control system failures would not lead to serious events or result in conditions that safety systems cannot safely handle. Systematic evaluations have not been rigorously performed to verify this belief. The potential for an accident that could affect a particular control system, and effects of the control system failures, may differ from plant to plant. Therefore, it is not possible to develop generic answers to these concerns, but rather plant-specific evaluations are required. The purpose of this unresolved safety issue is to define generic criteria that will be used for plant-specific evaluations.
The Waterford 3 control and safety systems have been designed with the goal of ensuring that control system failures will not prevent automatic or manual initiation and operation of any safety system equipment required to trip the plant or to maintain the plant in a safe shutdown condition following any C-17
 
11 anticipated operational occurrence 11 or 11 accident. 1 1 This has been accomplished by either providing independence between safety and nonsafety systems or providing isolating devices between safety and nonsafety systems. These devices preclude the propagation of nonsafety system equipment faults to the protection system. This ensures that operation of the safety system equipment is not impaired.
A systematic evaluation of the control system design, as contemplated for this unresolved safety issue, has not been performed to determine whether postulated accidents could cause significant control system failures which would make the accident consequences more severe than presently analyzed. However, a wide range of bounding transients and accidents is presently analyzed to assure that the postulated events such as steam generator overfill and overcooling events would be adequately mitigated by the safety systems. In addition, systematic reviews of safety systems have been performed with the goal of ensuring that control system failures (single or multiple) will not defeat safety system action.
Based on the above, we have concluded that there is reasonable assurance that the Waterford 3 plant can be operated prior to the ultimate resolution of this generic issue without endangering the health and safety of the public.
A-48 Hydrogen Control Measures and Effects of Hydrogen Burns on Safety Equipment: Following a loss-of-coolant accident in a light water reactor plant, combustible gases, principally hydrogen, may accumulate inside the primary reactor containment as a result of: (1) metal-water reaction involving the fuel element cladding; (2) the radiolytic decomposition of the water in the reactor core and the containment sump; (3) the corrosion of certain con struction materials by the spray solution; and (4) any synergistic chemical, thermal, and radiolytic effects of postaccident environmental conditions on containment protective coating systems and electric cable insulation.
Because of the potential for significant hydrogen generation as the result of an accident, 10 CFR Section 50.44, 11 Standards for Combustible Gas Control System in Light Water Cooled Power Reactors 11 and the GDC 41, 1 1 Containment Atmosphere Cleanup 11 in Appendix A to 10 CFR Part 50 require that systems be provided to control hydrogen concentrations in the containment atmosphere following a postulated accident to ensure that containment integrity is maintained.
10 CFR Section 50.44 requires that the combustible gas control system provided be capable of handling the hydrogen generated as a result of degradation of the emergency core cooling system such that the hydrogen release is five times the amount calculated in demonstrating compliance with 10 CFR Section 50.46 or the amount corresponding to reaction of the cladding to a depth of 0.00023 in., whichever amount is greater.
The accident at TMI-2 on March 28, 1979 resulted in hydrogen generation well in excess of the amounts specified in 10 CFR Section 50.44. As a result of this knowledge it became apparent to NRC that specific design measures are needed for handling larger hydrogen releases, particularly for smaller low pressure containments. As a result, the Commission determined that a rulemaking proceeding should be undertaken to define the manner and extent to which hydrogen evolution and other effects of a degraded core need to be taken into C-18
 
account in plant design. An advance notice of this rulemaking proceeding on degraded core issues was published in the Federal Register on October 2, 1980.
Recognizing that a number of years may be required to complete this rulemaking proceeding, a set of short-term or interim actions relative to hydrogen control requirements were developed and implemented. These interim measures were described in a second October 2, 1980 Federal Register notice. For plants with large dry containments such as Waterford 3, no near-term mitigation measures are required by the interim rule.
The Waterford 3 plant has about 3 million ft3 of net free volume. Assuming 30 to 50% metal-water reaction in the core, the resulting uniformly mixed concen tration of hydrogen in the containment will range from 6 to 10%. This is well below the concentrations for detonation and even below the limits for combustion with expected steam concentrations in the containment atmosphere following a LOCA.
Design pressure of the Waterford 3 containment is 44 psig. Analyses performed on the Zion and Indian Point plants show that the failure pressures are greater than twice their design pressures. The staff believes, therefore, that the failure pressure of the Waterford 3 containment is considerably greater than the design pressure.
If a substantial amount of metal-water reaction were to occur shortly following onset of a large LOCA and while the containment is still near its peak pressure, the pressure increase caused by the noncondensible hydrogen gas and its associated exothermic formation energy will be substantially less than the failure pressure.
If the metal-water reaction were to occur well after onset of the large LOCA, the containment heat removal system would have condensed much of the steam in the containment and reduced the containment pressure. This would provide a substantial margin for accommodating hydrogen generated by the metal-water reaction.
In addition, the "Short Term Lessons Learned11 from the TMI-2 accident have been implemented at the Waterford 3 plant. This action will reduce the likeli hood of accidents that could lead to substantial amounts of metal-water reaction.
Accordingly, pending resolution of this unresolved safety issue and the rule making proceeding on hydrogen generation, we have concluded that the Waterford 3 plant can be operated without undue risk to the health and safety of the public.
C-19
 
C. REFERENCES*
American Society of Testing Materials specifications:
ASTM A36-70a ASTM A522-70a Atomic Safety and Licensing Board, NRC:
ALAB-444, November 23, 1977 ALAB-491 ALAB-603 Branch Technical Positions:
BTP 5-2 BTP RSB 5-2 Code of Federal Regulations:
10  CFR Part 50, Appendix H 10  CFR  Section 50.35(a) 10  CFR  Section 50.44 10  CFR  Section 50.46 General Design Criterion:
GDC 41 in Appendix A to 10 CFR Part 50 Letters:
Leeter from NRC to Congress, dated December 30, 1977.
Letter from NRC to all applicants and licensees, dated May 19 (20), 1980.
Letter from D. Eisenhut 1 NRC, to LP&L, dated February 25, 1981.
Regulatory Guides:
RG 1. 79 RG 1.82 Standard Review Plan:
SRP 5.47 USNRC Reports:
NUREG-75/087 NUREG-0224 NUREG-0410 NUREG-0460 NUREG-0510 NUREG-0577 C-20
 
C. REFERENCES (Continued)*
USNRC Reports: (Continued)
NUREG-0582 NUREG-0588 NUREG-0606 NUREG-0609 NUREG-0612 NUREG-0649 NUREG-0660 NUREG-0705 NUREG/CR-0660
*See Appendix B, Bibliography, for complete citations and availability statements.
c-21
 
APPENDIX D Letter from Lawrence Livermore Laboratory D-1
 
LA\iVRENCE LiVERMORE L.A.BORAiORY NUCLEAR SYSTEMS SAFETY PROGRAM EG-81-17                            May 5, 1981 Dr. Robert E. Jackson, Chief Geosciences Branch Division of Engineering
: u. S. Nuclear Regulatory Commission Washington, D. C. 20555
 
==SUBJECT:==
LLNL Technical Assistance to the Division of Engineering, NRR, NRC, "Geoscience Case Reviews III" (FIN A0406)
 
==Dear Dr. Jackson:==
 
In accordance with your request, we are forwarding ten copies of our report on the site seisrnicity of the Waterford Stearn Electric Station, Unit 3, near Taft, Louisiana.
If we may be of any further assistance to you, please let us know.
Sincerely yours, fifA' Don L. Bernreuter Principal Co-Investigator Dae H. Chung Principal Co-Investigator DLB/DHC/ca
 
==Enclosure:==
Report {10)
D-3
 
REPORT ON THE SITE SEISMICITY FOR THE WATERFORD STEAM ELECTRIC STATION, UNIT 3 (Taft, Louisiana)
(Waterford-3 Site)
At the request of the Geoscience Branch of the Division of Engineering, the U.S. Nuclear Regulatory Commission, the Lawrence Livermore National Labortory (LLNL) has evaluated the seismological aspects of the Waterford-3 site. This review has been conducted in accordance with NRC Standard Review Plans (SRP) Sections 2.5.1 and 2.5.2. As in the Construction Permit Safety Evaluation Report (USNRC, 1973), we have followed the tectonic province approach to determine the vibratory ground motion corresponding to the Safe Shutdown Earthquake (SSE). This review indicates that there is no new information available to change the conclusions in the CP Safety Evaluation Report (CP-SER) regarding the seismic design spectra. We find that 0.10g and 0.05g are adequate to represent ground motion for the SSE and the Operating Basis Earthquake (OBE), respectively.
King (1969) in his discussion of the tectonic map of North America defines the Atlantic and Gulf Coastal Plains as platform deposits (Mesozoic and younger) that were laid over the deformed Paleozoic and older rocks of the Appalachian and Ouachita foldbelts. The platform deposits thicken and slope seaward from the exposed parts of these foldbelts, the basement decending beneath them. The continental shelves which border these coastal plains are their submerged extensions.
The site is within the Gulf Costal Plain Tectonic Province. The Gulf Coastal Plain has been divided into a number of subprovinces. During the CP review it was determined that the site is located in the Mississippi Deltaic Plain of the East Gulf Costal Plain and that the site is situated on the north flank of the Gulf Coast Geosyncline within this tectonic province. The plant area is underlained by more than 30,000 ft. of unconsolidated to partly indurated sediments that range in age from Jurassic (about 180 MYBP) to Holocene {about 1.5 MYBP).
The Gulf Coastal Plain is a broad sedimentary basin with east-west f :.ho11+
tronrli nn
-* _.,_."::f "Utrrnn
                          \J,.., hanrlcc L.I' 1,,..,.., .
Tho n11t-r- ... nncc VU""''-"''  Vf"'-1  I
:.nno
                                                                            ... \.411 
                                                                                        ;n jjl
::ino f"..,nm I t UJII r.,.,..,,+.,,,...e,..,.,c-
                                                                                                              \.,,I l.,Q\..,  uu..;,  \U.
LI UI.. 1 lt; MYBP), along the northern boundary, to recent Quaternary (less than 0.01 MYBP)
            'loJ "'"""''                                                                  \,J..._
near the Gulf. Within these east-west trends the type and position of the earth's crust has resulted in distinct bands of similar sediment thickness.
The northern portion of this Province is characterized by continental crust with varying thickness which was partly controlled by late Triassic {about 225 MYBP) block faulting.
D-4
 
A hinge line, partly marked by faulting which terminated in the Tertiary (about 2 MYBP), separates the Gulf Coastal Plain from the Paleozoic (about 270 to 600 MYBP) Ouachita deformed crustal province. The Ouachita deformed crustal province borders the Precambrian craton which is broken by the New Madrid faulted zone in the area of the Mississippi Embayment north of Memphis, Tennessee. Faults in this system are believed to be related to present earthquake activity in this region (Zoback et al., 1980). The closest approach of the New Madrid faulted zone to the site is about 340 miles.
Numerous geologic structures, however, occur in the Gulf Coastal Plain in Louisiana. Essentially all of these structures appear to be growth structures; i.e., structures related more to sedimentation processes than to tectonic movements in the basement rocks. Most of the structures appear to be related to such phenomena as: (1) compaction due to the gradual and progressive accumulation of sediment in the sinking basins; (2) differential movement associated with the formation and growth of salt structures in the area, chiefly as domes and ridges; and (3) subsidence within the basin due to the withdrawal of materials such as oil, gas, water, salt and sulfur from the sediments and sedimentary rocks.
Many growth faults which occurred during Miocene (22 to 5 MYBP) are buried beneath the surface in the Gulf geosyncline south of the Cretaceous reef trend. Growth faults of the Grand Chenier system in the site and surrounding area are very old and these faults are non-seismic. The latest movements along the youngest fault of this Grand Chenier system were more than five and half million years ago. The longest fault system in the site area is the Baton Rouge fault zone. The Baton Rouge fault zone is an east-trending, discontinuous and, in part, an echelon zone of faulting that extends across Louisiana for more than 150 miles. The closest approach of this fault zone to the site is approximately 30 miles to the north. Vertical displacements of the ground surface along the fault of as much as 20 feet are represented by scarps in the upper Pleistocene sediments. Subsurface data indicate that the fault has been in existence for several tens of millions of years; vertical displacements ranging from 200 to more than 400 feet have been measured across the fault at depth. Historic movement of the fault is evidenced by the records of precise leveling made across the structure, and by the cracking and displacement of houses and other man-made structures that have been built across the fault in Baton Rouge and its environs.
The location of the fault, the type of movement that appears to be going on, and the apparent lack of seismicity along the fault suggest that much of the movement may be due to slow, progressive creep, and that the fault zone owes its existence and its movement principally to its location along a "hinge line. 11 This hinge line is a zone that parallels the axis of the Gulf Coast geosyncline and separates an area of higher, more stable land to the north from an area of depression and accumulation of sediment in the geosynclinal basin to the south. Slow movement along the fault, comparable to that going on today, will probably continue during the lifetime of the proposed plant.
0-5
 
For the purposes of establishing the Safe Shutdown Earthquake (SSE) for the Waterford-3 site, we recognize that different regions of this large geologic province exhibit vastly different levels of seismicity. In particular to arrive at the appropriate choice of the SSE for the Waterford 3-site, we recognize three areas of seismicity within or intersecting this large tectonic province: (1) the Mississippi Embayment (New Madrid) earthquake zone, (2) the Ouachita-Wichita belt of seismicity zone, and (3) seismic activities in the remainder of the Gulf Coastal Plain Tectonic Province. Because of distance from the site, earthquake events under (3) are of particular interest.
Because King's broad definition of the Gulf Coastal Plains province includes the very active Mississippi Embayment Earthquake Zone, it is necessary to define its closest approach to the site. This boundary was established at the Monroe Uplift in the CP Safety Evaluation Report for the Grand Gulf site and the closest approach of earthquakes similar to the 1811-12 series is considered to be near Memphis, Tennessee, over 400 miles from the site. Within the remainder of the Gulf Coastal Plains (the region between west Florida and where the Gulf Coastal Plain is narrowed and partly interrupted by the outer folds of the Cordillera in Mexico) there is very little seismic activity.      Few small earthquakes have been recorded and none larger than MMVII have been noted. Any large earthquakes (MMVIII or greater) located in the Gulf Coast province would have been recorded in New Orleans and other settlements. In fact, it is unlikely that any typical MMVII event would have escaped detection, because they are felt over a large area. Strictly speaking, intensity is a measure of damage at*a place and not of the energy (magnitude) of the earthquake, although correlations have been made between earthquake magnitude and epicentral intensity. Generally the correlation is good when applied to a limited region. However, earthquakes, though of small magnitude, may cause higher intensities over a limited area than would be indicated by their energy, because of very shallow focal depths or proximity to population centers.
Only during the last 10 to 15 years have enough instruments been available to locate smaller earthquakes in the Gulf of Mexico. Few earthquakes have occurred during this time in the Gulf and none larger than magnitude 4.8 (which corresponds to about a typical MMVI). If much larger earthquakes had occurred earlier they should have been felt on the land and recorded on the few seismographs available. No such occurrences are noted in the historical record.
There have been 13 historic seismic events with epicenters located within the Gulf Coast Seismic Zone. Of these, six events have occurred in the Province within about 200 miles of the Waterford 3 site.
These six events include: (1) an epicentral intensity of nearly VI MM event which occurred on October 19, 1930 at Donaldsonville, Louisiana, (2) an intensity V MM event which occurred on February 1, 1955 at Gulfport, Mississippi, (3) an intensity V MM event which occurred on November 19, 1958 D-6
 
at Baton Rouge, Louisiana, (4) a Gulf of Mexico event with a recorded magnitude of 4.8 which occurred o November 5, 1963 on the Texas-Louisiana continental slope, (5) an event with a recorded magnitude of 2.9 which occurred on September 9, 1975 in northern Mississippi, and (6) an event with a recorded magnitude of 3.0 which occurred on December 10, 1974 in southern Alabama.
The largest historical event is the Donaldsonville earthquake of October 19, 1930, with VI MM. Nuttli and Brill (1981) estimated the magnitude of this earthquake to be mb = 4.2. Donaldsonville is located at about 32 miles west-northwest of the Waterford-3 site. In the CP review, it was concluded that the site intensity would not be higher than VI MM and that the SSE acceleration o 0.10g proposed for the site. In the present review, we concur with this conclusion and believe the proposed SSE acceleration of 0.10g for the site is adequately conservative.
The Gulf of Mexico event of November 5, 1963 has the largest listed magnitude (mb = 4.8) for earthquakes within 200 miles of the site. See Fig.
2.5-42 of the Waterford-3 FSAR. No seismological information, other than the magnitude, is available to us. On the basis of our data base on the central United States, we estimate the site specific ground motion from this Gulf of Mexico earthquake\event to be less than O.Olg for the peak horizontal acceleration.
In addition to the six seismic events which occurred within about 200 miles of the site, seven other events with epicentral intensities IV-V MM or greater have been recorded in the Gulf Coastal Plains. Of these seven events, six had epicentral intensities of V MM. One earthquake within this province had an epicentral intensity VII MM. This earthquake was the Rusk (Texas) 11 11 event that occurred on January 8, 1891 (See Milne, 1911; Coffman and Von Hake, 1973). This earthquake is not considered typical of the province since its felt area was extremely small as compared with lesser intensity earthquakes characteristic of the region.
The January 8, 1891 Rusk, Texas, earthquake is reported by some sources as an MM intensity VII (Coffman and Von Hake, 1973, p. 39). Although it apparently caused MM VII damage over a small area, the earthquake was only reported at Rusk, Texas. Typical ty, a MM intensity VII earthquake is felt over a wide area. For example, the 1930 Donaldsonville, Louisiana, MM intensity VI, mb=4.2 earthquake was felt over an area of 18,500 square miles. Assessment of the brief description of the damage from the Rusk earthquake reported in the Dallas, Texas, newspaper is difficult because the earthquake was accompanied by violent weather conditions. It is difficult to distinguish the earthquake damage from the storm damage. The intensity scale is not precise and must be carefully interpreted. Only chimney damage was reported.
Nuttli and Brill (1981) interpret earthquakes with relatively high epicentral intensity and small felt areas as being very small magnitude shallow events occurring in the upper few kilometers of the crust. The Rusk D-7
 
earthquake was evaluated in detail in the Allens Creek CP-SER (1974) where the conc1usion was reached that the Rusk event should not be considered as a true
,..,., intensity VII, but as a very shallow, small earthquake of mb=3.8 (according to Nuttli and Brill, 1981). We concur with this conclusion.
Following the guidelines provided in Appendix A of 10 CFR Part 100, we have detennined SSE for the Waterford-3 site. The proposed SSE acceleration level of 0.10g is a conservative representation of the safe shutdown earthquake and it corresponds approximately to a MM intensity VI occurring near the Waterford-3 site using the Trifunac-Brady relationship. If we assume an event similar to the Donaldsonville intensity VI MM earthquake occurs in the general vicinity of the site, the Applicant 1 s proposed SSE acceleration level of 0.10g would still be conservative.
The Applicant has proposed 0.05g for the acceleration level corres ponding to the operating basis earthquake. The design vibratory ground acceleration for OBE is taken to one-half the design vibratory ground acceleration for SSE, and this is consistent with Appendix A to 10 CFR 100.
Considering the low seismicity of the Gulf Coastal Plain Tectonic Province, we find that the proposed acceleration value for OBE is adequately conservative for the Waterford-3 site.
References Cited:
J.L. Coffman and C.A. van Hake (1973), Earthquake History of the United States, NOAA Publication 41-1, U.S. Department of Commerce, Washington, D.C.
P.B. King {1969), The Tectonics of North America - A Discussion to Accompany the Tectonic Map of North America Scale 1:500,000, Geological Survey Prof.
Paper G28, U.S. Department of Interior, Washington, D.C.
J. Milne (1911), Catalogue of Destructive Earthquakes, British Assoc. for the Adv. Sci., Appen1dx I, pp. 649-740.
O.W. Nutt1i and K.G. Brill, Jr. (1981), Earthquake Source Zones in the Central United States Determined from Historical Seismicity, Preprint from Saint Louis University.
M.D. Zoback, R.M. Hamilton, A.J. Crone, D.P. Russ, f.A. McKeown, and S.R.
Brockman, Recurrent Intraplate Tectonism in the New Madrid Seismic Zone, Science, 209, pp. 971-976 (1980).
U.S. Nuclear Regulatory Commission (1974), Safety Evaluation of the A11ens Creek Nuclear Power Generating Station, Units 1 and 2, Docket Nos. 50-446 and 50-467.
0-8
 
APPENDIX E EVALUATION OF LOUISIANA POWER ANO LIGHT COMPANY'S PRELIMINARY CONTROL ROOM ASSESSMENT The NRC perfonied an early review of LP&L's preliminary control ro011 assess11ent (PCRA) without the usual 5-day onsite design/audit review. Construction of the Waterford 3 control rOOII was not C01l1)1ete enough to permit an effective 5-day onsite review.
E.l HUMAN FACTORS DEFICIENCIES IDENTIFIED The following sections describe htaan engineering discrepancies identified by LP&l, corrective actions proposed for SOftle discrepancies, and our coaaents on these discrepancies.
LP&L identified SOiie discrepancies for which it proposed corrective actions.
Other discrepancies were identified by LP&L, and no corrective actions were proposed in the PCRA. The staff has identified discrepancies during its review of the PCRA.
This section presents those discrepancies considered by the staff to require corrective actions before loading fuel. However, the applicant has not c011-itted itself to aaking corrective actions in the PCRA. The staff plans to address and schedule resolution of discrepancies observed in this early review in a suppleaental safety evaluation.
E.1.1 Main Control Board Anthrop011etric Design The LP&L reviewers used soae of the anthropometric criteria given in HUREG-1580 to evaluate the design of the 11ain control boards. They concluded that opera tors would have difficulty in that none of the control boards or controls and displays are within the rec01111ended anthropo111etric envelopes for height, depth, or viewing distance; soae of the convexed aeters are located so high as to cause excessive parallax error; the annunciator panel positions are very high and lettering is too saa11 for easy reading; and plans do exist for adding two half annunciator panels above the present positions. The cathode-ray tube (CRT) control keyboards (several) are placed so low as to necessitate bending and reaching for 110st operators.
In sry, even an 11 average operator" would find soae routine operations tir ing and uncoafortable. The evaluation concluded that the average operator could, in reality, aanage to operate the controls and perfora ..aintenance on the displays/recorders of the existing board configuration by leaning over the boards.
The staff believes that the applicant should address the problea of control board anthrop011etrics by eaking iaproveaents that w111 accoaodate a greater spectrum of the reactor operator population.
E-1
 
E.1.2 Operator Console Design The operator console is at a sitdown console in the center of the main control area. Final configuration of the console is not complete. However, in its present configuration, access around the console to the control boards is not convenient. A proposed enlarged configuration will create additional obstruc tions. The applicant is considering a central access passage. The applicant had not evaluated whether the CRT turrets on the console would obstruct the operator's view of the main control panels. LP&L plans to perform a thorough investigation of the console's use as part of the control room review being done to satisfy NUREG-0700. The staff agrees with the applicant 1 s proposed plan to review its console in light of NUREG-0700.
E.1.3 Documentation/Procedures Storage and Workspace At present, the only control room storage facilities for procedures and other documents is a two-drawer file cabinet in the operator console. This limited space will be inadequate for the substantial documentation needed to support normal and emergency operations, A work surface is also needed where material can be reviewed by several persons at once away from the controls on the operators console. LP&L plans to investi gate the amount of work space required during a task analysis program and will provide the work space necessary based on the results of that investigation.
E.1.4 Glare The lighting system was not in final configuration during the preliminary assess ment. The LP&L reviewers observed that the lighting levels were excessively high, which contributed to significant glare problems on meter faces, recorder faces, and CRTs. It was also observed that the supervisor's office windows will provide a source of reflection and glare that will interfere with CRT viewing. LP&L plans to review the glare problems on completing installation of the control room lighting and completing construction of the supervisor's office. NRC concurs with the applicant's proposal to reduce the glare problems by employing good lighting features to achieve lighting levels necessary to accomplish work required in given locations as suggested in NUREG-0700, Section 6.2.
E.1.5 Communications Communications between the control room and peripheral areas do not appear to be adequate. Specifically mentioned for improvement are communications with the computer room and the kitchen/lavatory facilities. LP&L states that this concern will be addressed through staffing and administrative procedures. LP&l believes that the private page system line and commercial telephone presently installed in the computer room will provide adequate communication with the control room. NRC believes the applicant should also use the guidance on communications as presented in NUREG-0700, Section 6.1.5.
E.1.6 Annunciators The annunciator legends are not engraved with lettering large enough to be read from the associated response controls. LP&L estimated that an operator standing E-2
 
at the edge of the benchboard would be able to resolve details on the annunci ators at a distance of no more than 5 to 6 ft laterally. The annunciator legends will not be readable from behind the operator console where an operator spends much of his time. This will necessitate the operator moving up to the control board for every alarm unless an additional operator is controlling the main pane 1.
The annunciator audible alarms are automatically terminated after 3 to 5 sec.
The Waterford 3 annunciator system has a considerably greater number of windows (tiles) than most plants. This probably necessitates the use of the smaller windows. LP&L should consider reducing the number of windows and increasing their size.
The legends were difficult to read at the 11 return to normal11 flash rate of 1 flash/sec.
Maintenance of the annunciators will be impossible without standing on the benchboard or using a special ladder designed to bring the operator to the correct height and in from the edge of the benchboard. The annunciator window assemblies are difficult to remove and are loose when reinstalled. LP&L plans to investigate problems with annunciators. The staff recommends that NUREG-0700 be consulted to evaluate the annunciator system for additional discrepancies and other human factors guidance on annunciators, E. 1. 7 Controls Toggle switches on a vertical panel (CP-13) in a high traffic area are subject to inadvertent actuation.
The excessive and varied use of safeguards against inadvertent actuation (three different types of key switches, 11 think buttons11 dual actuation, etc.) may cause problems when quick operator response is required under stress. The basic switch and indicating light assembly (a microswitch model CMC device) used in the control room have several human factors discrepancies associated with it:
(1)    Excessive force is required to actuate some of the switch knobs. The spring loaded control knobs were noted as especially difficult to actuate.
(2) Thern are too many conventions for switch positions, labeling, and color coding. These varied conventions cause much operator confusion because of the widespread use of the switch in the control room. An operator must examine nearly identical switches to determine the method of operation, the meaning of the integral indicator lights, and the available position 11 choices of each. Since the fixed position momentary contact and the 11 hold (throttle) controls are not differentiated, examination will not always be sufficient to determine the required method of operation.
The operators do not understand the logic and arrangement for storing and using keys for the keylock switches. Administrative controls and training should be upgraded to ensure proper utilization of key/ switches during stressful events.
E-3
 
E.1.8 Display The displays used in the control room had the following general and specific prob1ell!s:
(1) Glare and poor visibility were reported by the operators.
(2) The dual-scale Meters present several proble.s: Some dual meters have scales that are not identical and can confuse the operators; the relation ships of the dual-scale meter labels to the scales is unclear; and the scales are sometimes obscured.
(3) Needed indications are not always provided in the appropriate panel area.
For exaniple, the startup rate is provided on the reactor protection panel only.
(4) ''Vertical<< orientation scales are sometimes used on horizontally placed meters.
(5) The scale graduations on some meters make interpolation difficult. It is often hard to d1ffrentiate between major and minor index marks.
E.1.9 Panel Layout There is a poor relationship between associated displays and controls. The panel ele,nents are grouped by system or plant function, but these groups contain both primary and secondary parameters clustered together. Mixed parameters are grouped together (i.e., flows, pressures, teaperatures, levels, concentra tions, etc.) without any easily noted distinctions between the displays. S0111e mirror-imaging of subgroups was found, and an apparent concern for "balance, symmetry, uniformity, and general good appearance" of ele111ents has enforced a disassociated control/display relationship on some panels. After cOIDJ)letion of task analysis, LP&l plans to address the issue of panel layout (i.e., dis play and device coordination) during an extensive demarcation and labeling1 effort scheduled to begin in June 1981. The staff believes the applicant s proposed approach to improve panel layouts will result in effective improvements.
E.1.10 Labeling The largest number of operator observations and connents concerned labeling.
LP&l plans an extensive demarcation and labeling effort to begin in June 1981.
NUREG-0700 should be consulted for information on proper label placeaent.
Some exa11ples of discrepancies are noted below: There is no hierarchical label ing scheae; there are any conflicting labeling conventions; many exceptions to these conventions are found; abbreviations are not standardized.
The operators also reported mislabeling, missing labels, switchable labels, inadequate labels, illegible labels, and confusing label arrangefflents.
In general, controls are labeled below the control switch, where the legend will be obscured while the control is beig operated.
E-4
 
Some control switches have two devices associated with them. These controls are labeled with the priury device label below the switch and the secondary device label engraved in the lower half of the control switch. This convention can lead to confusion.
The engraved switch faceplate labels are hard to read due to low contrast, glare, sa11 letter size, and the poor grouping of legends. Dual indication vertical meters are labeled on the bottom for the right scale marking, and on the top for the left scale marking.
E.1.11 Process COtRputer Integration The process computer input/output procedure and format adequacy could not be evaluated, due to lack of information. However, the systems descriptions pro vided indicate a poor integration of the computer with the control room opera tors. The computer hard copy printout devices are located outside of the main control area, behind panel CP-50. LP&L has established a program to integrate the plant computer and the safety parameter display system into the man- machine system of the control room.
The report also indicated that the operators may need to 11 bootstrap-start11 the computers when no other computer staff member is available. Operator training programs should emphasize bootstrap starts.
E.1.12 Recorders The recorders in the control room exhibit typical maintenance types of deficien cies. Incorrect scales and incompatible paper were sometimes installed.
The recorder windows are quite small. This presents problems when reading the trend tracings. LP&L plans to reevaluate recorder display requirements during the Task Analysis program performed to satisfy NUREG-0700.
E.2 IMPLEMENTATION OF HUMAN FACTORS IMPROVEMENTS Supplement B to LP&l 1 s PCRA documents changes that the applicant has already begun implementing.
The applicant has set up a new system known as Design Change Notification.
Changes ranging from the correction of vendor errors to complete rearrangement of operator control stations are being made using the Design Change Notification system as the vehicle for making such changes.
The photographs of controls and displays as shown in Supplement A to LP&L's PCRA present a variety of HEDs including demarcation, lighting, meter glare, control/ display relationships, environmental effects, poor hierarchial label ing practices, poor mimics, circuit breaker associations, indicators undiffer entiated frOffl pushbutton switches, and trend recorders with mixed modes.
The applicant has also presented a su!Mlary of future efforts to further the detailed evaluation of the contro1 room. These future efforts include estab lishing a multidiscipline team, performing task analyses, and considering operation of the unit both with and without the process computers. NRC believes these efforts conform with the approaches presented in NUREG-0700 and are acceptable to the staff.
E-5
 
The applicant's report presented an initial overview that attempts to cover a wide range of human factors concerns. The applicant's work to date reflects the appreciation and utilization of NUREG/CR-1580 and the existing human fac tors design guidelines (MIL-STD-14728). The applicant has documented that when ever discrepancies are discovered, they will delineate design solutions and develop a basis for evaluating their adequacy. As a basis for the review, the applicant has noted that, although historical documentation does not exist, it is apparent that many design tradeoffs and decisions were made, and that a high level of consistency and organization is reflected in much of the control board design.
During the applicant's review, many discrepancies were identified and documented in the report. The applicant did not document a commitment to correct them at this time. Additional assessment by both the engineering and operating staffs will be made before potential modifications will be proposed. NRC will require that the proposed modifications be documented for staff evaluation in accordance with licensing obligations.
Some environmental surveys, such as lighting and noise levels, could not be conducted at this time because of the stage of plant construction; however, the applicant 1 s human factors consultants have identified discrepancies that may require modification. The applicant proposes carpeting for the floors and wall treatment to reduce reflected noise and glare. NRC concurs with this proposal from the human factors point of view, so long as the materials used in the control room do not violate NRC fire protection requirements.
E-6
 
E. REFERENCES*
Department of Defense:
MIL-STD-1472B USNRC reports:
NUREG-0700 NUREG/CR-1580
*See Appendix 8, Bibliography, for complete citations and availability statements.
E-7
 
APPENDIX F ABBREVIATIONS ACCWS  - auxiliary component cooling water system ACFM    - actual cubic feet per minute ACRS    - Advisory Committee on Reactor Safeguards ADV    - atmospheric dump valve AFW    - auxiliary feedwater AFWS    - auxiliary feedwater system ALARA  - as low as reasonably achievable AN0-2  - Arkansas Nuclear One, Unit 2 ANSI    - American National Standards Institute ASB    - Auxiliary Systems Branch ASI    - axial shape index ASLB    - Atomic Safety and Licensing Board ASME    - American Society of Mechanical Engineers ANS    - American Nuclear Society ASOEA  - Assistant Secretary of the Office of Environmental Affairs ATWS    - anticipated transient without scram BIL    - basic impulse insulation level B&O    - Bulletins and Orders (Task Force)
BOL    - beginning of life BS      - Bachelor of Science degree B&W    - Babcock and Wilcox BWR    - boiling water rector BTP    - Branch Technical Position CACS    - containment air cooler system CAD    - containment atmosphere dilution CARS    - containment atmosphere release system CCAS    - containment cooling actuation signal ccs    - containment cooling system ccw    - component cooling water CD      - consolidated drained CE      - Combustion Engineering Inc.
CEA    - control element assembly CEADS  - control element assembly drive system CEDM    - controi eiement drive mechanism CEPADAS - Computerized Emergency Planning and Data Acquisition System CFR    - Code of Federal Regulations CESSAR  - Combustion Engineering Standard Safety Analysis Report CHF    - critical heat flux CGCS    - combstible gas control system CIAS    - containment isolation actuation signal CIS    - containment isolation signal COLSS  - core operating 1imit supervisory system CP      - construction permit CPCS    - core protection calculator system CPIS    - containment purge isolation signal CRD    - control rod drive CRT    - cathode-ray tube F-1
 
CSAS  - containment spray actuation system css    - containment spray system CVAS  - controlled ventilation area system eves    chemical and volume control system CVN    - Charpy V-notch cws    - circulating water system OBA    - design basis accident DE    - dose equivalent DEG    - double-ended guillotine DES    - double-ended slot DES    - Draft Environmental Statement DES/PD - double-ended slot at the pump discharge DNB    - departure from nucleate boiling ONBR  - departure from nucleate boiling ratio DOE    - Department of Energy EAB    - exclusion area boundary EAL    - emergency action level ECCS  - emergency core cooling system EFAS  - emergency feedwater actuation system EFW    - emergency feedwater EFS    - emergency feedwater system EHC    - electrohydraulic c.ontro1 EOC    - emergency operations center EOF    - emergency operations facility EOL    - end of 1 ife EPIP  - Emergency Plan Implementing Procedures EPZ    - emergency planning zone ERTS  - Earth Resources Techno 1 ogy Sate 11 i te ESF    - engineered safety feature ESFAS  - engineered safety feature actuation signal ESWS  - essential service water system FAA    Federal Aviation Administration FEMA  - Federal Emergency Management Agency FES    - Final Environmental Statement FHBVS  - fuel handling building ventilation system FHS    - fuel handling system FMEA  - failure modes and effects analysis FSAR  - Final Safety Analysis Report GAO    - General Accounting Office GDC    - General Design Criterion HAZ    - heat-affected zone HED    - human engineering discrepancy HELB  - high energy line break HEPA  - high-efficiency particulate air HFEB  - Human Factors [ngineering Branch HID    - high impact design HPCI  - high-pressure coolant injection HPSI  - high-pressure safety injection H&V    - heating and ventilating HVAC  - heating, ventilation, ana a!r conditioning I&C    - instrumentation and control ICC    - inadequate core cooling ICSB  - Instrumentation and Control Systems Branch F-2
 
IE    - Office of Inspection and Enforcement IEEE  - Institute of Electrical and Electronics Engineers INEL  - Idaho National Engineering Laboratories INPO  - Institute of Nuclear Power Operations ISEG  - independent safety engineering group
!SI  - inservice inspection LA18  - Louisiana State Highway 18 LCD  - limiting conditions of operation LER  - licensee event report LLL  - Lawrence Livermore Laboratory LNED  - Louisiana Nuclear Energy Division LOCA  - loss-of-coolant accident LOEP  - Louisiana Department of Public Safety, Office of Emergency Preparedness LOVS  - loss-of-voltage signal LPCI  - low-pressure coolant injection LPG  - liquified petro1eum gas LPZ  - low population zone LP&L  - Louisiana Power and Light Company LPSI  - low-pressure safety injection LPMS    loose parts monitoring system LTOP  - low temperature overpressure protection LWR  - light water reactor MCB  - main control board MCC  - motor control center MOS  - megawatt demand setter MEV  - million electron volt MFIV  - main feedwater isolation valve MM    - modified Mercalli MSIS  - main steam isolation signal MSIV  - main steam isolation valve MSL  - mean sea level MSLB  - main steam line break MSS  - Middle South Services MSSS  - main steam supply system MSU  - Middle South Utilities MT      magnetic particulate MTEB  - Materials Engineering Branch MVA  - million volt amp MWe    megawatts (electrical)
MWt  - megawatts (thermal)
MYBP  - million years before present NAWAS - National Alert Warning System NOE  - nondestructive examination NEMA  - National Electrical Manufacturers Association NEPA  - National Environmental Policy Act NFPA  - National Fire Protection Association NIS  - nuclear instrumentation system NNS  - non-nuclear safety NOAA  - National Oceanic and Atmospheric Administration F-3
 
NPIS      - nuclear plant island structures NPSH      - net positive suction head NRC      - U.S. Nuclear Regulatory Commission NRR      - Office of Nuclear Reactor Regulation NSRR      - nuclear safety research reactor NSSS      - nuclear steam supply system NWS      - National Weather Se,ice QBE      - operating basis earthquake OCR      - overconsolidation ratio OL        - operating license OMMS      - Operational Man-Machine Interface System ORNL      - Oak Ridge National Laboratory DSC      - operational support center PAGS      - Protective Action Guides PCB      - power circuit breaker PCI      - pellet/cladding interaction PCRA      - preliminary control room assessment PCS      - primary coolant system PD        - pump discharge PDF      - project design flood PLUME EPZ - plume EPZ = plume exposure pathway EPZ PMF      - probable maximum flood PMH      - probable maximum hurricane PMP      - probable maximum precipitation PORC      - Plant Operations Review Committee PORV      - power operated relief valve PPS      - plant protection system PSAR      - preliminary safety analysis report PWR      - pressurized water reactor QA        - quality assurance QAC      - Quality Assurance Criteria RAB      - reactor auxiliary building RAS      - recirculation actuation signal RCP      - reactor coolant pump RCPB      - reactor coolant pressure boundary RCS      - reactor coolant system RG        - Regulatory Guide RHR      - residual heat removal RMS      - radiation monitoring system RO        - reactor operator RPS      - reactor protection system RPV      - reactor pressure vessel RTS      - reactor trip system RWCUS    - reactor water cleanup system RWSP      - refueling water storage pool RWST      - refueling water storage tank SAB      - Safety Analysis Branch SAR      - safety analysis report SBVS      - shield building ventilation system SCA      - single-channel analyzer sec      - stress corrosion cracking SOC      - shutdown cooling SOCS      - shutdown cooling system F-4
 
SEL      - System Engineering Laboratoris SER      - safety evaluation report SGTR      - steam generator tube rupture SIAS      - safety injection actuation signal SIS      - safety injection system SLB      - steam line break SMSA      - standard metropolitan statistical area SONGS-2&3 - San Onofre Nuclear Generating Station, Units 2 and 3 SPDS      - safety parameter display system SPERT    - special power excursion reactor test SPT      - standard penetration test SQRT      - Seismic Qualification Review Team SRC      - Safety Review Committee SRO      - senior reactor operator SRP      - Standard Review Plan SSE      - safe shutdown earthquake STA      - shift technical advisor STP      - standard temperature and pressure STS      - Standard Technical Specifications SUPS      - static uninterruptible power supply SUT      - startup transformer TBD      - to be determined TLD      - thermoluminescent dosimeter TMI-2    - Three Mile Island Unit 2 TSC      - technical support center TSP      - trisodium phosphate UAT      - unit auxiliary transformer UHS      - ultimate heat sink USCG      - U.S. Coast Guard UT        - ultrasonic inspection UU        - unconsolidated-undrained VCT      - volume control tank WMS      - waste management system F-5
 
APPENDIX G GUIDELINES FOR DEMONSTRATION OF OPERABILITY OF PURGE AND VENT VALVES
 
GUIDELINES FOR DEMONSTRATION OF OPERABILITY OF PURGE AND VENT VALVES OPERABILITY In order to establish operability it must be shown that the valve actuator's torque capability has sufficient margin to overcome or resist the torques and/or forces (i.e., fluid dynamic, bearing, seating, friction) that resist closure when stroking from the initial open position to full seated (bubble tight) in the time limit specified. This should be predicted on the pressure(s) estab lished in the containment following a design basis LOCA. Considerations which should be addressed in assuring valve design adequacy include:
: 1. Valve closure rate versus time - i.e., constant rate or other.
: 2. Flow direction through valve; aP across valve.
: 3. Single valve closure (inside containment or outside containment valve) or simultaneous closure. Establish worst case.
: 4. Containment back pressure effect on closing torque margins of air operated valve which vent pilot air inside containment.
: 5. Adequacy of accumulator (when used) sizing and initial charge for valve closure requirements.
: 6. For valve operators using torque limiting devices - are the settings of the devices compatible with the torques required to operate the valve during the design basis condition.
: 7. The effect of the piping system (turns, branches) upstream and downstream of all valve installations.
: 8. The effect of butterfly valve disc and shaft orientation to the fluid mixture egressing from the containment.
DEMONSTRATION Demonstratio of the various aspects of operability of purge and vent valves may be by analysis, bench testing, insitu testing or a combination of these means.
Purge and vent valve structural elements (valve/actuator assembly) must be evaluated to have sufficient stress margins to withstand loads imposed while valve closes during a design basis accident. Torsional shear, shear, bending, tension and compression loads/stresses should be considered. Seismic loading should be addressed.
Once valve closure and structural integrity are assured by analysis, testing or a suitable combination, a determination of the sealing integrity after closure and long term exposure to the containment environment should be evaluated. Emphasis should be directed at the effect of radiation and of the containment spray chemical solutions on seal material. Other aspects such as the effect on sealing from outside ambient temperatures and debris should be considered.
G-1
 
The following considerations apply when testing is chosen as a means for demonstrating valve operability:
Bench Testing A. Bench testing can be used to demonstrate suitability of the in-service valve by reason of its tracibility in design to a test valve. The following factors should be considered when qualifying valves through bench testing.
: 1. Whether a valve was qualified by testing of an identical valve assembly or by extrapolation of data from a similarly designed valve.
: 2. Whether measures were taken to assure that piping upstream and down stream and valve orientation are simulated.
: 3. Whether the following load and environmental factors were considered
: a. Simulation of LOCA
: b. Seismic loading
: c. Temperature leak
: d. Radiation exposure
: e. Chemical exposure
: f. Debris B. Bench testing of installed valves to demonstrate the suitability of the specific valve to perform its required function during the postulated design basis accident is acceptable.
: 1. The factors listed in items A.2 and A.1 should be considered when taking this approach.
In-Situ Testing In-situ testing of purge and vent valves may be performed to confirm the suitability of the valve under actual conditfons. When performing such tests, the conditions (loading, environment) to whkh the valve(s) will be subjected during the test should simulate the design basis accident.
NOTE: Post test valve examination should be performed to establish structural integrity of the key valve/actuator components.
G-2
 
APPENOIX .H Principal Contributiors R. Kirkwood  - Mechanical engineering D. Terao        Mechanical engineering F. Rinadldi  - Structural engineering J. Kimball    - Seismology H. Lefevre    - Geology R. Gonzales  - Hydrology
: 0. Thompson  - Geophysical J. Schiffgens - Materials engineering F. Litton      Materials engineering J. Halapatz    Materials engineering B. Elliot      Materials engineering M. Bolotsky    Materials engineering M. Hum          Materials engineering D. Huang        Materials engineering
: 0. Smith        Materials .engineering J. Gleim      - Materials engfn.eerfng J. Spraul      Qua 1 ity *assurance .
W. Belke      - Quality assurance T. Y. Cheng  - Seismic .qual Hicatio.n M. Slosson    - Environmental *qualification F. Witt      - Chemical engineering P. Sears      - Chemical engineering B. Turovlin  - Chemical engineering K. Campe      - Siting ana]ysis M. Karlowicz  - Financial qua11fication I. Dinitz    - Indemniy re.qui.rements 0
J. Wermeil    - Auxi i ary systems.
J. Rosenthal  - Instrumentation and control It Giardina  - Power systems N. Trehan    - Power systellls C. Y. Liang  - Reactor systems M. Rubin      - Reactor systems J. Lewis      - Meterology J. Read      - Accident evaluation M. Thadani    - Accident evaluation J. Hayes      - Effluent treatment S. Block      - Radiological assessment Y. S. Huang  - Containment systems
: 0. Powers    - Core performance L. Kopp      - Core performance L. Phi1lip    - Core performance J. Holonich  - Core performance R. Benedict  - Licensee qualifications H-1
 
W. Long        Procedures and test review M. Goodman  - Procedures and test revh?w C. Anderson  - Generic issues D. Vito      - Technical specifications D. Parrotti  - Emergency planning C. Gaskin    - Security V. De- L iso - Ope_rator 1 icensing R. Ramirez  - Human factors issues
 
I NRC        FORM    335 U.S. NUCLEAR REGULATORY COM*
: 1. f1EPpRj NUMBER      (Assigned by    OD-Cl l'(LJIIBG-0787 (7 77)
BIBLIOGRAPHIC DATA SHeET flTLE ANO SUBTITLE (Add Volume No , ;f appropriate}
12 (Leave blank I Safety Evaluation Report Related to the Operat.ion of I
Waterford Steam Electric Station, Unit 3                                                    I '.5_  REC-,PlNT'S ACCESSION NO 7  AUTHOR\SJ                                                                                    5.' DATc REPORT COMPLETED -
MONTH                          I YEAR Julv                            1981
: 9. PERFORMING ORGANIZATION NAME ANO MAILING ADDRESS /Include Zip Code/                                  DATE REPORT ISSUED Office of Nuclear Reactor Regulation                                                                MONTH                          I YEAR u.s. Nuclear Regulatory Commission                                                                      Julv                            1981 Washington, D.C. 20555                                                                        6 (Leave blank) 8 /Leave blank) 12    SPONSORING ORGANIZATION NAME AND MAILING ADDRESS 10 PROJECT TASK/WORK UNIT NO.
(Include Zip Code!
Same as 9. above 11    CONTRACT NO.
TYPE OF REPORT                                                    I PERIOD COVERED 13                                                                                                    (lnclus1ve dares/
15    SUPPLEMENTARY NOTl=S                                                                      14. (Leave olank)
Docket No. 50-382
: 16. ABSTRACT (200 words or less; The Safety Evaluation Report for the application filed by lou.isiana Power & Light Company for a license to operate the Waterford Stearn Electric Station, Unit 3 (Docket No. 50-382),
located in St. Charles Parish, Louisiana has been prepared by the Office of Nuclear Reactor Regulation of the Nuclear Regulatory Commission. Subject to favorable resolution of the items discussed in the Safety Evaluation Report, the staff concludes that the plant can be operated by the Louisiana Power & Light Company without endangering the health and safety of the public.
I i ; 7 t<EY WORDS Ai'\JD :JOCU',1E',T A'cALYSIS                              1 72. DESCRIPTORS i
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Revision as of 01:40, 17 January 2022

NUREG-0787, Safety Evaluation Report Related to the Operation of Waterford Steam Electric Station, Unit 3 (Redacted)
ML21224A116
Person / Time
Site: Waterford Entergy icon.png
Issue date: 07/31/1981
From:
NRC/NRR/DORL/LPL4
To:
Klett A, NRR/DORL/LPL4
References
ML20009E071 NUDOCS 8107270044, NUREG-0787
Download: ML21224A116 (621)
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