ML18151A183

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Licensing Rept for Operation W/Core Rated Power of 2,546 Mwt Surry Power Station Units 1 & 2.
ML18151A183
Person / Time
Site: Surry  Dominion icon.png
Issue date: 08/31/1994
From:
VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:
Shared Package
ML18151A184 List:
References
NUDOCS 9409080261
Download: ML18151A183 (343)
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Text

  • LICENSING REPORT FOR OPERATION WITH A CORE RATED POWER OF 2546 MWT SURRY POWER STATION UNITS 1 AND 2 VIRGINIA POWER

. AUGUST, 1994 9409080261 940830 PDR ADOCK 05000280 P PDR J

TABLE OF CONTENTS Section Description Paz:e No.

1.0 Program Description 1.1 Definition of Goals . . . . . . . . ; . . . . . . . . . . . . . . . . . . . . 16 1.2 Applicable Design Criteria . . . . . . . . . . . . . . . . . . . . . . . . . 16 1.3 Scope Summary . . . . . . . . . . . . . . . . . . . . . . . . . *. . . . . . 17 2.0 NSSS Accident Analysis Evaluation Description 2.1 Operating Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 2.2 Key Analysis Parameter Ranges* . . . . . . . . . . . . . . . . . . . . . 23 2.3 Evaluation Approach & Scope Summary . . . . . . . . . . . . . . . . 25 3.0 Safety Evaluations 3.1 Nuclear Design and Core Thermal-Hydraulic Design . . . . . . . . . 27 3.1.1 Nuclear Core Design Evaluation . . . . . . . . . . . . . . . . . 27 3.1.2 Core Thermal-Hydraulic Design Evaluation . . . . . . . . . . 29 3.2 NSSS Safety Analysis Evaluation Methodology . . . . . . . . . . . . 31 3 .2.1 Overall Evaluation Approach . . . . . . . . . . . . . . . . . . . 31 3.2.2 Analytical Methods *. . . . . . . . . . . . . . . . . . . . . . . . 32 3.2.3 NSSS Event Categomation by Uprate Effect . . . . . . . . . 34 3.3 Evaluation of Unaffected Events . . . . . . . . . . . . . . . . . . . . . 38 3.3.1 Malpositioning of Part-Length Control Rod Assemblies . . . 38 3.3.2 Startup of an Inactive Reactor Coolant Loop . . . . . . . . . 38 3.3.3 Likelihood of Turbine-Generator Unit Overspeed . . . . . . 38 3 .4 Evaluation of Validated Events . . . . . . . . . . . . . . . . . . . . . 39 3.4.1 Rupture of Main Steam Pipe . . . . . . . . . . . . . . . . . . . 39 3.4.2 Excessive Heat Removal Due to Feedwater System . . . . . 44 Malfunctions 3.4.3 Loss of Normal Feedwater . . . . . . . . . . . . . . . . . . . . 46 3 .4 .4 Rupture of a Control Rod Drive Mechanism Housing . . . . 47

(Control Rod Assembly Ejection) 3.4.5 Small Break Loss of Coolant Accident . . . . . . . . . . . . . 48 3.4.6 Large Break Loss of Coolant Accident . . . . . . . . . . . . . 50 3.5 Evaluation of
Reanalyzed Events . . . . . . . . . . . . . . . . . . . . 53 3.5.1 Uncontrolled Control-Rod Assembly Withdrawal . . . . . . 53 from a Subcritical Condition 3.5.2 Uncontrolled Control-'Rod Assembly Withdrawal . . . . . . . 64 at Power 3.5.3 Control-Rod Assembly Drop/Misalignment . . . . . . . . . . 79 2

3.5.4 Chemical and Volume Control System Malfunction . . . . . 81 3.5.5 Excessive Load Increase Incident . . . . . . . . . . . . . . . . 87 3.5.6 Loss of Reactor Coolant Flow . . . . . . . . . . . . . . . . . . 97 3.5.7 Locked Rotor Incident . . . . . . . . . . . . . . . . . . . . . . 115 3.5.8 Loss of External Electrical Load . . . . . . . . . . . . . . . . 126 3.5.9 Steam Generator Tube Rupture . . . . . . . . . . . . . . . . 143 3.6 Containment Integrity & Safeguards Equipment Evaluations . . . 155 3.6.1 LOCA Mass and Energy Release Analysis . . . . . . . . . . 155 3.6.2 LOCA Containment Response Analysis . . . . . . . . . . . 201 3.6.3 Equipment Qualification Inside & Outside Containment . . 230

3. 7 NSSS Accident Radiological Consequences Analyses . . . . . . . . 232 3.7.1 General Discussion & Analysis Approach . . . . . . . . . . 232 3.7.2 Evaluation of Reanalyzed Events . . . . . . . . . . . . . . . 233 3.7.3 Summary of Dose Analysis Results . . . . . . . . . . . . . . 277 3; 8 Additional Design Basis & Programmatic Evaluations . . . . . . . 283 3.8.1 Limiting PSV Inlet Conditions During Feedline Break . . 283 3.8.2 Analyses For Compliance With 10CFR50,Appendix R . . 285 3.8.3 Analyses For Anticipated Transient Without Scram . . . . 286 3.8.4 Shutdown Operations . . . . . . . . . . . . . . . . . . . . . . 287 3.8.5 Emergency Condensate Storage Tank Sizing . . . . . . . . 288 Evaluation 3.8.6 RWST Boron Concentration Requirements . . . . . . . . . 289 3.8.7 Analyses for Compliance with Station Blackout Rule, 10CRF50.63 ... ~ . . . . . . . . . . . . . . 290
4. 0 Systems, Structures and Components Evaluation 4.1 . RCS Component and Fluid Systems Evaluation . . . . . . . . . . . 291 4.1.1 Reactor Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . 291 4.1.2 Reactor Vessel Internals . . . . . . . . . . . . . . . . . . . . . 294 4.1.3 Control Rod Drive Mechanism . . . . . . . . . . . . . . . . * . 294 4.1.4 Reactor Coolant Pumps . . . . . . . . . . . . . . . . . . . . . 294 4.1.5 Steam Generators . . . . . . . . . . . . . . . . . . . . . . . . . 294 4.1.6 Pressurizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296 4.1. 7 Piping and Supports . . . . . . . . . . . . . . . . . . . . . . . 297

.4.1.8 Auxiliary Valves and Pumps . . . . . . . . . . . . . . . . . . 297 4.1.9 Auxiliary Heat Exchangers and Tanks . . . . . . . . . . . . 298 4.1.10 Chemical and Volume Control System . . . . . . . . . . . . 299 4.1.11 Residual Heat Removal and Safety Injection Systems . . . 299 4.1.12 Aux Feedwater System . . . . . . . . . . . . . . . . . . . . . 300 4.1.13 Sampling Systems . . . . . . . . . . . . . . . . . . . -. . . . . . 301 3

4.2 Balance of Plant Systems Evaluation . . . . . . . . . . . . . . . . . . 302 4.2.1 Main Steam System . . . . . . . . . . . . . . . . . . . . . . . . 302 4.2.2 Extraction Steam System . . . . . . . . . . . . . . . . . . . . . 302 4.2.3 Auxiliary Steam System . . . . . . . . . . . . . . . . . . . . . . 304 4.2.4 Condensate and Feedwater Systems . . . . . . . . . . . . . . . 305 4.2.5 Feedwater Heaters . . . . . . . . . . . . . . . . . . . . . . . . . 305 4.2.6 Main Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . 306 4.2. 7 Moisture Separator and High Pressure Heater Drain System 307 4.2.8 Low Pressure Heater. Drain System . . . . . . . . . . . . . . . 308 4.2.9 Circulating Water System . . . . . . . . . . . . . . . . . . . . . 309 4.2.10 Service Water System . . . . . . . . . . . . . . . . . . . . . . 309 4.2.11 Component Cooling Water System . . . . . . . . . . . . . . 310 4.2.12 Bearing Cooling Water System . . . . . . . . . . . . . . . . . 311 4.2.13 Water Treatment System . . . . . . . . . . . . . . . . . . . . 311 4.2.14 Boron Recovery System . . . . . . . . . . . . . . . . . . . . . 311 4.2.15 Fuel Pool Cooling System . . . . . . . . . . . . . . . . . . . 312

  • 4.2.16 'Containment Depressuriz.ation . . . . . . . . . . . . . . . . . 312 4.2.17 Steam Generator Blowdown System . . . . . . . . . . . . . . 313 4.2.18 Containment Air Recirculation and Plant HVAC Systems 313 4.2.19 Flow-Accelerated Corrosion . . . . . . . . . . . . . . . . . . 316 4.3 Electrical Systems Evaluation . . . . . . . . . . . . . . . . . . . . . . 318 4.3.1 Main Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . 318 4.3.2 Generator Isophase Bus Duct . . . . . . . . . . . . . . . . . . 318 4:3.3 Station Service Transformer . . . . . . . . . . . . . . . . . . . 319 4.3.4 Reserve Station Service Transformer . . . . . . . . . . . . . . 320 4.3.5 Main Transformer . . . . . . . . . . . . . . . . . . . . . . . . . 320 4.3.6 Motor Feeders . . . . . . . . . . . . . . . . . . . . . . . . . . . 321 4.3.7 GDC-17 Reanalysis . . . . . . . . . . . . . . . . . . . . . . . . 322 4.3.8 Protective Relaying . . . . . . . . . . . . . . . . . . . . . . . . 322 4.4 Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323 4.5 Pipe Stress and Supports . . . . . . . . . . . . . . . . . . . . . . . . 324 4.6 Control Systems and Instrumentation . . . . . . . . . . . . . . . . . 327
4. 7 Validation of Instrumentation & Control Systems Setpoints . . . . 329
4. 7 .1 Reactor Protection & Engineered Safety Features Systems 329 Setpoints 4.7.2 Reactor Control Systems Setpoints . . . . . . . . . . . . . . . 332 4
  • 5.0 6.0 Documents Affected by NSSS Accident Evaluations . . . . . . . . . . . . . 333 5 .1 5.2 Technical Specifications . . . . . . . . . . . . . . . . . . . . . . . . . . 333 Design Document Impact . . . . . . . . . . . . . . . . . . . . . . . . 339 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 342 5

LIST OF TABLES Table Title Page 2.1-1 Surry Units 1 and 2 Power Capability Parameters 21 for 2546 Mwt Core Rated Power 2.2-1 Surry Units 1 and 2 Key NSSS Accident Analysis Parameter Ranges 24 for 2546 Mwt Core Rated Power 3.6.1-1 LOCA Mass & Energy Release Analysis System Parameters 172 Initial Conditions 3.6.1-2 LOCA Mass & Energy Release Analysis System Parameters 173 Containment Backpressure Profile 3.6.1-3 LOCA Mass & Energy Release Analysis System Parameters 174 Surry Unit 1 & 2 Core Decay Heat Fraction 3.6.1-4 LOCA Mass & Energy Release Analysis Safety Injection Flow 175 Maximum SI - Single Train 3.6.1-5 LOCA Mass & Energy Release Analysis Safety Injection Flow 176 Minimum SI - Single Train 3.6.1-6 LOCA Mass & Energy Release Analysis Safety Injection Flow 177 Maximum SI - Two Train 3.6.1-7 Pump Suction Double Ended Rupture 178 Blowdown Mass and Energy Release (Applicable-for all PSDER Cases) 3.6.1-8 Pump Suction Double Ended Rupture, Maximum SI - Single Train 179 Reflood Mass and Energy Release 3.6.1-9 Pump Suction Double Ended Rupture, Maximum SI - Single Train 180 Principal Parameters During Reflood 3.6.1-10 Pump Suction Double Ended Rupture, Maximum SI - Single Train 181 Post Reflood Mass and Energy Release

.3.6.1-11 Pump Suction Double Ended Rupture, Maximum SI - Single Train 182 Mass Balance 3.6.1-12 Pump Suction Double Ended Rupture, Maximum SI - Single Train 183 Energy Balance 6

LIST OF TABLES (CONTINUED) 3.6.1-13 Pump Suction Double Ended Rupture, Minimum SI - Single Train 184 Reflood Mass and Energy Release 3.6.1-14 Pump Suction Double Ended Rupture, Minimum SI - Single Train 185 Principal Parameters During Reflood 3.6.1-15 Pump Suction Double Ended Rupture, Minimum SI - Single Train 186 Post Reflood Mass and Energy Release 3.6.1-16 Pump Suction Double Ended Rupture, Minimum SI - Single Train 187 Mass Balance 3.6.1-17 Pump Suction Double Ended Rupture, Minimum SI - Single Train 188 Energy Balance 3.6.1-18 Pump Suction Double Ended Rupture, Maximum SI - Two Train 189 Reflood Mass and Energy Release 3.6.1-19 Pump Suction Double Ended Rupture, Maximum SI - Two Train 190 Principal Parameters During Reflood 3.6.1-20 Pump Suction Double Ended Rupture, Maximum SI - Two Train 191 Post Reflood Mass and Energy Release 3.6.1-21 Pump Suction Double Ended Rupture, Maximum SI - Two Train 192 Mass Balance 3.6.1-22 Pump Suction Double Ended Rupture, Maximum SI - Two Train 193 Energy Balance 3.6.1-23 Hot Leg Double Ended Rupture - Blowdown Mass and Energy Release 194 3.6.1-24 Hot Leg Double Ended Rupture - Blowdown Mass Balance 195 3.6.1-25 Hot Leg Double Ended Rupture - Blowdown Energy Balance 196 3.6.1-26 Hot Leg Double Ended Rupture, Maximum SI - Two Train 197 Long Term NPSH Analysis, Reflood and Post Reflood Mass and Energy Release 7

LIST OF TABLES (CONTINUED) 3.6.1-27 Hot Leg Double Ended Rupture, Maximum SI - Two Train 198 Long Term NPSH Analysis - Principal Parameters During Reflood 3.6.1-28 Hot Leg Double Ended Rupture, Maximum SI - Two Train 199 Long Term NPSH Analysis - Mass Balance 3.6.1-29 Hot Leg Double Ended Rupture, Maximum SI - Two Train 200 Long Term NPSH Analysis - Energy Balance 3.6.2-1 Pump Suction Double Ended Rupture, Minimum SI - Single Train 215 Mass and Energy Releases for LOCTIC Analysis 3.6.2-2 Containment Peak Pressure - Loss of Coolant Accident 219 Key Containment Assumptions and Results 3.6.2-3 Pump Suction Double Ended Rupture, Minimum SI - Single Train 220 Containment Depressurization Key Containment Assumptions and Results 3.6.2-4 Pump Suction Double Ended Rupture, Minimum SI - Single Train 221 Accident Chronology 3.6.2-5 Safeguards Pump NPSH Analysis - Loss of Coolant Accident 222

. Key Containment Assumptions and Results

.3.7.2.1-1 Surry Containment and ECCS x/Q 244 3.7.2.1-2 Surry Control Room Occupancy Factors 244 3.7.2.1-3 LOCA Control Room and Offsite Doses 245 3.7.2.2-1 Primary Coolant and Secondary Side Radionuclide Inventories:

Technical Specification Limits Plus Concurrent Iodine spike 251 3.7.2.2-2 Primary Coolant and Secondary Side Radionuclide Inventories:

Technical Specification Limits Plus Pre-Accident Iodine Spike 252 3.7.2.2-3 Volumes Used in Analysis of Main Steam Line Break 253 3.7.2.2-4 x/Q for Releases from the Unaffected Steam Generators 253

  • 8

LIST OF TABLES (CONTINUED) 3.7.2.2-5 Flow From Affected SG to the Turbine Building and 253 From the Turbine Building to the Environment 3.7.2.2-6 MSLB Control Room and Offsite Doses 254 3.7.2.3-1 Steam Generator Tube Rupture Break Flow Rates and Releases 260 3.7.2.3-2 SGTR Control Room and Offsite Doses 260 3.7.2.4-1 Primary Coolant and Secondary Side Radionuclide 266 Inventories: Technical specification Limits Plus Pre-Accident Iodine Spike and 5 % Failed Fuel 3.7.2.4-2 Steam Generator Volumes Released During a Locked 267 Rotor Accident 3.7.2.4-3 LRA Control Room and Offsite Doses 267 3.7.2.5-1 Activity Released to the Containment or Fuel 273 Building 3.7.2.5-2 Fuel Handling Accident Control Room Ventilation 273 Flow Rate 3.7.2.5-3 FHA Control Room and Offsite Doses 274 3.7.3-1 Control Room and Offsite Doses Previously Reported to NRC 2q9 3.7.3-2 Summary of Control Room and Offsite Doses 280 4.1.1-1 Reactor Vessel Stress Intensities 292 4.1.1-2 Reactor Vessel Usage Factors 293 4.1.8-1 Auxiliary Pumps and Valves 298 4.2.2-1 Extraction Steam Piping Stress Analysis Design Conditions 303 4.2.2-2 Extraction Steam Line Non-Return Valves (NRV) 304 4.2.2-3 Feedwater Heater Shell Side Pressures 304 9

LIST OF TABLFS (CONTINUED) 4.2.7-1 H. P. Heater Drain Pumps 308 4.2.8-1 L. P. Heater Drain Pumps 309 4.3.6-1 Pump BHP 321 4.5.1-1 Comparison of System Pressure and Temperature 326

4. 7 .1-1 Assumed Reactor Protection & Engineered Safety Features 331 Settings for 2546 MWt Core Rated. Power
  • 10

Figure LIST OF FIGURES Page 2.1-1 Reactor Coolant Temperatures Versus Percent Rated Load for 22 Surry Unit 1 and 2 2546 MWt Core Rated Power 3.5.1-1 Rod Withdrawal from Subcritical - Neutron Power 61 3.5.1-2 Rod Withdrawal from Subcritical - Core Heat Flux 62 3.5.1-3 Rod Withdrawal from Subcritical - Temperatures 63 (Fuel, Clad, Moderator) 3.5.2-1 Rod Withdrawal at Power 70 Minimum DNBR vs Insertion Rate at Full Power 3.5.2-2 Rod Withdrawal at Power 71 Nuclear Power - Full Power limiting DNBR case 3.5.2-3 Rod Withdrawal at Power 72 Pressurizer Pressure - Full Power limiting DNBR case 3.5.2-4 Rod Withdrawal at Power 73 RCS Average Temperature - Full Power limiting DNBR case 3.5.2-5 Rod Withdrawal at Power 74 Minimum DNBR vs Insertion Rate at 60% Power 3.5.2-6 Rod Withdrawal at Power 75 Minimum DNBR vs Insertion Rate at 10% Power 3.5.2-7 Rod Withdrawal at Power 76 Nuclear Power - RCS Overpressure Case 3.5.2-8 Rod Withdrawal at Power 77 RCS Average Temperature - RCS Overpressure Case 3.5.2-9 Rod Withdrawal at Power 78 Cold Leg Pressure - RCS Overpressure Case 3.5.5-1 Excessive Load Increase-Manual Rod Control-BOL 89 Nuclear Power, Pressurizer Pressure & Water Volume 3.5.5-2 Excessive Load Increase-Manual Rod Control-BOL 90 Core Average Temperature and DNBR

  • 11
  • Figure 3.5.5-3 LIST OF FIGURES (CONTINUED)

Excessive Load Increase-Manual Rod Control-EOL Nuclear Power, Pressurizer Pressure & Water Volume Page 91 3.5.5-4 Excessive Load Increase-Manual Rod Control-EOL 92 Core Average Temperature and DNBR 3.5.5-5 Excessive Load Increase-Auto Rod Control-BOL 93 Nuclear Power, Pressurizer Pressure & Water Volume 3.5.5-6 Excessive Load Increase-Auto Rod Control-BOL 94 Core Average Temperature and DNBR 3.5.5-7 Excessive Load Increase-Auto Rod Control-EOL 95 Nuclear Power, Pressurizer Pressure & Water Volume 3.5.5-8 Excessive Load Increase-Auto Rod Control-EOL 96 Core Average Temperature and DNBR 3.5.6-1 Complete Loss of Flow - Undervoltage Case 101 RCS Mass Flow Rate 3.5.6-2 Complete Loss of Flow - Underfrequency Case 102 RCS Mass Flow Rate 3.5.6-3 Complete Loss of Flow - Undervoltage Case 103 Nuclear Power 3.5.6-:.4 Complete Loss of Flow - Undervoltage Case 104 Core Inlet Temperature 3.5.6-5 Complete Loss of Flow - Undervoltage Case 105 RCS Average Temperature 3.5.6-6 Complete Loss of Flow - Undervoltage Case 106 Pressurizer Pressure 3.5.6-7 Complete Loss of Flow - Undervoltage Case 107 Minimum DNBR 3.5.6-8 Complete Loss of Flow - Undervoltage Case 108 Minimum DNBR (Enlarged Scale) 12

Figure LIST OF FIGURES (CONTINUED) Page 3.5.6-9 Complete Loss of Flow - Underfrequency Case 109 Nuclear Power 3.5.6-10 Complete Loss of Flow - Underfrequency Case 110 Core Inlet Temperature 3.5.6-11 Complete Loss of Flow - Underfrequency Case 111 RCS Average Temperature 3.5.6-12 Complete Loss of Flow - Underfrequency Case 112 Pressurizer Pressure 3.5.6-13 Complete Loss of Flow - Underfrequency Case 113 Minimum DNBR 3.5.6-14

  • Complete Loss of Flow - Underfrequency Case 114 Minimum DNBR (Enlarged Scale) 3.5.7-1 Locked Rotor - DNBR Analysis Case 121 Core Inlet Mass Flow Rate
  • 3.5.7-2 3.5.7-3 Locked Rotor - DNBR Analysis Case Core Heat Flux Locked Rotor - DNBR Analysis Case Core Inlet Temperature 122 123 3.5.7-4 Locked Rotor - RCS Overpressure Case 124 RCS Pressures - Pressurizer, RCP Exit, Lower Plenum 3.5.7-5 Locked Rotor - .RCS Overpr~sure Case 125 Steam Generator Pressure 3.5.8-1 Loss of External Load - BOC with Pressurizer Relief & Spray 132 Nuclear Power 3.5.8-2 Loss of External Load - BOC with Pressurizer Relief & Spray 133 Core Inlet Temperature 3.5.8-3 Loss of External Load - BOC with Pressurizer Relief & Spray 134 Pressurizer Liquid Volume
  • 13

Figure LIST OF FIGURES (CONTINUED) Page 3.5.8-4 Loss of External Load - BOC with Pressurizer Relief & Spray 135 RCS Cold Leg Pressure

  • 3.5.8-5
  • Loss of External Load - BOC with Pressurizer Relief & Spray 136 Steam Generator Pressure 3.5.8-6 Loss of External Load - BOC with Pressurizer Relief & Spray 137 Hot Channel DNBR 3.5.8-7 Loss of External Load - BOC without Pressurizer Relief & Spray 138 Nuclear Power 3.5.8-8 Loss of External Load - BOC without Pressurizer Relief & Spray 139 Core Inlet Temperature 3.5.8-9 Loss of External Load - BOC without Pressurizer Relief & Spray 140 Pressurizer Liquid Volume 3.5.8-10 Loss of External Load - BOC without Pressurizer Relief & Spray 141 RCS Cold Leg Pressure

Figure LIST OF FIGURES (CONTINUED) Page 3.6.2-3 Containment Temperature Transients - Hot Leg and Pump Suction DER 225 3.6.2-4 Containment Pressure Transients - Pump Suction DER 226 Limiting Depressum.ation Case 3.6.2-5 ORS Pump Available NPSH, Hot Leg DER - Limiting NPSH Case 227 3.6.2-6 IRS Pump Available NPSH, Hot Leg DER - Limiting NPSH Case 228 3.6.2-7 LHSI Pump Available NPSH, Pump Suction.DER - Limiting NPSH Case 229 15

1.0 PROGRAM DESCRIPTION 1.1 Definition of goals Virginia Electric and Power Company (VEPCO) has undertaken a program to uprate Surry Power Station (SPS) Units 1 and 2 to a maximum core power level of 2546 MWt each. The original licensed maximum core power level is 2441 MWt. The uprating program will result in a total NSSS power output of 2558 MWt including 12 MWt of reactor coolant pump thermal output. Unless otherwise noted, 100% power in this report refers to a core power level of 2546 MWt.

The purpose of this report is to provide the basis for the determination that continued safe plant operation can be achieved at the uprated conditions. The licensing basis assessment includes a review of the accident analyses, component and system design, Emergency Operating Procedures, Technical Specifications and appropriate sections of the UFSAR. This report, upon approval of the NRC, will allow the power increase during Cycle 14 for Unit 1 and Cycle 13

  • for Unit 2 and beyond.

1.2 Applicable Design Criteria The analyses performed in support of the Surry uprating program have been completed in accordance with applicable quality assurance requirements. Equipment reviews and evaluations have been performed in accordance with industry codes, standards, and regulatory requirements applicable to Surry. Assumptions and acceptance criteria for the various analyses are addressed in the respective sections in Section 3.0. The capability of Surry Unit 1 and Unit 2 to operate at uprated conditions was verified in accordance with guidelines contained in Westinghouse Topical Report WCAP-10263 (1.0-1) 16

1.3 Scope Summary Section 2.0 of this report defines the operating parameters and key analysis parameter ranges.

It also outlines the evaluation approach and scope summary.

Section 3.0 of this report provides the results of the evaluations for the Safety Analyses:

  • Nuclear Design and Core Thermal Hydraulic Design
  • NSSS Safety Analysis Evaluation Methodology
  • Evaluation of Unaffected Events
  • Evaluation of Validated Events
  • Evaluation of Reanalyzed Events
  • Containment Integrity & Safeguards Evaluation
  • NSSS*Accident .Radiological Consequences Analyses
  • Additional Design Basis & Programmatic Evaluation Section 4.0 of this report provides the results of the evaluations.for the systems, structures and
  • components:

RCS Component and Fluid System Evaluations Balance of Plant System Evaluations*

  • Electrical Systems Evaluations
  • Structures
  • Pipe Stress and Supports
  • Control Systems and Instrumentation Section 5.0 outlines specific Tech. Spec. and design document impacts.

Section 6.0 reports the conclusions of the report.

References (1.0-1) WCAP - 10263, "A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor Power Plant," January, 1983.

17

2.0 NSSS ACCIDENT ANALYSIS EVALUATION DESCRIPTION 2.1 Operating Parameters At the present time, Surry Units 1 and 2 are licensed to operate at a core rated power of 2441 MWt. This report supports a license amendment request which seeks approval to operate both Surry units at a core rated power of 2546 MWt. Considering an additional 12 MWt of net heat addition from the reactor coolant pumps, this is equivalent to a total NSSS thermal power rating of 2558 MWt.

Table 2.1-1 presents a summary of Reactor Coolant System design parameters for the existing licensed conditions for Surry Units 1 and 2, along with parameters calculated for the increased power rating; These.parameters values represent limiting conditions which are used in the design evaluations of NSSS components and systems. Certain other evaluations (e.g., NSSS accident analyses) may use different values, as required by the specific analysis methodology. A.

comparison of the present and uprated power capability parameters is described below.

2.1.1 Reactor Power The uprating will increase the reactor thermal power by 4.3% versus the original design conditions. This power level corresponds to the current Engineered Safeguards Design Rating

. of Surry Units 1 and 2.

2.1.2 Reactor Flow and Tube Plugging The original operating parameters are based upon a steam generator tube plugging level of O%

and the associated Thermal Design Flow of 88,500 gpm per loop. The NSSS system and components evaluations performed for the uprating program conservatively assume a tube plugging level of 7 %; these evaluations are generally insensitive to small values of tube plugging. The Thermal Design Flow can be maintained at 88,500 gpm per loop due to actual 18

plant flow margin. NSSS accident analyses and core thermal/hydraulic assessments assume 15 %

tube plugging.

2.1.3 Reactor Coolant Temperatures As shown on Table 2.1-1, the full power reactor coolant system temperatures for the uprated conditions are within 3°F. of those for the current 2441 MWt power level, with the vessel average temperature 1.4 °F less than the current licensed value. As expected, the greater power level leads to a slightly greater temperature rise (2.6°F) in the coolant as it passes through the vessel. Figure 2.1-1 provides a graphical comparison of the reactor vessel cold leg, hot leg and vessel average temperatures. It shows that there is little difference between these parameters for the* current and uprated operating modes throughout the power range.

2.1.4 Steam Pressure Operation at the greater power requires an increase in steam generator heat transfer rate, which is obtained by increasing the temperature difference between reactor coolant and secondary plant steam. The reactor coolant temperatures for uprated operation are nearly the same as those for the current power level. Therefore, it is expected that the greater power rating would be obtained at a lower steam temperature and corresponding saturation pressure. This is not reflected in the uprated parameters provided in Table 2.1-1, because a smaller steam generator fouling factor (based on plant operational experience) was used in the generation of the revised parameters. This compensated for the steam pressure decrease associated with the increased power level. As a result, an essentially constant design value for steam pressure (785 psia vs.

784 psia) was maintained for the uprating.

19

2.1.5 Steam Flow Steam flow at the 2558 MWt conditions has increased over the 2441 MWt conditions roughly in proportion to the thermal power increase.

2.1.6 Feedwater Temperature The increase in power level will result in an increase in the hot full power feedwater temperature by approximately 5.5°F.

2.1. 7 Core Bypass Flow The difference in the core bypass flow was the result of the removal of thimble plugs associated with 15 x 15 standard fuel for operation with the Surry Improved Fuel (SIF). This change was implemented in 1988. The absence of thimble plugs allows flow through fuel assemblies which

  • have neither control rods nor burnable poison assemblies, effectively increasing bypass flow beyond the original design value of 4.5%.

Comparison of the data presented in Table 2 .1-1 and Figure 2 .1-1 indicates that the proposed conditions do not vary significantly from those of the original plant design.

20

Table 2.1-1 Surry Units 1 and 2 Power Capability Parameters for 2546 MWt Core Rated Power Present Uprated Design Basis Design Basis NSSS Power, MWt1 2441 2558 Reactor Power, MWt 2441 2546 Thermal Design Flow, gpm per loop 88,500 88,500 Tot.al Reactor Flow, 1()6 Ihm/hr 100.7 101.1 Reactor Coolant Pressure, psia 2250 2250

  • Reactor Coolant Temperature, °F Core Outlet 608.2 609.3 Vessel Outlet 605.6 605.6 Core Average . 577.1 576.5 Vessel Average 574.4 573.0 Vessel/Core Inlet 543.0 540.4 Steam Generator Outlet 543.0 540.1 Steam Generator Steam Temperature, °F 516.0 515.9 Steam Pressure, psia 785 784 Tot.al Steam Flow, 1()6 lbm/hr 10.66 11.26 Feedwater Temperature, °F 437.7 443.2 Zero Load Temperature, °F 547 547 Steam Generator Tube Plugging; % 0 7.Q2 Core Bypass Flow, % 4.5 6.0 Fuel Design 15 x 15 STD/SIF 15 x 15 SIF 1

NSSS parameters for original design power of 2441 MWt include no pump heat; proposed uprated parameters include 12 MWt pump heat 2

NSSS component and systems evaluations assume 7%; NSSS accident analyses assume 15%

  • 21

Figure,2.1-1 Reactor Coolant Temperatures Versus Percent Rated Load for Surry Units 1 and 2 2546 MWt Core Rated Power 610 T VESSEL EXJT:

600 590 vessa AVERAGEi 580 570 II,,

vessa INLET!

  • 540

~ .*

530 520 510 500 0 10 20 30 40 50 60 70 so 90 100

% RATED THERMAL LOAD

_ _ _ UPRATED

                  • CURRENT 22

2.2 Key Analysis Parameter Ran2es & Uncertainties This section presents values of NSSS accident analysis key safety parameters assumed in the Surry uprating analyses. The data are presented in terms of the parameter operational ranges which the analyses support. The revised NSSS accident analyses have incorporated assumptions which have maintained and in certain cases expanded the existing operational ranges for key safety parameter limits. Table 2.2-1 presents key parameter ranges assumed in the present power and uprated power analyses in the areas of: core characteristics, system and component characteristics and containment operating limits.

It can be seen that most parameters have been evaluated for operation over either a wider range or for greater absolute value than in the existing analyses. This has been achieved while, in general, increasing the reported margin to key analysis acceptance criteria. For NSSS accident analyses, this has been possible via the use of improved analytical methods for large break LOCA (i.e., the BASH evaluation model) and for core DNB analyses (i.e., the Virginia Power

  • Statistical DNBR Evaluation Methodology). In the containment integrity analyses, increased analysis margin has been realized via a two-fold approach which: 1) involved use of plant-specific information to reduce excess analysis conservatisms and 2) established a program of rigorous interface between the mass and energy release data generation (by Westinghouse) and the data usage for containment analyses (by Stone & Webster).

Reference (2.2-1) WCAP-12910, "Pressurizer Safety Valve Set Pressure Shift," WOG Project MUHP 2351, March, 1991.

23

Table 2.2-1 Surry Units 1 and 2 Key NSSS Accident Analysis Parameter Ranges for 2546 MWt Core Rated Power Parameter Description Present Uprated Power Power Core Characteristics Moderator Temperature Coefficient-Most Positive + 3 pcm/°F + 6 pcm/OF1 Moderator Tempera~e Coefficient-Most Negative - 35 pcm/°F - 45 pcm/ 0 F2 Steam Generator Tube Plugging 0-15% 0-15%

Maximum FQT - LOCA Analysis Limit 2.32 2.32 Maximum FAHN - Statistical DNB Analysis Limit 1.56 1.56

. Hot Assembly *Relative Power Factor (LOCA) 1.465 1.465 S~stem & ComJ;2Qnent Characteristics Pressurizer Safety Valve Model +3 % setpoint shift/3 % Ref. (2.2-1) accumulation 1 % setpoint shift

  • Inside Recirculation Spray Flow (per pump)

Outside Recirculation Spray Flow (per pump)

Maximum RWST Temperature Service Water Flow to Recirculation Spray 3000 gpm 3000 gpm 45°F 3000-3500 gpm 3000-3250 gpm 45°F Heat Exchanger(per cooler) 7200 gpm 7789-6930 gpm3 Minimum Intake Canal Level , 23 ft 23 ft Containment Qnerating Limits Containment Bulk Average Temperature l00°F - 120°F 75°F - 125°F Maximum Service Water Temperature *95°F 95°F Containment Air Partial Pressure 9.0 - 10.3 psi 9.0 - 10.3 psi 1

Analysis of RCCA Ejection Assumes + 3 pcml°F 2

Analysis of Excessive Load Increase assumes - 35 pcm/°F 3

Limiting canal drawdown scenario variation over first 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> post-LOCA

  • 24

2.3 Evaluation Approach & Scope Summary In Reference (2.3-1), Westinghouse has described a methodology by which to systematically evaluate the effects of a proposed uprating upon plant design and licensing basis features.

Virginia Power has applied this methodology in evaluating the effects of uprating upon the Surry NSSS accident analyses. As it relates to accident analyses, this methodology involves the application of these four key principles:

1. The impact of uprating is verified for compliance with respect to the existing plant licensing basis.
2. The impact of uprating is evaluated to determine whether any unreviewed safety questions exist.
3. Events are evaluated for adverse impact from the proposed change in power and associated operating conditions. Events which are adversely
  • impacted are reanalyzed.
4. Accident reanalyses employ current NRC-approved analytical methods.

The analyses and evaluations which constitute the existing licensing basis for Surry Units 1 and 2 were reviewed for potential impact of the proposed operating conditions. The specific approach taken to categorize the events is described in Section 3.2.3. Section 3.0 provides a detailed discussion of the events and aspects of the plant licensing basis which were evaluated. The scope of assessment presented in this report involves the following areas of plant design and licensing basis:

1. NSSS Accident Analyses
2. Validation of Reactor Protection & Engineered Safety Features Systems Setpoints
3. LOCA Mass and Energy Release Analysis 25
4. Containment Integrity & Safeguards Equipment Analysis
5. Plant Emergency Operating Procedures
6. Miscellaneous Design Basis Analyses & Programmatic Evaluations In each of these areas listed in Items 1, 2, 5 & 6 above, Virginia Power has performed analyses or evaluations to determine the effect of operation at the proposed conditions. Westinghouse Electric Corporation has performed LOCA mass and energy release analysis (Item 3) which accounts for the uprated plant conditions. Stone & Webster Engineering Corporation performed the analyses to quantify the containment and safeguards equipment behavior for operation at the uprated conditions (Item 4).

References (2.3-1) WCAP-10263, "A Review Plan for Uprating the Licensed Power of a Pressurized

  • *Water Reactor Power Plant," January 1983 .
  • 26

3.0 SAFETY EVALUATIONS 3.1 Nuclear Design and Core Thermal-Hydraulic Design 3.1.1 Nuclear Core Design Evaluation The effects of the proposed uprating upon the nuclear design bases and methodologies for Surry Units 1 and 2 have been evaluated. The proposed power level is 4.3% greater than the current core rated power. The effects of the increased thermal power and associated fuel and moderator temperature changes upon core physics characteristics are small and are explicitly modeled in the core neutronics models. The specific values of key core safety parameters, such as power distributions, peaking factors, reactivity coefficients and rod worths are primarily dependent upon reload core design strategy. Based on the Virginia Power experience with the North Anna uprating, the variation in such key parameters as a result of the proposed power uprating is expected to be similar to typical variations which may occur during the normal reload design process. The uprating imposes no more severe variations than are already accommodated during normal engineering design activities .

  • The proposed uprating changes require no change to nuclear design philosophy or methods. The Virginia Power reload evaluation methodology (3 .1-1) involves assessing the impact upon safety analyses of key safety parameters associated with reload core designs. This process will continue to be applied for cores designed under the uprated conditions. If the uprating causes the value of any key safety parameter to be outside the bounds of that accommodated by the applicable safety analysis, an assessment of the impact upon transient analyses will be included in the reload safety evaluation. This basic process is employed regardless of the origin of such changes.

An uprated core power level at Surry Units 1 and 2 potentially affects the neutron fluence analyses used as input to calculations which demonstrate compliance with regulations governing reactor vessel integrity. These regulations include:

1. 10 CFR 50.61 - Requirements for Protection Against Pressurized Thermal Shock (PTS) (PTS Reference Temperature, or RTPrs, calculations)
  • 27
2. 10 CFR 50 Appendix G - Requirements for Protection Against Reactor Vessel Fracture (Heatup and Cooldown Curve and Charpy Upper Shelf Energy (CvUSE) calculations)

The fluence analyses used as input to calculations which demonstrate compliance with these regulations have conservatively assumed that uprated power operation was implemented in 1990.

Since the uprated value for this key safety parameter has been included in the existing calculations, there are no outstanding reactor vessel integrity considerations for Surry Unit 1 and 2 operation at the proposed conditions.

References (3.1-1) VEP-FRD-42, Revision 1-A, "Reload Nuclear Design Methodology, "Virginia Electric and Power Company, September 1986, and Supplement 1, by Letter from M. L. Bowling to NRC, Serial No.93-723, dated December 3, 1993 .

28

3.1.2 Core Thermal-Hydraulic Design Evaluation This section describes .the impact of the proposed uprating upon the reload core thermal-hydraulic evaluation process for Surry Unit 1 and 2. Presented is a summary of the existing evaluation methodology, along with a summary of the impact of core uprating upon each of the design areas evaluated for reload cores.

A Surry implementation analysis of the Virginia Power Statistical DNBR _Evaluation Methodology (3.1.2-1) was submitted to the NRC in July 1991 (3.1.2-2) and approved in June 1992 (3.1.2-3). In the Statistical DNBR Evaluation Methodology, a series of nominal thermal-hydraulic statepoints are randomly varied to account for the impact of key thermal-hydraulic analysis parameter uncertainties. Each random statepoint is used as input to a detailed core

,*thermal-hydraulic analysis .to determine the statepoint' s minimum departure from nucleate boiling ratio (DNBR). The DNBR results are subjected to a statistical evaluation to determine the DNBR standard deviation associated with each nominal statepoint resulting from the random variation of thermal-hydraulic analysis parameters. The standard deviations are then correlated as a function of a system parameter (e.g., RCS temperature or pressure) to permit the maximi7.ation of the standard deviation over the entire range of operating parameters. The nominal statepoints included several statepoints at both thermal design flow and at low flow ,

conditions.

The proposed design parameters following core uprating implementation were evaluated with respect to those assumed in the Statistical DNBR Evaluation Methodology implementation.

analysis. The uprated core power was assumed in the implementation analysis. In addition, the

  • proposed values of RCS pressure, RCS average temperature and RCS flow rate for uprated operation have been confirmed to be within the range considered in the implementation analysis.

This allows continued application of the methodology. Confirmation that transient thermal-hydraulic analysis DNBR's remain above the applicable statistical DNBR limit will continue to ensure that the onset of DNB will be avoided at a 95% probability/95% confidence level.

29

~I An evaluation of the applicability of existing thermal-hydraulic analysis methods and transient thermal-hydraulic analyses is performed for each reload core. Each reload core is evaluated to confirm that bounding values of its characteristics are modeled in the detailed core thermal-hydraulic analyses. The relevant thermal-hydraulic items considered on a reload basis that could be affected by core uprating are evaluations of core bypass flow rate, core thermal limits, axial power distribution effects and retained DNBR margin.

Except for the core thermal limits, there are no direct effects of the core uprating upon these items. The proposed core thermal limits have been generated for the proposed uprated

. conditions. A power increase does increase the total temperature rise across the core, which could increase the skewing of axial power distributions. Such effects are explicitly modelled in the reload core* design process. Provided that the reload core meets the Technical Specification minimum measured RCS flow rate (total RCS flow rate ~273,000 gpm), average RCS temperature requirements (RCS average temperature s577°F) and the peaking factors specified

  • in the cycle Core Operating Limits Report, core uprating presents no outstanding safety
    • considerations for the reload thermal-hydraulic assessment.

Each reload thermal/hydraulics evaluation consolidates and summarizes DNBR penalties applicable to the reload core in question. This process will continue to be applied following implementation of core uprating. Penalties will be considered on a case-by-case basis in the reload thermal/hydraulics evaluation to determine if they remain applicable following uprating.

References:

(3.1.2-1) VEP-NE-2-A, "Statistical DNBR Evaluation Methodology", June 1987.

  • (3.1.2-2) Letter from Bart C. Buckley to W. L. Stewart, "Surry Units 1 and 2 - Issuance of

. Amendments Re: F Delta H Limit and Statistical DNBR Methodology," Letter Serial No.92-405, June 8, 1992. *

(3.1.2-3) Letter from W. L. Stewart to USNRC, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Proposed Technical Specifications Changes - Fi:1H Increase/Statistical DNBR Methodology," Letter Serial No.91-374, July 8, 1991.

30

3.2 NSSS Safety Analysis Evaluation Methodology 3.2.1 Overall Evaluation Approach In assessing the potential impact of the proposed core uprating upon the existing NSSS safety analyses, Virginia Power employed a methodology developed by Westinghouse for this purpose (3.2-1). The intent of the reference is to establish a methodology to guide licensees in performing the assessment of plant design in support of power increase license amendments.

This topical report provided these key criteria which were employed in the NSSS safety analysis evaluation:*

1. All aspects ~f NSSS safety analyses which are affected by the proposed uprated plant conditions are evaluated for potential impact.
2. *The evaluations are performed to verify compliance with respect to current plant
  • , licensing analysis basis.
3. Design analyses which are adversely impacted are reanalyzed using current analytical techniques.

Virginia Power employed a process analogous to that applied for a reload core safety evaluation to determine the impact of the proposed uprating upon NSSS safety analyses. For each area of design analysis, the values of key safety parameters assumed in the existing analysis were compared with the proposed uprated value for these parameters. Key safety parameters are a group of analysis inputs to which the results of a specific analysis are most sensitive. They may consist of plant initial conditions, instrumentation settings, safety-related system characteristics or other detailed inputs modeled in the NSSS safety analysis computer simulation. If the existing analysis .value for key safety parameters conservatively bounds the uprated value, the analysis is unaffected. If one or more parameter values are not bounded, then the analysis is validated by further review .. This validation activity may involve use of additional conservatism inherent in the existing analysis or other documentation that the analysis results are not adversely impacted by uprating. Events for which this was not successful were reanalyzed assuming the proposed uprated conditions. Section 3.2.2 summarizes the specific analytical methods employed in the reanalyses. The categorization of accidents which resulted from this overall evaluation approach is presented in Section 3.2.3.

31

3.2.2

  • Analytical Methods Listed below are the key sources of documentation for the analysis and evaluation methods which have been used in the Surry Unit 1 and 2 uprating analyses. Methodologies are presented for each of the following design areas: nuclear core design; thermal-hydraulic core design; NSSS accident analyses (LOCA and non-LOCA events); LOCA mass and energy release analysis; containment response analysis and radiological dose consequences analysis.

Virginia Power Methods

1. "Reload Nuclear Design Methodology" (VEP-FRD-42, Revision 1-A, September, 1986 and supplemented by Letter from M. L. Bowling to NRC, Serial No.93-723, dated December 3, 1993)- Defines standard Virginia Power practice for the design and evaluation of reload cores.
  • 2.' "Vepco Reactor Core Thermal/Hydraulic Analysis Using the COBRA IDC/MIT Computer Code" (VEP-FRD-33-A, dated October, 1983) - Methodology for performance of detailed core thermal/hydraulic calculations for safety analysis.
3. Statistical DNBR Evaluation Methodology (VEP-NE-2-A dated June, 1987) -

Methodology for accounting for analysis uncertainties in thermal/hydraulic calculations.

4. "Nuclear Design Reliability Factors" (VED-FRD-45-A, dated October, 1982)

-Presents factors which define the reliability of calculations of reactor core parameters.

5. "Qualification of the WRB-1 CHF Correlation in the Virginia Power COBRA Code" (VEP-NE-3-A, dated July, 1990) - Methodology for utilization of the WRB-1 CHF correlation in production thermal/hydraulic calculations.
6. "Vepco Evaluation of the Control Rod Ejection Transient" (VEP-NFE-2-A, dated December, 1984) - Methodology for performance of control rod ejection transient analysis .

. 7. "Reactor System Transient Analyses Using the RETRAN Computer Code" (VEP-FRD-41-A dated May, 1985) - Methodology for performance of NSSS transient analysis.

32

8. "Methodology for the Analysis of the Dropped Rod Event" (WCAP-11394-P-A, dated January 1990) - Dropped control rod event analysis methodology.
9. "LOCADOSE NE319, A Computer Code System for Multi-Region Radioactive Transport and Dose Calculation," Theoretical, Users & Validation Manuals, Revision 3, July 1990, Bechtel Power Corporation, San Fraiicisco, CA.

Westinghouse Non-LOCA Analysis Methods

1. WCAP-7907-A, "LOFTRAN Code Description," April, 1984.

LOCA Analysis Methods

1. "Westinghouse ECCS Evaluation Model-1981 Version" (WCAP-9220-P-A, dated February, 1982).
2. "The 1981 Version of the Westinghouse ECCS Evaluation Model Using the BASH Code" (WCAP-10266-P-A, Rev. 2, dated March, 1987).
3. "Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code" (WCAP-10054-P-A, dated August, 1985).
4. "NOTRUMP: A Nodal Transient Small Break and General Network Code" (WCAP-10079-P-A, dated August, 1985).
  • LOCA Mass and Energy Release Analysis Methods
1. "Westinghouse Mass and Energy Release Data for Containment Design," WCAP-8264-P-A, Rev. 1, August 1975.

2 . . "Westinghouse LOCA Mass and Energy Release Model for Containment Design-March 1979 Version," WCAP-10325-P-A, May 1983.

Containment Response Analysis Methods

l. LOCTIC-A Computer Code to Determine the Pressure and Temperature of Dry Containments to a Loss of Coolant Accident," SWND-1, Stone and Webster Engineering Corp, September, 1971, Letter of December 6, 1971, from W. J. L.

Kennedy, Chief Nuclear Engineer, Stone and Webster Engineering Corp., to P.A.

Morris, Director, Division. of Reactor Licensing, AEC.

33

3.2.3 NSSS Event Categorization by Uprate Effect Applying the approach described in Section 3.2.1, each NSSS accident described in the Surry

  • unit 1 and 2 UFSAR was evaluated for potential impact of the proposed uprated conditions.

Each event was placed in one of three categories, depending upon whether the key safety parameter values assumed in the existing event analyses bound the values associated with uprated operation. These categories are: 1) event is unaffected by uprating, 2) event requires validation, because key parameter values are not bounded (or there are special considerations) and 3) event

  • requires reanalysis, because key *parameter values *are not bounded and have potentially significant impact on the analysis results. The events in each of these categories and a brief description of the rationale involved is described below. More detailed descriptions of the evaluation or analysis of each event for operation at the proposed uprated conditions is presented in Sections 3.3, 3.4 and 3.5.

3.2.3.1 Events Unaffected by Uprating For events in this category, the proposed uprating either does not alter the value of key safety parameters for the event, or the event* is otherwise not credible. The report section containing

  • the evaluation description is listed.

Malpositioning of Part-Length Control Rod Assemblies (Section 3.3.1)

These control rods are no longer in the Surry cores, so that this event is no longer credible.

Power operation with less than 3 operable RCS loops is precluded by the Surry Technical Specifications, so that this is not a credible event.

Likelihood of Turbine-Generator Unit Overspeed (Section 3.3.3)

The proposed uprated conditions do not alter the system behavior or assumptions employed in the existing analysis of this event.

34

3.2.3.2 Events Requiring Validation For events*in this category, the proposed uprating causes key safety parameter values to become more adverse. Each event is evaluated to validate that the key safety parameter values assumed in the existing event analysis bounds the proposed values associated with uprated operation.

Certain events in this category have existing licensing analyses which were performed at the uprated core rated power of 2546 MWt. These events are validated to confirm that the remainder of the assumed key safety parameter values bound the proposed. values. The report section containing the evaluation description is listed.

Rupture of Main Steam Pipe (Section 3.4.1)

This event was .*evaluated to demonstrate that the core thermal-hydraulic and containment response effects are not adversely affected by the uprating. The evaluation also serves to document the existing licensing basis status for containment response to this event The existing analyses of the events listed below assumed a rated core power of 2546 MWt.

These analyses were validated to confirm that the remainder of the assumed key safety parameter values bound the proposed values for the uprating.

Excessive Heat Removal Due to Feedwater System Malfunctions (Section 3.4.2)

Loss.of Normal Feedwater (Section 3.4.3)

Rupture of a Control Rod Drive Mechanism Housing (Control Rod Assembly Ejection) (Section 3.4.4)

Small Break Loss of Coolant Accident (Section 3.4.5)

Large Break Loss of Coolant Accident (Section 3.4.6) 3.2.3.3 Events Requiring Reanalysis For events in this category, the proposed uprating causes key safety parameter values to become more adverse, and validation has concluded that one or more parameter values are not bounded 35

by the values assumed in the existing analysis. These events are reanalyzed using current NSSS accident analysis methodologies. The report section containing the reanalysis description is listed.

Uncontrolled Control-Rod Assembly Withdrawal from a Subcritical Condition (Section 3.5.1)

The key safety parameters assumed in the existing analysis remain bounding for the proposed uprating, since this event is analyzed at no load conditions. The event was reanalyzed to accommodate future reload core design needs for expanded key safety parameter limits.

Uncontrolled Control-Rod Assembly Withdrawal at Power (Section 3.5.2)

The proposed increase in core rated power and the change in Overtemperature &

Overpower 4 T protection setpoints (Reference Temperature T') required reanalysis

  • of this event. The analysis results confirm that the required core protection is provided at the uprated conditions. The analysis employed the Virginia Power Statistical DNBR Evaluation Methodology (3.2-2).

Control-Rod Assembly Drop/Misalignment (Section 3.5;3)

The proposed increase in core rated power required regeneration of the plant-specific core thermal limit lines used in the analysis of this event. These limits are employed during the reload safety evaluation of each core to confirm acceptable DNB performance. The analysis employed the Virginia Power Statistical DNBR Evaluation Methodology (3.2-2).

Chemical and Volume Control System Malfunction (Section 3.5.4)

The event case initiated at power conditions was reanalyzed to accommodate the proposed increase in core rated power and the revised Overtemperature & Overpower 4 T protection setpoints (Reference Temperature T') .

  • 36

-1I Excessive Load Increase Incident (Section 3.5.5)

The limiting scenarios for this event are initiated from full power conditions. It was reanalyzed to accommodate the proposed increase in core rated power. The analysis employed the Westinghouse standard (non-statistical) thermal-hydraulic analysis methodology.

Loss of Reactor Coolant Flow (Section 3.5.6)

This event, which is a limiting DNB transient, was reanalyzed to accommodate the proposed increase in core rated power. The analysis DNB employed the Virginia

. Power Statistical DNBR Evaluation Methodology (3.2-2).

    • Locked Rotor Incident (Section 3.5.7)

This event was reanalyzed to .confirm that acceptable DNB results and RCS pressurization are obtained for operation with the proposed increase in core rated power. The DNB analysis employed the Virginia Power Statistical DNBR Evaluation Methodology (3.2-2).

Loss of External Electrical Load (Section 3 .5. 8)

This event was reanalyzed to confirm that applicable limits for RCS and main steam system pressurization are met for operation at the proposed core rated power.

Steam Generator Tube Rupture (Section 3.5.9)

This event was reanalyzed to accommodate the proposed increase in core rated power and to implement the Westinghouse Owners' Group analysis methodology (3.2-3).

References (3.2-1) WCAP-10263, "A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor Power Plant," January 1983.

(3.2-2) VEP-NE-2-A, "Statistical DNBR Evaluation Methodology," June, 1987.

(3.2-3) WCAP-13247, "Report on the Methodology for the Resolution of the Steam Generator Tube Uncovery Issue," March 1992.

37

3.3 Evaluation of Unaffected Events 3.3.1 Malpositioning of Part-Length Control Rod Assemblies This event was originally evaluated in Surry UFSAR Section 14.2.3. The part length control rod assemblies have since been removed from the core and no longer require any design evaluation.

3.3.2 Startup of an Inactive Reactor Coolant Loop Technical Specification 3.3.A. ll (Safety Injection 'System) prohibits power operation with less than three reactor coolant loops in service. This prohibition is further discussed in UFSAR Section 14.2.6. The Surry uprating analysis effort has not included any analyses of two loop operation which would provide the licensing basis for two loop power operation. The initial assumptions for FSAR analyses are that the plant is maintained within the limits of the Technical

. Specifications. Therefore, because two loop operation is and will continue to be prohibited by Technical Specifications, no analysis of this event is required for uprated conditions. Since the plant zero load conditions are not changed by the uprating, the startup of an inactive reactor coolant loop (zero power cases) discussed in the UFSAR are not impacted.

3.3.3 Likelihood of Turbine-Generator Unit Overspeed Surry UFSAR Section 14.2.13 presents the assessment of this event. The existing analysis has accounted for the effects of turbine missiles generated at speeds of up to 120 % of rated turbine-generator speed. The turbine-generator speed is constant and is not dependent upon reactor power level. The failure modes and consequences of turbine-generator overspeed which are evaluated in the UFSAR are not affected by the proposed uprated conditions. The existing analysis of this event, therefore, remains applicable for operation at the proposed .conditions.

38

3.4 Evaluation of Validated Events 3.4.1 Rupture of Main Steam Pipe This section presents the evaluation performed to demonstrate that the proposed conditions do not invalidate the existing licensing analysis basis for core and containment response effects of the rupture of a main steam pipe inside containment. This evaluation has involved reviewing the existing basis, specifying how it satisfies the applicable regulatory criteria and demonstrating that the proposed operating conditions are bounded by the assumptions employed in the existing analysis basis.

3.4.1.1 Core Thermal-Hydraulics Asses.sment A rupture of a main steam pipe is assumed to include any accident which results in an uncontrolled steam -release from a steam generator. The release can occur due to a break in a pipe line or due to a valve malfunction. The steam release results in an initial increase in steam flow which decreases during the accident as the steam pressure falls. The energy removal from the Reactor Coolant System causes a reduction of reactor coolant temperature and pressure. With a negative moderator *temperature coefficient, the cooldown results in a reduction of core

  • shutdown margin. If the most reactive control rod assembly is assumed stuck in its fully withdrawn position, there is a possibility that the core will become critical and return to power even with the remaining control rod assemblies inserted. A return to power following a main steam pipe rupture is a potential problem mainly because of the large hot channel factors which exist when the most reactive rod is assumed stuck in its fully withdrawn position. Assuming the worst combination of circumstances which could lead to resumption of power generation following a main steam line break, the core is ultimately shut down by the boric acid in the Safety Injection System.

The existing analyses were evaluated to assess potential impact from the proposed uprated conditions. All the cases described in UFSAR Section 14.3.2 assume hot zero power initial conditions with all but the most reactive control assembly inserted. If the reactor is just critical or operating at power at the time of a main steam line break, the reactor is tripped by the normal overpower protection system when the power level reaches a trip point. Following a trip at 39

power the reactor coolant system contains more stored energy than at no load, the average coolant temperature is higher than at no load and there is appreciable energy stored in the fuel.

Thus, the additional stored energy is removed via the cooldown caused by the main steam line break before the no load conditions of reactor coolant system temperature and shutdown margin assumed in the analyses are reached. After the additional stored energy has been removed, the cooldown and reactivity insertions proceed in the same manner as in the analysis which assumes a no load condition at time zero. However, since the initial steam generator mass is greatest at no load, the magnitude and duration of the reactor coolant system cooldown are less for main steam line breaks occurring at power. Since the operating conditions at no-load are not impacted by the core uprate a reanalysis was not required.

3.4.1.2 Containment Response As.sesmient The existing licensing analysis basis for containment response to a postulated main steamline break was evaluated for potential impact from the proposed core uprating. The analysis basis was modified from its original status as described below. Analysis of the containment response following a steamline rupture was not included in the original NSSS safety analyses performed for Surry Units 1 and 2. The containment integrity design assessment was based upon the calculation of effects following a large break LOCA accident (the containment design basis accident).

The impact of main steamline break on containment response was evaluated during the analyses performed for elimination of the boron injection tank. In 1983, Virginia Power requested a license amendment which allowed a reduction in the minimum required boric acid storage tank boron concentration of the boron injection tank (3.4.1-1). Reference (3.4.1-2) documented an evaluation of the MSLB containment response which was requested by NRC. The NRC, in the SER for the associated Technical Specifications changes (3.4.1-3), made these observations concerning the containment temperature effects of MSLB for Surry:

'The licensee has performed sensitivity studies to address the impact of reducing the BIT boron concentration on early MSLB energy release, and has

  • 40

concluded that the current equipment qualification temperature envelopes for the Surry plants are adequate. Since LOCA conditions dominate the containment functional design considerations, the licensee used the LOCA temperature profiles for post-accident equipment qualification in lieu of MSLB temperature profiles ... Based on a review of the information submitted by the licensee, and because of the similarity of the licensee's request to other staff actions, we conclude that the licensee's proposal to eliminate the minimum boron concentration requirement in the BIT will not adversely affect the containment functional performance.'

From this statement, it is concluded that containment temperature profiles associated with the large break LOCA analysis represent the limit approved by the NRC in Reference (3.4.1-3).

Later in the Evaluation section of Reference (3.4.1-3), the assessment of Reference (3.4.1-2) is discussed:

'The November 30, 1983 letter responded to staff questions related to the

  • containment response following a postulated design basis main steam line rupture with a reduced boron concentration. The licensee compares the Surry analysis to that performed for the Beaver Valley Power Station and concludes that the Beaver Valley calculations are bounding.'

The November 30, 1983 letter (3.4.1-2) addressed both the containment temperature and pressurization aspects of the MSLB event. It stated that although MSLB does not form the basis for the equipment qualification containment temperature envelopes, the effect of the boron reduction on MSLB containment temperatures would not be significant. Reference (3 .4 .1-2) made the comparison and described the conservatisms in the Beaver Valley MSLB containment pressurization analysis versus Surry. It is concluded from the above statement that the NRC has effectively approved the Beaver Valley containment pressure response as an acceptable bounding result for application to Surry .

  • 41

Summary of Surry MSLB Licensing Basis

. The details of the preceding discussion can be summarized to indicate the current licensing analysis status. The following lists the key features of the Surry Unit 1 and 2 licensing analysis basis for containment response to a design basis main steamline break accident. This basis was previously approved in the NRC' s SER for boron injection tank concentration reduction (3.4.1-).

1. Transient temperature & pressure behavior for containment design is established from analysis of design basis large break LOCA.
2. LOCA temperature transient results are used for post-accident equipment qualification as allowed by IE Bulletin 79-0lB and its supplements. Enclosure 4 to IE Bulletin 79-0lB states that for a PWR MSLB inside containment, "equipment qualified for a LOCA environment is considered qualified for a MSLB environment in plants with automatic spray systems not subject to disabling single component failures". The Surry spray systems meet this condition.
3. MSLB transient temperature & pressure . behavior is established from an analysis of design basis MSLB for Beaver Valley Unit 1 which bounds the expected response for Surry Unit 1 and 2.
4. The transient temperature & pressure behavior for the Surry design basis large break LOCA bounds that obtained in the Beaver Valley Unit 1 MSLB analysis.

For the uprating evaluation, it is necessary to establish that the proposed conditions will not invalidate the conclusions previously established with respect to main steamline break containment response. The proposed uprating has no effect upon the first two aspects of basis listed above, since these are associated with application of regulatory requirements. Such administrative issues are independent of plant operating conditions. For the uprating evaluation, it is *thus only necessary to confirm the items 3 and 4 listed above concerning the relative severity of Surry and Beaver Valley analyses.

42

Comparison of Surry and Beaver Valley Analyses Item 3 requires validation that the expected containment response to a main steamline break for Surry is bounded by the Beaver Valley Unit 1 response documented in Reference (3.4.1-2). The Beaver Valley analysis was concluded to be bounding primarily because of a much greater assumed auxiliary feed water flowrate than is credible for Surry. The assumed flowrate to the faulted steam generator for Beaver Valley is approximately 4 times-the Surry value of 400 gpm.

Since the proposed uprating involves essentially no change in steam gen~rator operating parameters, the previous conclusion that Surry MSLB containment response is bounded by Beaver Valley 1 remains valid.

Validation of item 4 requires demonstrating that the revised Surry LOCA analysis containment

  • -* response bounds the .expected Surry MSLB response. The uprating containment response to a large break LOCA is described in Section 3.6.2. The mass and energy releases from the revised.

LOCA analysis were compared with the corresponding MSLB values used in the previous evaluation. The revised Surry LOCA analysis results bound the Surry MSLB results documented

  • previously (3.4.1-2).

References (3.4.1-1) Letter from W. L. Stewart to Harold R. Denton (NRC), "Amendment to Operating Licenses DPR-32 and DPR-37, Surry Power Station Units 1 and 2, Proposed Technical Specifications Change," Serial No. 521, September 13, 1983.

(3.4.1-2) Letter from W. L. Stewart to Harold R. Denton (NRC), "Supplement to An Amendment to Operating Licenses DPR.:.32 *and DPR Proposed Reduction in Boron Concentrations - Surry Power Station Units 1 and 2, 11 Serial No. 521B, November 30, 1993.

(3 .4 .1-3) 11 Safety Evaluation by the Office of Nuclear Reactor Regulation Related to Amendment No. 95 to Facility Operating License No. DPR-32 and Amendment No.

94 to Facility Operating License No. DPR Virginia Electric and Power Company Surry Power Station, Unit Nos. 1 and'2 -Docket Nos. 50.:.280 and 50-281, February 11 24, 1994. (NRC SER for BIT boron concentration reduction) 43

3.4.2 Excessive Heat Removal Due to Feedwater System Malfunctions The current licensing basis analysis of this event, described in Section 14.2.7 of the Surry UFSAR, assumed a core rated power of 2546 MWt. The existing analysis was validated to

  • confirm that all key safety parameter values assumed bound the proposed uprating conditions.

Two types of feedwater malfunction events were considered - feedwater temperature reduction and excessive feedwater flow. A rapid decrease in feedwater temperature would be caused by the accidental opening of the feedwater heater bypass valves, diverting flow around the low pressure feedwater heaters, while excessive feedwater flow would result from the full opening of feedwater regulating and bypass valves in one or more steam generator loops due to malfunction of the feed water control system or operator error. The assumptions regarding the feedwater temperature and flow transients remain bounding for uprated operation.

The limiting excess feedwater flow event is a transient resulting from a sudden increase in feedwater flow to 150% of its normal level in all three loops, with rod control in the automatic mode. Because of the increased feedwater flow the core will stabilize at a slightly higher power due to moderator reactivity feedback. However, the mismatch between feed water and steam flow rates will eventually activate the steam generator high-high level trip causing feedwater isolation.

Even after feedwater isolation the steam generator inventories will continue to boil away since power is still being generated in the core, until the steam generator low-low level setpoint is reached tripping the reactor. In the most limiting feedwater temperature reduction event assuming a 20°F drop in temperature, the core power will reach a new equilibrium level at about 3 % higher than the initial level, soon after the feedwater temperature stabilizes at the lower value.

Both events were analyzed using the reference Surry two-loop model developed for use with the RETRAN code (3.4.2-1). Detailed thermal hydraulic analysis was performed with the COBRA code (3.4.2-2). Of the two events the excess feedwater flow transient is more limiting with respect to departure from nucleate boiling (DNB), but still retains an adequate margin to the DNBR limit.

  • 44

References (3.4.2-1) VEP-FRD-41A, "Reactor System Transient Analysis Using the RETRAN Computer Code," Virginia Electric and Power Company, May 1985.

(3.4.2-2) VEP-FRD-33-A, "Vepco Reactor Core Thermal/Hydraulic Analysis Using the COBRA IIIC/MIT Computer Code," October, 1983 .

  • 45

3.4.3 Loss of Normal Feedwater The loss of normal feedwater event analysis described in Section 14.2.11 of the Surry UFSAR assumed a core rated power of 2546 MWt. The existing analysis was validated to confirm that all key safety parameter values assumed bound the proposed uprating conditions. This transient results in a loss in the capability of the secondary system to remove the heat generated in the reactor. It is characterized by a rapid rise in the RCS pressure, temperature and the pressurizer water volume. The transient is terminated by a reactor trip (which occurs on a low-low steam generator water level signal) and the cooling provided by auxiliary feed water flow. The auxiliary feedwater provides a heat sink following reactor trip to remove residual heat, which otherwise could heat the primary system water to the point where water relief from the pressurizer could occur, potentially resulting in core damage. Since the plant is tripped well before the steam generator heat transfer capability is reduced, the primary system variables never approach a DNB condition.

  • The existing UFSAR analysis of this transient was performed to explicitly account for the effects of reactor coolant system pump heat (3.4.3-1). The analysis was performed using the RETRAN computer code with the single loop analysis model described in Reference (3.4.3-2). The results showed that there is no water relief from the pressurizer safety or relief valves during the

. transient. All the key analysis assumptions delineated in the UFSAR have been confirmed to equal or bound the proposed uprated conditions. These key parameters include: core rated power, RCS average temperature, reactor coolant pump net heat addition, auxiliary feedwater flowrate, steam generator secondary side liquid inventory and steam generator safety valve capacity. The results and conclusions of the existing analysis therefore remain applicable for uprated operation of Surry Unit 1 and 2.

References (3.4.3-1) Letter from R.H. Leasburg (VP) to H. R. Denton (NRC), "Supplement to Proposed Technical Specification Change," Serial No. 539, September 14, 1981.

(3.4.3-2) VEP-FRD-41A, "Reactor System Transient An3:1ysis Using the RETRAN Computer Code," Virginia Electric and Power Company, May 1985.

46

3.4.4 Rupture of a Control Rod Drive Mechanism Housing (Control Rod Assembly Ejection)

A rupture of a control rod drive mechanism housing is described in Section 14.3.3 of the Surry UFSAR. This analysis was performed in accordance with* the approved Virginia Power methodology (3.4.4-1). The existing analysis assumed a core rated power of 2546 MWt. The analysis was validated to determine potential impact of the proposed uprating conditions. The key safety parameters for this transient are primarily. core-related features such as ejected rod worth, post-ejection peaking factor and amount of doppler reactivity feedback. These analysis parameters are verified for each reload core as part of the reload safety evaluation process.

Validation of values for these key core-related parameters will continue for reload cores designed

  • *under* the proposed uprated conditions.

The existing analysis supports a moderator temperature coefficient (MTC) limit of + 3 pcm/°F from zero to 50% rated thermal power, linearly decreasing to Opcm/°F at 100% rated thermal power. This is the upper limit specified in *the Core Operating Limits Report for present operating cycles.

In addition to these core-related features, core rated power is the most significant remaining key safety parameter. Since the existing analysis assumed the uprated power level of 2546 MWt, it is applicable for the uprated conditions. The results and conclusions of the existing analysis therefore remain applicable for uprated operation of Surry Units 1 and 2.

References (3.4.4-1) VEP-NFE-2-A, "VEPCO Evaluation of the Control Rod Ejection Transient",

December 1984 .

  • 47

3.4.5 Small Break Loss of Coolant Accident The analysis of the small break LOCA transient is reported in Section 14.5.2 of the Surry UFSAR. The existing analysis assumed a core rated power of 2546 MWt. The analysis was performed with the NOTRUMP Evaluation Model (3.4.5-1) (3.4.5-2). This analysis was evaluated to determine the potential impact of the proposed uprated conditions.

Major analysis assumptions have been validated to bound the proposed uprated conditions, plant fuel design and Technical Specifications limitations presented in the present license amendment request. The value of each parameter is equal to or conservative with respect to the proposed operating values. It is therefore concluded that the existing analysis of record, for operation at

  • the uprated core thermal power of 2546 MWt with Steam Generator Tube Plugging (SGTP) up to 15% in any SG will comply with all of the acceptance criteria specific in 10 CFR 50.46:
1. The calculated peak fuel rod clad temperature is below the requirement of 2200°F.
2. The amount of fuel element cladding that reacts chemically with water or steam does not exceed 1 % of the total amount of Zircaloy in the reactor.
3. The clad temperature transient is terminated at a time when the core is still amenable to cooling. The localized cladding oxidation limits of 17% are not exceeded during or after quenching.
4. The core remains amenable to cooling during and after the break.
5. The core temperature is reduced and the long-term heat is removed for an extended period of time.

Specifically, the 3 inch cold leg break was determined to be the limiting break, consistent with previous analyses. The reanalysis resulted in a limiting peak clad temperature of 1852°F, a maximum local oxidation of 3.20% and a total core zirconium-water reaction less than the 1 %

limit.

48

  • References (3.4.5-1) WCAP-10079-P-A, Meyer, P. E.: "NOTRUMP, A Nodal Transient Small Break And General Network Code," August 1985.

(3.4.5-2) WCAP-10054-P-A, Lee, N., et al.: "Westinghouse Small Break ECCS Evaluation Model Using The NOTRUMP Code," August 1985.

49

3.4.6 Large Break Loss of Coolant Accident The existing analysis of record for the large break LOCA transient was performed assuming a core rated power of 2546 MWt. The analysis employed the 1981 Evaluation Model with BASH (3.4.6-2). This analysis was implemented as the analysis of record via a station 10CFR50.59 evaluation (3.4.6-1) in conjunction with the provisions of Surry Technical Specification 6.2.C (relating to the Core Operating Limits Report). Analysis assumptions have been made which reflect operation with uprated core power and increased steam generator tube plugging (SGTP) in addition to changes in other key analysis inputs. This analysis was evaluated to confirm that assumed key parameter values bound the parameter values associated with the proposed uprating.

This analysis was performed using the Westinghouse 1981 large break LOCA evaluation model with BASH. Technical Specification 6.2.C lists this as an acceptable reference methodology for determination of relevant power distribution limits in the Core Operating Limits Report. The Surry analysis uses a corrected. version of the LOCBART code, which is part of the BASH

  • Evaluation Model. Westinghouse has corrected and improved the spacer grid heat transfer model used in the BART and BASH ECCS Evaluation Models (3.4.6-3).

The analysis assumes an uprated core power of 2546 MWt, with the associated primary and secondary system parameters. The analysis assumes that 15 % of the tubes in each steam generator are plugged. *The key safety parameter values have been validated to be equal to or bound those from the proposed uprated condition.

The analysis assumes LHSI flow performance data which are conservatively lower than previous LHSI test results from Surry. The performance data used in this analysis was benchmarked to a LHSI flow of 2970 gpm for the three lines delivering to a RCS backpressure of O psig (14. 7 psia) with a full RWST .

  • 50

The analysis assumes a reference cosine axial power distribution with a peak Heat Flux Hot Channel Factor, FQ(z), value of 2.32. In addition, the analysis assumes a slightly greater hot assembly relative power factor of 1.465.

These and other major analysis assumptions have been validated to bound the proposed uprated conditions, plant fuel design and Technical Specifications limitations presented in the present license amendment request. The value of each parameter is equal to or conservative with respect to the proposed operating values. It is therefore concluded that the existing analysis of record, for operation at the uprated core thermal power of 2546 MWt with SGTP up to 15 % in any SG will comply with all of the acceptance criteria specific in 10 CFR 50.46:

  • 1. The calculated peak fuel rod clad temperature is below the requirement of 2200 °F.
2. The amount of fuel element cladding that reacts chemically with water or steam does not exceed 1 % of the total amount of Zircaloy in the reactor.
3. The clad* temperature transient is terminated at a time when the core is still amenable to cooling. The localized cladding oxidation limits of 17 % are not exceeded during or after quenching.
4. The core remains amenable to cooling during and after the break.
5. The core temperature is reduced and the long-term heat is removed for an extended period of time.

Specifically, the double-ended, cold-leg guillotine break with a discharge coefficient (CJ of 0.4 was determined to be the limiting break size and location, consistent with previous analyses.

The reanalysis resulted in a limiting peak clad temperature of2120°F, a maximum local cladding oxidation of 8.67%, and a total core metal-water reaction of less than 1 %.

References (3.4.6-1) "Surry Power Station Units 1 and 2 - Safety Evaluation for Revised Large Break LOCA Analysis, 11 10CFR50.59 Safety Evaluation 94-082, March 28, 1994.

(3.4.6-2) WCAP-10266-P-A, Rev. 2, "The 1981 Version of the Westinghouse ECCS Evaluation Model using the BASH Code, 11 March 1987.

  • 51

(3.4.6-3) Letter from Nick Liparulo (Westinghouse-Manager, Nuclear Safety & Regulatory Activities) to USNRC, "Notification of Changes to the Westinghouse Large Break LOCA ECCS Evaluation Model," ET-NRC-92-3787, December 22, 1992; transmits WCAP-10484, Addendum 1, "Spacer Grid Heat Transfer Effects During Reflood" .

  • 52

3.5 Evaluation of Reanalyzed Events 3.5.1 Uncontrolled Control-Rod Assembly Withdrawal from a Subcritical Condition A control rod assembly withdrawal incident is defined as an uncontrolled addition of reactivity to the reactor core by the withdrawal of control rod assemblies, resulting in a power excursion.

While the probability of a transient of this type is extremely low, such a transient could be caused by a malfunction of the reactor control or control rod drive systems, or by operator error. This could occur with the reactor either subcritical or at power. The "at power" case is discussed in Section 3.5.2.

Reactivity is added at a prescribed and controlled rate in bringing the reactor from a shutdown

.* condition to a low power level during startup by control rod withdrawal. Although the initial startup *procedure uses the method of, boron dilution, the normal startup is with control rod assembly withdrawal. Control rod assembly motion can cause much faster changes in reactivity than can be made by changing boron concentration.

The control. rod drive mechanisms are wired into preselected banks, and these bank configurations are not altered during core life.* The assemblies are therefore physically prevented from being withdrawn in other than their respective banks. Power supplied to the rod banks is controlled such that no more than two banks can be withdrawn at any time. The control rod drive mechanism* is of the magnetic latch. type and the coil actuation is sequenced to provide variable speed rod travel. The maximum reactivity insertion rate is postulated in a detailed analysis assuming the simultaneous withdrawal of the combination of the two rod banks of the maximum combined worth at maximum speed.

Should a continuous control rod assembly' withdrawal be initiated from subcritical or low power conditions, the transient will be terminated by the following automatic safety features:

1. , Source *range flux level trip - actuated when either of two independent source range channels indicates a flux level above a preselected, manually adjustable value. This trip function may be manually bypassed when either intermediate range flux channel indicates
  • 53

a flux level above* the source range cutoff power level. It is automatically reinstated when both intermediate range channels indicate a flux level below the source range cutoff power level.

2. Intermediate range control rod stop - actuated when either of two independent intermediate range channels indicates a flux level above a preselected, manually adjustable value. This control rod stop may be manually bypassed when two out of the four power range channels indicate a power level above approximately 10% of full power. It is automatically reinstated when three of the four power range channels are below this value.
3. Intermediate range flux level trip- actuated when either of two independent intermediate range channels indicates a flux level above a preselected, manually adjustable value.

This trip function may be manually bypassed when two of the four power range channels are reading above approximately 10% of full power and is automatically reinstated when three of the four channels indicate a power level below this value.

4. Power range flux level trip (low setting) - actuated when two out of the four power range
  • channels indicate a power level above approximately 25% of full power. This trip function may be manually bypassed when two of the four power range channels indicate a power level above approximately 10 % of full power and is automatically reinstated when three of the four channels indicate a power level below this value.
5. Power range control rod stop - actuated when one out of the four power range channels indicates a power level above a preset setpoint. This function is always active.
6. Power range flux level trip (high setting) - actuated when two out of the four power
  • range channels indicate a power level above a preset setpoint. This trip function is
  • always active.

Reactor protection for subcritical and low power rod withdrawal events has traditionally been assumed to be provided by the Power Range high flux trip (low setpoint) for events initiated both above and below permissive P-6. Source Range protection was assumed to not be available, since the Source Rang~ channel lacked the redundancy required to assume trip availability. in UFSAR accident analyses. More recently, however, a Technical Specification change was 54

sought to increase the required number of available Source Range Channels below permissive P-6 from 1 to 2 (3.5.1-1). This change, along with Source Range trip bistable operability testing to verify Source Range channel response characteristics, validates the assumption of Source Range trip availability in accident analyses. An additional Technical Specification change was made to further enhance the availability of the Source Range channel by imposing an allowable Source Range channel outage time for power levels below P-6. This change ensures startup protection by providing confirmation of the availability of the source range channel (3 .5 .1-6).

Rod withdrawal from subcritical events may be initiated from above or below permissive P-6.

Below P-6, one or two reactor coolant pumps may be operating, or RCS cooling may be provided by the Residual Heat Removal (RHR) system. For any operating condition below P-6, Source Range protection or open trip breakers provide reactor protection against a rod withdrawal from subcritical event. Additional protection is provided by the other operable reactor protection system circuitry, including the Intermediate Range and Power Range Qow setpoint) reactor trips. As was demonstrated in the North Anna Core Uprating submittal (3 .5 .1-

  • 3), and subsequent responses to NRC questions (3.5.1-4)(3.5.1-5), events initiated from allowable operating conditions below P-6 will not result in significant power generation or core heat flux when a reactor trip is actuated on the Source Range channel. This conclusion is also applicable to Surry. Therefore, reactor protection is provided for all operating conditions below P-6, including one-RCP, two-RCP, and RHR operation.

The nuclear power response to a continuous reactivity insertion originating above P-6 is characterized by a very fast rise terminated by the reactivity feedback effect of the negative fuel temperature coefficient. This self-limitation of the, initial power burst results from a fast negative fuel temperature feedback (Doppler effect) and is of prime importance during a startup incident since it limits the power to a tolerable level before external control action. After the initial power burst, the nuclear power is momentarily reduced and then if the incident is not terminated by a reactor trip, the nuclear power increases again, but at a much slower rate.

55

3.5.1.1 Method of Analysis A complete reanalysis of the rod withdrawal from subcritical event was performed for the Surry core uprating effort, using the RETRAN computer code and the associated Virginia Power reactor system transient analysis methodology (3.5.1-7). The analysis includes the simulation of the plant neutron kinetics, and the core thermal and hydraulic feedback equations. The RETRAN code calculates nuclear power, core heat flux, average fuel, clad _and coolant temperatures. The detailed core thermal-hydraulics analysis was performed using the COBRA computer code (3.5.1-8) to generate the MDNBR (Minimum Departure from Nucleate Boiling Ratio) at the statepoint for the DNB-limiting case of the transient. .

Unlike previous Surry analyses, the current reanalysis assumes the operation of all three reactor coolant pumps. Proposed Technical Specification changes which accompany this amendment request prohibit achieving criticality with less than 3 reactor coolant pumps operating. The following additional assumptions were made to provide conservative results for this analysis:

1. Since the magnitude of the nuclear power peak reached during the initial part of the transient, for any. given rate of reactivity* insertion, is strongly dependent on the Doppler reactivity feedback, a conservative fuel-temperature-dependent Doppler coefficient was used.
2. The contribution of the moderator reactivity coefficient is negligible during the initial part of the transient because the heat transfer time constant between the fuel and the moderator is much longer than the nuclear flux response constant. However, after the initial nuclear flux peak, the succeeding rate of power increase is affected by the moderator reactivity coefficient. A conservative value of +6 pcm/°F for the MTC was used in the analysis since the positive value yields the maximum peak core heat flux (1 pcm = 10-s Ak/k).
3. The reactor is assumed to be at hot zero power with a Tav, of 547°F. This assumption is more conservative than that of a !ower initial system temperature. The higher initial system temperature yields a larger fuel-to-water thermal conductivity, a larger fuel
  • 56

thermal capacity, and a less negative (smaller absolute magnitude) Doppler temperature coefficient (DTC). The less negative coefficient reduces the Doppler feedback effect, thereby increasing the nuclear flux peak. The high nuclear flux peak combined with a high fuel thermal capacity and large thermal conductivity yields a larger peak heat flux.

Initial multiplication (k.,) is assumed to be 1.0 since this results in the maximum nuclear power peak.

4. The most adverse combination of instrument and setpoint errors, as well as delays for trip signal actuation and control rod assembly release, are taken into account. A 10%

increase has been assumed for the power range high flux trip low setpoint, raising it from the-nominal 25%- to 35%. The rise in nuclear flux is so rapid, however, that the effect of errors in the trip setpoint on the actual time at which the rods are released is negligible.

5. The rate of negative reactivity insertion corresponding to the trip action is based on the assumption that the highest worth control* rod assembly rs stuck in its fully withdrawn position. A conservatively low value was assumed for the total trip reactivity from zero power.
6. The maximum positive reactivity insertion rate assumed (112.5 pcm/sec) is greater than that for the simultaneous withdrawal of the combination of the two control banks having the greatest combined worth at maximum *speed (45 in/min).
7. The initial power level was assumed to be below the power level expected for any shutdown condition. The combination of highest reactivity insertion rate and lowest initial power produces the highest peak heat flux.
8. The delayed neutron fraction (l3 ir} was assumed to be at its maximum value, as that 0

would maximize the thermal energy released into the coolant. .

9; On the secondary side, the condenser dump valves are assumed closed, thus causing a pressure buildup that would contribute to the heatup of the primary system.

For the pressure-limiting case, to conservatively overestimate the pressurization in the RCS, the

  • following additional assumptions are made:

57

    • .(i)

(ii)

Initial pressurizer pressure is "2280 psia* (30 psi above the nominal) .

Initial pressurizer level is 5% above the nominal.

(iii) PORVs and pressurizer sprays that would mitigate the pressurization are not credited.

(iv) The PSV loop seals are filled with water. Displacing the liquid in the loop seal causes a delay in the opening* of the PSVs, thus driving the primary system pressures higher.

In the DNB-limiting case, the following specific assumptions are made to decrease the primary pressurization and increase the energy released into the coolant, thus minimizing the calculated margin to DNB:

(i) Initial pressurizer pressure and level are held at their nominal values.

(ii) Pressurizer sprays and PORVs are *credited, thereby mitigating system pressurization.

(iii) For the MDNBR calculation, lower bound values for the pressurizer pressure, RCS flow and the bypass flow fraction are used.

3.5.1.2 Results Figures 3.5.1-1 through 3.5.1-3 show the transient behavior*for a DNB-limiting case, with the incident terminated by reactor trip at 35 % power. As seen in Figure 3 .5 .1-1, the nuclear power increases to the trip point in 7 .3 sec. The power then overshoots to approximately 966 %, but only momentarily. Therefore, the energy .release and the fuel temperature increase are moderate. The thermal flux response, of interest for DNB considerations, is shown in Figure

3. 5 .1-2. The beneficial effect of the inherent thermal lag of the fuel is evidenced by a peak heat flux of only 53% of the nominal rating. There is an adequate margin to DNB during the transient since the rod surface heat flux remains below the design value, and there is a high degree of subcooling at all times in the core. Figure 3 .5 .1-3 shows the response of the average fuel, cladding and coolant temperatures. The average fuel temperature peaks at 956°F which 58

. is much lower than the nominal full power value of 1311 °F. The average coolant temperature rises to only 566.4 °F while the clad temperature peaks at 597°F. A COBRA calculation at the statepoint with very conservative adjustments to the thermal-hydraulic input variables gives a minimum DNBR above the design limit.

  • The pressure-limiting case results in a pressurizer pressure peak of 2656 psia at 11. 6 sec, while the overall primary system peaks at 2720 psia in'* the cold leg at 11. 8 sec.

3.5.1.3 Conclusion It is concluded that, *in the unlikely event of a control rod assembly withdrawal incident from

  • . subcritical: conditions, the core and reactor coolant system are not adversely affected, as the peak thermal power and the peak- coolant temperature in the DNB-limiting case are well below their nominal full power values. An explicit statepoint calculation using very conservative assumptions results in a minimum DNBR above the design limit.

In the case that examines primary system pressure, it can be shown that the RCS pressure peaking will be less than 110 % of design pressure.

References (3.5.1-1) Letter from W. L. Stewart to USNRC, "Virginia Electric and Power Company; Surry Power Station Units 1 and 2; Proposed Technical Specifications Changes,"

Serial No.87-212, dated May 22, 1987.

(3.5.1-2) Letter from C. P. Patel (USNRC) to W. L. Stewart, "Surry Units 1 and 2 -

Issuance of Amendments Re: Changes to Sections 3. 7 and 4.1 (TAC Nos. 55380, 55381, 60307, and 60308)," Serial No.88-096, dated February 17, 1988.

(3.5.1-3) Letter from W. L. Stewart to USNRC, Amendment to Operating Licenses NPF-4 and NPF-7; North Anna Power Station Units 1 and 2; Proposed Technical Specifications Changes," NRC Letter Serial No.85-077, dated May 2, 1985 (North Anna Core Uprating Project).

59

(3.5.1-4) Letter from W. L. Stewart to H. R. Denton, "Virginia Electric and Power Company; Response to NRC Request for Additional Information; Core Uprate Program; North Anna Power Station Units 1 and 2," Serial No. 85-772A, dated February 6, 1986.

(3.5.1-5) Letter from L. B Engle (NRC) to W. L. Stewart, Amendments 84 and 71 to Facility Operating Licenses NPF-4 and NPF-7, NRC Letter Serial No.86-575, dated August 25, 1986 (North Anna Core Uprating Project).

(3.5.1-6) Letter from B. C. Buckley to W. L. Stewart, "Surry Units 1 and 2 - Issuance of Amendme~ts Re: Intermediate Range High Flux Reactor Trip Setpoint," dated April 21, 1993.

(3.5.1-7) VEP-FRD-41-A, "Reactor System Transient Analyses Using the RETRAN Computer Code," May 1985.

(3.5.1-8) VEP-FRD-33-A, "Vepco Reactor Core Thermal/Hydraulic Analysis Using the COBRA IDC/MIT Computer Code," October 1983.

60 .

Figure 3.5.1-1 Rod Withdrawal from Subcritical - Neutron Power 0

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Figure 3.5.1-2 Rod Withdrawal from Subcritical - Core Heat Flux 0

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  • TI ME CSECl 62

Figure 3.5.1-3 Rod Withdrawal from Subcritical - Temperatures

  • (Fuel, Clad, Moderator) 0 0

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LINE - FUEL DASHED - CLAD DOTTED - MODERATOR 63

3.5.2 Uncontrolled Control-Rod Assembly Withdrawal at Power

  • The Uncontrolled Rod Cluster Control Assembly (RCCA) Bank Withdrawal at Power (RWAP) event is characterized by a reactivity increase resulting from the withdrawal of one or more RCCA banks from the core during power operation. The initiating event is a postulated single failure in a control system such as the rod control system or the reactor control system or faulty action by a reactor operator. The addition of* reactivity to the core tends to be distributed uniformly, due to the RCCA bank arrangement. The energy removal capabilities of the secondary *system tend *to lag
  • behind
  • the core--power- increase- resulting** from the -rod bank withdrawal. This energy mismatch causes the Reactor *Coolant System (RCS) pressure and temperature to increase. The possibility exists that the core heat flux could exceed the ability of the RCS fluid to conduct the heat from the fuel, potentially leading to a Departure from Nucleate Boiling (DNB) and subsequent cladding failure. The RCS temperature and pressure transients can be limited by the operation of RCS and main steam (MS) pressure relief valves; however, the power excursion generally continues until terminated by the addition of negative reactivity from the safety control rod banks due to a reactor trip. The limiting event conditions occur shortly after safety control bank insertion, when the minimum DNB ratio (MDNBR)
  • .occurs. The Reactor Coolant Pumps (RCPs) remain operational throughout the event so that, in the absence of DNB, sufficient RCS flow exists to adequately handle the transfer of energy

As stated above, maintaining the fuel cladding integrity is the primary concern for the RWAP event. However, maintaining the RCS ,as a fission product barrier is also a concern.

Specifically, the heating of the RCS fluid during a RWAP event causes the fluid density to decrease, resulting in a volumetric expansion of the fluid. Operation of the pressurizer sprays and Power Operated Relief Valves (PORVs) can mitigate the effects of the subsequent pressure increase, but can do nothing to counteract the volumetric expansion. Should the expansion of the RCS fluid continue uncontested, the discharge of liquid through the PORVs or Pressurizer Safety Valves (PSVs) is likely. Industry tests have demonstrated the capability of the PORVs and PSVs to relieve significant liquid flow rates. For the rod withdrawal at power event, the reactor prot~tion system terminates the heatup of the reactor coolant system before any liquid reUef occurs .

  • 64

Provided the integrity of the fission product barriers is not compromised, sensible and decay heat can be removed by steaming to the condenser through the steam bypass system, to the atmosphere *through the MS PORV or the. Main Steam Safety Valves (MSSVs), or any

. combination of the three methods. Feedwater remains available to the steam generators (SGs) from either the Main Feedwater (MFW) system or the Auxiliary Feedwater (AFW) system to replenish the secondary coolant. Shortly after reactor trip, the energy removal capability of the SGs will exceed the RCS sensible and decay heat levels, and the reactor operators/automatic control systems will function to maintain. the plant at the new equilibrium condition.

The automatic features of the reactor protection system that prevent core damage in a RWAP incident include the following:

1. Nuclear power range instrumentation actuates *a reactor trip if two out of the four channels !exceed an overpower setpoint.
2. Reactor trip is actuated if any two out of three delta-T channels exceed an overtemperature delta-T setpoint. This* setpoint is automatically varied with coolant temperature and axial power imbalance, coolant temperature and pressure to protect against DNB.
3. Reactor trip is actuated if any two out of three delta-T channels exceed an overpower delta-T setpoint. This setpoint is automatically varied with coolant temperature and axial power imbalance to ensure that the allowable heat generation rate (kW/ft) is not exceeded.
4. A pressurizer high pressure reactor trip, actuated from any two out of three pressur~

channels, is set at a fixed point. This set pressure is less than the set pressure for the pressurizer safety valves.

  • 5. A pressurizer high water level reactor. trip, actuated from any two out of three level channels, is actuated at a setpoint. This affords additional protection for control rod .

assembly withdrawal incidents.

6. In addition to the above listed reactor trips, there are the following control rod assembly withdrawal blocks:

a; High nuclear power (one out of four).

b. High overpower delta-T (two out of three).
c. High overtemperature delta-T (two out of three).

65

The region of permissible operation (power, pressure, and temperature) is bounded by the following reactor trips: nuclear overpower (fixed setpoint), high pressure (fixed setpoint), low pressure (anticipatory rate sensitive setpoint) and overpower and overtemperature delta T (variable setpoints). These trips are designed to prevent a DNBR less than the design DNBR limit.

The manner in which the combination of overpower and overtemperature delta-T trips provide protection over the full range of reactor coolant system conditions is illustrated in UFSAR Figure 7.2-1.

Upon trip of the reactor by the above protection system features, the turbine generator is also tripped. As a result the steam generator shell-side pressure and reactor coolant temperature will increase rapidly. However there is not a significant increase if the steam bypass pressurizer pressure control systems are functioning normally.

The analysis presented below shows that no fuel damage occurs by demonstrating that the DNBR limit is met for the rod withdrawal event. Also shown is that the RCS and MS system pressure

  • .relieving devices have sufficient capacities to ensure the safety of the unit without relying on the mitigating capabilities of the pressurizer pressure control or MS bypass systems.

3.5.2.1 Method of Analysis The RWAP transient is analyzed with theRETRAN (3.5.2-1) and COBRA (3.5.2-2) codes. The RETRAN system code simulates the neutron kinetics, Reactor Coolant System, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves. The code computes pertinent plant variables, including temperatures, pressures, and power level. The COBRA code is used to calculate the DNBR for the transient using the WRB-1 DNB correlation (3.5.2-3).

For the DNBR evaluation cases, the initial power level, pressurizer pressure, and RCS average tempelc!ture are assumed to be at values consiste~t with the nominal hot full power values at the uprated (2546 MWt) cond.i.tion. -The effects of normal control system variations and

  • measurement uncertainties associated with these parameters are treated statistically and 66.

incorporated into the design DNBR limit (see UFSAR Chapter 3.4, "Thermal/Hydraulic Design and Evaluation") in accordance with Virginia Power's Statistical DNBR Methodology (3.5.2-4).

The calculation of the DNBR is consistent with the current Technical Specifications Core Operating Limit Report limit on F~H as modified by a 0.3 part power multiplier.

For cases where reactor coolant system pressures are of primary interest, the initial reactor power, pressurizer pressure and RCS average temperature are assumed to be at the maximum values consistent with steady state full power operation, including allowances for calorimetric and other instrument errors. -In-addition-these cases-are performed with the-pressurizer pressure relieving devices (pressurizer spray and PORVs) disabled.

All cases incorporate the assumption of 15% steam generator tube plugging. To obtain conservative results the following assumptions are made:

l. Reactivity coefficients - two cases are analyzed:
a. Minimum reactivity feedback. A positive moderator temperature coefficient of

+ 6.0 pcm/ °Fin conjunction with a least negative Doppler temperature coefficient is used in the analysis .

  • 2.
b. Maximum reactivity feedback. A conservatively large negative moderator coefficient -45.0 pcm/oF and a large (in absolute magnitude) negative Doppler temperature coefficient are assumed.

The reactor trip on high neutron flux is assumed to be actuated at a_conservative value of 118 % of nominal full power. The delta-T trips include all adverse instrumentation and setpoint errors, while the delays for the trip signal actuation are assumed at their maximum values.

3. The RCCA trip insertion characteristic is based on the assumption that the highest worth assembly is stuck in its fully withdrawn position.
4. A spectrum of reactivity insertion rates is analyzed. The maximum positive reactivity insertion rate is greater than the maximum rate of two sequential control rod banks moving at the maximum speed with normal overlap..

The effect of rod cluster control assembly movement on the axial core power distribution is accounted for by causing a decrease in overtemperature and overpower delta-T trip setpoints proportional to a decrease in margin to DNB.

67

3.5.2.2 Results Figure 3.5.2-1 shows the minimum DNBR as a function of reactivity insertion rate from initial full power operation for the minimum and maximum reactivity feedback. It can be seen that the high-neutron flux and overtemperature delta-T trip setpoints provide protection over the whole range of reactivity insertion rates since the minimum DNBR for all insertion rates is greater than the design limit.

Figures 3.5.2-2 through 3~5.-2-4-show the-response of.nuclear-power;**pressurizer pressure, and average coolant temperature to the. limiting DNBR case initiated from full power (.8 pcm/sec insertion rate). The slow rod withdrawal allows for a sufficient rise in temperature and pressure to cause a* trip on overtemperature delta-T. The minimum DNBR for this case remains well above the limit as indicated by Figure 3 .5 .2-1.

Figures 3.5.2-5 and 3.5.2-6 show the minimum DNBR as a function of reactivity insertion rate

. for the rod withdrawal event*starting at60 and lOpercent power, respectively. The results are similar to the 100 percent power case, except that as the initial power is decreased, the range over which the overtemperature delta-T trip is effective is increased. In all cases the DNBR is greater than the design limit. '

Figures 3.5.2-7 through 3.5.2-8 show the nuclear power, RCS average temperature, and cold

.. leg pres*sure response to ;the limiting overpressure rod withdrawal incident. This case initiates

  • from 12 % power with a reactivity insertion rate of 55 pcm/sec and minimum reactivity feedback. The pressurizer pressure reaches the pressurizer high pressure trip setpoint at 11.37 seconds* and the reactor trips after a 2 second delay. The cold leg pressure reaches a peak value of 2742.34 psia at 15.2 sec into the transient.

Cases performed to maximize the main steam pressure (maximize the RCS average temperature prior to trip) show that the maximum main steam pressure occurs for rod withdrawal events initiated at 12 % power. The cases providing the maximum main steam pressure are those which allow a gradual but large rise in the RCS average temperature. These are cases with low insertion rates and minimum reactivity feedback or relatively high insertion rates with maximum reactivity feedback. As these cases trip on overtemperature delta-T the RCS temperature is 68

nearly the same and therefore the maximum main steam pressure is fairly constant over a range of insertion rates at approximately 1190 psia. A sensitivity to steam generator tube plugging

  • (SGTP) between unplugged and 15 % SGTP indicates the unplugged conditions could increase the main steam pressure by approximately 10 psi.

3.5.2.3 Conclusions This analysis indicates that for an uncontrolled rod withdrawal at power event, the following criteria are met:

a. The minimum DNBR remains above the 95/95 DNBR design limit (UFSAR Section 3.2.3).
b. Pressure at the most limiting RCS location is less than 110% of RCS design pressure, or 2750 psia (the Emergency Condition Stress Limit specified in Section ill of the ASME Code).
c. Pressure at the most limiting Main Steam System (MSS) location is less than 110% of MSS design pressure, or 1210 psia (the* Emergency Condition Stress Limit specified in Section ill of the ASME Code).
  • References (3.5.2-1) VEP-FRD-41-A, "Reactor System Transient Analyses Using the RETRAN Computer Code," May 1985.

(3.5.2-2) VEP-FRD-33-A, "Vepco ~eactor Core Thermal/Hydraulic Analysis Using the COBRA illC/MIT Computer Code," October 1983.

(3.5.2-3) VEP-NE-3, R. C. Anderson, "Qualification of the WRB-1 CHF Correlation in 11 the Virginia Power COBRA Code, July 1990.

(3.5.2-4) VEP-NE-2-A, "Statistical DNBR Evaluation Methodology, 11 June 1987.

  • 69

Figure 3.5.2-1 Rod Withdrawal at Power Minimum DNBR vs Insertion Rate at Full Power 2.2 2.1 2

HIGH\T~P* * * * ...

I I

I HIGH FLUX TRIP 1.9 I I

a: I a, I z I C I I

1.8 ,

OTC~ TRIP I I

I

            • I
1. 7 ' I OTDT TRIP 1 .6

_ _ _Maximum Reactivity Feedback

---Minimum Reactivity Feedback 1.5 0.1 1 10 100 REACTIVITY INSERTION RATE (pcm/sec)

  • 70

Figure 3.5.2-2 Rod Withdrawal at Power Nuclear Power - Full Power Limiting DNBR Case 120 100 iii C 80 E0 z

0 C:

Cl) tJ Cl) 60 Q.

Cl) 3:

0 Q.

...re Cl) u::, 40 2':

20 0

0 20

  • 40 60 80 100 120 l1me Csecondsl
  • 71

Figure 3.5.2-3 Rod Withdrawal at Power Pressurizer Pressure - Full Power Limiting DNBR Case 2350 2300 2250 ca "iii C.

...::I Cl) 2200 Ill en Cl)

C.

Cl)

-~

N 2150 V)

V)

l C.

2100 2050 I 2000 0 20 40 60 80 100 120 Time (seconds) 72

Figure 3.5.2-4 Rod Withdrawal at Power RCS Average Temperature - Full Power Limiting DNBR Case 590 588 586 584

~

m l'CI Cl,)

C.

582 E

m f- 580 Cl,)

Cl l'CI Cl,)

<t 578 C.

0 0

..J 576 574 572 570 0 20 40 60 80 100 120 nme (seconds) 73

Figure 3.s:2-s Rod Withdrawal at Power Minimum DNBR vs Insertion Rate at 60% Power 2.7 2.6 . .

2.5 I I

HIGH FLUX TRIP 1 I

2.4 I I

I I

2.3

  • I I

I 2.2 I HIGH FLUX\IP

. a:

CXl ___ Maximum Reactivity Feedback I 2

C ----Minimum Reactivity Feedback I 2.1 I I

I I

2 I I

I I

1 .9 I I

I I

1.8 . . I

" I

1. 7 I . . ~'

" I OTDT TRIP OTDT TRIP 1.6 0.1 1 10 100 REACTIVITY INSERTION RATE (pcm/sec) 74

Figure 3.5.2-6 Rod Withdrawal at Power Minimum DNBR vs Insertion Rate at 10% Power 3.4 I I

3.3 I I

3.2 I I

I 3.1 I I

3 I 2.9 I I

2.8 I I

2.7 I

HIGH FLUX TRIP_.,

I 2.6 _ _Maximum Reactivity Feedback I

a: ----------Minimum Reactivity Feedback aJ I z 2.5 I C I 2.4 I I

2.3 I I

2.2 I I

2.1 I I

2 I OTOT TRIP I OTDT TRIP i

I 1.9 I

I 1.8 I

\ ~

1. 7 \,

1.6 0.1 10 100 REACTIVITY INSERTION RATE ( pcm/secl 75*

Figure 3.5.2-7 Rod Withdrawal at Power

  • Nuclear Power - RCS Overpressure Case 120 I I

100 80

  • ~

~

if iii Cl)

~

.EC:

2 0

0 60 T

-u C:

Cl) 2= ...CJ Cl)

Q.

I I

40 20 -

0 0 5 10 15 20 Time lseconds) 76

Figure 3.5.2-8 Rod Withdrawal at Power RCS Average Temperature - RCS Overpressure Case 574 572 570 568 566 u.

Qj

-=... 564 ca Qj s-

=Qj 562 I-CJ) u a:

S60 558 556 554 552 0 5 . 10 15 20 Time (secondst

  • 77

Figure 3.5.2-9 Rod Withdrawal at Power Cold Leg Pres.sure - RCS Overpresmre Case 2750 -

2700 I

I i

2650 --

2600

  • Ill "iii 2550 C.

Cl)

Ill Ill Cl) 2500 C.

T 2450 l 2400 I 2350 2300 0 5 10 15 20 Time (secondst

  • 78

3.5.3 Control-Rod Assembly Drop/Misalignment When operating at power, a dropped (withdrawn) control rod, single or multiple, may initiate a transient leading to reduced margins to fuel design limits and in particular to DNBR design limits. This approach to the design limits would result from increased power distribution peaking factors with the inserted (dropped) rods and a possible power transient produced by feedback or automatic control which might, depending on the control system, cause the power level to exceed the initial level. The Surry units have a turbine runback and control rod withdrawal block which *are initiated by*any rod-on-bottom-signal or- one-of four negative flux rate signals to mitigate the effects of a dropped rod event.

Westinghouse has developed and received NRC approval for a methodology for analyzing the dropped rod event which would not take credit for any direct trip or automatic power reduction due to the dropped rod (3.5.3-1). Virginia Power validated this methodology for application to Surry and implemented this approach as the design methodology for the Surry units (3.5.3-2).

Application of this methodology allows elimination of any or all of these reactor protection system features: Turbine Runback on Rods on Bottom, Control Rod Withdrawal Block on Rods on Bottom, Turbine Runback on Negative Flux Rate and Control Rod Withdrawal Block on Negative Flux Rate.

The methodology involves performing analyses in three separate design areas to evaluate the dropped rod event. These analyses, referred to as transient, nuclear, and thermal:-hydraulic analyses, provide 1) the statepoints of reactor power, temperature, and pressure at the most limiting time in the transient, 2) the radial power peaking factor at the most limiting conditions in the transient, and 3) the DNB analysis at the conditions determined by items 1 and 2, respectively. Only the nuclear and thermal-hydraulic analyses are affected by changes in the core loading or power rating. The thermal-hydraulic analysis is based on plots of inlet temperature versus core power level at constant pressure and FAR and the limiting DNBR.

These curves, called the dropped rod limit lines, were reanalyzed assuming the uprated core power and are available for use. The nuclear analysis determines the pre-drop F t.H at the DNBR limit and compares this to the Fill limit, assuming the reload-specific values of moderator temperature coefficient, dropped rod worth, and inserted bank worth. This analysis will be carried out once the reload design calculations are completed for the uprated core.

79

References (3.5.3-1) WCAP-11394-P-A, "Methodology for the Analysis of the Dropped Rod Event,"

January, 1990.

(3.5.3-2) VEP-FRD-42, Revision 1-A, "Reload Nuclear Design Methodology," September, 1986 and Supplement 1, by Letter from M. L. Bowling to NRC, Serial No.93-723, dated December 3, 1993.

80

3.5.4 Chemical and Volume Control System Malfunction

3. 5 .4 .1 Identification of Causes and Accident Description Reactivity can be added to the core by feeding primary-grade water into the Reactor Coolant System via the reactor makeup portion of the Chemical and Volume Control System. Boron dilution is a manual operation under strict administrative controls with procedures calling for a limit on the rate and duration of dilution. A boric acid blend system is provided to permit the operator to match-the boron -concentration of-reactor-coolant-makeup water-during normal charging to that in the Reactor Coolant System. The Chemical and Volume Control System is designed to limit, even under postulated failure modes, the potential rate of dilution to a value which, after indication through alarms and instrumentation, provides the operator sufficient time to correct the situation in a safe and orderly manner.

The opening of the primary water makeup control valve creates a dilution flow path to the Reactor Coolant System. Inadvertent dilution from this source can be readily terminated by closing the control valve. For makeup water to be added to the Reactor Coolant System at

  • . pressure, at least one charging pump must be running in addition to a primary grade water transfer pump.

The rate of addition of unborated makeup water to the Reactor Coolant System when it is not at pressure is limited by the capacity of the two primary grade water transfer pumps. The maximum addition rate is defined as the flow rate achieved with both pumps running. The boric acid from the boric acid tank is blended with primary grade water in the blender; the composition is determined by the preset flow rates of boric acid and primary grade water on the control board.

Two separate operations are required to dilute: 1) The operator must switch from the automatic makeup mode to the dilute mode. 2) The blender switch must be turned to the "on" position.

Omitting either step prevents dilution, making the possibility of an inadvertent dilution very remote.

81

Information on the status of the reactor coolant makeup is continuously available to the operator.

Lights are provided on the control board to indicate the operating condition of the pumps in the Chemical and Volume Control System. Alarms are actuated to warn the operator if boric acid or demineralized water flow rates deviate from preset values as a result of system malfunction.

Although the proposed core uprating affects only the dilution cases initiated from power operation, all operating conditions were evaluated and are discussed below.

3.5.4.2 Method of Analysis 3.5.4.2.1 General To cover all phases of plant operation, boron dilution during Refueling, Cold Shutdown,

.Intermediate Shutdown, Hot Shutdown, Reactor Critical, and Power Operation (automatic and manual control modes) are considered (3.5.4-1). The case of an inadvertent dilution during a planned dilution or makeup activity is not considered here as an accident analysis, since evaluation of such dilutions is not required by the Standard Review Plan. Boron dilution during startup of an inactive loop is discussed in UFSAR Section 14.2.6.

The following parameter value ranges were considered in the boron dilution analyses:

. 1.

  • Steam Generator Tube Plugging Fraction (SGTPF): 0 % to 15 %*SGTP. The effective RCS Volume excludes the pressurizer, reactor vessel upper head, and plugged steam generator tube volumes.
2. Dilution Flow Rate (QJ with RCS at Operating Pressure corresponds to the maximum charging pump flow rate with the RCS pressurized in charging mode with one pump operating.
3. Dilution Flow Rate for Unpressurized RCS corresponds to the maximum flow rate the primary grade water transfer pumps are capable of delivering to the charging pump inlet.
4. Bounding values of dilution flow density and RCS Water Density were assumed (maximum dilution density and minimum RCS density).
5. Minimum Shutdown Margin at Power: 1. 77% AK/K.

82

.3.5.4.2.2 Boron Dilution During Refueling and Cold Shutdown

  • *The primary grade water flow path is locked out during Refueling and Cold Shutdown

. conditions, thereby procedurally preventing a boron dilution event from occurring during these operating conditions (3.5.4-1),(3.5.4-2). Technical Specifications require manual valve 1-CH-223 (2-CH-223 for Unit 2), the primary grade makeup water control valve, to be locked in the closed position within 15 minutes following a planned dilution during Refueling and Cold Shutdown conditions. This ensures that the source of primary grade water is completely isolated from the reactor coolant system. -As an -alternative; Technical Specifications indicate that manual valves 1-CH-212, 1-CH-215, and 1-CH-218 (2-CH-212, 2-CH-215, and 2-CH-218 for Unit 2) may be locked shut if for any reason it is desired that 1-CH-223 (2-CH-223) be maintained open.

This alternative combination of valve lockouts has the same effect as locking out valve 1-CH-223 (2-CH-223). An additional indication of the status of the primary grade water system is provided by the primary grade water flow recorder on the vertical board in the main control room.

It is recognized that there are many paths for dilution of the moderator. The rationale behind isolating the main primary .grade water flow. path is to preclude dilutions that would cause a rapid, uncontrolled decrease in shutdown margin. Low dilution flow rates have a high probability of being identified and corrected before a significant loss of shutdown margin occurs .

.* 3.5.4.2.3 Boron Dilution During Intermediate Shutdown and Hot Shutdown Administratively controlled shutdown margin requirements have been implemented at Surry to ensure that at least 15 minutes are available from initiation of dilution to loss of shutdown margin for corrective operator action in response to aii inadvertent boron dilution at Intermediate.

Shutdown and Hot Shutdown (3.5.4-1), (3.5.4-2). The adequacy of these administrative shutdown margin requirements is verified for each reload core.

The analysis which determined the magnitude of the administrative shutdown margin requirements assumed a 245 gpm dilution flow rate, which is the maximum flow rate of

  • unborated water that can be delivered by the primary grade water transfer pumps. For the case in which no reactor coolant pumps (RCPs) are operating, a reduced RCS volume (consistent with 83

mid-loop Residual Heat Removal System operation) is assumed. For the case in which one or more reactor coolant pumps (RCPs) are running, the analysis assumes the full RCS volume (less the upper head, pressurizer, and plugged tube volume) is undergoing dilution. The administrative shutdown margin required to obtain acceptable accident analysis results is smaller for this case.

Intermediate Shutdown includes RCS temperatures between 200°F and 547°F, and Hot Shutdown includes RCS temperatures greater than 547°F. A lower RCS temperature at Intermediate Shutdown reduces the-temperature-(and density) difference-between the,RCS and cold dilution flow. This reduces the effective reactivity insertion rate due to boron dilution. In order to ensure that the Intermediate Shutdown conditions Boron Dilution event analysis bounds that for Hot Shutdown conditions, a maximum RCS temperature and minimum dilution fluid temperature are* assumed in the Intermediate/Hot Shutdown Boron Dilution event analysis.

There are several plant features that help to preclude the possibility of an inadvertent boron dilution at Intermediate and Hot Shutdown. Nuclear instrumentation is available to provide a secondary indication of a dilution in progress. For the time during which the source range

  • instrumentation is operable, a source range count rate alarm is expected before half of the shutdown margin available at the initiation of the transient is diluted away.

Station operating procedures prescribe that the shutdown rod banks be withdrawn from the core while the unit is in startup conditions through power operation conditions. Should an unplanned boron dilution incident occur with the reactor at these conditions (either because of equipment failure or operator error), the high flux alarm will alert the operator of this condition and the shutdown rod banks can be inserted into the core immediately. This will give the operator sufficient time to isolate the sources of primary grade water from the reactor coolant system before shutdown margin is lost.

An additional indication of the status of the primary grade water system is provided by the PG water flow rate recorder on the vertical .board in the main control room .

. It is recognized that there are many paths for dilution of the moderator. The emphasis here is

  • to place controls and checks on the main primary grade water flow path .to preclude dilutions 84

that would cause a rapid decrease in shutdown margin. Low dilution flow rates have a high probability of being identified and corrected before a significant loss of shutdown margin occurs.

Ensuring adequate operator response time, an~ placing controls and checks on the dilution flow path ensures that a boron dilution event will not lead to criticality.

3.5.4.2.4 Boron Dilution at Reactor Critical and at Power The analysis of the Boron Dilution event at Reactor Critical conditions demonstrates that at least 15 minutes are available from positive indication of.a dilution in progress (alarm or reactor trip) to loss of shutdown margin for corrective operator action (3.5.4-1),(3.5.4-2). The analysis conservatively assumed a minimum of 1.77% shutdown margin is available at the beginning of the dilution.

The Boron Dilution at Power event is analyzed for the rods in automatic and manual control cases. The results of the analysis indicate that 15 minutes are available after positive indication of a dilution in progress (reactor trip) for corrective operator response before a return to criticality .

  • Bounding transient analysis results are obtained for the 100% power case with rods in manual control and only the Technical Specification minimum required shutdown margin available to compensate for the dilution. The minimum shutdown margin required by Technical Specifications is verified to be available at the rod insertion limit. Any additional SDM available with rods at the rod insertion limit represents unmodelled conservatism.

For automatic rod control cases initiated at or below 100% power, rod insertion due to a T.v/T"'r deviation will result in a rod insertion limit alarm prior to the consumption of any of the Technical Specification minimum required shutdown margin. With either automatic or manual rod control, boron dilution events initiated at or below 100% power will result in an RCS temperature increase and, ultimately, in a high RCS temperature alarm~ Positive indication of a dilution in progress in the analyzed boron dilution at power case (100% power; manual rod control) is assumed to be provided by the OT~ T reactor trip. In this analysis case, the high RCS temperature alarm is conservatively assumed to not actuate .

      • 85

In terms of reactivity insertion rate, the automatic rod control case of the Boron Dilution at Power event is bounded in severity by the manual rod control case, since automatic rod insertion

  • reduces the effective reactivity insertion rate due to boron dilution. The reactivity insertion rate transient resulting from an inadvertent boron dilution is essentially identical to that of a control rod assembly withdrawal accident. The reactivity insertion rates used in the analysis are well within the range of reactivity insertion rates considered in Section 3.5.2, "Uncontrolled Control Rod Withdrawal at Power." Acceptable DNBR results for the Boron Dilution at Power analysis are inferred from the results of the Rod Withdrawal at Power accident analysis.

3.5.4.3 Conclusions Because of the procedures involved in the dilution process, and the administrative blocking of the primary grade water flow path, an erroneous dilution is not considered credible in the refueling and cold shutdown operating conditions. Nevertheless, numerous alarms and indications are available to alert the operator to any unintentional dilution of boron in the reactor coolant. For credible boron dilution events, (at Intermediate and Hot Shutdown, Reactor Critical and at Power), the maximum reactivity addition rate is slow enough to allow the operator to determine the cause of the addition and to take corrective action before the excessive shutdown

  • margin is lost.

References (3.5.4-1) Letter from W. L. Stewart to USNRC, "Virginia Electric and P~~er Company; Surry Power Station Units No. 1 and 2; Proposed Technical Specification Change; Boron Concentration Increase," NRC Letter Serial No. 90 746, dated December 21, 1990 (Surry Boron Concentration Increase Project). Also NRC Letter Serial No. 90-746A, "Request for Additional Information," dated February 8, 1991.

(3.5.4-2) Letter from B. C. Buckley (NRC) to W. L. Stewart, Amendments 153 & 150 to Facility Operating Licenses DPR-32 and DPR-37, NRC Letter Serial No.91-238, dated April 11, 1991 (Surry RWST Boron Concentration Increase Project) .

  • 86

3.5.5 Excessive Load Increase Incident 3.5.5.1 Introduction

  • ..An excessive load increase incident is defined as a rapid increase in the steam flow that causes a power mismatch between the reactor core power and the steam generator load demand. The reactor control system is designed to accommodate a 10 percent step load increase or a 5 percent/minute ramp load increase in the range of 15 to 100 percent of full power. Any loading rate in excess of these values may cause a reactor trip actuated by the reactor protection system.

This accident could result from either an administrative violation, such as excessive loading by the operator, or an equipment malfunction in the steam dump control or turbine speed control.

Although a reactor trip for this event is not expected to occur, core protection for the excessive

, load increase event is provided by the overtemperature and overpower delta-T trips, the power range high neutron flux trip and the low pressurizer pressure trip. This transient is analyzed to determine the effect of the uprating on the calculated DNBR.

  • . 3.5.5.2 Method of Analysis This accident is analyzed using the LOFTRAN code (3.5.5-1) and Westinghouse standard non-statistical thermal-hydraulic analysis methodology. Four cases are analyzed to demonstrate the plant behavior following a 10 percent step load increase from rated load. These cases are as follows:
1. Manually controlled reactor at beginning-of-life.
2. Manually controlled reactor at end-of-life.
3. Reactor in automatic control at beginning-of-life.
4. Reactor in automatic control at end-of-life.

At beginning-of-life, the core is assumed to have a zero moderator temperature coefficient of reactivity and therefore, the least inherent transient capability. At end-of-life, the moderator temperature coefficient of reactivity has its highest absolute value. This results in the largest amount of reactivity feedback due to changes in coolant temperature.

87

All other assumptions are consistent with those in the Surry UFSAR.

3.5.5.3 Results Figures 3.5.5-1 through 3.5.5-4 illustrate the transient with the reactor in the manual control mode. For the beginning-of-life case, power remains essentially constant and the average core temperature shows a large decrease. The minimum DNBR remains essentially constant throughout the transient. For the end-of-life, manually controlled case, there is an increase in power due to the moderator feedback~*TheDNBRdecreases slightly-below its-initial value-then remains constant. The DNBR remains above the limit value of 1.30 during the entire transient.

Figures 3.5.5-5 through 3.5.5-8 illustrate the transient assuming the reactor is in the automatic control mode. Both the beginning-of-life and the end-of-life cases show substantial increases in core power. Both the BOL and EOL cases show a slight increase in Tavg above the initial value.

For both the BOL and EOL cases, the minimum DNBR remains above the design limit value.

3.5.5.4 Conclusions

  • In all cases, the minimum DNBR during the transient is greater than the design limit value.

Also, equilibrium conditions of core power and core average temperature were reached in all four cases.

Reference (3.5.5-1) WCAP-7907-A, Burnett, T.W.T. et. al, "LOFTRAN Code Description," April, 1984 .

  • 88

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. Nuclear Power, Pressurizer Pressure & Water Volume

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3.5.6 Loss of Reactor Coolant Flow 3.5.6.1 Flow Coastdown Incidents A loss of flow incident can result from a mechanical or electrical failure in a reactor coolant pump or from an interruption in the power supply to these pumps. If the reactor is at power at the time of the incident, the immediate effect is a rapid increase in coolant temperature. This increase could result in DNB with subsequent fuel damage if the reactor is not tripped promptly.

The following reactor trip circuits provide the necessary protection against a loss of flow incident:

1. Low reactor coolant flow,
2. Reactor coolant pump motor circuit breaker opening,
3. Low voltage on pump power supply busses, and
4. Low frequency on pump power supply busses (opens RCP supply breakers).

Of these, only the low reactor coolant flow reactor trip is assumed in the analysis. The low frequency and low voltage signals are not credited for reactor protection, but are assumed to trip the RCPs at their appropriate setpoints .

The simultaneous loss of electric power to all reactor coolant pumps is the most severe credible loss of flow event. For this condition, reactor trip together with flow sustained by the inertia of the coolant and rotating pump parts (following the RCP trips) is sufficient to prevent Reactor Coolant System overpressure and the limiting DNBR from being reduced below the design DNBR limit.

3.5.6.2 Method of Analysis The two limiting cases that were analyzed are as follows:

1. Loss of three out of three RCPs from a nominal power level of 100% (uprated 2546 MWt), due to an undervoltage condition .
      • 97
2. Loss of three out of three RCPs from a nominal power level of 100% (uprated 2546 MWt), due to a frequency decay condition (-5 Hz per second).

Partial losses of flow from the loss of fewer than three reactor coolant pumps are protected by the same low flow reactor trip. Because of the identical protection setpoint, and correspondingly higher coolant flow rates throughout the transient, the partial loss of flow events are less limiting than the complete* 1oss of flow events. Therefore, the partial loss of flow events are bounded by the complete loss of flow analyses and no specific partial loss of flow analyses are run.

The above analyses assume core characteristics associated with the 15 x 15 SIF fuel product.

The analysis incorporates an enthalpy hot channel factor (F~h) of 1.56 and the "Statistical DNBR Evaluation Methodology." (3.5.6-1)(3.5.6-2)

The normal power supplies for the pumps are three buses supplied by the generator. Each bus supplies power to one pump. When a generator trip occurs, the pumps are automatically transferred to a bus supplied from external power lines, and the pumps continue to supply coolant flow to the core. The simultaneous loss of power to all reactor coolant pumps is a

  • highly unlikely event. Following any turbine trip, where there are no electrical faults that
  • require tripping the generator from the pump supply network, the generator remains connected to the .network for approximately thirty (30) seconds. The reactor coolant pumps remain connected to the generator, thus e~uri11:g full flow for thirty (30) ~onds after t!te reactor trip before any transfer is made. Since each pump is on a separate bus, a single-bus fault would not result in the loss of more than one pump.

A full unit simulation with RETRAN (3.5.6-3) is used in the analysis to compute the core average and hot-spot heat flux transient responses, including flow coastdown, temperature, reactivity, and control-rod assembly insertion effects.

These data are then used in a detailed thermal-hydraulic computation using the Virginia Power COBRA code (3.5.6-4) to compute the DNB margin. This computation solves the continuity, momentum, and energy equations of fluid flow, together with the WRB-1 DNB correlation discussed in UFSAR Section 3.4.2.

98

A least negative Doppler Temperature Coefficient (-1.0 pcm/°F) and most positive Moderator Temperature Coefficient ( +6 pcm/°F) were assumed since these result in higher heat flux at the time of minimum DNBR. The sensitivity to the effective delayed neutron fraction was

  • evaluated. A minimum delayed neutron fraction was used because it produced the most limiting DNBR.

Following the loss of flow induced by underfrequency or undervoltage, the reactor is assumed to trip on low flow in any loop. The low flow trip setting is 90% of full loop flow; the trip signal is *assumed* to be--initiated at -87%- of-minimum -measured- flow,- allowing 3% for instrumentation errors. It is also assumed that, upon reactor trip, the most reactive control rod assembly is stuck in its fully withdrawn position, resulting in a minimum insertion of negative reactivity. The assumed trip reactivity was -4000 pcm which is confirmed to be bounding for each reload cycle.

Reactor coolant flow coastdown curves for the limiting undervoltage and underfrequency induced loss of flow accidents are shown in figures 3.5.6-1 and 3.5.6-1, respectively. The flow profile for the undervoltage transient includes an initial 2 % flow penalty to account for the potential of a "back EMF~ phenomenon prior to the trip of the RCP. The RCP will maintain flow at or above 98 % for undervoltage conditions less severe than the undervoltage trip setpoint. This is modelled by a prompt drop in flow from 100 % to 98 % of minimum measured flow followed by a five second delay prior to the RCP trip on (undervoltage). The reactor is not assumed to trip until the low flow setpoint has been reached.

3.5.6.3 Results Both the underfrequency and the undervoltage trip events were analyzed. The two events were found to have identical values of minimum DNBR. The minimum DNBR's for the two accidents showed a considerable margin to the design DNBR limit.

The transient responses of power, inlet temperature, average temperature, pressurizer pressure, and DNBR are plotted in Figures 3.5.6-3 through 3.5.6-8 for the undervoltage case and 3.5.6-9 through 3.5.6-14 for the underfrequency case.

99

References (3.5.6-1) Letter from B. C. Buckley (NRC) to W. L. Stewart, "Surry Units 1 and 2 -

Issuance of Amendments Re: F Delta-H Limit and Statistical DNBR Methodology," Serial No.92-405, June 1, 1992.

(3.5.6-2) VEP-NE-2-A, "Statistical DNBR Evaluation Methodology," June 1987.

(3.5.6-3) VEP-FRD-33-A, "VEPCO Reactor Core Thermal/Hydraulic Analysis Using the COBRA-IDC/MIT Computer Code," October 1983.

(3.5.6-4) VEP-FRD-41-A, "Reactor System Analysis Using the RETRAN Computer Code" ,-May 1985 .

100

Figure 3.5.6-1 Complete Loss of Flow - Undervoltage Case RCS Mass Flow Rate 0

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  • 3/01 94 14 .06. 11 101

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  • 3/01U4 14.36.25 110

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  • 3/01 /94 14.36.25 111

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  • 3/06/C'i 9.24.50 113

Figure 3.5.6-14 Complete Loss of Flow - Underfrequency Case

.Minimum DNBR *(Enlarged Scale)

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3.5. 7 Locked Rotor Incident 3.5.7.1 Identification of Causes and Accident Description

  • The Locked Rotor/Sheared Shaft events are characterized by the rapid loss of forced circulation in one Reactor Coolant System (RCS) loop. A Locked Rotor event is defined as the seizure of a reactor coolant pump (RCP) motor due to a mechanical failure. The Sheared Shaft event is defined as the separation of the RCP impeller from the motor due to the severance of the impeller shaft. For both the Locked Rotor and the Sheared Shaft events, the postulated RCP failure causes the reactor* coolant* flow-*rate *to decrease-more--rapidly than a normal RCP coastdown.

During power operation the reduction in RCS flow caused by a Locked Rotor or Sheared Shaft event results in degradation of the heat transfer between the fuel and the reactor coolant, and between the reactor coolant and the secondary coolant in the steam generator (SG). As a result of the reduced fluid velocity, the core differential ( Ii T) and average temperatures (T.vJ increase.

The reduced heat transfer to the secondary fluid also contributes to the reactor coolant temperature increase. The expansion of the RCS fluid that accompanies the temperature increase causes an insurge of coolant into the pressurizer, and thus an increase in the reactor coolant system pressure. The reduced fluid velocity and subsequent temperature rise also act to reduce the heat transfer from the fuel, causing the fuel temperature to increase. Fuel damage could then result if specified acceptable fuel damage limits are exceeded during the transient, i.e. if the fuel experiences a Departure from Nucleate Boiling (DNB). Due to the severe nature of these postulated failures, the likelihood that a limited number of fuel rods will experience DNB is significant. Thus, timely actuation of the Reactor Protection System (RPS) is required to help limit the number of potential fuel failures.

The immediate core power response during a Locked Rotor or Sheared Shaft event will change in accordance with the RCS temperature and pressure based on the magnitude and direction of the moderator reactivity feedback. As such, a Locked Rotor or Sheared Shaft event occurring in the presence of a positive Moderator Temperature Coefficient (MTC) will see an increase in core power as the RCS temperature increases. Conversely, the presence of a negative MTC will cause the core power to .decrease as the RCS temperature increases.

  • If the Rod Control System
  • 115

is in automatic, movement of the control rods will generally be in a direction such that a power reduction occurs.

The core power response is also influenced by the magnitude of the fuel Doppler coefficient.

The reduced capability of the reactor coolant to remove energy from the reactor core causes the fuel temperature to increase. In the presence of a negative fuel Doppler coefficient, a fuel temperature increase contributes negative reactivity to the core, which acts to diminish the core power increase.

The potential for a Locked Rotor or Sheared Shaft event is present during all modes of operation where at least one RCP is functioning to provide forced circulation. However, the consequences of a locked rotor or sheared shaft event are reduced dramatically when the reactor is not at power. During sub critical or zero power operation, natural circulation is more than adequate to remove decay heat following the loss of forced circulation. Thus, the potential for exceeding the specified fuel design limits is nearly zero when the reactor is not at power.

Maintaining the fuel cladding integrity is a primary concern for the Locked Rotor/Sheared Shaft

  • . event, although integrity may not be maintained for all fuel rods. Therefore, maintaining the RCS as a fission product barrier becomes more significant. Specifically, RCS integrity may be challenged as a result of the volumetric expansion of the fluid caused by the heating of the RCS fluid. Operation of the pressurizer sprays and power operated relief valves (PORVs) can help limit the impact of the subsequent pressure increase, but cannot counteract the volumetric

. expansion of the RCS fluid. In general; the short duration of the locked rotor event acts in concert with the functioning of the pressurizer safety valves (PSVs), ,to prevent excessive RCS pressurization. Thus, timely actuation of the RPS is also required to help limit the RCS pressure response ..

Sensible and decay heat can be removed by steaming to the condenser through the steam bypass system, to the atmosphere through the main steam (MS) PORV or the main steam safety valves (MSSVs), or any combination of the three methods. However, the desirability of a given method is based on system availability and the extent to which the fission product barriers have

replenish the secondary coolant. Shortly after the reactor is shut down, the energy removal capability of the SGs will exceed the RCS sensible and decay heat levels, and the reactor

  • operators/automatic control systems will function to maintain the plant at the new equilibrium condition.

3.5. 7 .2 Method of Analysis 3.5.7.2.1 General To cover all applicable phases*of plant*operation;*locked*rotor and sheared *shaft events during Cold Shutdown, Intermediate Shutdown, Hot Shutdown, Reactor Critical (manual rod control),

and Power Operation (automatic and manual rod control modes) are considered. A transient analysis is only required for the Locked Rotor and Sheared Shaft events at full power with manual rod control. The results for a Locked Rotor or Sheared Shaft event at any of the remaining operating conditions are bounded by those of the full power manual rod control case.

  • Except where otherwise noted, the following assumptions are made in the Locked Rotor/Sheared Shaft transient analysis:
1. The DNB analysis employs a statistical treatment of key analysis uncertainties; the transient cases are initiated from nominal thermal/hydraulic conditions (core power of 2546 MWth; .

vessel T.v, of 573.0°F; pressurizer pressure of 2250 psia; and the Technical Specification Minimum Measured Flow Rate).

2. The main steam and RCS overpressurization analyses employ a deterministic treatment of key analysis uncertainties (102 % power; nominal Tav, + 4 °F; nominal pressurizer pressure

+ 30 psi; and Thermal Design Flow).

3. Reactor protection is assumed to be provided by the low.coolant loop flow rate reactor trip at 87% of the applicable analysis flow rate. A 1.0 second trip delay is assumed.
4. The analysis supports a moderator temperature coefficient (MTC) core design limit of +6.0 pcm/F from 0% to 50% power and a linearly decreasing limit-to 0.0 pcm/Fat 100% power.

The analysis is non-limiting at EOC.

5. Unaffected reactor coolant pumps were assumed to trip 2.0 seconds after reactor trip on low loop coolant flow. The inertia of the unaffected pumps was conservatively reduced by 10%

from the design value.

117

6. In the DNB transient analyses, the turbine trip following reactor trip was conservatively assumed to not function. In the main steam and RCS overpressurization transient analyses, the turbine trip following reactor trip was conservatively assumed to actuate.
7. Manual rod control was assumed.
8. In the DNB transient analyses, the pressurizer sprays and PORVs are conservatively assumed to be operable. In the main steam and RCS overpressurization transient analyses, the pressurizer sprays and PORVs are conservatively assumed to not actuate.
9. The RCS overpressurization analysis assumes 50% bypass flow. The high degree of bypass flow in the overpressurization cases compensates-for* the uncertainty associated with the thermal/hydraulic behavior of the core due to coolant voiding during a locked rotor event.

3.5.7.2.2 Transient Analysis for DNB

  • .* The transient analysis for DNB considerations utilizes the RETRAN transient analysis code (3.5. 7-3) and the COBRA illC/MIT detailed core thermal/hydraulics code (3 .5. 7-4). The WRB-1 critical heat flux correlation (3.5.7-1) is used in the analysis.
  • The transient analysis for DNB is performed to determine the number of fuel pins that experience DNB as a result of a Locked Rotor or Sheared Shaft event. A fuel pin is assumed to fail if the predicted MDNBR *is less than the statistical DNBR (3.5. 7-2) Design Limit. The Lockr.d Rotor DNB event scenario is therefore designed to produce the most limiting DNB response. From an analytical perspective, this goal is achieved by choosing initial conditions and analysis assumptions that will maximize coolant temperature and the power-to-flow ratio and minimize pressure during the event.

The analysis results demonstrate that no rods have a calculated MDNBR less than the statistical DNBR Design Limit. The radiological dose consequences analysis for the locked rotor event (see Section 3.7.2.4) assumes 5% of the rods fail. Figures 3.5.7-1 through 3.5.7-3 provide transient results for core inlet mass flow rate, core heat flux and core inlet temperature from the limiting DNBR analysis case.

118

3.5.7.2.3 Transient Analysis for RCS and Main Steam Overpressurization The transient analysis**for RCS and main steam overpressurization considerations utilires the

.*RETRAN transient analysis code (3.5. 7-3). The transient analysis for overpressurization considerations verifies that the peak RCS pressure (intact cold leg pump exit pressure) and peak main steam pressure (intact loop steam generator pressure) remain below 110% of RCS and main steam design pressure (2750 psia and 1210 psia, respectively). The Locked Rotor overpressurization event scenario is designed .to produce the most limiting overpressurization response. *Froman analytical perspective,-this*goal is-achieved by-choosing-initial conditions and analysis assumptions that will minimize RCS energy removal and ~aximize core coolant expansion during the transient.

Figures 3.5. 7-4 and 3.5. 7-5 provide transient results for RCS pressure and steam generator

  • pressure from the limiting pressurization analysis cases.

3.5. 7 .3 Conclusions For the scenarios for which a transient analysis was performed, the following conclusions are applicable:

a. Acceptable offsite dose consequences are ensured, since the analysis demonstrates that the fraction of fuel rods predicted to experience Departure from Nucleate Boiling
  • .(DNB) is*. less than that which provides acceptable offsite dose analysis results. Dose calculations for locked rotor are presented in Section 3.7.2.4.
b. Reactor Coolant System (RCS) integrity is maintained throughout the transient as demonstrated by analysis of transient RCS pressure. Specifically, the maximum RCS pressure, which occurred in the intact cold leg pump exit, remained below 2750 psia throughout the transient.
c. Main Steam System (MSS) integrity is maintained throughout the transient as demonstrated by analysis of transient MSS pressure. Specifically, the maximum main steam pressure, which occurred in the intact loop steam genera~or, remained below 1210 psia throughout the transient.

119

References (3.5.7-1) VEP-NE-3-A, "Qualification of the WRB-1 CHF Correlation in the Virginia Power COBRA Code," July 1990 (3.5.7-2) VEP-NE-2-A, "Statistical DNBR Evaluation Methodology," Topical Report dated June 1987.

(3.5.7-3) VEP-FRD-41-A, "Reactor System Transient Analyses Using the RETRAN Computer Code," May 1985.

(3.5.7-4) VEP-FRD-33-A, "Vepco Reactor Core Thermal/Hydraulic Analysis Using the

  • COBRA me/MIT-Computer Code,"- October 1983.

120

Figure 3.5.7-1 Locked Rotor - DNBR Analysis Case Core Inlet Mass Flow Rate 0

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Figure 3.5. 7-2 Locked Rotor - DNBR Analysis Case Core Heat Flux 0

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  • ;Ir 1194 10.54.44 122

Figure 3.5.7-3 Locked Rotor - DNBR Analysis Case Core Inlet Temperature 0

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Figure 3.5. 7-4 Locked Rotor - RCS Overpressure Case RCS Pressures - Pressurizer, RCP Exit, Lower Plenum 0

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DOTTED - LOUER PLENUM 124

.. * '9/94 15.35.27

Figure 3.5. 7-5 Locked Rotor - RCS Overpressure Case Steam Generator Pressure 0

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  • ;.'~9/94 17.56.52 125

3.5.8 Los.s of External Electrical Load 3.5.8.1 General Discussion The loss of external electrical load may result from an abnormal variation in network frequency or other adverse network operating conditions. It may also result from a trip of the turbine generator or the opening of the main breaker from the generator that fails to cause a turbine trip but causes a large, rapid nuclear steam supply system load reduction by the action of the turbine control.

The unit is designed to accept a step loss of load from 100% to 50% without actuating a reactor trip. The automatic steam bypass system, with 40% steam dump capacity to the condenser, is able to accommodate this load rejection by reducing the severity of the transient imposed on the Reactor Coolant System. The reactor power is reduced to the new equilibrium power level at a rate consistent with the capability of the Rod Control System. The pressurizer relief valves may be actuated, but the pressurizer safety valves and the steam generator safety valves do not lift for the 50 % step loss of load with condenser steam dumps.

In the event the steam bypass (condenser dump) valves fail to open following a large load rejection, or in the event of a complete loss of load with the bypass valves operating, the steam generator safety valves may lift and the reactor may be tripped on a high pressurizer* pressure, high pressurizer level or overtemperature fl. T signal. The steam generator shell-side pressure and reactor coolant temperature will increase rapidly. The pressurizer safety valves and steam generator safety valves are, however, sized to protect the Reactor Coolant and Main Steam Systems, respectively, against all load losses, including a complete loss of steam load without the bypass system (condenser dumps) or atmospheric dumps (main steam PORVs) available.

The steam dump valves will not be opened for load reductions of 10% or less. For larger load reductions they may open.

The most likely source of a complete loss of load on the Nuclear Steam Supply System is a trip of the turbine generator. In this case, there is a direct reactor trip signal (unless below approximately 10 % power) derived from either the turbine autostop oil pressure or a closure of the turbine stop valves. Reactor Coolant System temperatures and pressures do not significantly increase if the steam bypass and pressurizer pressure control systems are functioning normally.

126

However, in this analysis, the behavior of the Nuclear Steam Supply System is evaluated for a complete loss of steam load from full power without direct reactor trip. The analysis, presented

  • below, shows the adequacy of the pressure relieving devices to prevent Main Steam System and

.Reactor Coolant System overpressurization and to show that no fuel damage occurs. The latter is demonstrated by conservatively requiring that the 95/95 DNBR design limit is met for the hottest rod in the core.

As will be shown, the reactor coolant system and Main Steam System pressure relieving devices have sufficient-capacities to ensure the- safety* of.the--unit-without --relying--on the mitigating capabilities of the Automatic Rod Control, Pressurizer Pressure Control or Main Steam Bypass Systems.

3.5.8.2 Method of Analysis The complete loss of load transients are analyzed with the Virginia Power RETRAN (3.5.8.1) and COBRA (3.5.8-2) models.

  • The RETRAN model_ is used to perform the overall Reactor System transient analysis. The.

model describes the neutron kinetics, Reactor Coolant System including the pressurizer and pressurizer safety and relief valves and spray, and the Main Steam System including the steam generators and main steam safety valves. Outputs of the RETRAN analysis include reactor power level, , temperatures and pressures at various points in the Reactor Coolant System, pressurizer water -volume and Main Steam System pressure.

The COBRA model is used to calculate the detailed subchannel thermal conditions, including a time and position dependent Departure from Nucleate Boiling Ratio (DNBR).

3.5.8.3 Initial Operating Conditions For cases where the Departure from Nucleate Boiling Ratio (DNBR) is of interest, the initial power level, pressurizer pressure and RCS average temperature are assumed at their nominal hot full power values at the uprated (2546 MWt) condition. The effects of normal control

  • system variations and measurement uncertainties associated with these parameters are treated 127

statistically and incorporated into the design DNBR limit in accordance with Virginia Power's Statistical DNBR methodology (3.5.8-3).

For cases where Reactor Coolant System pressures are of primary interest, the initial reactor power and Reactor Coolant System temperature are assumed to be at their maximum values consistent with steady state full power operation, including allowances for calorimetric and other instrument errors. The initial Reactor Coolant System pressure is assumed to be at the minimum value consistent with steady state full power operation, including allowances for instrument errors. This results-in the maximum time-delay-to high -pressure trip.

The complete loss ofload is analyzed for both beginning-of-cycle (BOC) and end-of-cycle (BOC) conditions. At BOC a moderator temperature coefficient (MTC) of +3.0 pcm/°F is assumed.

The analysis supports a MTC core design limit of +6.0pcm/°F from 0% to 50% power and a linearly decreasing limit to 0.0 pcm/°F at 100% power. A Doppler temperature coefficient corresponding to the least negative value is used.

At EOC a moderator coefficient of -45.0 pcm/°F is assumed. A Doppler temperature coefficient corresponding to the most negative value is used.

No credit is taken for the operation of any of the main steam bypass (condenser dump) valves or of the power operated steam genei;ator relief valves. The steam generator pressure rises to the safety valve setpoint, where the release of steam through the safety valves limits the main steam pressure. The main steam safety valves are assumed to open at their design pressure setpoin t + 3 %, with an additional 3 % pressure accumulation to the full steam flow capacity.

Two cases for both the beginning and end of life are analyzed as follows:

1. Full credit is taken for the effect of pressurizer spray and power-operated relief valves in reducing or limiting primary coolant pressure.
2. No credit is taken for the effect of pressurizer spray and power-operated relief valves

. in reducing or limiting primary coolant pressure.

128

  • All cases examined assumed reactor is in manual rod control mode. This provides the limiting initial reactor power response to the event. In addition, all cases incorporate the assumption of 15 % steam generator tube plugging.

3.5.8.4 Results Only the BOC cases are presented here, since they provide the limiting results with respect to the analysis acceptance criteria of interest.

3.5.8.4.1- BOC Case with RCS Pressure Control Transient results for the RETRAN BOC/Pressure Control case are presented in Figures 3.5.8-1 to 3.5.8-6. These are discussed as follows:

Figure 3.5.8 Nuclear power initially increases in the presence of the RCS heatup and the assumed positive moderator coefficient. Peak power reaches about 116.5 % before the effects of reactor trip on high pressurizer pressure dominate.

  • Figure 3.5.8 RCS inlet temperature increases by about 41 °F prior to the excursion being terminated by reactor trip.

Figure 3.5.8 Pressurizer liquid volume responds to the RCS heatup by increasing from 696 cubic feet to a maximum of about 1057 cubic feet leaving about 240 cubic feet of minimum steam space.

Figure 3 .5. 8 Cold leg pressure follows a similar trend, reaching a peak value of 2667 psia at 17 .5 seconds.

Figure 3.5.8-5 -Main steam pressure reaches a maximum value of 1187.3 psia (23.7 psia margin to the design limit) at 22 seconds. This case is expected to be limiting for main steam pressure.

129

Figure 3.5.8 Hot Channel DNBR initially increases slightly due to the pressure increase.

Then as the core inlet temperature starts to increase, there is a DNBR decrease to a minimum of l.84 at about 16 seconds, i.e. about 1 second after the shutdown and control rods begin to insert. As can be seen, this event is not limiting from the standpoint of hot channel DNBR.

3.S.8.4.2 BOC Case Without Pns.mre Control This is the limiting RCS overpressure case. The results are presented in Figures 3.5.8-7 to 3 .5. 8-11. These are discussed as follows:

  • Figure 3.5.8 Nuclear power initially increases in the presence of the RCS heatup and the assumed positive moderator coefficient. Peak power reaches about 105 % before the effects of reactor trip on high pressurizer pressure dominate. The peak power is lower for this case than for the pressure control case (Figure 1) because in this case the high pressurizer pressure trip setpoint is reached earlier.

Figure 3.5.8 RCS inlet temperature increases by about 33°F. Again the temperature

  • increase is less than for the pressure control case because of the earlier trip.

Figure 3 .5. 8 Pressurizer liquid volume responds to the RCS heatup by increasing from 751 cubic feet to a maximum of about 896 cubic feet leaving about 400 cubic feet of minimum steam space.

Figure 3. 5. 8 Cold leg pressure follows a similar trend, reaching a peak value of 2745 psia (about 5 psi margin to the analysis limit) at 10.2 seconds.

Figure 3.5.8 Main steam pressure reaches a maximum value of 1173.7 psia (36.3 psi margin to the design limit) at 19 seconds or slightly less than the primary pressure control case, as expected.

130

3.5.8.5 Conclusions

  • The analysis indicates that for a complete loss of external electrical load without a direct or immediate reactor trip the following criteria are met:
a. The minimum transient DNBR remains above the 95/95 DNBR design limit.
b. Pressure at the most limiting RCS location is less than 110% of RCS design pressure, or 2750 psia (the Emergency Condition Stress Limit specified in Section ill of the ASME Code).
c. Pressure-at the most-limiting Main-Steam-System (MSS) location is less than 110% of MSS design pressure, or 1210 psia (the Emergency Condition Stress Limit specified in Section ill of the ASME Code).

References (3.5.8-1) VEP-FRD-41-A, "Reactor System Transient Analyses Using the RETRAN

  • Computer Code," May 1985.

(3.5.8-2) VEP-FRD-33-A, "Vepco Reactor Core Thermal/Hydraulic Analysis Using the COBRA illC/MIT Computer Code," October 1983.

(3.5.8-3) VEP-NE-2A, "Statistical DNBR Evaluation Methodology," Topical Report June 1987.

  • 131

3.5.8-1 Loss of External Load - BOC with Pressurizer Relief & Spray Nuclear Power 0

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3.5.8-3 Loss of External Load - BOC With Pressurizer Relief & Spray Pressurizer Liquid Volume 0

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3.5.8-6 Loss of External Load - BOC with Pressurizer Relief & Spray Hot Channel DNBR a:

CQ z

C 0 5 10 15 20 25 30 Time - Seconds

  • 137

3.5.8-7 Loss of External Load - BOC without Pressurizer Relief & Spray Nuclear Power 0

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3.5.8-8 Loss of External Load - BOC without Pressurizer Relief & Spray Core Inlet Temperature 0

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  • 5/09/94 13.03.39 139

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  • 5/09/94 13.03.39 140

3.5.8-10 Loss of External Load - BOC without Pressurizer Relief & Spray RCS Cold Leg Pressure 0

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  • 5/09/94 13.03.39 141

3.5.8-11 Loss of External Load - BOC without Pressurizer Relief & Spray Steam Generator Pressure 0

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3.5.9 Steam Generator Tube Rupture 3.5.9.1 General

.. The accident examined is the complete severance of a single steam generator tube near the top of the tube bundle. It is assumed that the accident takes place at full power and while the reactor coolant is contaminated with the maximum radionuclide concentrations allowable by the Technical Specifications, including the effects of pre-accident iodine spiking.* The accident leads to the contamination of the secondary side due to the leakage of radioactive coolant from the Reactor Coolant System and,-*in the event of-a coincidental-loss-of offsite-power,.a discharge of activity to the atmosphere through the steam-generator safety valve and/or power operated relief valyes. The analysis presented here conservatively assumes a single power operated relief valve on the header closest to the ruptured generator sticks open following reactor trip.

    • The steam-generator tube material is Inconel 600, and, as the material is highly ductile, it is considered that the complete severance of a tube is extremely conservative. Surry Unit 1 and
2. steam generator tube bundles were replaced in 1979 and 1980, respectively, .and operating experience since then has been extremely good. After over 14 years of operation, plugging levels on all generators is essentially 0% (24 tubes total for all six steam generators, as of June 1994).

The more probable mode of tube failure would be .one or more minor leaks of undetermined origin. Activity in the Steam and Power Conversion System is subject to continual surveillance, and .an . accumulation of minor leaks that approach the equivalent of one tube rupture is not permitted during unit operation. For RCS .leaks in excess of 50 gpm with indications of secondary activity, an abnormal procedure for large steam generator tube leak is implemented which directs the operator to a) identify and isolate secondary release paths from the ruptured generator, (SG PORVs, steam flow to the turbine driven AFW pump, etc.), b) align the condenser air ejector discharge to containment and c) commence an orderly unit shutdown. For RCS leaks in excess of 150 gpm, the* unit is tripped and emergency operating procedures are entered.

Once the operator has determined a tube rupture has occurred, his first priority is to identify and isolate the faulty generator as soon as possible in order to minimize the contamination of the secondary system and ensure the termination of any activity discharge to the atmosphere. The 143

recovery procedure can be carried out on such a time scale as to ensure that break flow to the secondary system is terminated before the water level in the affected steam generator can rise

  • into the main steam pipe. Sufficient indications and controls are provided to enable the operator

.to perform these functions satisfactorily. Simulator training and classroom instruction on the tube rupture accident are a significant emphasis of the licensed operator requalification program.

3.5.9.2 Method of Analysis and Description of the Accident The thermal hydraulic portion of the tube rupture*accident-is-simulated-with the Virginia Power RETRAN model (3.5.9-1). Key analysis assumptions were as follows:

1) A double ended tube rupture was modeled. Break flow was calculated using the extended Henry subcooled flow model with a discharge coefficient (CD) of 0.5 .

. This model *overpredicts the actual break flows observed in the 1987 North Anna Unit 1 double-ended rupture. The resultant decrease in RCS pressure eventually reduces the overtemperature ~ T trip setpoint to the* full power value resulting an a reactor and turbine trip .

  • 2)
3) The PORV on the main steam header nearest the ruptured generator is assumed to remain fully open until 30 minutes after event initiation. Thus atmospheric releases are assumed for the first 30 minutes. For the normal case of condensers available, a high air ejector radiation signal diverts the air ejector exhaust to containment. Following safety injection, this exhaust path is also isolated. Offsite power and the condenser are available, the volatile species undergo two stages of partitioning (i.e. in the steam generator and the condenser) prior to being released to the atmosphere. Thus the case of loss of offsite power (or the condenser otherwise unavailable) is the limiting case from the standpoint of site dose .
  • 144
4) After reactor and turbine trip, the Reactor Coolant System continues to depressurize to the safety injection setpoint. Two high head safety injection pumps are
  • 5)
  • assumed to operate. The Reactor Coolant System pressure stabilizes at the point where break flow and safety injection flow are essentially equal.

Auxiliary feedwater initiation is conservatively neglected for the first 30 minutes. This maximizes the energy removal through the break and stuck open PORV.

The thermal hydraulic results are shown in Figures 3.5.9-1 through 3.5.9-7 as follows:

Figure 3.5.9 RCS Average Temperature: Following the rupture, RCS temperature is relatively stable until the unit trips on overtemperature A.Tat 74.7 seconds. The turbine stop valves are assumed to close within the next 2 seconds. Temperature continues to decrease in response to addition of cold safety injection water (safety injection occurs in response to low pressurizer pressure at 247 seconds) and the release of steam through the stuck open PORV (the PORV opens at 87.5 seconds). In actual operating practice,

  • .additional cooldown would be imposed by the operators as directed by the emergency procedures to support primary side depressurization to reduce the break flow.

Figure 3.5.9 Reactor Norm~ized Power: As discussed above, reactor trip is on overtemperature A. T at 74. 7 seconds.

Figure 3.5.9 Ruptured Loop Steam Pressure: After the reactor and turbine trip, pressure in the steam* generator initially increases; The expected response would be an increase followed by stabilization atthe no-load pressure of.about 1005 psig, but since the analysis assumes an atmospheric dump sticks open, there is a gradual depressurization.

Figure 3.5.9 Pressurizer Pressure: The initial drop in pressurizer pressure results from excess of tube rupture flow over the charging flow. The pressurizer level controller, which would increase charging flow and tend to retard this initial depressurization, is not modeled.

Immediately following reactor trip the depressurization rate is accelerated. Safety injection is initiated on low pressurizer pressure, the depressurization drops significantly as a result.

145

Figure 3.5.9 Through the Stuck Qpen PORV: This represents the primary potential source of radioactivity transport to the environment if the condenser steam dumps are not available.

Figure 3.5.9 Break Flow: The initial break flow through the two ends of the ruptured steam generator tube is about 80 lbm/sec or approximately 800 gpm. The flow drops off quickly in response to the RCS depressurization until safety injection is initiated. Then the flow stabilizes, as equilibrium between the break flow and safety injection is established, at about 550 gpm.- -The--slight increasing-trend-in-mass . flow. beyond -this point is a result of increased fluid density due to the RCS cooldown.

Figure 3.5.9 Integrated Break Flow: At one-half hour after initiation of the event, approximately 108,000 lbm of fluid has been transferred from the RCS to the secondary side of the ruptured steam generator.

This calculation takes no credit for operator action to cool down and depressurize the Reactor Coolant System prior to steam generator isolation, i.e., for the first 30 minutes. In an actual event, within 30 minutes the operators would be expected to achieve the following:

1. Ensure that power is available to the emergency buses and that safety injection and auxiliary feedwater are actuated. Verify that main feedwater is isolated.
2. Control the reactor system cooldown to maintain no-load temperature.

Stop* the reactor coolant pumps if safety injection flow to the core is indicated and the minimum required RCS subcooling is not maintained.

3. If not already completed, identify the ruptured steam generator by rising water level or high steam line radiation indications and isolate flow from this steam generator. Adjust auxiliary feedwater flow to maintain the specified water levels in the ruptured and intact steam generators.
4. Initiate RCS cooldown through the intact steam generators by dumping steam to the main condenser or through the steamline PORV (depending on the availability of offsite power).

146

5. Depressurize the RCS to minimi7.e break flow and refill the pressurizer using the pressurizer spray or, if spray is unavailable, the pressurizer PORVs. Maintain
  • 6.

the RCS pressure within the pressure-temperature limit curve for the Reactor Coolant System.

Terminate safety injection flow upon establishing required minimum RCS subcooling, secondary heat sink requirements and level in the pressurizer.

7. Establish normal letdown and charging functions and control RCS pressure to minimize primary-to secondary leakage.
8. Initiate appropriate post -* SGTR cooldown procedures;
  • A revised dose analysis*has been performed, using the thermal hydraulic results presented above.

Details of this analysis and the resultant offsite and control room doses are presented in Section 3.7.2.2.

References (3.5.9-1) VEP-FRD-41-A, "Reactor System Transient Analyses Using the RETRAN Computer Code," May 1985 .

  • 147
  • Figure 3.5.9-1
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  • 148

Figure 3.5.9-2 Steam Generator Tube Rupture - Reactor Normalized Power 1.2 -

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Figure 3.5.9-3 Steam Generator Tube Rupture - Ruptured Steam Generator Pressure 1200 -

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Figure 3.5.9-4 Steam Generator Tube Rupture - Pressurizer Pressure 2500 2000

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Figure 3.5.9-5 Steam Generator Tube Rupture - Open SG PORV Mass Flow Rate 120 100 80

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  • 152

Figure 3.5.9-6 Steam Generator Tube Rupture - Break Mass Flow Rate 80 70 -

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  • 153

Figure 3.5.9-7 Steam Generator Tube Rupture - Break Integrated Mass Flow 120000 *-

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3.6 Containment Integrity & Safeguards Equipment Evaluations 3.6.1 WCA Mass and Energy Release Analysis 3.6.1.1 Purpose of Analysis The analysis documented in this section involves Westinghouse calculations of the long term Loss of Coolant Accident (LOCA) mass and energy releases for the pump suction double ended rupture (PSDER) *and hot leg double ended rupture (HLDER) break cases with the proposed uprated conditions. This documentation provides the analytical basis with respect to the LOCA containment mass**and energy-release for-the operation of the -Surry-Power Station *Unit-1 and 2 at the described conditions.

Rupture of any of the piping carrying pressurized high temperature reactor coolant, termed a LOCA, will result in release of steam and water into the containment. This, in tum, will result in an increase in the containment pressure and temperature. The mass and energy release rates described in this section are used in further computations to evaluate the containment heat removal systems capability and containment structural integrity following a postulated loss of coolant accident. These analyses are performed to demonstrate compliance with General Design Criteria 38 and 50 of 10 CFR 50, Appendix A. Section 3.6.1.2 presents the long term mass and energy release analysis for containment pressurization evaluations. Section 3.6.1.3 presents the post-blowdown mass and energy releases for use in evaluation of recirculation spray pump available NPSH.

3.6.1.2 System Characteristics and Modeling Assumptions The mass and energy release analysis is sensitive to the assumed characteristics of various plant systems, in addition to other key modeling assumptions. Some of the most critical items are:

RCS initial conditions, core decay heat, safety injection flow, and metal and steam generator heat release modeling. Specific assumptions concerning each of these items are discussed below.

Tables 3.6.1-1 through 3.6.1-6 present key data assumed in the analysis.

For the long term mass and energy release calculations, operating temperatures which bound the highest full power average coolant temperature were used as initial conditions. A core rated power of 2546 MWt (adjusted for calorimetric error of +2 percent of power) was assumed.

155

The use of higher temperatures is conservative because the initial fluid energy is based on coolant temperatures which are at the maximum levels attained in steady state operation.

Additionally, an allowance of +4.0°F is reflected in the temperatures in order to account for instrument error and deadband. The initial Reactor Coolant System (RCS) pressure in this analysis is based on a nominal value of 2250 psia. Also included is an allowance of + 30 psi, which accounts for the measurement uncertainty on pressurizer pressure. The selection of 2250 psia as the limiting pressure is considered to affect the blowdown phase results only, since this

  • represents the initial pressure of the RCS. The RCS rapidly depressurizes from this value until the point at which it equilibrates-with containment pressure.

The rate at which the RCS blows down is initially more severe at the higher RCS pressure.

Additionally the RCS has a higher fluid density at the higher pressure (assuming a constant temperature) and subsequently has a higher RCS mass available for releases. Thus, 2280 psia initial pressure was selected as the limiting case for the long term mass and energy release calculations. A 3 % increase in the nominal RCS volume (which is composed of 1. 6 % allowance for thermal expansion and 1.4% for uncertainty) is also modeled. These assumptions conservatively maximize the mass and energy contained in the RCS .

  • The selection of the fuel design features for the long term mass and energy calculation is based on the need to conservatively maximize the core stored energy. The margin in core stored energy was chosen to be + 15 percent. Thus, the analysis Vf?ry conservatively accounts for the stored energy in the core. The assumed fuel conditions were adjusted to provide a bounding analysis for the current Surry Improved Fuel (SIF) design with the Performance+ features. The following items serve as the basis to ensure conservatism in the core stored energy calculation:

a conservatively high reload core loading, time of maximum fuel densification, i.e., highest beginning of cycle (BOC) fuel temperatures, and irradiated fuel assemblies are assumed to have a minimum average bumup of 2..15000 MWD/MTU ..

  • Regarding safety injection flow, the mass and energy calculation considered configurations to conservatively bound potential alignments. The spectrum of cases included: Minimum SI -

Single Train (conservatively low ECCS flowrates); Maximum SI - Single Train (conservative early depletion of refueling water storage tank); and Maximum SI - Two Train (nominal configuration).

156

The following assumptions were employed to ensure that the mass and energy releases are conservatively calculated, thereby maximizing energy release to containment:

1. Maximum expected operating temperature of the Reactor Coolant System (100% power conditions).
2. An allowance in temperature for instrument error and dead band ( +4.0°F).
3. Margin in RCS volume of 3% (which is composed of 1.6% allowance for thermal expansion and 1.4% for uncertainty).
4. Core-rated-power of 2546 MWt.
5. Allowance for calorimetric error (+2% power).
6. Conservative coefficient of heat transfer (i.e., steam generator primary/secondary heat transfer and Reactor Coolant System metal heat transfer).
7. Allowance in core stored energy for effect of fuel densification.
8. -A* margin* in core stored energy ( + 15 % included *to account for manufacturing tolerances).
9. An allowance for RCS initial pressure uncertainty ( +30 psi).
10. A maximum containment backpressure equal to design pressure.
11. The steam generator metal mass was modeled to include only the portion of the steam generators (SG) which is in contact with the fluid on the secondary side. Portions of the SGs such as the elliptical head, upper shell and miscellaneous internals have poor heat transfer due to location. The heat stored in these areas available for release to containment will not be able to effectively transfer energy to the RCS, thus the energy will be removed at a much slower rate and time period (>10000 seconds).
12. A provision for modeling steam flow from the steam generators prior to closure of the main steam isolation valves was conservatively addressed. Main steamline isolation time equal to 3.75 seconds was considered.
13. As noted in Section 2.4 of Reference (3.6.1-1), the option to provide more specific modeling pertaining to decay heat has been *exercised -to specifically reflect the Surry Unit 1 and 2 core heat generation, while retaining the two sigma uncertainty to assure conservatism.
14. Steam generator tube plugging level (0% uniform).

- Maximizes reactor coolant volume and fluid release.

- Maximizes heat transfer area across the SG tubes.

157

- Reduces coolant loop resistance, which reduces ~p upstream of break and increases break flow.

Use of the above conditions and assumptions result in a bounding analysis of the release of mass and energy from the RCS in the event of a LOCA. This analysis is applicable for operation of Surry Unit 1 and 2 at a core rated power of 2546 MWt.

3.6.1.3 Long Term WCA Mass and Energy Release Analysis 3.6.1.3.1 Introduction The evaluation model used for the long term LOCA mass and energy release calculations was the March 1979 model described in Reference (3.6.1-1). This evaluation model has been reviewed and approved by the NRC, and has been used in the analysis of other dry containment plants. These mass and energy releases are used in the Stone and Webster containment response analysis described in Section 3.6.2.

3.6.1.3.2 WCA Mass and Energy Release Phases The containment system receives mass and energy releases following a postulated rupture in the RCS. These releases continue over a time period, which, for the LOCA mass and energy analysis, is typically divided into four phases:

1. Blowdown - the period of time from accident initiation (when the reactor is at steady state operation) to the time that the RCS and containment reach an equilibrium state.at containment design pressure.
2. Refill - the period of time when the lower plenum is being filled by accumulator and ECCS water. At the end of blowdown, a large amount of water remains in the cold legs, downcomer and lower plenum. To conservatively consider the refill period for the purpose of containment mass and energy releases, it is assumed that this water is instantaneously transferred to the lower plenum along with sufficient accumulator water to completely fill the lower plenum. This allows an uninterrupted release of mass and energy to containment. Thus, the refill period is conservatively neglected in the mass and energy release calculation.

158

3. Reflood - begins when the water from the lower plenum enters the core and ends when the core is completely quenched.
4. Post-reflood (Froth) - describes the period following the reflood transient. For the pump suction break, a two-phase mixture exits the core, passes through the hot legs and is superheated in the steam generators. After the broken loop steam generator cools, the break flow becomes two phase.

Computer Codes The Reference (3.6.1-1) mass and energy release evaluation model is comprised of mass and energy release versions of the following codes: SATAN VI, WREFLOOD and FROTH. These codes were used to calculate the long term LOCA mass and energy releases for the Surry Power Station Unit 1 and 2.

SATAN calculates blowdown, the first portion of the thermal-hydraulic transient following break initiation, including pressure, enthalpy, density, niass and energy flowrates, and energy transfer between primary and secondary systems as a function of time.

The WREFLOOD code addresses the portion of the LOCA transient where the core reflooding phase occurs after the primary coolant system has depressurized (blowdown) due to the loss of water through the break and when water supplied by the Emergency Core Cooling refills the reactor vessel and provides cooling to the core. The most important feature is the steam/water mixing model (See Section 3.6.1.3.5.2).

FROTH models the post-reflood portion of the transient. The FROTH code is used for the steam generator heat addition calculation from the broken and intact loop steam generators.

3.6.1.3.3 Break Size and Location Generic studies have been performed with respect to the effect of postulated break size on the LOCA mass and energy releases. The double ended guillotine break has been found to be limiting due to larger mass flow rates during the blowdown phase of the transient. During the reflood and froth phases, the break size has little effect on the releases.

159

Three distinct locations in the reactor coolant system loop can be postulated for pipe rupture:

1. Hot leg (between vessel and steam generator)
  • 2.

3.

Cold leg (between pump and vessel)

Pump suction (between steam generator and pump)

The break locations analyzed for this program are the pump suction double ended rupture, PSDER (10.48 ft2) and the hot leg double ended rupture, HLDER (9.18 ft2). Break mass and energy releases have been calculated for the blowdown, reflood and post-reflood phases of the LOCA for each case analyzed.-The following-information-provides-a discussion on*each break location.

The hot leg double ended rupture has been shown in previous studies to result in the highest .

blowdown mass and energy release rates. Although the core flooding rate would be the highest

  • for this break location, the amount of energy *released from the steam generator secondary is minimal because the majority of the fluid which exits the core bypasses the steam generators venting directly to containment. As a result, the reflood mass and energy releases are reduced significantly as compared to either the pump suction or cold leg break locations where the core
  • exit mixture must pass through the steam* generators before venting through the break. For the hot leg break, generic studies have confirmed that there is no reflood peak (i.e., from the end of the blowdown period the containment pressure would continually decrease). The hot leg double ended rupture reflood and post-reflood phase calculations are not required to determine peak containment pressure,
  • but were calculated for use in the calculation for the recirculation spray pump available- NPSH. Further details about this analysis are contained in Section
3. 6 .1. 4. The mass and energy releases for the hot leg break blowdown phase are included in the present section.

The cold leg break location has also been found in previous studies to be much less limiting in terms of the overall containment energy releases. The cold leg blowdown is faster than that of the pump suction break, and more mass is released into the containment. However, the core heat transfer is greatly reduced, and this results in a considerably lower energy release into containment. Studies have determined that the blowdown transient for the cold leg is, in general, less limiting than that for the pump suction break. During reflood, the flooding rate is 160

greatly reduced and the energy release rate into the containment is reduced. Since the PSDER case provides bounding results, the cold leg break location is not explicitly analyzed .

  • The pump suction break combines the effects of the relatively high core flooding rate, as in the hot leg break, and a break flow path through which the stored energy in the steam generators can be transferred to the containment. As a result, the pump suction break yields the highest energy flow rates* during the post-blowdown period since all of the Reactor Coolant System available energy contributes to the calculated mass and energy releases.

3.6.1.3.4 Assesmient of Single Failure Effects An analysis of the effects from various single failures has been performed on the mass and energy release rates for each break analyzed. An inherent assumption in the generation of the mass and energy *release** is that* offsite power is lost. This results in the actuation of the emergency diesel generators, required to power the safety injection system. This is not an issue for the blowdown period which is limited.by the HLDER break.

  • Three cases have been analyzed for the effects of a single failure. In the case of minimum safeguards, the single failure postulated to occur is the loss of an emergency diesel generator.

This results in the loss of one pumped safety injection train. Two *variations on the minimum safeguards scenario were addressed. The first case was a maximum safety injection (SI) flow, single train case. This case will result in low flow rates, but an early refueling water storage tank depletion. The second case is the minimum safety injection flow, single train failure. As compared to the first case the SI flow would be minimized, although the time of RWST depletion would be later. Sensitivities indicate that low head safety injection pump NPSH is minimized for .the minimum SI-single train case, and containment depressurization and subatmospheric peak pressure are more limiting for the* maximum SI-single train scenario. For the case of maximum safeguards, no failure is postulated to occur. The analysis of the cases described ensures that the effect of all credible single failures is bounded.

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3.6.1.3.5 Mass and Energy Release Data 3.6.1.3.5.1 Blowdown Mass and Energy Release Data

  • A version of the SATAN-VI code, which is the code used for the Emergency Core Cooling System (ECCS) calculation in Reference (3.6.1-2), is used for computing the blowdown.

transient. The code utilizes the control volume (element) approach with the capability for modeling a large variety of thermal fluid system configurations. The fluid properties are considered uniform and thermodynamic equilibrium is assumed in each element. A point kinetics model is used with-weighted- feedback- effects. --The-major-* feedback effects include

  • .moderator density, moderator temperature and Doppler broadening. A critical flow calculation

. for subcooled (modified Zaloudek), two-phase (Moody) or superheated break flow is

. incorporated into the *analysis. The methodology for the use of this model is described in Reference (3.6.1-1).

Table 3.6.1-7 presents the calculated mass and energy releases for the blowdown phase of the PSDER break. For the pump suction breaks, break path 1 in the mass and energy release tables refers to the mass and energy exiting from the steam generator side of the break; break path

  • 2 refers to the mass and energy exiting from the pump side of the break.

Table 3.6:1-23 presents the calculated mass and energy release for the blowdown phase of the HLDER break. For the hot leg break mass and energy release tables, break path 1 refers to the mass and energy exiting from the reactor vessel side of the break; break path 2 refers to the mass and energy exiting from the steam generator side of the break.

3.6.1.3.5.2 Reflood Mass and Energy Release Data The WREFLOOD code used for computing the reflood transient is, a modified version of that used in the 1981 ECCS evaluation model (3.6.1~2).

The WREFLOOD code consists of two basic hydraulic models -* one for the contents of the reactor vessel, and one for the coolant loops. The two models are coupled through the interchange of the boundary conditions applied at the vessel outlet nozzles and at the top of the downcomer. Additional transient phenomena, such as pumped safety injection and accumulators, 162

reactor coolant pump performance and steam generator release, are included as auxiliary equations which interact with the basic models as required. The WREFLOOD code permits the capability to calculate variations during the core reflooding transient of basic parameters, such as core flooding rate, core and downcomer water

  • levels, fluid thermodynamic conditions (pressure, enthalpy, density) throughout the primary system, and mass flow rates through the primary system. The code permits hydraulic modeling of the two flow paths available for discharging steam and entrained water from the core to the break, i.e. the path through the broken loop and the path through the unbroken loops.

A complete thermal equilibrium mixing condition for the steam and emergency core cooling injection water during the reflood phase has been assumed for each loop receiving ECCS water.

This is consistent with the usage and application of the Reference (3.6.1-1) mass and energy release evaluation model in recent analyses, e.g. D.C. Cook Docket (3.6.1-3). Even though the

. Reference**(3.6.1-l) model credits steam/mixing only in the intact loop and not in the broken loop, justification, applicability and NRC approval for using the mixing model in the broken loop has been documented (3. 6.1-3). This assumption is justified and supported by test data, and is summarized as follows:

  • The model assumes a complete mixing condition (i.e., thermal equilibrium) for the steam/water interaction. The complete mixing process, however, is made up of two distinct physical processes. The first is a two phase interaction with condensation of steam by cold ECCS water.

The second is a single phase mixing of condensate and ECCS water. Since the. steam release is the most important influence to the containment pressure transient; the steam condensation part of the mixing process is the only part that need be considered. (Any spillage directly heats only the sump.)

The most applicable steam/water mixing test data has been reviewed for validation of the containment integrity reflood steam/water mixing model. This data is that generated in 1/3 scale tests (3.6.1-4), which are the largest scale data available and thus most clearly simulates the flow regimes and gravitational effects that would occur in a PWR. These tests were designed specifically to study the steam/water interaction for PWR reflood conditions.

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From the entire series of 1/3 scale tests, a group corresponds almost directly to containment integrity reflood conditions. The injection flowrates for this group cover all phases and mixing conditions calculated during the reflood transient. The data from these tests were reviewed and discussed in detail in Reference (3.6.1-1). For all of these tests, the data clearly indicate the occurrence of very effective mixing with rapid steam condensation. The mixing model used in the containment integrity reflood calculation is therefore wholly supported by the 1/3 scale steam/water mixing data.

Additionally, the-following-justification-is noted.---The-post-blowdown--limiting break for the.

containment integrity peak pressure analysis is the pump suction double ended rupture break.

For this break, there are two flowpaths available in the RCS by which mass and energy may be released to containment. One is through the outlet of the steam generator, the other via reverse flow through the reactor coolant pump. Steam which is not condensed by ECCS injection in the intact RCS loops passes around the downcomer and through the broken loop cold leg and pump in venting to containment. This steam also encounters ECCS injection water as it passes through the broken loop cold leg, complete mixing occurs and a portion of it is condensed. It is this portion of steam which is condensed that is taken credit for in this analysis. This assumption is justified based upon the postulated break location, and the actual* physical presence of the ECCS injection nozzle. A description of the test and test results is contained in References (3.6.1-1) and (3.6.1-4).

The methodology previously discussed in Reference (3.6.1-1) has been utilized and approved on

  • the Dockets for numerous dry containment plants such as Beaver Valley Unit 2, Millstone Unit 3 and Indian Point Unit 2.

Tables 3.6.1-8, 3.6.1-13 and 3.6.1-18 present the calculated mass and energy release for the reflood phase of the pump suction double ended rupture maximum SI - single train, minimum SI - single train and maximum SI - two train safeguard cases, respectively.

The transients of the principal parameters during reflood are given in Tables 3.6.1-9, 3.6.1-14 and 3.6.1-19 for the PSDER safeguard cases .

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3.6.1.3.S.3 Post-Reflood Mass and Energy Release Data

  • The FROTH code (3.6.1-5) is used for computing the post-reflood transient. FROTH calculates the heat release rates resulting from a two-phase mixture level present in the steam generator tubes. The mass and energy releases that occur during this phase are typically superheated due to the depressurization and equilibration of the broken loop and intact loop steam generators.

During this phase of the transient, the RCS has equilibrated with the containment pressure, but the steam generators contain a secondary inventory at an enthalpy that is much higher than the primary side. Therefore,- there is*a significant *amount *of*reverse**heat transfer that occurs.

Steam is produced in the core due to core decay heat. For a pump suction break, a two phase fluid exits the core, flows through the hot legs and becomes superheated as it passes through the steam generator. Once the broken loop cools, the break flow becomes two phase. The methodology for the use of this model is described in Reference (3.6.1-1).

The mass and energy release rates calculated by FROTH are processed as described in Section 3.6.2.1 for use in the containment response analysis, performed by Stone and Webster with the LOCTIC code. The tables in the present section contain the composite data used in the LOCTIC

  • containment response analyses. Tables 3.6.1-10, 3.6.1-15 and 3.6.1-20 present the two phase post-reflood (froth) mass and energy release data for the PSDER cases.

3.6.1.3.S.4 Decay Heat Model As part of the Surry Core Uprating effort a detailed HLDER mass and energy release analysis (Section 3.6.1.4) was completed for use in the evaluation of recirculation spray pump available NPSH. The 1975 mass and energy release evaluation model (3.6.1-5) was used for this calculation. The decay heat standard available and incorporated into the Reference (3.6.1-5) evaluation model was adopted by the ANS Standards Subcommittee in October 1971.

The NRC staff Safety Evaluation Report (SER) for the March 1979 evaluation model approved use of the November 1979 ANS Standard-5.l decay heat model for the calculation of mass and energy releases to the containment following a loss-of-coolant accident. Therefore, to more realistically model the RCS, the Reference (3. 6.1-6) decay heat model was utilized for this core uprating effort in conjunction with the 1975 evaluation mod~l. This standard was used in the 165

mass and energy release model with the following input specific for the Surry Power Station Unit 1 and 2. The primary assumptions which make this calculation specific for the Surry Power

  • Station are the enrichment factor, minimum/maximum number of new fuel assemblies per cycle and fuel cycle length. A conservative lower bound for enrichment of 3% was used. Table 3.6.1-3 lists the decay heat values used in this analysis.

Significa,nt assumptions in the generation of the decay heat values:

1. Decay heat sources considered are fission product decay and heavy element decay of U-239 and -Np-239.
2. Decay heat power from fissioning isotopes other than U-235.is assumed to be identical to that of U-235.
3. . Fission rate is constant over the operating history of maximum power level.
4. The factor accounting for neutron capture in fission products has been taken from Equation ll*ofReference (3.6.1-6) up to 10,000 seconds, and Table 10 of Reference (3.6.1-6) beyond 10,000 seconds.
  • 5. The fuel has been assumed to be at full power for 10' seconds.
6. The number of atoms of U-239 produced per second has been assumed to be equal to 70 % of the fission rate. *
7. The total recoverable energy associated with one fission has been assumed to be 200 MeV/fission.
8. Two sigma uncertainty (two times the standard deviation) has been applied to the fission product decay.

3.6.1.3.5.5 Steam Generator Equilibration and Depressurization Steam generator equilibration and depressurization is.the process by which secondary side energy is removed from the steam generators in stages. The FROTH computer code calculates the heat removal from the secondary mass until the secondary temperature is Tsat at the containment design pressure. After the FROTH calculations, steam generator secondary energy is removed based on first and second stage rates; The first stage rate is applied until the steam generator reaches Tsat at the user specified intermediate equilibration pressure, when the secondary pressure is assumed to reach the actual containment pressure. Then the second stage rate is used until the* final depressurization, when the secondary r.eaches the reference temperature of Tsat 166

at 14.7 psia, or 212°F. The heat removal of the broken loop and intact loop steam generators are calculated separately.

. During the FROTH calculations, steam generator heat removal rates are calculated using the secondary side temperature, primary side temperature and a secondary side heat transfer coefficient determined using a modified McAdam's correlation. Steam generator energy is removed during the FROTH transient until the secondary side temperature reaches saturation temperature at the containment design pressure. The constant heat removal rate used during the first heat removal stage is- based on the**final heat-removal rate calculated by FROTH. The SG energy available to be released during the first stage interval is determined by calculating the difference in secondary energy available at the containment design pressure and that at the (lower) user specified intermediate equilibration pressure, assuming saturated conditions. This energy is then divided by the first stage energy removal rate, resulting in an intermediate equilibration 'time.**

  • At this time, the rate of energy release drops substantially to the second stage rate. The second stage rate is determined as the fraction of the difference in *secondary energy available between the intermediate equilibration and final depressuriz.ation at 212°F, and the time difference from the time of the intermediate equilibration to the user specified time of the final depressuriz.ation at 212 °F. With standard methodology, all of the secondary energy
  • remaining after the intermediate equilibration is conservatively assumed to be released by imposing a mandatory cooldown and subsequent depressuriz.ation down to atmospheric pressure at 3600 seconds, i.e., 14.7 psia and 212°F.

3.6.1.3.6 Sources of Mass and Energy The sources of mass considered in the LOCA mass and energy release analysis are given in Tables 3.6.1-11, 3.6.1-16, 3.6.1-21 and 3.6.1-24. These sources are the reactor coolant system,

'accumulators and pumped safety injection.

The energy inventories considered in the LOCA mass and energy release analysis are given in Tables 3.6.1-12, 3.6.1-17, 3.6.1-22 and 3.6.1-25. the energy sources include:

1. Reactor Coolant System Water
2. Accumulator Water
3. Pumped Injection Water 167
4. Decay Heat
5. Core Stored Energy
6. Reactor Coolant System Metal

- Primary Metal (includes SG tubes)

7. Steam Generator Metal (includes transition cone, shell, wrapper, and other internals)
8. Steam Generator Secondary Energy (includes-fluid mass and steam mass)
9. Secondary Transfer of Energy (feedwater into and steam out of the steam generator secondary)

This analysis employs certain terminology to describe the energy content of the various energy sources modeled. The following terms are used for these -energy reference points:

Available Energy:energy existing above the statepoint of 212°F and 14.7 psia Total Energy Content:energy existing above the statepoint of 32°F and 14.7 psia It should be noted that the inconsistency in the energy balance tables from the end of Reflood to 3600 seconds, i.e., "Total Available" data versus "Total Accountable", resulted from the omission of the reactor upper head in the analysis following blowdown. It has been concluded that the results are more conservative when the upper head is neglected. This does not affect the instantaneous mass and energy releases or the integrated values,* but causes an increase in the total accountable energy within the energy balance table.

The mass and energy inventories are presented at the following times, as appropriate:

1. Time zero (initial conditions)
2. End of blowdown time
3. End of refill time
4. . End of reflood time
5. Time of broken loop steam generator equilibration to pressure setpoint
6. Time of intact loop steam generator equilibration to pressure setpoint
7. Time of full depressurization (3600 seconds) 168

In the mass and energy release data presented, no Zirc-water reaction heat was considered because the clad temperature did not rise high enough for the rate of the Zirc-water reaction heat to be of any significance.

The consideration of the various energy sources in the mass and energy release analysis provides assurance that all available sources of energy have been included in this analysis. Thus the review guidelines presented in Standard Review Plan Section 6.2.1.3 have been satisfied.

3.6.1.4 Mas.sand Energy Releases for Available NPSH Analysis (Hot Leg Double Ended Rupture, Post-Blowdown)

In support of Stone and Webster's evaluation of recirculation spray pump available NPSH, a

  • LOCA long term mass and energy release analysis, specifically addressing the hot leg double ended rupture (HLDER) was completed. Mass and energy releases for use in the evaluation HLDER, Maximum Safety injection - two train case are provided in Tables 3.6.1-23 (blowdown) and Table 3.6.1-26 (reflood and post-reflood phases).

The large break LOCA mass *and energy releases were generated using the evaluation models described in References (3.6.1-1) and (3.6.1-5). The blowdown phase mass and energy releases were calculated using the Reference (3.6.1-1) evaluation model, as described in Section 3.6.1.3.5.1 and provided in Table 3.6.1-23. The large break LOCA mass and energy releases for the reflood and post-reflood phases were generated using the 1975 mass and energy release evaluation model (3. 6.1-5). Tables 3. 6.1-26 through 3. 6.1-29 provide the hot leg mass and energy instantaneous releases, reflood principal parameter transient conditions and mass and energy balance data for the reflood and post"."reflood phase. The Reference (3.6.1-5) mass and energy release evaluation model was utilized because *of its capability to calculate reflood and post-reflood phase transient mass and energy release data. The focus of the Reference (3.6.1-1) evaluation model is for the pressure and temperature response of containment. As noted in Section 3.6.1.3.3, generic studies confirm that for the hot leg break, there is no reflood peak, therefore the reflood code applicability of the Reference (3.6.1-1) model was not pursued. The Reference (3.6.1-5) evaluation model still remains a valid analytical tool that has been reviewed and approved by the NRC, although it does not exhibit the benefits of the improved model, i.e.,

169

steam water mixing model during reflood. Please note the reflood and post-reflood phase modeling of the Reference (3.6.1-5) evaluation model has been enhanced to incorporate the 1979 decay model as described in Section 3.6.1.3.5.4 for this Surry core uprating program. The HLDER mass and energy releases in Table 3.6.1-29 are based on the initial conditions consistent with the design basis analysis of Section 3.6.1.3.

The analysis performed to calculate long term mass and energy releases following a postulated HLDER is similar to the analysis described in Section 3.6.1.3. The transient is divided into four phases: blowdown, refill,- reflood and -post-reflood. The- characteristics of the phases are also similar except for the hot leg break, where the amount of energy released from the SG is minimal because the majority of the fluid which exits the core bypasses the SG venting directly to containment.

  • The analysis as'noted above utilized both the Reference (3.6.1-1) and (3.6.1-5) mass and energy release evaluation models. The computer models used were comprised of mass and energy release versions of the following codes: SATAN VI model (3. 6.1-1) for blowdown WREFLOOD and POST model (3.6.1-5) for reflood and post-reflood phases. These codes were used to calculate the long term LOCA mass and energy releases for the hot leg break. The blowdown releases are calculated with the same version of the SATAN code described in Section 3. 6.1. 3 .2.

The WREFLOOD code addresses the portion of the LOCA transient where the core reflooding phase occurs after the primary coolant system has depressurized (blowdown) due to the loss of water through the break and when water supplied by the Emergency Core Cooling System refills the reactor vessel and provides cooling to the core. The WREFLOOD version of the Reference (3.6.1-5) model does not include the enhanced steam/water mixing model of Reference (3.6.1-1).

The POST code calculates the amount of superheat energy applied to the post-blowdown boil-off via heat transfer from the steam generator secondary side. It also performs an energy balance calculation involving the thick and thin metal energies, core stored energy and residual core decay heat .

  • 170

References (3.6.1-1) WCAP-10325-P-A, "Westinghouse LOCA Mass and Energy Release Model for Containment Design -March 1979 Version", May 1983.

(3.6.1-2) WCAP-9220-P-A, Rev. 1, "Westinghouse ECCS Evaluation Model - 1981 Version", Rev. 1, February 1982.

(3.6.1-3) Docket No. 50-315, "Amendment No. 126, Facility Operating License No.

DPR-58 (TAC No. 7106), for D.C. Cook Nuclear Plant Unit 1", June 9, 1989.

(3.6.1-4) EPRI 294-2, Mixing of Emergency Core Cooling Water with Steam; 1/3 Scale Test-and-Summary; (WCAP-8423), Final -Report-June 1975.

(3.6.1-5) WCAP-8264-P-A, Rev. 1, "Westinghouse Mass and Energy Release Data For Containment Design", August 1975.

(3.6.1-6) ANSI/ANS-5.1-1979, American National Standard for Decay Heat Power in I

Light Water Reactors", August 1979 .

  • 171

Table 3.6.1-1 WCA ~ & Energy Release Analysis System Parameters Initial Conditions PARAMETERS VALUE Core Thermal Power (MWt) 2546 Reactor Coolant System Flowrate, per Loop {gpm) 88500 Vessel Outlet Temperature 1 {°F) 605.6 Core Inlet Temperature1 (°F) 540.4 Vessel Average Temperature 1 {°F) 573.0 Initial Steam Generator Steam Pressure (psia) 785 Steam Generator Design Model 51F Steam Generator Tube Plugging(%) 0 Initial Steam Generator Secondary Side Mass (lbm)

Liquid Mass 96861 Vapor Mass 6539 Assumed Maximum Containment Backpressure (psia) 59.7 Accumulator Water Volume (ft') 1000 N2 Cover Gas Pressure (psia) 600 Temperature (°F) 105 Safety Injection Delay (sec) 27.0 (includes time to reach pressure setpoint) 1 These are nominal values; analysis value includes +4.0°F allowance for instrument error and deadband 172

Table 3.6.1-2 WCA Mass & Energy Release Analysis System Parameters Containment Backpressure Profile Time Pressure (sec) (psig) 0.0 -4.05 5.0 22.06 15.0 39.03 18.7 41.48 19.2 41.48

'100.0 36.86 200.0 33.58 400.0 27.90 600.0 22.14

  • 800.0 1000.0 1200.0 17.95 14.80 12.45 1400.0 9.96 1600.0 7.11 1800.0 5.14 2000.0 3.67 2570.0 1.01 2580.0 0.98 3000.0 0.05 3530.0 -0.53 3600.0 -0.55 173

'!rah1e 3.6.1-3 LOCA Mas* & Energy Release Analysis Systea Parameter*

Surry Unit 1 and 2 Core Decay Beat Fraction Time Decay Heat

{sec) {BTU/BTU) 10 0.052168 15 0.048917 20 0.047448 40 0.041405 60 0.038402 80 0.036324 100 *0~03476 150 0.032104 200 0.03036 400 0.0266 600 0.024426 800 0.022885 1000 0.021666 1500 0.019429 2000 0.017851 4000 0.014334 6000 0.01263 8000

  • 0.011588
  • 10000 0.010856 15000 0.01013 20000 0.009368 40000 0.007784 60000 0.006976 80000 .0.006439 100000 0.006034 150000 0.005336 200000 0.004859 400000 o.0*03191 600000 0.003212 800000 0.002844 1000000 0.002589 1500000 0.002175 2000000 0.001915 4000000 0.001356 6000000 0.00109 8000000 0.000924 10000000 0.000804
  • 174

.Table 3. 6 .1-4 LOCA Mass & Energy Releaae Analyai* Safety Injection Flow Maximum SI - Single Train

  • RCS Pressure fpsig)

INJECTION MODE (REFLOOD PHASE)

Total Flow (GPM) 0 3978.7 40 3975.1 80 3649.0 120 2975.6 160 1513.2 175 753.9 200 515.2 INJECTION MODE (POST-REFLOOD PHASE)

RCS Pressure Total Flow fpsig) (GPM) 45 3828.8 RECIRCULATION MODE RCS Pressure Total Flow fpsig} (GPM) 0 3429.2 175

Table 3.6.1-5 LOCA Mas* & Energy Release Analyai* Safety Injection Flow Minimum SI - Single Train

  • RCS Pre111*ura (psiq)

INJECTION MODE (REFLOOD PHASE)

Total Flow (GPM) o 3303.6 40 3300.7 80 2771.0 120 1881.5 160 501.2 165 376.4 200 394.5 INJECTION MODE (POST-REFLOOD PHASE)

RCS Pressure Total Flow (psiq) (GPM) 45 3136.9 RECIRCULATION MODE RCS Pressure Total Flow (psiq) CGPM) o 2777. 7

  • 176

TABLE 3.6.1-6 LOCA Maas & Energy Release Analysis safety Injection Flow Maximum SI - Two Train

  • RCS Pressure (psiq)

INJECTION MODE (REFLOOD PHASE)

Total Flow (GPM) 0 4784.2 40 4778.1 80 4772.1 120 4008.2 160 2439.0 175 1414.4 200 788.6 INJECTION MODE (POST-REFLOOD PHASE)

RCS Pressure Total Flow (psiq) (GPM) 45 4679.1 RECIRCULATION MODE RCS Pressure Total Flow (psiq) (GPM) 0 4241.5

  • 177

Table 3.6.1-7 Pump Suction Double Ended Rupture Slowdown Mas* and Energy Release (Applicable for All PSDER cases)

TIME BR.EAlt PATH N0.1 FLOW BREAK PATH N0.2 FLOW THOUSAND THOUSAND SECONDS LBM./SEC .BTU/SEC LBM./SEC BTU/SEC

.ooo 147896.1 79856.5 147896.1 79856.5

.100 39713.7 21300.9 *20013.9 10695.1

.200 40312.1 21750.9 21992.3 11761. 4

.301 41091.3 22345.1 22177.5 11872 .5

.400 43235.1 23725.8 21754.2 11657.4

.501 42777.9 23717.3 20912.8 11214.7

.*101 43345.9 -24525.4 19422~3 10423.3 .

.901 42424.9 24424.4 18385.6 9870.8 1.40 38056.7 22838.3 17473.5 9386.2 1.80 33705.4 21055.6 17303.1 9292.4 2.40 26785.9 17813.0 16742.5 8987.6 2.60 21303.8 14380.7 16467.9 8840.0 3.00 17618.6 12156.6 15460.3 8300.8 3.30 15477.5 10767.8 14884.2 7995.6 3.80 13034.0 9172.2 14076.2 7569.7

. 4.20 11877 .5 8411.2 13467.5 7248.8 4.80 10713.7 7607.7 12595.7 6787.6 5.20 10217.'6 7223.4 12189.3 6573.4 5.40 10041.7 7067.4 13041.9 7036.3 5.80 10344.8 7260.5 12667.0 6837.8 6.20 8566.1 '6775. 3 12168.1 6573.7 6.40 8125.9 6532.9 11983.2 6475.5 7.00 8228.0 6346.3 11699 .5 6330.2 7.80 9032.3 6399.1 11074.9 5987.3 8.40 9249.0 6269.1

  • 10654. 6 5757.0 10.4 7141.6 5139. 7
  • 9480.6 5118. 6 12.4 5602.3 4340.4 8211.3 4432.4 14.2 4506.8 3646.1 6858.1 3617.9 14.6 4250.8 3456.5 7104.6 3605.7 14.8 4150.7 3381.0 6061.4 3012.1 15.0 4064.5 3321.3 7478.6 3609.2 15.2 3949.0 3249.6 11434.8 5552.2 15.4 3777.8 3156.4 9671.0 4723.9.

15.6 3670.3 3140.0 6185.5 3022.5 15.8 3700.7 3213.6 4396.0 2099.2 16.0 3566.8 . 3172. 9 10523.2 4773.4 16.2 3319.7 3090.5 8769.6 4098.7 16.4 3201.0 3102.8 5375.8 2537.0 16.6 3156.1 3148.1 4068.8 1882.5 16.8 2970.9 3095.4 5133.0 2188.2 17.0 2601. 6 2894.5 7761.4 3272. 0 17.2 2297.2 2719.2 5733.7 2430.4 17.4 2093.7 2553.6 4375.3 1860.7 17.8 1779. 9 2198.1 3063.7 1277 .9 18.0 1614.5

  • 1999.3 3169.2 1229.8 18.4 1291.0 1605.9 4746.6 1711. 7 19.4 716.4 897.8 3091.4 1031.9 20.6 378.4 476.2 1248.1 366.2 21.2 261.1 329.0 .o .o 22.6 .o .o .o .o 178

Table 3.6.1-8 PUMP SUCT:IOH DOUBLE ENDED RUPTURE MAX:IMUM S:I - S:IRGLE TRA:IH REFLOOD MASS AND ENERGY RELEASE T:IME BREAK PATH :N0.1 FLOW BREAK PATH H0.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 22.6 .o .o .o .o 23.5 .o .o .o .o 23.6 44.4 52.3 .o .o 23.7 25.2 29.6 .o .o 24.1 47.4 55.8 .o .o 24.8 70.8 83.4 .o .o 25.7 96.5 113.7 .o .o 26.7 119.2 140.5 .o .o 27.7 140.0 165.0 182.3 2.8 28.7 317.2 374.9 3093.8 309.8 29.0 424.4 502.6 4286.4 449.3 29.7 460.4 545.7 4606.6 503.3 30.7 454.0 538.1 4544.3 499.9 32.7 435.3 515.8 4366.7 483.2 33.0 432.6 512.5 4340.4 480.7 33.7 426.3 sos.a 4279.8 474.9 34.7 417.7 494.7 4195.S 466.9

'35. 7 409.5 484.9 4114.1 459.1 36.7 401.6 475.5 4035.6 451.6 37.7 394.1 466.6 3960.0 444.3 38.7 386.9 458.0 3887.0 437.4 39.7 380.1 449.8 3816.7 430.6 41.7 367.2 434.4 3683.3 417.9 43.7 355.3 420.3 3558.7 406.0 45.7 344.3 407.2 3441.9 394.8 47.7 334.1 395.1 3332.0 384.3 48.8 199.7 235.5 252.7 . 87.2 so.a 196.3 231.5 251.5 as.a 58.8 184.6 217.7 247.6 80.9 60.8 182.S 215.2 249.2 80.5 68.8 174.7 206.0 258.8 79.9 70.8 172.8 203.7 261.4 79.8 78.8 164.6 194.0 272.5 79.7 82.8 160.3 188.9 278.9 79.9 83.8 159.1 187.6 280.5 79.9 91.4 150.1 176.9 294.5 80.7 91.8 149.6 176.3 295.3 80.8 95.8 144.2 170.0 303.6 81.4 99.8 138.4 163.1 312.6 82.2 101.8 136.5 160.9 315.9 82.3

  • 109 .8 134.1 158.0 322.0 81.3 115.8 132.2 155.8 326.3 80.4 123.8 129.6 152.8 331. 7 79.1 139.8 124.4 146.5 341.9 76.3 145.8 122 .4 144.2 345.6 75.2
  • 153.8 119. 7' 141.0 350.S 73.8 155.8 119.0 140.2 351. 7 73.4 163.8 116.3 137.0 356.5 71.9 195.8 105.3 124.0 375.6 66.2 198.5 104.3 122.9 377.2 65.7 179

TABLE 3.6.1-9 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM XI - SINGLE TRAIN PRINCIPAL PARAMETERS DURING REFLOOD FLOODING INJECTION CARRYOVER CORE DOWNCOMER FLOW

~ ~ RATE FRACTION HEIGHT HEIGHT FRACTION TOTAL ACCUMULATOR SPILL ENTHALPY SECONDS DEGREE F IN/SEC FT FT (POUNDS MASS PER SECOND) BTU/LBM 22.6 172.2 .000 .ooo .oo .oo .333 .o .o .o .oo 23.3 170.2 26.080 .ooo .64 1.47 .000 7194.8 7194~8 .o 74.03 23.5 169.0 30.117 .ooo 1.12 1.56 .ooo 7104.5 7104.5 .o 74.03 24.7 168.5 2.632 .299 1.50 4.72 .408 6764.7 6764.7 .o 74.03 25.7 168.6 2.490 .421 1.64 7.50 .439 6516.2 6516~2 .o 74.03 29.0 168.8 4.815 .624 *2.00 15.52 .682 5737.0 5217.6 .o 68.74 29.7 168.7 4.919 .649 2.10 15.57 .685 5496.0 4982.0 .o 68.56 30.7 168.6 4.688 .673 2.24 15.57 .684 5343.0 4828.4 .o 68.40 33.0 168.6 4.324 .701 2.51 15.57 .679 5063.8 4546.3 .o 68.05 38.2 169.1 3.856

  • 723 3.01 15.57 .667 4554.4 4031.5 .o 67.32 44.1 170.5 3.522 .730 3.50 15.57 .654 4101. 5 3574~0 .o 66.51 47.7 171.5 3.364 .732 3.78 15.57 .647 *3868.6 3339.0 .o 66.02 48.8 171.9 2.446 .722 3.84 15.55 .539 543.2 .o .o 15.55
51. 7 173.0 2.401 .722 4.01 15.52 .536 543.5 .o .o 15.55 61.8 178.0 2.276
  • 723 4.55 15.48 .526 544.3 .o .o 15.55 70.6 183.4 2.190 .724 5.00 15.49 .520 544.8 .o .o 15.55 so.a 190.6 2.093 .724 5.51 15.51 .511 545.4 .o .o 15.55 91.4 198.5 1.982 .725 6.00 15.54 .498 546.0 .o .o 15.55 103.8 207.8 1.855 .725 6.55 15.56 .482 546.7 .o .o 15.55 114. 7 215.8 1.803 .726 7.00 15.57 .483 546.7 .o .o 15.55 127.8 224.4 1. 738
  • 728 7.53 15.57 .483 546.7 .o .o 15.55 140.1 231.4 1.678 .730 8.00 15.57 .484 546.7 .o .o 15.55 149.8 236.4 1.631 .731 8.36 15.57 .484 546.7 .o .o 15.55 153.8 238.3 1.611 .731 8.51 15.57 .484 546.7 .o .o 15.55 167.8 244.4 1.543 .733 9.00 15.57 .485 546.7 .o .o 15.55 183.8 250.5 1.466 .734 9.54 15.57 .485 546.7 .o .o 15.55 198.5 255.4 1.397 .735 10.00 15.57 .485 546.7 .o .o 15.55 180

TABLE 3.6.1-10 SURRY UNITS 1 ARD 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - SINGLE TRAIN POST REFLOOD MASS ARD ENERGY RELEASE TIME BREAK PATIi :N0.1 FLOW BREAK PATIi :N0.2 FLOW TBOUSARD TBOUSARD SECO:NDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 198.6 118.6 148.0 413.8 71.5 203.6 119.0 148.5 413.4 71.2 213.6 118.3 147.7 414.1 71.0 218.6 118.8 148.2 413.7 70.7 228.6 118.1 147.3 414.4 70.6 233.6 118.5 147.9 413.9 70.3 243.6 117.8 147.0 414.7 70.1 248.6 118.2 147.5 414.2 69.8 258.6 117.5 146.6 415.0 69.7 263.6 117.9 147.1 414.6 69.4 268.6 117.5 146.7 414.9 69.3 273.6 118.0 147.2 414.5 69.0 283. 6

  • 117.2 146.2 415.3 68.9 288.6 lH.6 146.7 414.9 68.6 298.6 116.8 145.8 415.7 68.4 313.6 117.2 *146.2 415.3 67.8 323.6 116.4 145.2 416.1 67.6 328.6 116.7 145.7 415.7 67.3

.343. 6 116.2 145.* 1 416.2 66.9 358.6 116.5 145.3 416.0 66.3 368.6 115.6 144.3 416.9 66.1 383.6 115.8 144.S 416.7 65.S 398.6 115.1 143.7 417.3 65.1 413.6 115.S 144.1 417.0 64.S 418.6 115.1 143.6 417.4 64.4 433.6 115.3 143.9 417.1 66.1 448.6 114.9 143.3 417.6 65.6 463.6 115.0 143.S 417.5 65.0 478.6 114.4 142.7 418.1 64.6 488.6 114.8 143.2 417.7 64.0 503.6 114.1 142.3 418.4 63.6 518.6 114.S 142.9 418.0 62.9 523.6 114.0 142.2 418.S 62.8 538.6 114.3 142.6 418.2 64.3 543.6 113.7 141.9 418.7 64.2 563.6 113.8 142.0 418.7 63.3 598.6 113.1 141.2 419.3 61.9 618.6 113.4 141.4 419.1 63.0 658.6 112.6 140.S 419.9 61.2 668.6 112.9 140.8 419.6 60.6 693.6 112.3 140.2 420.1 61.5 1097.2 112.4 140~2 420.1 60.9 1097.3 58.9 73.1 473.6 70.1 1317 .1 58.9 73.1 473.6 70.1 1317.2 53.4 61.5 479.0 70.9 3529.9 39.9 46.0 492.6 72.9 3530.0 43.1 49.6 402.4 50.3 3599.9 42.7 49~2 402.8 50.31 3600.0 42.7 49.2 402.8 50.3 3600.1 35.8 41.2 409.8 47.S 10000.0 25.8 29.7 419.7 48.7 100000.0 14.4 16.S 431.2 so.a 1000000.0 6.2 7.1 439.4 51.0 181

TABLE 3.6.1-11 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - SINGLE TRAIN MASS BALANCE TIME (SECONDS) .oo 22.60 22.60 198.50 1097.17 1317.14 3600.00 MASS (THOUSAND LBM)

INITIAL IN RCS AND ACC 605.48 605.48 605.48 605.48 605.48 605.48 605.48 ADDED MASS PUMPED INJECTION .oo .oo .00 93.17 571.63 669.76 1686.86 TOTAL ADDED .oo .oo .00 93.17 571. 63 669.76 1686.86

      • TOTAL AVAILABLE *** 605.48 605.48 605.48 698.64 1177.11 1275.24 2292.34 DISTRIBUTION REACTOR COOLANT 419.33 50.34 67.55 125.42 125.42 125.42 125.42 ACCUMULATOR 186.15 134.71 117.50 .oo .oo .oo .oo TOTAL CONTENTS 605.48 185.05 185.05 125.42 125.42 125.42 125.42 EFFLUENT BREAK FLOW .oo 420.42 420.42 573.21 1051. 67 1149.80 2166.91 ECCS SPILL .oo .oo .oo .oo .oo .oo .oo TOTAL EFFLUENT .oo 420.42 420.42 573.21 1051.67 1149.80 2166.91
      • TOTAL ACCOUNTABLE *** 605.48 605.46 605.46 698.63 1177 .09 1275.22 2292.33 182
  • TABLE 3.6.1-12 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - SINGLE TRAIN ENERGY BALANCE TIME (SECONDS) .oo 22.60 22.60 198.50 1097.17 1317.14 3600.00 ENERGY (MILLION BTU)

INITIAL ENERGY IN RCS,ACC,S GEN 619.40 619.40 619.40 619.40 619.40 619.40 619.40 ADDED ENERGY PUMPED INJECTION .oo .oo .oo 1.45 8.89 20.19 138.16 DECAY HEAT .oo 4.99 4.99 20.29 74.84 86.05 181. 78 HEAT FROM SECONDARY I

.oo -1.27 -1.27 -1.27 4.17 4.18 4.18 TOTAL ADDED .oo 3. 72 3.72 20.47 87.89 110.43 324.12

      • TOTAL AVAILABLE *** 619.40 623.12 623.12 639.87 707.29 729.82 943.52 DISTRIBUTION REACTOR COOLANT 242.89 9.78 11.06 31.14 31.14 31.14 31.14 ACCUMULATOR 13.89 10.05 8.78 .oo .oo .oo .oo CORE STORED 19.49 10.04 10.04 3.87 3.24 3.20 2.68 PRIMARY METAL 125.38 118.32 118.32 95.28 54.62 50.26 42.26 SECONDARY METAL 61.86 61.63 61.63 55.48 33.37 29.67 24.97 STEAM GENERATOR 155.89 159.65 159.65 140.76 85.41 76.22 64.74 TOTAL CONTENTS 619.40 369.48 369.48 326.53 207.79 190.48 165.78 EFFLUENT BREAK FLOW .oo 253.65 253.65 307.65 493.81 533.65 772 .OS ECCS SPILL .oo .oo .oo .00 .00 .oo .oo TOTAL EFFLUENT .00 253.65 253.65 307.65 493.81 533.65 772 .OS
      • TOTAL ACCOUNTABLE *** 619.40 623.13 623.13 634.18 701.60 724.13 937.83 183

TABLE 3.6.1-13 PUMP SUCTION DOUBLE ENDED RUPTURE MINIMUM SI - SINGLE TRAIN REFLOOD MASS AND ENERGY RELEASE TIME BREAX PATH NO.l FLOW BREAX PATH N0.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC 22.6 .o .o .o .o 23.5 .o .o .o .o 23.6 44.4 52.3 .o .o 23.7 25.2 29.6 .o .o 24.1 47.4 55.8 .o .o 24.8 70.8 83.4 .o .o 25.7 96.5 113.7 .o .o 26.7 119.2 140.5 .o .o 27.7 139.4 164.3 149.9 2.3 28.7 294.2 347.6 2818.4 284.4 29.0 417.0 493.8 4206.5 448.0 29.7 452.5 536.3 4525.1 502.1 30.7 446.2 528.8 4462.9 498.8 32.7 427.7 506.6 4285.3 482.1 34.7 410.2 485.8 4114.3 465.8 35.7 402.0 476.0 4033.0 458.0 36.7 394.2 466.7 3954.6 450.5 38.7 379.6 449.3 3806.2 436.2 40.7 366.3 433.4 3668.2 423.0 42.7 354.1 418.8 .3539.5 410.7 44.7 342.7 405.3 3419.0 399.1 46.7 332.3 392.9 3305.9 388.3 47.8 260.8 308.0 243.0 118.2 48.8 250.8 296.1 239.5 113.3 52.8 238.0 281.0 234.7 107.0 60.8 214.9 253.6 226.1 95.9 61.8 212.2 250.3 225.1 94.6 65.8 202.3 238.6 221.5 89.9 73.8 184.4 217.5 215.2 81. 7 81.8 169.1 199.3 209.9 74.9 89.8 156.0 183.9 205.5 69.3 97.8 145.2 171.1 202.0 64.8 105.8 136.3 160.6 199.1 61.2 113.8 129.2 152.2 196.9 58.3 121.8 123.6 145.7 195.2 56.1 129.8 119.5 140.8 193.9 54.5 137.8 116.4 137.2 192.9 53.3 143.8 115.4 136.0 193.9 53.1 147.8 114.8 135.2 197.0 53.6 151.8 114.1 134.5 202.0 54.6 155.8 113.3 133.5 208.5 55.9 159.8 112.1 132.0 216.3 57.4 163.8 110.4 130.1 225.1 59.1 165.8 109.8 129.4 229.5 59.9 173.8 109.3 128.8 244.7 62.4 175.8 109.1 128.5 248.0 62.8 183.8 107.8 127.0 259.8 63.9 191.8 106.1 124.9 269.0 64.1 199.8 104.0 122.5 276.2 63.6 200.3 103.9 122.4 276.6 63.6 184

TABLE 3.6.1-14 I

SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - SINGLE TRAIN PRINCIPAL PARAMETERS DURING REFLOOD FLOODING INJECTION CARRYOVER _CORE DOWNCOMER FLOW TIME TEMP RATE- FRACTION HEIGHT HEIGHT FRACTION TOTAL ACCUMULATOR ~ ENTHALPY SECONDS DEGREE F IN/SEC n n (POUNDS MASS PER SECOND) BTU/LBM 22.6 172.2 .000 .000 .oo .oo .333 .o .o .o .00 23.3 170.2 26.080 .000

  • 64 1.47 .ooo 7194.8 7194.8 .o 74.03 23.5 169.0 30.117 .ooo 1.12 1.56 .ooo 7104.5 7104.5 .o 74.03 24.7 168.5 2.632 .299 1.50 4.72 .408 6764.7 6764.7 .o 74.03 25.7 168.6 2.490 .421 1.64 7.50 .439 6516.2 6516.2 .o 74.03 29.0 168.8 4.751 .624 2.00 15.52 .680 5642.9 5236.4 .o 69.82 29.7 168.7 4.855 .649 2.10 15. 5_7 .683 5402.5 5004.5 .o 69.72 30.7 168.6 4.628 .672 2.24 15.57 .681 5249.7 4850.7 .o 69.59 33.1 168.6 4.257 .701 2.51 15.57 .* 676 4960.1 4556.5 .o 69.27 38.3 169.3 3.798 .723 3.01 15.57 .664 4454.5 4042.3 .o 68.62 44.3 170.7 3.463
  • 730 3.50 15.57 .650 3997.5 3578.0 .o 67.89 46.7 171.4 3.357 .731 3.68 15.57 .645 3840.6 3418.8 .o 67.61 47.8 171. 7 2.853 .727 3.76 15.56 .593 434.0 .o .o 15.55
51. 7 173.1 2.706 .727 4.01 15.22 .585 437.1 .o .o 15.55 60.8 177. 7 2.463 .726 4.54 14.59 .573 440.2 .o .o 15.55 69.3 182.9 2.277 .725 5.00 14.18 .561 442.4 .o .o 15.55 79.8 190.2 2.086 .723 5.53 13.88 .546 444.5 .o .o 15.55 90.0 197.7 1.936
  • 722 6.00 13.76 .531 446.0 .o .o 15.55 101.8 206.6 1.801 .722 6.51 13.78 .515 447.2 .o .o 15.55 113.9 215.3 1.699 .722 7.00 13.94 .502 448.1 .o .o 15.55 127.8 224.0 1.619 .724 7.53 14.26 .490 448.7 .o .o 15.55 140.6 231.0 1.575 .726 8.00 14.63 .484 449.1 .o .o 15.55 155.8 238.4 1.542 .729 8.54 15.07 .481 449.3 .o .o 15.55 169.3 244.1 1.499 .731 9.00 15.35 .478 449.5 .o .o 15.55 185.8 250.4 1.452 .733 9.54 15.51 .481 449.4 .o .o 15.55 200.3 255.2 1.396 .735 10.00 15.56 .483 449.4 .o .o 15.55 185

TABLE 3.6.1-15 SURRY UNITS 1 ARD 2 PUMP SUCTION DOUBLE ENDED RUPTURE MINIMUM SI - SINGLE TRAIN POST REFLOOD MASS AND ENERGY RELEASE TIME BREAK PATH N0.1 FLOW BREAK PATH N0.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/S'i£ LBM/SEC BTU/SEC 200.3 117.9 147.0 318.3 68.6 205.3 117.6 146.6 318.7 68.5 210.3 118.0 147.2 318.2 68.2 220.3 117.3 146.3 318.9 68.1 225.3 117.8 146.9 318.5 67.8 235.3 117.0 146.0 319.2 67.6 240.3 117.5 146.5 318.8 67.4 250.3 116.8 145.6 319.5 67.2 255.3 117.2 146.1 319.1 66.9 260.3 116.8 145.7 319.4 66.9 265.3 117.2 146.2 319.0 66.6 275.3 116.5 145.3 319.8 66.4 280.3 116.9 145.8 319.4 66.2 290.3 116.1 144.8 320.1 66.0 305.3 116.5 145.3 319.8 65.4 315.3 115.7 144.3 320.5 65.3 340.3 116.0 144.6 320.3 64.3 350.3 115.1 143.6 321.1 64.2 355.3 115.5 144.0 320.8 63.9 370.3 114.9 143.3 321.3 63.5 385.3 115.1 143.5 321.2 65.4 400.3 114.4 142.7 321.8 64.9 415.3 114.8 143.1 321.5 64.3 425.3 114.0 142.2 322.2 64.1 450.3 114.2 142. 4. 322.1 63.1 465.3 113.7 141. 7 322.6 62.7 475.3 114.1 142.3 322.1 62.2 490.3 113.5 141.5 322.8 61. 7 500.3 113.9 142.0 322.4 61.2 505.3 113.4 141.4 322.8 61.2 515.3 113.7 141.8 322.5 63.0 520.3 113.2 141.2 323.0 62.9 530.3 113.5 141.5 322.8 62.4 535.3 113.0 140.9 323.3 62.3 560.3 113.2 141.2 323.0 61.2 565.3 112.6 140.4 323.6 61.1 590.3 112.3 140.1 323.9 60.1 595.3 112.7 140.6 323.5 59.8 610.3 112.3 140.0 324.0 61.4 615.3 112.6 140.4 323.7 61.1 670.3 111.8 139.4 324.5 58.7 1107.3 111.7 139.3 324.6 59.0 1107. 4 58.8 72.8 377.S 68.6 1338.6 58.7 72.8. 377.5 67.5 1338.7 53.2 61.3 383.0 68.5 3529.9 39.9 46.0 396.3 70.9 3530.0 43.1 49.6 339.0 43.0 3599.9 42.7 49.2 336.2 42.61 3600.0 42.7 49.2 336.2 42.6 3600.1 35.8 41.2 343.2 39.8 10000.0 25.8 29.7 353.1 41.0 100000.0 14.4 16.5 364.6 42.3 1000000.0 6.2 7.1 372.8 43.2 186

TABLE 3.6.1-16 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MINIMUM SI - SINGLE TRAIN MASS BALANCE TIME (SECONDS) .00 22.60 22.60 200.27 1107.30 1338.58 3600.00 MASS (THOUSAND LBM)

INIT!AL IN RCS AND ACC 605.48 605.48 605.48 605.48 605.48 605.48 605.48 ADDED MASS PUMPED INJECTION .00 .oo .oo 76.72 472.40 560.50 1417.44 TOTAL ADDED .00 .oo .oo 76.72 472.40 560.50 1417.44

      • TOTAL AVAILABLE *** 605.48 605.48 605.48 682 .. 19 1077.87 1165.97 2022.92 DISTRIBUTION REACTOR COOLANT 419.33 50.34 67.55 125.35 125.35 125.35 125.35 ACCUMULATOR 186.15 134.71 117.50 .oo .oo .oo .oo TOTAL CONTENTS 605.48 185.05 185.05 125.35 125.35 125.35 125.35 EFFLU)!:NT BREAK FLOW .oo 420.42 420.42 556.82 952.50 1040~60 1897.55 ECCS SPILL .oo .oo .oo .oo .oo .oo .oo TOTAL EFFLUENT .oo 420.42. 420.42 556.82 952.50 1040.60 1897.55
      • TOTAL ACCOUNTABLE *** 605.48 605.46 605.46 682.18 1077.86 1165. 96 2022.so 187

TABLE 3.6.1-17 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MINIMUM SI - SINGLE TRAIN ENERGY BALANCE TIME (SECONDS) .oo 22.60 22.60 200.27 1107.30 1338.58 3600.00 ENERGY (MILLION BTU)

INITIAL ENERGY IN RCS,ACC,S GEN 619.40 619.40 619.40 619.40 619.40 619.40 619.40 ADDED ENERGY PUMPED INJECTION .00 .oo .oo 1.19 7.35 17.21 116.60 DECAY HEAT .00 4.99 4.99 20.42 75.37 87.13 181.83 HEAT FROM SECONDARY .00 -1.27 ,;_1.27 -1.27 4.22 4.27 4.27 TOTAL ADDED .oo 3. 72 3.72 20.34 86.94 108.61 303.70

      • TOTAL AVAILABLE *** 619.40 623.12 623.12 639.74 706.34 728.01 922.10 DISTRIBUTION REACTOR COOLANT 242.89 9.78 11.06 31.11 31-.11 31.11 31.11 ACCUMULATOR 13.89 10.05 8.78 .oo .oo .oo .oo CORE STORED 19.49 10.04 10.04 3.87 3.24 3.19 2.68 PRIMARY METAL 125.38 118.32 118.32 95.49 54.78 50.27 42.33 SECONDARY METAL 61.86 61.63 61.63 55.55 33.53 29.70 25.03 STEAM GENERATOR 155.89 159.65 159.65 141.01 85.87 76.39 64.99 TOTAL CONTENTS 619.40 369.48 369.48 327.04 208.54 190.66 166.15 EFFLUENT BREAK FLOW .oo 253.65 253.65 307.02 492 .11 531. 66 750.26 ECCS SPILL .00 .oo .oo .oo .oo .00 .00 TOTAL EFFLUENT .00 253.65 253.65 307.02 492 .11 531. 66 750.26
      • TOTAL ACCOUNTABLE *** 619.40 623.13 623.13 634.05 700.65 722. 32 916.41 188

TABLE 3.6.1-18 SURRY UN ITS 1 AND 2 PIN> SUCT Ulf DCUlLE ENDED RlPTURE NAXltul SI - TWO TRAIii REFLO(J) NASS AND ENERGY RELEASES TIME BREAK PATH IIO. 1 FLOY BREAK PATH IIO. 2 FLOY LBN/SEC TIIWSAII) TIIWSAII)

Sl;CONDS BTU/SEC LBM/SEC BTU/SEC 22.6 .0 .0 .0 .0 23.5 .o .0 .0 .o 23.6 44.4 52.3 .o .o 23.7 25.2 29.6 .o .0 24.1 47.4 55.8 .o .0 24.8 70.8 83.4 .o .o 25.7 90.6 113.7 .o. .0 26.7 119.2 140.5 .0 .0 27.7 140.0 165.0 221.5 3.4 28.7 335.7 397.0 3311.0 326.9 29.0 434.5 514.7 4393.0 451.8 29.7 470.5 557.8 4710.7 504.7 30.7 463.9 550.0 4647.8 501.2 33.7 445.1 527.5 4469.9 484.5 32.9 443.3 525.3 4452.3 482.8 33.7 436.0 516.6 4383.7 476.2 34.7 427.3 506.2 4298.2 468.2 35.7 419.0 496.3 4216.5 460.4 36.7 411.0 486.8 4137.8 452.9 37.7 403.4 477.7 4061.8 445.7 38.0 401.2 475.0 4039.6 443.6 38.7 396.2 469.0 3988.7 432.0 39.7 389.2 460.7 3918.1 438.8 40.7 382.6 452.8 3850.0 432.0 41.7 376.2 445.2 3784.3 425.6 43.7 370.1 437.9 3n0.7 419.3 43.7 364.2 430.9 3659.3 413.3 43.9 363.0 429.5 3647.2 407.4 45.7 353.1 417.6 3542.1 406.3 46.7 347.8 411.4 3486.2 396.3 47.7 343.7 405.3 3432.0 390.9 48.7 156.9 185.0 398.3 385.8 53.7 155.1 182.8 402.1 93.0 61.7 142.3 179.5 407.7 92.2 63.7 151.6 178.7 409.0 90.8*

71.7 148.9 175.5 414.3 90.5 73.7 148.2 174.7 415.5 89.1 89.7 142.8 168.3 425.8 88.7 101.7 138.7 163.4 433.5 86.0 107.7 136.6 161.0 437.4 83.9 115.7 133.7 157.6 442.8 82.9 117.7 133.0 156.8 444.1 81.5 149.7 121.2 142.8 465.3 81.1 157.7 118.1 139.1 470.6 75.5 161.7 116.5 137.3 473.2 74.1 169.7 113.4 133.7 478.5 73.4 173.7 111.9 131.9 481.1 n.1 189.7 107.5 126.6 487.8 71.4 197.7 105.3 124.0 491.1 70.5 201.5 104.3 122.9 493.7 70.3 189

TABLE 3.6.1-19 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - TWO TRAIN PRINCIPAL PARAMETERS DURING REFLOOD INJECTION FLOODING CARRYOVER CORE DOWNCOMER FLOW IQIAL ,a!:,';~Y:l:UlLaIQB SPILL ENTHALPY TIME FRACTION HEIGHT HEIGHT FRACTION (BTU/LBM)

SECONDS TEMP RATE FT FT (POUNDS MASS PER SECOND)

DEGREE F IN/SEC 22.6 172.2 .000 .000 .oo .oo .333 .o .o .o .oo 23.3 170.2 26.080 .ooo .64 1.47 .ODO 7194.8 7194.8 .o 74.03 23.5 169.0 30.117 .ooo 1.12 1.56 .ooo 7104.5 7104.5 .o 74.03 24.7 168.5 2.632 .299 1.50 4.72 .408 6764.7 6764.7 .o 74.03 25.7 168.6 2.490 .421 1.64 7.50 .439 6516.2 6516.2 .o 74.03 29.0 168.8 4.902 .624 2.00 15.52 .686 5853.6 5190.0 .o 67.40 29.7 168.7 5.001 .649 2.11 15.57 .688 5614.9 4951.4 .o 67.12 30.7 168.6 4.764 .673 2.24 15.57 .687 5461.8 4798.3 .o 66.93 32.9 168.5 4.408 .701 2.50 15.57 .682 5192.5 4529.0 .o 66.56 38.0 169.0 3.936 .723 3.00 15.57 .671 4686.8 4023.1 .o 65.75 43.9 170.3 3.594 .731 3.51 15.57 .659 4228.4 3564.6 .o 64.85 47.7 171.3 3.424 .732 3.81 15.57 .651 3980.9 3317.0 .o 64.28 48.7 171.6 2.154

  • 716 3.86 15.57 .485 664.4 .o .o 15.55 51.5 172. 6 2.137
  • 717 4.00 15.57 .485 664.4 .o .o 15.55
61. 7 177 .3 2.082
  • 719 4. 51, 15.57 .486 664.4 .o .o 15.55 71.9 183.2 2.029 .720 5.00 15.57 .486 664.4 .o .o 15.55 82.7 190.4 1.975 .721 5.50 15.57 .486 664.4 .o .o 15.55 93.8 198.4 1.919 .723 6.00 15.57 .486 664.4 .o .o 15.55 105.7 207.2 1.858 .724 6.52 15.57 .486 664.4 .o .o 15.55 117.2 215.6 1.798 .726 1.00 15.57 .487 664.4 .o .o 15.55 129.6 223.7 1. 733 .728 7.51 15.57 .486 664.4 .o .o 15.55 142.6 231.1 1.666 .729 8.00 15.57 .486 664.4 .o .o 15.55 157.7 238.6 1.588 .731 8.55 15.57 .486 664.4 .o .o 15.55 170.5 244.1 1.521 .732 9.00 15.57 .485 664.4 .o .o 15.55 185.7 249.9 1.455 .733 9.50 15.57 .486 664.4 .o .o 15.55 201.5 255.2 1.390 .735 10.00 15.57 .487 664.4 .o .o 15.55 190

TABLE 3.6.1-20 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - TWO TRAIN POST REFLOOD MASS AND ENERGY RELEASES TIME BREAK PATH NO. 1 FLOW BREAK PATH NO. 2 FLOW SECONDS LBM/SEC THOUSAND LBM/SEC THOUSAND BTU/SEC BTU/SEC 201.6 119.3 149.0 531.4 73.2 206.6 119.0 148.6 531. 7 73.1 211.6 119.5 149.2 531.3 72.8 221.6 118.8 148.3 532.0 72.6 226.6 119.2 148.9 531.5 72.3 236.6 118.5 148.0 532.2 72.2 241.6 119.0 148.6 531.8 71.9 251.6 118.2 147.7 532.5 71. 7 256.6 118. 7 148.2 532.1 71.4 266.6 117.9 147.3 532.8 71.3 271.6 118.4 147.8 532.4 71.0 281.6 117.6 146.9 533.1 70.8 286.6 118.0 147.4 533.7 70.5 291.6 117.6 146.9 533.1 70.4 296.6 118.0 147.4 532.7 70.2 306.6 117.3 146.5 533.5 70.0 311.6 i17.7 146.9 533.1 69.7 316.6 117.3 146.5 533.5 69.6 321.6 117.6 146.9 533.1 69.4 331.6 116.8 145.9 533.9 69.2 341.6 116.8 145.9 534.0 68.8 356.6 117.0 146.2 533.7 68.2 366.6 116.2 145.1 534.5 68.1 381.6 116.4 145.4 534.3 67.4 396.6 115.8 144.6 534.9 67.0 421. 6 116.1 145.0 534.6 66.0 431.6 115.3 144.1 535.4 65.8 456.6 115.5 144.2 535.3 67.2 471. 6 114.9 143.5 535.8 66.7 481.6 115.4 144.2 535.3 66.2 496.6 114. 7 143.3 536.0 65.7 506.6 115.1 143.8 535.6 65.2 511.6 114. 7 143.2 536.1 65.l 521. 6 115.0 143.6 535.8 64.6 526.6 114.5 143.0 536.3 64.6 541.6 114.8 143.4 536.0 63.8 546.6 114.2 142.7 536.5 66.0 571. 6 114.3 142.8 536.4 64.8 611. 6 113.5 141. 7 537.2 63.2 626.6 113.8 142.2 536.9 64.5 671.6 113.0 141.2 537.7 62.5 1091.2 113.0 141.1 537.8 62.7 1091. 3 59.0 73.2 591. 7 72.1 1318.4 58.9 73.1 591.8 72 .3 1318.5 53.4 61.5 597.3 72.9 3529.9 39.9 46.0 610.8 72.6 3530.0 43.1 49.6 535.5 65.8 3599.9 42.7 49.2 535.9 65.8 3600.0 42.7 49.2 535.9 65.8 3600.1 35.8 41.2 542.9 63.0 10000.0 25.8 29.7 552.8 64.1 100000.0 14.4 16.5 564.3 65.4 1000000.0 6.2 7.1 572.5 66.4 191

TABLE 3-21 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - TWO TRAIN MASS BALANCE TIME (SECONDS) .oo 22.60 22.60 201~51 1091.16 1318.44 3600.00 MASS (THOUSAND LBM)

INITIAL IN RCS AND ACC 605.48 605.48 605.48 605.48 605.48 605.48 605.48 ADDED MASS PUMPED INJECTION .oo .oo .00 115.88 694.74 827.01 2147.18 TOTAL ADDED .oo .oo .oo 115.88 694.74 827.01 2147.18

      • TOTAL AVAILABLE *** 605.48 605.48 605.48 721.35 1300.22 1432.48 2752.66 DISTRIBUTION REACTOR COOLANT 419.33 50.34 67.55 125.52 125.52 125.52 125.52 ACCUMULATOR 186.15 134.71 117.50 .oo .oo .oo .oo TOTAL CONTENTS 605.48 185.05 185.05 125.52 125.52 125.52 125.52 EFFLUENT BREAK FLOW .oo 420.42 420.42 595.82 1174.68 1306.95 2627.12 ECCS SPILL .oo .oo .oo .oo .oo .oo .oo TOTAL EFFLUENT .oo 420.42 420.42 556.82 952.50 1040.60 1897.55
      • TOTAL ACCOUNTABLE *** 605.48 605.46 605.46 721.34 1300.20 1432.47 2752.64 192

TABLE 3.6.1-22 SURRY UNITS 1 AND 2 PUMP SUCTION DOUBLE ENDED RUPTURE MAXIMUM SI - TWO TRAIN ENERGY BALANCE TIME (SECONDS) .oo 22. 60

  • 22.60 201.51 1091.16 1318.44 3600.00 ENERGY (MILLION BTU)

INITIAL ENERGY IN RCS,ACC,S GEN 619.40 619.40 619.40 619.40 619.40 619.40 619.40 ADDED ENERGY PUMPED INJECTION .oo .oo .oo 1.80 10.80 25.46 178.58 DECAY HEAT .oo 4.99 4.99 20.51 74.52 86.12 181.79 HEAT FROM SECONDARY .oo -1.27 -1.27 -1.27 4.11 4.18 4.18 TOTAL ADDED .oo 3.72 3.72 21.05 89.44 115.76 364.54

      • TOTAL AVAILABLE *** 619.40 623.12 623.12 640.44 708.84 735.16 983.94 DISTRIBUTION REACTOR COOLANT 242.89 9.78 11.06 31.15 31.15 31.15 31.15 ACCUMULATOR 13.89 10.05 8.78 .oo .oo .oo .oo CORE STORED 19.49 10.04 10.04 3~87 3.25 3.20 2.68 PRIMARY METAL 125.38 118.32 118.32 95.20 54.85 50.34 42.31 SECONDARY METAL 61.86 61.63 61.63 55.59 33.58 29.73 25.02 STEAM GENERATOR 155.89 159.65 159.65 141.08 85.88 76.38 64.87 TOTAL CONTENTS 619.40 369.48 369.48 326.89 208.70 190.79 166.03 EFFLUENT BREAK FLOW .oo 253.65 253.65 307.86 494.45 538.68 812.23 ECCS SPILL .oo .oo .oo .oo .oo .oo .oo TOTAL EFFLUENT .oo 253.65 253.65 307.86 494.45 538.68 812.23
      • TOTAL ACCOUNTABLE *** 619.40 623.13 623.13 634.75 703.15 729.47 978.25 193

TABLE 3.6.1-23 SURRY UNIT 1 AND 2 HOT LEG DOUBLE ENDED RUPTURE BLOWDOWH MASS ARD ENERGY RELEASE TIME BREAK PATH HO .1 FLOW BREAK PATH H0.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC LBM/SEC BTU/SEC

.000 97796.9 61319.6 97796.9 61319.6

.100 44302.2 27906.2 25174.9 15676.2

.201 32479.3 20834.5 23505.3 14594.3

.301 31740.7 20355.1 20807.5 12812. 4

.500 30852.8 _19801. 0 . 18619.3 11165.9

.701 30154.6 19423.6 17500.7 10229.9

.901 29607.6 19183.0 16752.7 9593.2 1.30 28031. 7 18506.4 15907.6 8847.1 1.80 26097.3 17554.2 16002.7 8684.9 2.40 23298.9 15946.2 16408.2 8751. 5 2.80 21629.1 14870.7 16481.9 8747.1 3.10 20642.5 14190.4 16394.0 8687.2 3.40 19830.2 13576.2 16205.1 8584.9 3.70 19209.5 13056.0 15934.4 8447.3 4.00 18769.2 12625.4 15581.1 8272. 5 4.40 18556.1 12262.2 14959.4 7968.0 4.60 18759.1 12269.7 14601.0 7792.8 4.80 13553.7 9799.7 14253.7 7624.5 5.00 14437.8 10293.3 13897.8 7451.4 5.40 15127.3 10366.0 12928.3 6965.4 6.20 16036.3 10426.0 11183.9 6096.6 6.40 15887.8 10270.9 10765.6 5885.4 7.00 16636.5 10473.1 9623.0 5302.1 7.40 17246.1 10694.4 8968.9 4965.6 7.60 17812.3 10938.8 8671.3 4812.4 7.80 17895.8 10948.3 8388.3 4666.8 8.00 17652.3 10761.0 8117.8 4527.6 8.20 16567.5 10159.9 7855.9 4393.0 8.40 14870.2 9240.1 7604.0 4263.8 8.80 14966.7 9234.9 7131.1 4023.3 9.40 14523.8 8930.1 6508.5 3711. 0 9.80 13634.5 8412.9 6123.8 3519.5 10.6 12298.1 7634.6 5417.1 3175.7 11.4 10924.8 6875.8 4795.8 2881.9 12.4 9076.4 5921. 9 4081.3 2552.2 13.0 7689.6 5289.7 3539.1 2314.3 13.8 5917.3 4609.6 2709.1 1975.2 14.4 4673.6 4108.7 2254.7 1763.0 14.8 3742.2 3625.3 2063.6 1657.1 16.2 1510.3 1804.0 1549.0 1403.7 16.6 998.4 1234.2 1373.5 1343.l 17.4 512.7 646.1 1032.9 1210.2 18.0 333.2 422.2 703.1 866.2 18.6 .o .o 384.3 476.8 19.2 .o .o 185.6 233.1 19.6 359.6 457.7 185.7 233.4 21.4 414.6 523.1 124.8 158.0 21.8 504.2 623.9 132.6 167.9 22.4 .o .o 128.4 162.1 22.8 .o .o .o .o

      • 194

TABLE 3.6.1-24 SURRY UNITS 1 AND 2 HOT LEG DOUBLE ENDED RUPTURE BL0WDOWH MASS BALANCE TIME (SECONDS) .oo 22.80 MASS (THOUSAND LBM)

INITIAL IN RCS AND ACC 605.48 605.48 ADDED MASS PUMPED INJECTION .oo * .00 TOTAL ADDED .oo .oo

      • TOTAL.AVAILABLE *** .. 605.48 . . . 605.48 DISTRIBUTION REACTOR COOLANT 419.33 86.28 ACCUMULATOR 186.15 117. 66 TOTAL CONTENTS 605.48 203.93 EFFLUENT BREAK FLOW .oo 401.53 ECCS SPILL .oo .oo TOTAL EFFLUENT .oo 401.53
      • TOTAL. ACCOUNTABLE *** 605.48 605.46 195

TABLE 3.6.1-25 SURRY UNITS 1 AND 2 HO!l' LEG DOUBLE ENDED RUP!l'URE BLOWDOWN ENERGY BALANCE

!l'IME (SECOHDS) .oo 22.80 ENERGY (MILLION BTU)

INITIAL ENERGY IN RCS,ACC,S GEN 619.40 619.40 ADDED ENERGY PUMPED INJECTION .00 .oo DECAY HEAT .oo 5.50 HEAT FROM SECONDARY .oo -2.53 TOTAL ADDED .oo 2.98

      • TOTAL AVAILABLE *** 619.40 622.37 DISTRIBUTION REACTOR COOLANT 242.89 18.94 ACCUMULATOR 13.89 8.78 CORE STORED 19.49 a.as PRIMARY METAL 125.38 116.24 SECONDARY METAL 61.86 60.28 STEAM GENERATOR 155.89 155.34 TOTAL CONTENTS 619.40 367.66
  • EFFLUENT BREAK FLOW ECCS SPILL TOTAL EFFLUENT TOTAL ~CCOUNTABLE ***

.oo

.oo

.oo 619.40 254.70

.oo 254.70 622.36

  • 196

TABLE 3.6.1-26 SURRY UNITS 1 AND 2 BOT LEG DOUBLE ENDED RuP!rURB MAXIMUM SI - !rwo Train LONG TERM HPSB ANALYSIS REFLOOD AND POST REFLOOD MASS AND ENERGY RELEASE TIME STEAM RELEASE WATER RELEASE SECONDS LBM/SEC 1000 BTU/SEC LBM/SEC 1000 BTU/SEC 22.8 .o .o .o .o 23.0 .o .o .o .o 23.1 .o .o .o .o 23.3 733.6 146.1 .o .o 23.4 420.1 225.7 .o .o 25.7 1153.7 389.0 .o .o 28.8 1775.0 500.3 .o .o 29.8 1907.5 522.1 .o .o 35.4 1841.2 511.9 2997.3 199.5 47.8 1628.8 468.1 2044.8 131. 6 48.5 1620.6 397.8 .o .o 50.0 1527.9 368.9 .o .o 59.2 905.7 307.9 .o .o 88.7 423.5 258.6 .o .o 100.0 408.7 254.5 .o .o 115.81 394.2 249.9 .o .o 115.811 98.9 117.5 .o .o 200.0 85.2 101.1 576.6 9.0 500.0 62.1 73.7 599.7 9.3 1000.0 47.5 56.4 614.3 9.6 1499.9 41. 6 49.4 620.2 9.6 1500.0 52.6 62.5 609.1 159.5 2000.0 48.1 57.2 613.6 160.7 5000.0 36.3 43.2 625.4 163.8 10000.0 29.3 34.8 632.5 165.6 20000.0 25.3 30.0 636.5 166.7 50000.0 19.9 23.6 641.9 168.1 100000.0 16.3 19.3 645.5 169.0 1000000.0 7.0 8.3 654.8 171.5 ENTRAINMENT ENDS AT 115.81 SECONDS 197

  • TABLE 3.6.1-27 SURRY UNITS 1 AND 2 BOT LEG DOUBLE ENDED RUPTURE MAXIMUM SI - Two Train LONG TERM NPSB ANALYSIS PRINCIPAL PARAMETERS DURING REFLOOD TIME FLOODING CARRYOVER CORE DOWNCOMER FLOW INJECTION TEMP RATE FRACTION HEIGHT HEIGHT FRACTION TOTAL ACCUMULATOR SPILL ENTHALPY SECONDS DEGREE F IN/SEC r.r r.r (CUBIC FEET PER SECOND) BTU/LBM

.oo 292.30 0.000 .000 .oo .oo .333 .o .o .o 15.55

.21 286.37 54.131 .000 .51 .17 .999 129.8 119.2 .o 69.23

.31 280.51 70.430 .000 1.03 -0.08 .849 129.3 118.7 .o 69.21

.49 275.01 6.391 .358 1.50 -0.09 .897 127.2 116.6 .o 69.14

.61 274.58 4.883 .387 1.53 0.27 .885 127.0 116.4 .o 69.13 2.94 264.83 7.406

  • 717 2.00 6.65 .921 114.5 103.8 .o 68.59 5.97 247.83 10.074 .809 2.50 13.05 .926 100.8 90.2 .o 67.86 7.01 241.64 10.673 .820 2.67 14.84 .926
  • 96. 7 86.1 .o 67.60 8.01 235.90 10.666 .825 2.83 15.57 .926 93.8 83.2 56.5 67.40 9.15 229.90 10.512 .828 3.00 15.57 .926 90.9 80.3 54.2 67.19 12.57 214.85 10.153 .831 3.50 15.57 .926 83.3 72.7 47.9 66.56 16.12 202.83 9.835 .830 4.00 15.57 .926 76.8 66.2 42.5 65.93 19.74 193.31 9.524 .827 4.50 15.57 .926 71.2 60.6 37.9 65.29 23.42 185.74 9.208 .825 5.00 15.57 .926 66.3 55.7 34.1 64.64 25.01 182.97 9.071 .823 5.21 15.57
  • 926 64.4 53.7 32.7 64.36 25.65 181.93 9.017 .823 5.30 15.57 .926 10.6 .o .o 15.55 27.20 179.56 8.371 .819 5.50 14.72 .925 10.6 .o . .o 15.55 31.45 174.14 6.702 .805 6.00 12.89 .921 10.6 .o .o 15.55 36.44 169.64 5.217 .788 6.50 11.51 .915 10.6 .o .o 15.55 42.35 166.18 4.048
  • 770 7.00 10.63 .906 10.6 .o .o 15.55 49.33 163.67 3.256 .754 7.50 10.26 .897 10.6 .o .o 15.55 57.27 161.81 2.810 .744 8.00 10.29 .890 10.6 .o .o 15.55 65.87 160.29 2.600 .738 a.so 10.59 .886 10.6 .o .o 15.55 74.81 158.87 2. 511 .735 9.00 11.02 .885 10.6 .o .o 15.55 83.88 157.40 2.476 .734 9.50 11.50 .884 10.6 .o .o 15.55 93.01 155.85 2.462 .733 10.00 12.01 .884 10.6 .o .o 15.55 198

~ 3.6.1~28 SURRY UNITS 1 AND 2 BOT LEG DOUBLE ENDED RUPTURE MAXIMUM SI - Two Train LONG TERM HPSB ANALYSIS MASS *BALANCE TIME (SECONDS) .00 22.80 115.81 1500.00 MASS (1000 LBM)

AVAILABLE INITIAL IN RCS AND ACC 605.48 605.48 605.48 605.48 ADDED MASS PUMPED INJECTION .oo .oo 65.93 981.93 TOTAL ADDED .oo .00 65 *.93 981.93

      • TOTAL AVAiLABLE *** 605.48 605.48 671.41 1587.41 DISTRIBUTION REACTOR COOLANT 419.33 86.28 136.10 148.70
  • ACCUMULATOR 186.15 117.66 .oo .00 TOTAL CONTENTS 605.48 203.93 136.10 148.70 EFFLUENT BREAK FLOW .oo 401.53 486.89 565.18 ECCS SPILL .oo .oo '48. 41 873.52 TOTAL EFFLUENT TOTAL ACCOUNTABLE ***

.oo 605.48 401.53 605.46 535.30 671.40 1438.70 1587.40

  • 199

TABLE 3.6.1-29 SURRY UNITS 1 AND 2 BOT LEG DOUBLE EHDED RUPTURE MAXIMUM SI - Two Train LONG TERM HPSB ANALYSIS ENERGY BALANCE TIME (SECONDS) .oo 22.80 115.81 1500.00 ENERGY (1000000 BTU)

AVAILABLE ENERGY IN RCS,ACC,S GEN 619.40 619.40 619.40 619.40 ADDED ENERGY PUMPED INJECTION .oo .oo 1.18 15.42 DECAY HEAT .oo 5.50 .14.26 95.47 HEAT FROM SECONDARY .oo -2.53 -2.53 -2.53 TOTAL ADDED .oo 2.98 12.91 108.36

      • TOTAL AVAILABLE *** 619.40 622.37 632.31 727.76 DISTRIBUTION REACTOR COOLANT 242.89 18.94 27.65 27.85 ACCUMULATOR 13.89 8.78 .oo .00 CORE STORED 19.49 8.08
  • 69 .69 THIN METAL 13.59 11.44 5.84 5.84 THICK METAL 24.67 24.27 20.87 11.11

.oo 296.17 367.66 254.70 288.64 343.70 285.43 287.85 333.35 378.40 ECCS SPILL .oo .oo 3.19 16.02

  • TOTAL EFFLUENT .oo 254.70 288.62 394.42
      • TOTAL ACCOUNTABLE *** 1?19.40 622.36 632.32 727. 77 200

3.6.2 WCA Containment Response Analysis 3.6.2.1 Analysis Model of WCA Accident Response 3.6.2.1.1 Response to Loss of Coolant Accident The following discussion parallels that which is found in UFSAR Section 5.4, "Containment Design Evaluation." Key aspects of the containment response analysis and model are discussed in order to provide more complete documentation of the present core uprating evaluation.

There can be two significant peaks in the containment pressure transient following a LOCA depending on the break location. There is only one pressure peak following a rupture in the hot leg; there may be two peaks following a cold leg rupture. A pressure peak occurs near the end of the initial blowdown of the RCS after a double ended rupture (DER) of either a hot or cold leg. This will be referred to as the blowdown peak pressure. Its magnitude is a function of the following parameters:

1. The containment free volume.
2. The: mass* of air inside the containment structure (air mass is a function of initial pressure and temperature).
3. The amount of energy flow out of the break during the initial blowdown of the RCS .
4. The rate of heat removal from the containment atmosphere by the passive heat sinks within the containment structure; A hot leg DER produces the largest blowdown peak pressure. This event releases the most energy to** the .containment atmosphere during the initial blowdown since the hot leg pipe diameter is larger than that of an RCS pump discharge and there is no resistance to flow due to an RCS pump as in the case of a pump suction DER. The magnitude of the blowdown peak is

('

independent of the active engineered safety features (ESF) because they do not become effective until after the peak pressure occurs. However, the accumulators do have a small effect on the blowdown peak pressure.

Following a cold leg *break (at the RCS pump discharge or pump suction), a second pressure peak may occur after the end of the core reflooding period because the core effluent during and after reflooding passes through the steam generators to reach the break. The steam generator secondary water contains sufficient energy and the steam generator tubes have sufficient surface 201

area to boil the liquid portion of the core effluent. The magnitude of the second peak pressure is a function of the following parameters:

1. The containment free volume .
  • 2.

3.

4.

The mass of air inside the containment structure.

The rate of heat removal from the containment atmosphere by the passive heat sinks within the containment structure.

The rate of heat removal from the containment atmosphere by the containment heat removal systems.

5. The rate of mass and energy release to the containment from the break during the core reflooding period.
6. The mass of nitrogen added to the containment from the safety injection accumulators.
7. The amount of steam condensed by safety injection water.

Following the reflooding period, the containment depressurization systems and containment passive heat sinks remove energy from the containment atmosphere at a rate sufficient to reduce the pressure to less than atmospheric pressure within 60 minutes. The depressurization time is a function of the following parameters:

1. The containment free volume.
2. The mass of air inside the containment structure.
3. The rate of heat transfer between containment atmosphere and the passive heat sinks within the containment structure.
4. The rate of heat removal from the containment atmosphere by the containment heat removal systems (this is significantly dependent upon the ultimate heat sink temperature).
5. The rate of mass and energy release to the containment from the break following the end of core reflooding.
6. The mass of nitrogen added to the containment from the safety injection accumulators.

After the containment is depressurized, the depressurization systems continue to remove energy from the containment at a rate sufficient to maintain the containment at a subatmospheric pressure. The heated passive heat sinks add energy back to the containment atmosphere following depressurization. The containment experiences a subatmospheric pressure peak after the termination of containment spray associated with emptying of the RWST .

  • 202

3.6.2.1.2 Containment Response Analytical Model The LOCTIC computer program which is used to model the containment system, the passive

  • heat sinks and the containment heat removal systems was developed by Stone & Webster Engineering Corporation. A topical report (3.6.2-1) described in detail the assumptions used and the mathematical formulations employed.

CONTEMPTLT (3.6.2-2) code show excellent agreement.

Comparisons made with the standard LOCTIC has been under development for many years and was used in the design of eight operating units: Surry Power Station Units 1 and 2 (3.6.2-3), Maine Yankee Atomic Power Station (3.6.2-4), North Anna Station Units 1 and 2 (3.6.2-5), Beaver Valley Power Station Unit No. 1 (3.6.2-6), the Millstone Unit No. 3 (3.6.2-7) and the Beaver Valley Power Station Unit 2 (3.6.2-8).

LOCTIC calculates the temperature and pressure of the containment atmosphere as a function of time following a high energy pipe break accident. This calculation assumes the containment atmosphere to be a homogeneous mixture of steam and air in thermal equilibrium.

LOCTIC uses either of two models for the treatment of flashing of the break effluent. In the equilibrium flash model, the effluent is added directly to the containment atmosphere. Since this model maximizes energy input to the atmosphere, it is used to maximize containment pressure.

In the pressure flash model, the effluent expands at constant enthalpy to the containment total pressure. The saturated vapor is added to the atmosphere, and saturated liquid is added to the sump unmixed with the containment atmosphere. The pressure flash model maximizes energy input to the sump water and is thus used to maximize sump water temperature for pump available NPSH calculations.

The LOCTIC model conservatively accounts for condensation heat and mass transfer on containment surfaces. The heat transfer model also adds the thermal resistance of paint layers to the condensing film resistance. The code employs the Tagami heat transfer correlation with the formulation described in UFSAR Section 5.4. If the containment atmosphere temperature is less than the heat sink surface temperature, a conservatively small natural convection heat transfer coefficient is used. The code checks the surface temperature of each heat sink slab and uses the condensing coefficient or natural convection coefficient as applicable. Heat absorbed by passive heat sinks in containment is also calculated by LOCTIC (containment structure, internal concrete and miscellaneous metal equipment). The heat sinks are subdivided into various 203

groups with appropriate mesh spacing defined for each metal or concrete layer. The model considers transient heat conduction to the containment structure through the compos~te thermal resistance consisting of the paint film on the steel liner, the liner itself, the liner-concrete

  • interface and the concrete.

The LOCA mass and energy release rates are input to LOCTIC for the blowdown, reflood and post-reflood periods. The calculation of these release rates is described in Section 3. 6.1. During the post-reflood period, the release rates are adjusted for use in LOCTIC as described below.

This adjustment results in an energy release from the primary system which is consistent with the calculated containment pressure transient.

3.6.2.1.3 Post-Reflood Energy Release from Steam Generators During the post-reflood froth phase, the mass and energy release rates are modified for use in LOCTIC. The steam generator energy is released to the containment atmosphere in two stages referred to as the "equilibration stage" and the "depressurization stage." In the former:, the energy sources above the reference pressure used in calculating the mass and energy releases are brought into equilibrium with the containment pressure. The rate for this phase is set by the

  • Westinghouse froth calculation model. In the latter stage, the sources give up additional energy as the containment pressure decreases. The rate for this stage is set by the containment depressurization rate. The intact loop steam generators and metal energies are lumped together for this calculation. After the post-reflood froth period, LOCTIC computes the mass and energy
  • release tboil-off) to the containment atmosphere, which is governed by decay.

Broken Loop Steam Generator-Equilibrium Stage The mass and energy release rates into the containment during the time prior to broken loop steam generator equilibrium (I'*eq(bl)) were calculated with the Westinghouse model described in Section 3.6.1 (3.6.2-9) and are presented in Table 3.6.2-1. At the time (*~(bi>) when the broken loop equilibrates with the reference pressure (P*), the calculated containment pressure may be less than the reference pressure. If so, an extension of the broken loop equilibration stage is required. The total additional energy which must be transferred from the broken loop at any time during the extension of the equilibration state is:

204

E. AP.

AEeq (bl) = E.v (bl) -:-

  • 1 P*-P1o
  • where:

A~(b1> - Broken loop steam generator secondary energy to be removed during the extension of the broken loop equilibration stage.

E.v(bl) - The total energy (Btu) available in the broken loop steam generator secondary at the reference pressure relative to 212°F and 14.7 psia.

P* - The containment reference pressure used in the mass and energy release analysis (psia).

~ ,/'*.*: t w.,-*-,._:::; >_*

  • P1c - Assumed minimum containment pressure (14.7 psia) and AP1 is defined as:

AP1 = P1; i = 1 AP1-l - P1; i > 1 and "i" defines the ilb time interval following the referenced broken loop equilibration time t*eq(blJ 2

  • At the end of each interval, a new equilibration time is calculated by:

t'...<<i.1> = t* eq(bl) + A~(b1>

q*(b:L) 205

where:

~(bl) - Broken loop equilibration time based on calculated containment

  • t* oq(bl) -

pressure response.

Reference equilibration time in the broken loop.

q*(bl) - Secondary-to-primary heat transfer rate in the broken loop at t*oq(bl>*

When ~ 1>is calculated to be equal to the current time after accident initiation, the broken loop is assumed to be equilibrated. The energy rate to the containment from the broken loop between t*cq(bl> and ~(bl> is assumed to remain constant at q*(bl).

Broken Loop Steam Generator - Depressurization Stage During the depressurization stage, the steam generator secondary is brought to the ambient conditions in the containment. The secondary energy which remains after equilibration is:

  • where:

~l) = E.vo.1) - A~(bl)

Edcp(b1> .- Energy which must be transferred from the broken loop steam generator secondary during the depressurization stage.

E.v(bt> - The total energy available in the broken loop steam generator secondary at the reference pressure relative to 212 °F and 14.7 psia.

- Energy transferred from the broken loop steam generator secondary during the extension of the equilibration stage.

  • 206

The energy release rates during this period are those based on the reference pressure (P*) plu~

an additional energy increment due to depressurization of the secondary system as follows:

4Ecli:p(b1> - EIIV(b1> ( 4P )

P*-Plo

- The energy transferred from the steam generator secondary during a time increment.

and 4P - The change in containment pressure during the previous time increment.

The additional mass increment is then calculated by:

The h,, is the latent heat of vaporization at the current containment pressure.

Intact Loop Steam Generators - Equilibration Stage The same procedure is used as for the broken loop. However, metal and core energy are lumped with the steam generator energy for this calculation.

The equations are the same as those for the broken loop except that the subscript "(il)" replaces the subscript "(bl)."

207

Intact LoQp Steam Generators - Depressurization Stage During this period, the steam generator secondary side is brought to the ambient conditions with the containment and reactor coolant is assumed saturated for the containment pressure. The

  • secondary energy which remains after equilibration is:

~i1> = E.vri1> - AE,,q<m where Edcp(i1) - Energy which must be transferred from the intact loop steam generator secondary during the depressurization stage.

- Energy transferred from the intact loop steam generator secondary during the extension of the equilibration stage.

The energy release rates during this period are calculated as:

    • where AEclcp(il) = Eav(d) Ap P* - PLO

+ AEclccay + AERC

- The total energy removed from primary and secondary systems through boiloff during the time increment.

AEc1ocar - The core heat added during the time increment. .

- The energy transferred from the reactor coolant during the time increment. (Note: The reactor coolant is assumed saturated.)

Thus, the mass required to remove the energy (A~i1>) by boiling at total containment pressure is calculated as:

  • 208

where

- Saturated water vapor enthalpy at total containment pressure .

  • hlqj - Injected water enthalpy.

3.6.2.2 Containment Integrity and Operating Limits The mass and energy release data described in Section 3.6.1 is used, with certain modifications, in performing the containment response analysis with the Stone and Webster LOCTIC (3.6.2-1) computer code. In accordance with previous sensitivities for limiting break siz.e and location discussed in Section 3.6.1, these analyses were performed for the pump suction double ended guillotine rupture (PSDER) and hot leg double ended guillotine rupture (HLDER) breaks.

Sensitivity cases were performed to confirm the limiting break and single failure assumptions that are used.

The LOCA analysis consists of a peak pressure analysis, a depressurization analysis and an

  • analysis for the recirculation spray and low head safety injection (LHSI) pumps which confirms that adequate NPSH is available. As discussed in Section 3. 6.1, the limiting break analyzed for peak containment pressure is the HLDER. The depressurization analysis was performed for the limiting break, which is a double ended rupture at the reactor coolant pump suction (PSDER)

. with minimum engineered safety features (ESF). Similarly, the PSDER with minimum engineered safety features (ESF) gives the limiting NPSH for the low head safety injection pumps. For recirculation spray pump NPSH, the HLDER with maximum ESF produces the limiting conditions. The mass and energy data from each of these scenarios was analyzed with the LOCTIC computer code and the results are summariz.ed herein.

The containment analyses employed the same assumptions concerning loss of offsite power and single failure as in the existing analysis. The loss of offsite power is assumed to occur simultaneously with the start of the accident. The single failures analyzed include a diesel generator failure (i.e., minimum ESF) and a containment spray pump failure .

  • 209

3.6.2.2.1 Peak Pressure Analysis A peak pressure analysis was performed to ensure that the peak calculated containment pressure does not exceed the design pressure of 45 psig for operation at the proposed uprated conditions.

The maximum temperature is also compared against the design containment temperature in this analysis. As described in Section 3.6.1, use of the Reference (3.6.2-9) mass and energy release model results in the HLDER break having the peak calculated containment pressure.

For theHLDER break case, the Section 3.6.1-2 values of Westinghouse mass and energy release rates were used directly in LOCTIC with no modification. The results confirmed that the peak pressure occurs during blowdown, and decreases afterwards with no secondary pressure peaks produced.

The summary of key results from the depressurization analysis is presented in Table 3.6.2-2.

As shown on the table, the peak calculated containment pressure from the revised analysis of 44.44 psig is less than the design pressure of 45 psig. This result provides confirmation that adequate analysis margin exists to support operation with the increased core rated power. The containment pressure transients for the hot leg and pump suction DERs analyzed in the peak pressure analysis are presented in Figure 3.6.2-2. Figure 3.6.2-3 provides the containment temperature transients for the same cases.

3. 6.2.2.2 Depressurization Analysis The depressurization analysis is performed to show that the containment can conservatively be returned to subatmospheric conditions within one hour and remain subatmospheric thereafter.

The limiting transient for depressurization is the PSDER and the limiting single failure is the loss of one emergency diesel-generator which results* in the failure of one train of ESF to actuate (i.e., minimum ESF). However, the initial conditions must be specified differently for the depressurization analysis to conservatively determine the peak' subatmospheric pressure. The analysis sensitivity studies have confirmed the conservative containment initial conditions for depressurization analysis; these values were used in the present analysis. The assumptions for key containment parameters and analysis results are provided in Table 3.6.2-3. Only a pump suction DER is considered for the containment depressurization analysis since, as described earlier, this break produces the highest energy flow rates during the post-blowdown period.

210

The chronology for the depressuri7.ation transient (pump suction DER) is presented in Table 3.6.2-4. The containment pressure transient for limiting case is given in Figure 3.6.2-4. This figure illustrates the significant aspects of the pressure response to a LOCA when using the Reference (3.6.2-9) mass and energy data in the LOCTIC code; There are two pressure peaks.

The first peak occurs as a result of the blowdown from the accident. The pressure continues to decrease, in response to the containment and recirculation spray systems and the condensation of steam within the coolant loops which is calculated by the Reference (3.6.2-9) model. The second pressure peak follows *both LHSI .pump recirculation transfer and termination of containment spray flow upon emptying the RWST, after which time the containment pressure increases and approaches atmospheric for the last time.

The depressurization analysis results meet the applicable acceptance criteria, i.e., the containment is depressurized within one hour and is maintained subatmospheric thereafter. The analysis results indicate there is adequate margin to these acceptance limits for operation at the proposed uprated conditions.

3.6.2.3 Safeguards Pumps Net Positive Suction Head Analysis 3.6.2.3.1 Recirculation Spray Pump NPSH Analysis The LOCTIC computer code was used to calculate the net positive suction head available (NPSHA) for the inside and outside recirculation spray pumps. The NPSH analysis is performed

  • to make certain that the NPSHA exceeds that required (NPSHR) for the flow rate assumed throughout the analysis.

The assumptions made for the depressurization analysis maximize the energy release to the containment atmosphere (minimize energy release to the sump) in order to overestimate the containment pressure. The assumptions made for NPSHA analyses of the recirculation spray pumps minimize the energy release to the containment atmosphere and maximize the energy release to the containment floor. Thus, the containment pressure is underestimated and the containment floor water vapor pressure is overestimated. Since containment pressure is a positive term in the NPSHA equation and the floor water vapor pressure is a negative term, a conservative calculation of NPSHA. results.

211

For the revised analysis, these assumptions were implemented by use of the Westinghouse mass and energy data in a LOCTIC analysis which employs the pressure flash modelling described in North Anna UFSAR Table 6.2-47. This modelling essentially assumes that the steam and liquid components of the break effluent are perfectly mixed, and that the liquid component

. becomes saturated at the containment pressure before falling to the containment sump. In this manner, the energy contained in the sump water is maximized, which is conservative for NPSH calculations. The Westinghouse data were used for a sufficient transient duration (1500 seconds) to confirm that the limiting values of recirculation spray pump NPSH have occurred.

Table 3.6.2-5 summarizes the key containment assumptions and results from the recirculation spray pump NPSH analysis. As shown on the table, the NPSHA for both the IRS and ORS pumps meets the minimum requirements. The available NPSH transients for the ORS and IRS pumps are provided in Figures 3.6.2-5 and 3.6.2-6, respectively.

3.6.2.3.2 Low Head' Safety Injection Pump NPSH Analysis An analysis of the NPSHA for the low head safety injection pumps has been performed to ensure that the pumps can deliver up to 4030 gpm following (LHSI) the worst case LOCA. The injection mode and the recirculation mode have been evaluated. previously and it was found that

. the recirculation mode is limiting. The calculation of NPSHA in the recirculation mode considers the static head and suction line pressure. drop, the vapor pressure of the liquid in the sump and the containment pressure. This calculation ensures that the NPSHA meets the pump*

  • requirements.

The calculation of NPSHA is as follows:

NPSHA - h..,.. - ~ + b.i - hi-where h..,.. =

  • Containment pressure, ft.

~ = Vapor pressure of the fluid in the sump, ft.

h.tai = Static head of the fluid in the sump, ft.

  • h1""" = Suction line losses, ft.

212

Various sensitivity studies have been performed with the mass and energy data for uprate9 operation to establish the limiting break location, single failure, plant conditions and assumptions concerning safeguards equipment capability. These sensitivities show that the PSDER with

  • minimum ESF is the worst case. Maximizing the sump water temperature minimizes the NPSH
  • available. This is done by minimizing containment heat removed and maximizing the sump and RWST water temperatures.

The LHSI pump NPSH analysis also employed the Westinghouse mass and energy data in a LOCTIC analysis which assumes the pressure flash modelling. The PSDER with minimum safeguards is the limiting case for LHSi: NPSH. In the revised analysis, the interface with the mass and energy data is somewhat different since Westinghouse data is being used versus LOCTIC data as in the existing analysis. This change is briefly described here.

The Westinghouse Reference (3.6.2-9) model data is used for the blowdown, reflood and a portion of the post-reflood phases of the transient analysis. This interval extends from the time of the break to the at which the intact loop steam generators are in equilibrium with containment.

The Westinghouse data includes certain interface information at time of steam generator equilibrium, which is used in LOCTIC to calculate energy removal in the depressurization phase

  • of the transient. This calculation is essentially the same as that described in North Anna UFSAR Section 6.2.1.1.1.2, in which LOCTIC removes sufficient energy from the RCS and steam generators to maintain equilibrium with conditions in containment. This allows use of the improved Westinghouse modelling of blowdown and reflood energy releases, while incorporating the effects of containment conditions upon the releases in the longer-term depressurization phase of the transient.

To obtain acceptable analysis margin for containment depressurization and available NPSH for the LHSI pumps, it was necessary to reduce the RWST setpoint for LHSI recirculation mode transfer {RMT). The setpoints for both manual and automatic recirculation transfer were reduced approximately 5 % span from their existing values.

The net effect of these changes upon RWST analysis inputs was a slight benefit in total available RWST volume assumed at the completion of the automatic recirculation transfer. Figure 3.6.2-1 illustrates the key RWST setpoints and available volumes assumed in the revised analysis. Table 3.6.2-5 summarizes the results from the LHSI pump NPSH analysis. As indicated on the table, 213

the NPSHA for the LHSI pump meets the minimum requirements. The available NPSH transient for the LHSI pump is provided on Figure 3.6.2-7.

The RMT setpoint and associated Technical Specifications changes are summarized in Sections 5.1 and 5.2. The related changes in plant procedures and instrumentation will be implemented via the normal design change process prior to uprated operation.

References (3.6.2-1) "LOCTIC-A Computer Code to Determine the Pressure and Temperature of Dry Containments to a Loss of Coolant Accident," SWND-1, Stone and Webster Engineering Corp, September, 1971, Letter of December 6, 1971, from W. J. L.

Kennedy, Chief Nuclear Engineer, Stone and Webster Engineering Corp., to P.

A. Morris, Director, Division of Reactor Licensing, AEC.

(3.6.2-2) Aerojet Nuclear Company, CONTEMPT-LT - A Computer Program for Predicting Containment Pressure,-Temperature Response to a Loss-of-Coolant-Accident. ANCR-1219, June 1975.

(3.6.2-3) USAEC, Division of Reactor Licensing 1972. Safety Evaluation Report for Virginia Electric Power Company, Surry Power Station Units 1 and 2. Docket 50-280 and 50-281.

  • (3.6.2-4)

(3.6.2-5)

USAEC, Division of Reactor Licensing 1972.

Maine Yankee Atomic Power Station. Docket 50-309.

USAEC, Division of Reactor Licensing 1970.

Safety Evaluation Report for Safety Evaluation Report for Virginia Electric and Power Company, North Anna Power Station Units. I and 2.

  • Docket 50-338 and 50-339.

(3.6.2-6) USAEC, Directorate of Licensing 1974. Safety Evaluation Report for the Duquesne Light Company, Toledo Edison Company, Pennsylvania Power Company, Beaver Valley Power Station Unit 1. Docket 50-334.

(3.6.2-7) USNRC, Office of Nuclear Reactor Regulation. Safety Evaluation Report related to the operation of Millstone Nuclear Power Station, Unit No. 3, Northeast Nuclear Energy Company, Docket No. 50-423.

(3.6.2-8) USAEC, Directorate of Licensing 1974. Safety Evaluation Report Supplement No. 2 for the Cleveland Electric illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo Edison Company, Beaver Valley Power Station Unit 2. Docket 50-412 .

  • (3.6.2-9) WCAP-10325, "Westinghouse LOCA Mass and Energy Release Model for Containment Design-March 1979 Version," May, 1983.

214

Table 3.6.2-1 Pump Suction Double Ended Rupture, Minimum SI - Single Train Mass and Energy Releases for LOCTIC Analysis BREAK PATH NO. 1 FLOW BREAK PATH NO. 2 FLOW TIME THOUSAND THOUSAND SEC LBM/SEC BTU/SEC LBM/SEC BTU/SEC o.oo 147896.10 79856.50 147896.10 79856.50 0.10 39713.70 21300. 90 . 20013.90 10695.10 0.20 40312.10 21750.90 21992.30 11761. 40 0.30 41091.30 22345.10 22177.50 11872 .so 0.40 43235.10 23725. 80 21754.20 11657.40 a.so 42777.90 23717.30 20912.80 11214.70 0.70 43345.90 24525.40 19422.30 10423.30 0.90 42424.90 24424.40 . 18385 .60 9870.80 1.40 38056.70 22838.30 17473.50 9386.20 1.80 33705.40 21055.60 17304.2 9292.40 2.40 26785.90 17813.00 16742.50 8987.60 2.60 21303.80 14380.70 16467.90 8840.00 3.00 17618.60 12156.60 15460.30 8300.80 3.30 15477.50 10767.80 14884.20 7995.60 3.80 13034.00 9172.20 14076.20 7569.70 4.20 11877.50 8411.20 13467.50 7248.80 4.80 10713.70 7607.70 12595.70 6787.60 5.20 10217.60 7223.40 12189.30 6573.40 5.40 10041.70 7067.40 13041.90 7036.30 5.80 10344.80 7260.50 12667.00 6837.80 6.20 8566.10 6775. 30 12168.10 6572. 70 6.40 8125.90 6532.90 11983.20 6475.50 7.00 8228.00 6346.30 11699.50 6330.20 7.80 9032.30 6399.10 11074.90 5987.30 8.40 9249.00 6269.10 10654.60 5757.00 10.40 7141. 60 5139.70 9480.60 5118. 60 12.40 5602.30 4340.40 8211.30 4432.40 14.20 4506.80 3646.10 6858.10 3617.90 14.60 4250.80 3456.50 7104.60 3605.70 14.80 4150.70 3381.00 6061.40 3012.10 15.00 4064.50 3321.30 7478.60 3609.20 15.20 3949.00 3249.60 11434.80 5552.20 15.40 3777. 80 3156.40 9671.00 4723.90 15.60 3670.30 3140.00 6185.50 3022.50 15.80 3700.70 3213.60 4396.00 2099.20 16.00 3566.80 3172. 90 10523.20 4773.40 16.20 3319.70 3090.50 8769.60 4098.70 16.40 3201.00 3102.80 5375.80 2537.00 16.60 3156.10 3148.10 4068.80 1882.50 16.80 2970.90 3095.40 5133.00 2188.20 17.00 2601.60 2894.50 7761.40 3272. 00 17.20 2297.20 2719. 20 5732.70 2430.40 17.40 2093.70 2553.60 4375.30 1860.70 17.80 1779.90 2198.10 3063.70 1277. 90 18.00 1614.50 1999.30 3169.20 1229.80 18.40 1291.00 1605.90 4746.60 1711. 70 19.40 716. 40 897.80 3091.40 1031.90 20.60 378.40 476.20 1248.10 366.20 21.20 261.10 329.00 o.oo 0.00 22.60 o.oo o.oo o.oo 0.00 215

Table 3.6.2-1 (continued)

Pump Suction Double Ended Rupture, Nini.mwi SI - Single Train Maas and Energy Releases for LOCTIC Analysis BREAK PATH NO. 1 FLOW BREAK PATH NO. 2 FLOW TIME THOUSAND THOUSAND SEC LBM/SEC BTU/SEC LBM/SEC BTU/SEC 22.60 0.00 o.oo o.oo o.oo 23.50 0.00 o.oo o.oo o.oo 23.60 44.40 52.30 o.oo o.oo 23.70 25.20 29.60 0.00 0.00 24.10 47.40 55.80 0.00 0.00 24.80 70.80 83.40 o.oo o.oo 25.70 96.50 113.70 o.oo o.oo 26.70 119.20 140.50 o.oo o.oo 27.70 140.00 165.00 182.30 2.80 28.70 317.20 374.90 3093.80 309.80 29.00 424.40 502.60 4286.40 449.30 29.70 460.40 545.70 4606.60 503.30 30.70 454.0Q._ 538.10 4544.30 499.90 32.70 435.30" 515.80 4366.70 483.20 33.00 432.60 512.50 4340.40 480.70 33.70 426.30 sos.co 4279.80 474.90 34.70 417.70 494.70 4195.50 466.90 35.70 409.50 484.90 4114.10 459.10 36.70 401.60 475.50 4035.60 451. 60 37.70 394.10 466.60 3960.00 444.30 38.70 386.90 458.00 3887.00 437.40 39.70 380.10 449.80 3816.70 430.60 41.70 367.20 434.40 3683.30 417.90 43.70 355.30 420.30 3558.70 406.00 45.70 344.30 407.20 3441.90 394.80 47.70 334.10 395.10 3332.00 384.30 48.80 199.70 235.50 252.70 87.20 so.so 196.30 231.50 251.50 85.80 58.80 184.60 217.70 247.60 80.90 60.80 182.50 215.20 249.20 so.so 68.80 174.70 206.00 258.80 79.90 70.80 172.80 203.70 261.40 79.80 78.80 164.60 194.00 272.50 79.70 82.80 160.30 188.90 278.90 79.90 83.80 -159.10 187.60 280.50 79.90 91.40 1so.10* 176.90 294.50 80.70 91.80 149~60 176.30 295.30 80.80 95.80 144.20 170.00 303.60 81.40 99.80 138.40 163.10 312.60 82.20 101.80 136.50 160.90 315.90 82.30 109.80 134.10 158.00 322.00 81.30 115. 80 132.20 155.80 326.30 80.40 123.80 129.60 152.80 331. 70 79.10 139.80 124.40 146.50 341.90 76.30 145.80 122.40 144.20 345.60 75.20 153.80 119.70 141.00 350.50 73.80 155.80 119.00 140.20 351. 70 73.40 163.80 116. 30 137.00 356.50 71.90 195.80 105.30 124.00 375.60 66.20 198.50 104.30 122.90 377.20 65.70 198.60 118.60 148.00 413.80 71.50 203.60 119.00 148.50 413.40 71.20 213.60 118. 30 147.70 414.10 71.00 218.60 118.80 148.20 413.70 70.70 216

Table 3.6.2-1 (continued)

Pump Suction Double Ended Rupture,~llinimua SI - Single Train Ma** and Energy Release* for LOCTIC Analyai*

BREAK PATH NO. 1 FLOW BREAK PATH NO. 2 FLOW TIME THOUSAND THOUSAND SEC LBM/SEC BTU/SEC LBM/SEC BTU/SEC 228.60 118.10 147.30 414.40 70.60 233.60 118.50 147.90 413.90 70.30 243.60 117.80 147.00 414.70 70.10 248.60 118.20 147.50 414.20 69.80 258.60 117.50 146.60 415.00 69.70 263.60 117.90 147.10 414.60 69.40 268.60 117.50 146.70 414.90 69.30 273.60 118.00 147.20 414.50 69.00 283.60 117.20 .. 146.20. * ... ___ 415.30. . 68. 90 288.60 117.60 146.70 414.90 68.60 298.60 116.80 145.80 415.70 68.40 313.60 117.20 146.20 *....A15.30 67.80 323.60 116.40 145.20 . .-~6.10 67.60 328.60 116.70 145.70 -* 415. 70 67.30 343.60 116.20 145.10 416.20 66.90 358.60 116.50 145.30 416.00 66.30 368.60 115.60 144.30 416.90 66.10 383.60 115.80 144.50 416.70 65.50 398.60 115.10 143.70 417.30 65.10 413.60 *115. 50 144.10 417.00 64.50 418.60 115.10 143.60 417.40 64.40 433.60 115.30 143.90 417.10 66.10 448.60 114.90 143.30 417.60 65.60 463.60 115.00 143.50 417.50 65.00 478.60 114.40 142.70 418.10 64.60 488.60 114.80 143.20 417.70 64.00 503.60 114.10 142.30 418.40 63.60 518.60 114.50 142.90 418.00 62.90 523.60 114.00 142.20 418.50 62.80 538.60 114.30 142.60 418.20 64.30 543.60 113.70 141.90 418.70 64.20 563.60 113.80 142.00 418.70 63.30 598.60 113.10 141.20 419.30 61.90 618.60 113.40 141.40 63.00

    • ~OCO

.. * ~ : ; ~ ~ 61.20

  • - 658. 60 112.60 140.50 668.60 112.90 140.80 ' 419.60 60.60 693.60 112.30 140.20 420.10 61.50 1097.20 . '112.40 140.20 420.10 60.90 1100.00 112.40 140.20 392.11 60.90 1110.00 58.90 73.10 445.61 70.10 1140.00 58.90 73.10 445.62 70.10 1150.00 61.24 75.83 443.28 70.10 1160.00 71.17 87.38 433.35 70.10 1170.00 69.48 85.41 435.04 70.10 1200.00 69.22 85.10 435.31 70.10 1250.00 68.51 84.28 436.02 70.10 1300.00 67.85 83.50 436.70 70.10 1350.00 67.26 82.80 437.30 70.10 1400.00 69.67 80.86 434.89 6.21 1450.00 67.63 78.45 436.94 6.24 1500.00 66.13 76.67 438.44 6.26 1600.00 61.63 71.39 442.95 6.33 1700.00 60.59 70.13 444.00 6.34 I

~:~.

217

Table 3.6.2-1 (continued)

Pump Suction Double Ended Rupture, Ninimua SI - Single Train Maaa and Energy Release* for LOCTIC Analyai*

BREAK PATH NO. 1 FLOW BREAK PATH NO. 2 FLOW TIME THOUSAND THOUSAND SEC LBM/SEC BTU/SEC LBM/SEC BTU/SEC 1800.00 58.04 67.11 446.56 6.38 1900.00 55.55 64.18 449.05 6.41 2000.00 53.14 61.35 451.47 6.45 2200.00 49.12 56.64 455.49 6.51 2400.00 45.72 52.66 458.89 6.55 2500.00 44.24 50.93 460.37 6.58 2750.00 40.95 47.11 463.65 6.62 3000.00 38.32 44.05 466.28 6.66 3250.00 36.23. - 41.63 .468.35. 6.69 3500.00 36.47 41.90 478.38 34.64 3750.00 35.79 41.11 414.04 45.78 4000.00 34.76 39.92 415.23 45.40 4500.00 32.32 37.17 417.83 45.17 5000.00 31. 79 36.57 418.36 45.21 6000.00 29.92 34.41 420.23 45.44 7000.00 28.67 32.97 421.51 45.48 9000.00 26.55 30.52 423.77 45.25 11100.00 25.25 29.02 425.28 44. 72 15000.00 23.85 27.40 427.03 43.72 18000.00 22.74 26.12 428.36 44.2 22500.00 21.50 24.70 429.87 42.27 30000.00 20.06 23.04 431. 62 41.32 45000.00 17.70 20.32 434.42 40.01 60000.00 16.25 18.66 436.10 39.25 75000.00 15.29 17.55 437.22 38.72 85500.00 14. 71 16.88 437.90 38.43 100500.00 13.99 16.06 438.72 38.07 111000.00 13.65 15.66 439.13 37.85 120000.00 13.35 15.32 439.47 37.70

. 150000.00 12.36 14.19 440.60 37.19 165000.00 12.03 13.80 441.01 36.97 173700.00 11.83 13.57 441.23 36.86 218

~able 3.6.2-2 Containment Peak Pressure - Losa of Coolant Accident Key Containment Assumptions and Results Break Location/Type Hot Leg DER Pump Suction DER Key Containment Assumptions Initial Air Partial Pressure (psig) 10.30 10.30 Initial Bulk Average Temperature (°F) 125 125 Initial Dewpoint Temperature (°F) 125 125 Service Water Temperature (°F) 95 95 Refueling Water Storage Tank Temperature (°F) 45 45 Key Analysis Results Peak Containment Pressure (psig) 44.44 43.70 Time of Peak Pressure (sec) 17.9 19.4 Peak Containment Temperature (OF) 275.6 274.6 Energy Released to Containment 6up to 255.2 257.4 Time of Peak Pressure (10 Btu)

Energy Absorbed by Passive Heat 6 Sinks up to 13.28 14.0 Time of Peak Pressure ( 10 Btu) 219

Table l.6.2-3 Containment Depressurization - Pump Suction DER, Minimum SI-Single Train Key Containment Assumptions and Results Depressurization Subatmospheric Analysis Case Time Peak Pressure Key Containment Assumptions Initial Air Partial Pressure (psig) 9.10 9.10 Initial Bulk Average Temperature (°F) 125 75 Initial Dewpoint Temperature (°F) 125 75 Service Water-Temperature (°F) 95 95 Refueling Water Storage Tank Temperature (°F) 45 45 1 1 Containment Spray Thermal Efficiency (I) 98-94 98-94 Recirculation Spray Thermal Efficiency (I) 95 95 Key Analysis Results Depressurization Time (sec) 2820 2710 Subatmospheric Peak Pressure (psig) -0.47 -0.16 Subatmospheric Peak Pressure Time (sec) 5520 5030 1

Values used vary over this range during the course of the transient analysis

  • 220

Table 3.6.2-4 Pump Suction Double Ended Rupture, Minimum SI-Single Train

  • Accident Chronology Analysis Case Subatmospheric Depressurization Peak Time (sec) Event o.o o.o Accident occurs 2.4 2.3 CDA safety analysis limit reached (12.3 psig) 19.0 19.4 First containment pressure peak occurs 22.6 22.6 End of blowdown; emergency core cooling system becomes effective 198.5 200.3 Core reflooding ends 216.0 216.0 Inside Recirculation spray becomes effective 415.0 415.0 Outside Recirculation spray becomes effective 2700.0 2820.0 Containment pressure becomes subatmospheric 3500.0 3750.0 Switchover to recirculation mode of safety injection 5030.0 5510.0 Subatmospheric peak pressure occurs 221

Table 3.6.2-5 Safeguards Pump HPSB Analyai* - Losa of Coolant Accident Key Containment Assumption* and Results Analysis Case IRS Pump ORS Pump LHSI Pump Key Containment Assum:Qtions Initial Air Partial Pressure (psig) 9.00 9.00 9.00 Initial Bulk Average Temperature ( OF) 125 125 125 Initial Dewpoint Temperature (OF) 125 125 125 service Water Temperature (OF) 95. 25 95 Refueling Water Storage Tank Temperature (OF) 45 45 45 Containment Spray Thermal Efficiency(%) 100 100 100 Recirculation Spray Thermal Efficiency (%) 100 100 100 Key Analysis Results Minimum NPSH Available (ft) 13.0 10.0 17.0 NPSH Required (ft) 10.2 9.1 15.8 222

Figure 3.6.2-1 RWST Level and Alara Setpoint* for Surry unit 1 and 2 2546 MWt Core Rated Power Gallons 399,400 100% F.ull On Meter 387,100 TS Min (95.86%)

384,340 TS Min -.75%

373,000 Bendline Cl) u...

ni if C!)

ni a, 0

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s

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er, 66,630 Nominal (13.5%) ~ 514.0" m

63,240 Auto SO (15.75% + 2 Min) ~

39,630 Auto SO (11.25% + 3 Min) 21.840 -* Empty Alarm (2.0%)

21,200 ...L CS Tap CS Tap

  • 29'6"t 30"
14. 100 0% On Meter 0% On Meter 287" 6,400 CS Suction Bell CS Suction Bell 27'9" I 19.9" 27' _i_ _t_

1-- 19'

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  • 223

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3.6.3 High Energy Line Break Analyses for Equipment Qualification and Structural Analyses

  • 3.6.3.1 Equipment Qualification Inside and Outside Containment The Environmental Zone Description (EZD) documents the specification of parameters for all plant areas including environmentally harsh areas of the Surry Power Station Units 1 and 2 which contain safety-related equipment (IE Bulletin 79-0lB). These areas have been ascribed environmental zones which possess more or less uniform environments relating to temperature, pressure, relative humidity, chemical spray, radiation and submergence. The existing dose calculation in the EZD -used a reactor-*power value-of 2546 -MWt and therefore the present electrical equipment qualification is analyzed for the proposed increase.

As described in Section 3.4.1.2, the Surry Unit 1 and 2 licensing basis uses the LOCA temperature and pressure transient results for post-accident electrical equipment qualification inside* containment.. The containment response analysis, which was revised for Surry uprated operation, is described in Section 3.6.2.2. The analysis results have been compared with the existing time-dependent temperature and pressure limiting envelopes that characterize the containment environmental zones. The existing envelopes for temperature and pressure continue

  • to bound the calculated results from the revised LOCA analysis. There is thus no impact from uprated operation upon equipment qualification inside containment.

_'".fhe proposed increase in the maximum containl_!lent average temperature from 120°F to 125°F was also evaluated for potential impact upon electrical equipment qualification life calculations.

After review of applicable Qualification Documentation Review (QDR) Files it was concluded that either the QDRs used ambient temperatures of at least 125°F in aging calculations or they used sufficient margin in the present qualification life calculations to accommodate the proposed mcrease.

The existing high energy line break analyses supporting equipment environmental qualification outside containment are documented in the Surry UFSAR Appendix 14B. The existing calculations remain bounding for operation at the proposed uprated conditions. The uprating thus poses no impact upon equipment qualification design basis .

  • 230

3.6.3.2 Subcompartments Inside Containment

  • The existing containment integrity analyses includes structural analyses of these subcompartments inside containment: pressurizer cubicle, steam generator cubicle and reactor vessel cavity. The impact of uprating containment subcompartment pressurization was evaluated. Table 2.1-1 parameters were used. The evaluation concluded that the proposed conditions will cause a negligible increase in cubicle pressurization.

3.6.3.3 Subcompartments* Outside Containment The existing analyses of high energy line breaks for design of structural subcompartments outside containment have been evaluated for potential impact from the proposed uprating. Such analyses are performed for the Main Steam Valve House (MSVH), Auxiliary Building and the Turbine Building. It has been concluded that the existing accident analysis results (mass and energy releases) used in structural analyses remain bounding for operation at the proposed conditions .

  • 231
3. 7 NSSS Accident Radiological Consequences Analyses 3.7.1 General Discussion & Analysis Approach All five accidents that could potentially produce significant doses to control room operators at the Exclusion Area Boundary (BAB) or at the Low Population Zone (LPZ) boundary are analyzed in this section. To ensure that a complete and consistent set of Surry dose analyses is available both to *update the Surry UFSAR and to evaluate the impact of future plant changes, equipment problems or other issues on control room and offsite doses, all five accidents that

.. *could* potentially-produce*-significant doses-to-conttotroom -operators~* -at *the, Exclusion *Area Boundary (EAB) or at the Low Population Zone (LPZ) boundary were analyzed. In addition, an analysis of the potential EAB dose from a Waste Gas Decay Tank -(WGDT) Rupture was performed to show that the failure of a WGDT would not challenge the 10 CFR 100 dose limits.

Section 3.7.2 below provides a dose analysis for the following postulated events:

l)* Loss of Coolant Accident (LOCA)

2) Main Steam Line Break (MSLB)
3) Steam Generator Tube Rupture (SGTR)

-4) Locked Rotor Accident (LRA)

5) Fuel Handling Accident (FHA)
6) Waste Gas Decay Tank (WGDT) Rupture These analyses demonstrate compliance with:
  • the regulatory criteria in NRC Standard Review Plan (SRP) NUREG-0800 Section 6.4.

GDC 19 specifies that doses to control room personnel should be limited to a maximum of 5 Rem to the whole body or its equivalent to any part of the body. SRP 6.4 specifies that control room personnel doses should be limited to ~ maximum *of 30 Rem to the thyroid and 30 Rem to the skin. Offsite doses are limited to 25 Rem to thewhole body and 300 Rem to the thyroid by IO CFR Part 100.

These analyses are based on revised values of x/Q calculated from 1974-1987 meteorological data. Core radionuclide inventory was determined based on the proposed uprated core power 232

level of 2546 MWt plus 2 % instrument uncertainty which gives a total of 2597 MWt. (Note that the FHA and LOCA analyses are based on a core radionuclide inventory determined from a

  • slightly more conservative power level of 2605 MWt with instrument uncertainty). The LOCADOSE computer code was used along with methodologies as recommended by the NRC Standard Review Plan (SRP), NUREG-0800. The dose conversion factors used in these analyses are consistent with those provided in Regulatory Guide 1.109 (3. 7-13).

The modeling, assumptions, input data and results of a dose analysis for each postulated accident are provided below; -All dose calculations were performed-with the LOCADOSE computer code (3.7-3)(3.7-4)(3.7-5). Changes in assumptions (relative to previous Surry dose calculations) were also incorporated to improve consistency with the NRC Standard Review Plan (NUREG-0800) (3.7-6) guidance as discussed in Section 3.7.2 of this report.

3. 7 .2. Evaluation of Reanalyzed Events 3.7.2.1 Large Break Loss of Coolant Accident (WCA)

The methodology used to evaluate the control room and offsite* doses resulting from a LOCA

The methodology used to determine control room atmospheric dispersion factors (x/Q values) was as specified by Murphy and Campe (3.7-8). Atmospheric dispersion factors (x/Q values) for the EAB and LPZ were calculated based on 1974 to 1987 Surry meteorological data using Regulatory Guide 1.145 methodology. Core radionuclide inventory was based on a power level of 2605 MWt which is slightly conservative compared to the uprated power level for Surry of 2546 MWt plus 2 % for instrument uncertainty.

3.7.2.1.1 LOCA Analysis Approach NUREG-0800, Section 15.6.5, Appendices A and B, Revision 1, provides detailed guidelines for calculating doses from a LOCA in a PWR. Doses from all postulated release paths to the environment are calculated as required by NUREG-0800, and compared with 10 CFR 100 and GDC 19 exposure criteria. Radiological consequences of both containment leakage and

. post-LOCA leakage from Engineered Safety Feature (ESF) system components outside containment were considered.

233

To account for manual realignment of the safeguards area ventilation system to filtered exhaust, a 30 minute delay in filtration is included in the analysis of doses resulting from a LOCA. Surry Units 1 and 2 share a single fuel building. When spent fuel is being handled (except when sufficient decay has occurred after reactor shutdown for refueling such that air :filtration is no longer required to mitigate a FHA), automatic switch over from* fuel building air filtration to safeguards area filtration may be blocked. With this alignment, the exhaust from the safeguards area must be manually switched to filtered exhaust after a Safety Injection (SI) signal.

The review procedures of SRP -Section -15~6.5, Appendix -A that-are-applicable to Surry require the following 1:

Al. The design (stretch) power level of the core should be used for the analysis. The core is assumed to have operated at this power level for a sufficiently extended period (typically about 3 years) such that the maximum equilibrium fission product inventory is present. At the time of the accident, 25 % of all equilibrium iodine fission products and 100 % of the noble gas fission products are assumed available for release from the containment within a very short time (effectively instantaneously) after the accident. The iodine is assumed to be composed of 91 % elemental iodine, 4% organic iodides and 5% particulate iodine.

  • A2. The primary containment leakage rate for the LOCA dose analysis is obtained from SAR Section 6.2.6 (Section 5.3.2 for Surry 1 ). A check is made ofLOCA assumptions to verify that the primary containment leakage rate has been assumed to remain constant over the course of the accident for a BWR and to remain constant at one half of the initial leak rate after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for a PWR. Leak rates of less than 0.1 % per day have not been accepted by the staff because of integrated containment leakage test sensitivity limitations. The leakage rate used should correspond to that given in the technical specifications.

A3. (Deals with dual containments and is not applicable to Surry)

A4. The operation of the normal containment vent/purge system is reviewed. If the proposed system operation does not meet the regulatory positions, an analysis of the radiological consequences using this release path as an additional contributor to the total LOCA doses will be performed.

1

'Ihe SUrry UFSAR S'=Ction numbers correspoming to the stamard SAR format section numbers referenced by the SRP are indicated in parentheses().

234

A5. Credit for any engineered safety features such as atmosphere filtration systems, spray systems or ice condenser is determined in the review of Section 6.5 (Section 6.3 for Surry) of the SAR. These features* operate during the LOCA to mitigate the consequences by reducing the amount of iodine fission products released to the environment. Noble gas releases to the environment are unaffected by the presence of filters or sprays. Typically, single containments employ spray systems with a chemical additive (e.g., sodium hydroxide, sodium tetraborate) to scavenge iodine from the containment atmosphere. The iodine removal rates of an ice condenser or a chemical additive spray system are determined.

A6. The distances to the exclusion area boundary.and to the LPZ outer boundary are determined from Sections 2.1.2 and 2.1.3 of the applicant's SAR (Section 2.1.3.2 and 2.3.3 for Surry1).

A7. The appropriate x/Q values to be used in calculating the consequences of the accident are

  • , determined .in, accordance with SRP Section 2.3.4.

AS. The dose computation model appropriate for the containment system and ESF systems is*

selected which conservatively represents the transfer of radioactivity from the containment to the environment. The leak rates, spray removal rates, atmosphere filtration system

  • efficiencies and flow rates are used to indicate the rates at which the activity moves from one compartment to another.

A9. The containment leakage doses are combined with the calculated dose contributions from all other appropriate post-LOCA transport paths and the total thyroid and whole body LOCA doses are compared with the exposure guideline values of 10 CFR 100. If the calculated total doses exceed these guidelines, alternatives which wouid reduce the doses to an acceptable level are explored. Such alternatives may include increased distance and more efficient atmosphere filtration or spray systems.

As required by item Al above, a core power level of 2605 MWt was assumed for Surry LOCA dose analyses. This is slightly conservative compared with a Surry uprated power level of 2546 .

MWt plus 2 % for instrument uncertainty. The Surry core radionuclide inventory is determined from the Ci/MWt values in the LOCADOSE computer code.

  • 235

The assumptions in item Al above for fission product release fractions and the split of iodines between elemental, organic and particulate were used. As specified by SRP 6.2.6 (3.7-6) and

  • item A2 above, a 0.1 volume percent per day containment leak rate was used for the first hour when the containment pressure is above atmospheric. Surry has a sub-atmospheric containment system that is shown by analysis to return to sub-atmospheric pressure within one hour of the start of a LOCA. When the containment pressure is sub-atmospheric, any leakage would be into the containment. Therefore, no containment leakage is assumed after the first hour. Surry does not have a vent purge system that has to be considered as a LOCA release pathway (see item A4 above).

Relative to item A5 above, the following containment spray factors were used:

Elemental Iodine l - 10 per hour Organic Iodine l - 0 per hour Particulate Iodinel - 0.45 per hour Sprayed Volume - 73 %

Mixing Rate - 2 unsprayed volumes / hour Spray start time - 0.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> Also relative to item A5 above, a90% filter efficiency was used for leakage of airborne iodine from the safeguards area. All airborne iodine in the safeguards area is assumed to be elemental, so the 99 % filter efficiency ~~plies to all iodin~ releases from the ECCS system.

Based on a review of the Basis for Surry Technical Specification 4.1.2 and Regulatory Guide 1.52, the following control room ventilation system filter efficiencies were used for Surry:

Iodine Type Filter Efficiency

  • Elemental 90 %

Methyl 30%

Particulate 99 %

The 90 % elemental and 30 % methyl iodine removal efficiencies are indicated in Regulatory Guide 1.52 (3.7-9) as being appropriate for 2" charcoal filters without humidity control. The 99 % efficiency for particulate iodine is based on the use of HEPA filters..

236

NUREG-0800, Section 15.6.5, Appendix B discusses the requirements for evaluating the radiological consequences of leakage from engineered safety feature (ESP) components outside containment. The review procedures of Appendix B require consideration of the following:

Bl. The types of postulated leakage from ESF components, including specifically, the leakage from valve stems and pump seals that can be expected during the operation of the ESF recirculation systems and the leakage from a postulated gross failure of an ESF passive component such as the failure of a pump seal.

B2. The design and operational features that are provided to mitigate the potential for

  • radiological* consequences**from this*transport path*-such*as a leakage collection system, atmosphere filtration system, and technical specifications for ESF component leakage.

B3. The assumptions, model, and results of the dose calculations performed by the applicant for this fission product transport path be reviewed by NRC staff.

B4. An evaluation of the contribution of the radiological consequences of this transport path to the total radiological consequences from the hypothetical LOCA be performed in conjunction with the evaluation under SRP Section 15.6.5, Appendix A.

Specific criteria of SRP 15.6.5, Appendix B for Engineered Safety Feature System evaluations

  • are:

B5. ESF systems that circulate water outside the containment are assumed to leak during their intended operation (e.g., valve stem leakage) and as a result of a failure of a passive component.

B6. The radiological consequences from the postulated leakage should be calculated using conservative assumptions. 50 % of the core iodine inventory, based upon the maximum reactor power level, should be assumed to be mixed in the sump water being circulated through the containment external piping systems.

B7. The radiological consequences from ESF component leakage should be combined with the consequences from other fission product release paths to determine the total calculated radiological consequences from the hypothetical LOCA.

Other provisions of SRP 15.6.5, Appendix B include the following:

237

BS. The leakage for calculating the radiological consequences should be the maximum operational leakage and should be taken as two times the sum of the simultaneous leakage from all components in the recirculation systems above which the Technical Specifications would require declaring such systems to be out of service.

B9. For a plant that provides an ESF atmosphere filtration system in the areas of potential leakage from a gross failure of passive components, the dose assessment of failure of a passive component is not required.

BIO. The time-dependent temperature of the sump water circulating outside containment after the -LOCA *is- evaluated- to determine- -the-- fraction -of the-- leakage- that -flashes to steam assuming a constant enthalpy process. If the calculated flash fraction is less than 10% or if the water is "less than 212°F, then 10% of the iodine in the leakage is assumed to become airborne.

Bll. The airborne iodine is assumed to be released immediately to the environment. The

. atmospheric dispersion is based upon the ground level x/Q values. Atmosphere filtration system filters are evaluated with respect to the guidelines of Regulatory Guide 1.52. The doses at the nearest exclusion area boundary* and LPZ outer boundary are calculated using appropriate assumptions and methods and combined with the doses determined under SRP Section 15.6.5, Appendix A.

Surry has an ESP filtration syste~_ in the areas where a 1~ from failure of a passive ESF component could occur. Therefore, based on item B9 above, this LOCA analysis for Surry does not consider radiological consequences from the failure of a passive ESF component.

As required by item B6 above, 50% of the core iodine inventory is assumed to be released to the sump. Except for a short period (10 minutes) at the beginning of the accident, the water in the ESF system at Surry is taken from the containment sump at temperatures less than 212°F.

When the water temperature in the sump exceeds 212°F, the flashing fraction is less than 10%.

Therefore, Surry meets the requirements of item BlO above for assuming 10% of the iodine in the ESF system leakage becoming airborne. As required by item BS above, ESF leakage was assumed at 2 times the maximum leakage rate allowed by Technical Specifications.

238

As required by SRP 15.6.5, Appendix A (items AS and A9 above), the release of radionuclides to the environment was determined both for containment leakage and Engineered Safety

  • Components leakage.

239

3.7.2.1.2 Determination of x/Q Values The parameter x/Q defines the ratio of radionuclide concentration (x in curies/m3) to release rate (Qin curies/second). x/Q depends on the site meteorology (average wind speed and atmospheric stability) and distance between source and receptor. The equation shown below is given in Reference (3. 7-8) for a diffuse source to a point receptor (or. a point source with an elevation difference of more than 30% of the building height):

1. 1 Q

where: u = 5th percentile lowest wind speed a..,, az = atmospheric dispersion factors (Pasquill F)

K = 3/ (s/d) 14 s = distance between containment surface and receptor location d = diameter of the source building a * = projected area of the source building

  • The difference in elevation between the control room inlet and ventilation system exhaust at Surry is over 30 % of the source building height. Therefore, the above equation is applicable for determining x/Q for releases from both the containment and the ECCS vent. The control room x/Q values in Reference (3.7-10) were determined with the above equation, and these
  • values are used in this analysis. (Note that control room occupancy factors were not included in the x!Q values shown below because these occupancy factors were explicitly input to the.

LOCADOSE computer code.)

The EAB x/Q value shown in Reference (3.7-11) is no longer applicable. BAB and LPZ x/Q values given in Table 3. 7. 2.1-1 were determined for Surry based on Regulatory Guide 1.145 methodology using meteorological data for 1974 to 1987.

240

3. 7.2.1.3 WCADOSE Model for Surry WCA Analysis
  • LOCADOSE was used to model the* release of radionuclides for a LOCA at Surry. This computer code system first calculates radionuclide concentrations and releases to the environment. These radionuclide releases and concentrations are then used along with breathing rates and occupancy factors to calculate the resulting doses. The LOCADOSE computer code system modeled a LOCA at Surry with five volumes: (1) the environment, (2) the containment sump, (3) the portion of the containment covered by the Containment Chemical Spray System, (4) the portion of the-containment not covered-*by-the Chemical-Spray-System-and (5) the control room. The volumes used in the computer model were:

Unsprayed containment volume = 5.03 x lOS ft' Sprayed containment volume = 1.36 x 1()6 ft' Sump volume * = 1.65 x 1()6 liters Control room volume = 2.23 X 1()5 ft' The transfer of radionuclides is modeled by specifying flow rates between the various volumes

  • modeled. The inixing between the sprayed and unsprayed containment volumes was modeled based on 2 unsprayed volumes per hour. The containment leakage was modeled as 0.1 volume percent per day for the first hour. After the first hour, no containment leakage is assumed because the containment pressure returns to sub-atmospheric. The 0.1 volume percent per day was applied equally to the sprayed and unsprayed volumes. Thus, 0.1 volume percent of each of these volumes was modeled as leaking to the environment during the first hour of the LOCA.

ESF leakage is modeled at twice the maximum leakage rate allowed by Surry Technical Specifications:

Twice Tech. Spec.

Maximum Leak *Rate Time Period Qiters/min) 0 min. - 29 min. 3.21 X 102 29 min. - 30 days 1.60 X 101

  • 241

The control room ventilation system was modeled consistent with Reference (3. 7-8) and Surry control room ventilation system design and operation. An unfiltered inleakage of 10 CFM was

  • modeled from time O to 30 days. The control room was assumed to be on bottled air for the first hour of the accident; however, for conservatism the out-leakage for the first hour was modeled as only 10 cfm. After the first hour, a filtered intake of 1000 cfm was modeled.

The x/Q values given in Table 3. 7.2.1-1 were used for the control room. Because the ECCS and containment control room x/Q values are about the same, the slightly higher containment x/Q was also used for *ECCS "-leakage during *the *first hour after a -LOCA when there* are releases from both the containment and ECCS.

The core radionuclide inventory was model~ as initially being distributed as follows:

Containment Unsprayed Volume: 27% of core noble gas isotopes, and 27 % of 25 % of core iodines with a distribution of 91 % Elemental, 5 % Particulate, 4 % Organic Containment Sprayed Volume:  % of core noble gas isotopes, and 73 % of 25 % of core iodines with a distribution of 91 % Elemental, 5% Particulate, 4% Organic

  • Sump Volume: 50% of core inventory of iodines, 10% airborne, with 100% of airborne iodine being elemental

_This modeling_was consistent with the requirements of SRP 16.6.5, Appendices A and B as discussed above and assumes instantaneous release of the radionuclides from the reactor core.

The LOCADOSE code system calculates radionuclide releases to the environment and radionuclide concentrations versus time in each volume that is then used to calculate doses.

Occupancy factors and breathing rates are then used along with the radionuclide concentrations to calculate doses. The occupancy factors (fraction of time an individual occupies the control room) used for the control room are shown in Table 3.7.2.1-2. These occupancy factors are based on the guidance from the Reference (3.7-8) paper. The breathing rate used for the control room dose calculations was 3.47 x 1<>4 m3/sec, which is consistent with the Reference (3. 7-8) paper. The LOCADOSE code system uses dose conversion factors based on Regulatory Guide 1.109 to determine the doses from inhalation and immersion.

242

3.7.2.1.4 Results of Dose Calculations for WCA The models described above were used to analyze doses in the control room and offsite resulting from a LOCA at Surry. The calculated LOCA doses are given in Table 3.7.2.1-3. It should be noted that the control room whole body dose includes the dose due to direct shine from containment. This contribution due to direct shine is consistent with that used in previous control room dose calculations for a LOCA.

The calculated doses are less- than the -10 CFR -100 -limits-for the -BAB and LPZ,- and are less than the GDC-19 and SRP 6.4 criteria for the control room. Thus, Surry meets the regulatory criteria for doses at the uprated power level. The control room thyroid dose is slightly higher than the value previously reported to the NRC (3.7-10). However, the skin and whole body doses in control room have been reduced from the Reference (3. 7-10) values. The thyroid doses calculated for a LOCA at the BAB and LPZ are less than the values previously reported to the NRC in Reference (3. 7-11), but the whole body dose is slightly higher than the value shown in Reference (3. 7-11) .

  • 243

Table 3.7.2.1-1 Surry Containment and ECCS x/Q Time Period Control Room 3

x/Q EAB X'3Q LPZ x/p (hours) Csec /m ) ( sec/m) ( sec/m )

CONTAINMENT 0 - 2 1.16 X 10"3 3

0 - 8 4. 07 X 10" 5.04 X 10*5 8 - 24 2

  • 52 X 10"3 3. 43 X 10"5 24 - 96 1.43 X 10"3 1.49 X 10"5 96 - 720 4.03 X 10""' 4.50 X 10-6 ECCS LEAKAGE 0 - 2 1.16 X 10"3 0 - 8 4. 02 X 10"3 5. 04 X 10"5 8 - 24 2.41 X 10*3 3 .43 X 10"5 24 - 96 1.41 X 10"3 1.49 X 10*5 96 - 720 4. 03 X 10-4 4.50 X 10-6 Table 3.7.2.1-2 Surry Control Room Occupancy Factors Time Occuoancy Factor o - 8 hr 1.0 8 - 24 hr 1.0 24 - 96 hr o-. 6 96 - 720 hr 0.4
  • 244

Table 3.7.2.1-3 LOCA control Room and Offsite Doses Control Room Dose GDC-19 2 EAB 2-hour LPZ 30-Day 10 CFR 100

~ 30-Day Criteria Dose Dose Limit Dose (Rem) (Rem) (Rem) (Rem)

{Rem}

Thyroid 29.0 30 224 12.0 300 Skin 0.1 30 3* 0.2 ---

Whole Body 0.2 s 6 0.3 25

  • 2Control room skin and thyroid dose criteria not specified in GDC-19; values shown are taken from SRP Section 6.4.

245

3.7.2.2 Main Steam Line Break (MSLB)

A Main Steam Line Break (MSLB) involves the postulated double ended failure of one of the steam lines carrying steam from a steam generator to the turbine generator. Two cases have to be considered. Offsite doses are determined based on a case with minimal retention of radionuclides in the turbine building. The control room dose analysis assumes that the MSLB occurs in the turbine building, where the control room emergency air inlet is located, and that the turbine ventilation fans fail to operate.

Because the MSLB releases are assumed to occur in the turbine building, the normal x/Q methodology used for the control room does not apply. x/Q is used to determine the concentration of a radioisotope x in Ci/m3 from the release rate Qin Ci/sec. The control room x!Q is normally determined with the methodology of Reference (3. 7-8) based on the distance between release and receptor points and site meteorology. Depending on the type of release, building wake effects may also be considered. For the MSLB, the releases occur in the same building as the control room emergency inlet, so the Murphy and Campe x/Q methodology does not apply. Therefore, the direct pathway from the steam line break to the turbine building was modeled along with the intake of control room air from the turbine building.

3.7.2.2.1 MSLB Analysis Assumptions As indicated above, analysis of doses in the control room from a MSLB cannot be performed solely with the normal x/Q methodology. There is no control room x/Q defined for a situation when the releases are into the same building where the inlet to the control room is located.

Therefore, it was necessary to use a different approach to model the transport of radioactive steam releases from the broken steam line to the control room. (Normal x/Q methodology is

.applicable. to the modeling of the releases through the unaffected steam generators.)

The control room is normally modeled in the LOCADOSE computer code as a special volume "connected" only to the environment with the inlet concentrations based on releases to the environment and the x/Q for the control room. However, the control room radioisotope concentrations can be calculated with LOCADOSE by defining one of the user specified volumes 246

as the control room and appropriately modeling the air flows, including the inlet air from the turbine building, to this control room volume.

As a starting point for the MSLB analysis, the concentrations of each radioisotope in the primary liquid, secondary liquid and secondary steam were determined. Radionuclides are released with the steam from these sources through the break. These MSLB release rates are shown in Table 3.7.2.2-5.

The flow *rates -used in this analysis-- considered

  • the -volume* expansion ** that occurs when pressurized liquid or steam is discharged from the steam generator to the turbine building. The flow rate from the steam generator to the turbine building was based on the density of steam or liquid inside the steam generator, while the flow rate from the turbine building to the environment was based on the expansion of steam to atmospheric pressure inside the turbine
  • building. **This MSLB model is summarized below.
3. 7.2.2.2 Initial Radioisotope Concentrations *
  • For the MSLB, the radioactive material releases are determined by the initial radionuclide concentrations present in primary liquid, secondary liquid and secondary steam, plus any releases from failed fuel rods. The amount of activity in the primary and secondary coolant at the initiation of the MSLB is assumed to be the maximum levels allowed by the plant Technical Specifications. For Surry, Technical Specification 3.1.D.2 limits the primary coolant specific activity to sl.O µCi/gram dose equivalent J-.131, and Technical Specification 3.6.E limits the specific activity of the secondary coolant system to so.I µCi/gram dose equivalent I-131. The determination of these radionuclide inventories and concentrations corresponding to these limits is described below.

NUREG-0800, Section 15.1.5, Appendix A, requires that MSLB accidents consider iodine spiking above the value allowed for normal operations. Both a pre-accident iodine spike and a concurrent accident iodine spike must be considered. For Surry, the maximum iodine concentration allowed in Surry Technical Specifications for an iodine spike is 10 µCi/g dose equivalent I-131. NUREG-0800 defines a concurrent iodine spike. as an accident initiated increase in the release rate of iodine from failed fuel rods to a value 500 times the release rate 247

corresponding to the Technical Specifications limit for normal operations. A concurrent iodine spike is more likely than a pre-accident spike since the pressure change caused by an accident can increase iodine releases from failed fuel rods. A pre-accident iodine spike is unlikely, since some independent event would have had to occur shortly before the accident to cause the spike.

The primary liquid, secondary liquid and secondary steam radionuclide inventories, as well as the concurrent accident iodine spike appearance rates, are given in Table 3.7.2.2-1 for the concurrent accident case. The primary liquid, secondary liquid and secondary steam radionuclide inventories are given *in Table-3.-7.2;2-2-for-the pre-accident case;** The secondary side activity levels are initially the same (at the Technical Specification activity limit) for both cases. Only the primary liquid activities differ~ The concurrent iodine spike case assumes the primary coolant activity is initially at the steady state activity limit of 1 µ,Ci/ g dose equivalent 1-131, with iodine added at the appearance rates shown. The pre-accident spike case assumes the primary liquid activity is initially at the short term Technical Specifications limit of 10 µ,Ci/g dose equivalent 1-131. These inventories and appearance rates were input to the LOCADOSE code system to calculate doses from an MSLB. The masses of the primary liquid, secondary liquid and secondary steam used in this MSLB dose analysis are listed in Table 3.7.2.2-3 .

  • 3.7.2.2.3 Determination of x/Q Values The unaffecte,d steam generators are assumed to release steam through the secondary system steam relief valves. Based on the Reference (3.7-8) methodology, a diffuse source - point receptor x/Q can be used when the elevation difference between the point source (steam generator relief valves) and point receptor (control room emergency air inlet) is more than 30%

of the height of the source building. The steam releases from the unaffected generators meet this criterion. Using the Murphy and Campe methodology, the control room x/Q values shown in Table 3. 7.2.2-4 were determined for releases from the unaffected generators.

3.7.2.2.4 Main Steam Line Break WCADOSE Models The LOCADOSE computer code system was used to model the MSLB. Two LOCADOSE models were created, one fo.r the pre-accident iodine spike and the other for the concurrent accident spike. The only differences between the two m<>':1els were the initial radioisotope 248

inventories and the modeling of iodine release from the fuel rods for the concurrent accident case.

  • The flow rates from the primary coolant to the steam generators prior to the start of the accident were based on the maximum leak rates allowed by Technical Specifications. The maximum leakage from one generator (500 GPD) is chosen to be into the generator affected by the steam line break.

The affected* steam generator was- modeled -as discharging -through* the turbine building, while the other two generators were modeled as discharging directly to the environment. The flow rates from the affected steam generator liquid to the turbine building and from the turbine building to the environment are summarized in Table 3.7.2.2-5.

All of the iodine being released is conservatively assumed to be airborne. In practice, some of the steam generator discharge would be as water, which would retain some of the iodine in the liquid phase.

The mass release in thirty minutes (Table 3.7.2.2-5) is several times the initial mass of the steam generator. Therefore, the volume released from the steam generator to the turbine building was increased above the calculated values to ensure that substantially all of the radionuclides initially present in the affected steam generat1Jr were released.

Because the affected steam generator is essentially emptied of liquid during the MSLB, no partitioning of iodine between the liquid and steam is assumed for discharges from the affected generator. A partition factor of 0.01 was assumed for the unaffected generators. The flow rate from the turbine building to the environment considered the expansion as the steam pressure is reduced to atmospheric in the turbine building. In addition, because the turbine building is not a sealed building, air flow through the building was considered. The building has a forced ventilation system capable of approximately one volume exchange every six minutes. However, this forced ventilation system would not function after a loss of offsite power. One volume exchange per hour is a reasonable air flow rate for the turbine building without forced ventilation. For conservatism, the control room doses were calculated assuming only a 0.2 249

volume/hour air flow rate. A forced ventilation of 12 volumes/hour was also evaluated to provide a bounding case for offsite dose calculations.

The model for the control room ventilation system for the MSLB is consistent with that used for the LOCA analysis. The control room was assumed to be on bottled air for the first hour of the accident, while a filtered intake of 1000 cfm was modeled after the first hour. An unfiltered inleakage of 10 cfm was again assumed for the full duration of the accident (0 to 30 days).

3.7 .2.2.S -Results of Dose Analysis for MSLB

  • The control room, BAB and LPZ doses calculated for the MSLB are shown in Table 3.7.2.2-6.

As indicated in this table, skin and whole body doses resulting from an MSLB are less than 0.1 Rem and thus substantially less than the acceptance criteria. The limiting accident scenario for the calculation of the thyroid doses was determined to be a concurrent iodine spike case for the control room and BAB. The limiting thyroid dose for the LPZ was for a pre-accident iodine spike case.

The calculated control room thyroid dose from a MSLB is below the GDC-19 criteria; however,

  • it is slightly higher than the dose previously reported to the NRC in Reference (3.7-10). The doses calculated for a MSLB at the EAB and LPZ meet the 10 CPR 100 limits. The thyroid dose at the EAB is less than the value reported in Surry UFSAR Section 14.3.2.

250

Table 3.7.2.2-1 Primary coolant and Secondary Side Radionuclide Inventories Technical Specification Limits Plua concurrent Iodine Spike Primary coolant Secondary Side Activities concurrent Spike Appearance Rate (Ci/hr)

Activity Liquid (3 SG) Steam (3 SG)

Isotope (Curies) (Curies) (Curies) 1 4 Kr-85m 9.318 X 10 1.465 X 10 Kr-85 1.978 X 102 3.111 X 10-4 Kr-87 6.375 X 10 1 1.003 X 10-4 2 4 Kr-88 2.297 X 10 3.612 X 10 4

Xe-133m 1.528 X 102 2.404 X 10 Xe-133 1.537 X 10 4

2.417 X 10-2 1 10-S Xe-135m 1.063 X 10 1. 671 X 2 4 Xe-135 4.250 X 10 6.685 X 10 1

Xe-138 2.861 X 10 4.499 X 10-4 2 1 3 I-131 1.373 X 10 1.097 X 10 7.458 X 10-3 4.709 X 10 10 1 3

I-132 5.109 X 5.005 X 10° 3.403 X 10*3 9.757 X 10 2 1 I-133 2.231 X 10 1.238 X 10 8.414 X 10*3 1.110 X 10" 1

I-134 4.26 X 10 3.061 X 10*1 2.081 X 10-4 1.379 X 10 4

2 4 I-135 1.169 X 10 5.457 X 10° 3.030 X 10° 1.017 X 10

  • 251

Table 3.7.2.2-2 Primary Coolant and Secondary Side Radionuclide Inventories Technical Specification Limit* Plus Pre-Accident Iodine Spike Primary Coolant Secondary Side Activities Activity Isotope (Curies) Steam (3SG)

Liquid (3 SG) (Curies)

(Curies) 4 Kr-85m 9.318 X 10 1 1.465 X 10 2

KR-85 1.978 X 10 3.111 X 10-4 4

Kr-87 6.375 X 10 1 1.003 X 10 102 4 Kr-88 2.297 X 3.612 X 10 2 4 Xe-133m 1.528 X 10 2.404 X 10 Xe-133 1.537 X 104 2.417 X 10*2 1

Xe-135m 1.063 X 10 1. 671 X 10-S Xe-135 4.250 X 102 6.685 X 10-4 4

Xe-138 2.861 X 10 1 4.499 X 10 I-131 1.373 X 103 1.097 X 10 1 7.458 X 10*3 2

I-132 5.109 X 10 5.005 X 10° 3.403 X 10*3

  • 3 1 3 I-133 2.231 X 10 1.238 X 10 8.414 X 10*

2 4 I-134 4.26 X 10 3.061 X 10*1 2.081 X 10 I-135 1.169 X 103 5.457 X 10° 3.030 X 10*

3

  • 252

!rable 3.7.2.2-3 Volume* Uaed in Analy*i* of Main Steaa Line Break 3

Description Volume {ft) Notes Environment

  • Primary Coolant 8902 Secondary Liquid 2052 one steam generator Secondary Steam 4104 one steam generator Control Room 2.23 X 105 Turbine Building 6.00 X 106 Table 3.7.2.2-4 x/Q for Release* froa the Unaffected Steaa Generator*

Location Time xto {sec/m3 )

Control Room 0 to 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> 3.79 X 10-3

. EAB 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 1.16 X 10-3 LPZ 0 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 5.04 X 10-5 LPZ 8 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 3.43 X 10-5 LPZ 24 to 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> 1.49 X 10-5 LPZ 96 to 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> 4.50 X 10-6

  • !fable 3.7.2.2-5 Flow- From Affected BG to the -Turbine Building and From the ~rbine*

Building to the Environment Time Volume Released (CFM) 3 Volume Released (CFM)

Seconds SG to Turbine Building Turbine Building to Environment 0 41 1.632 X 103 2.396 X 106 41 181 3.818 X 103 1.132 X 106 181 - 1800 2.511 X 103 4.096 X 105

>1800 o.o o.o 3

Note that the release rates from the Steam Generator to the Turbine building are increased above the values calculated by the thermal hydraulic analysis by a factor of 5 after 41 seconds, and by a factor of 10 after 181 seconds. This ensures that all of the radionuclides initially present in the Steam Generator are released.

253

Tabla 3. 7*.2 .2-6 MSLB Control Rooa and Offaite Doaea Control Room 30-day GDC-19 4 EAB 2-hour LPZ 30-Day 10 CFR 100 Dose Dose Criteria Dose Dose Limit

.. _.Type (Rem) (Rem) (Rem) (Rem) (REM)

Thyroid 3.6 30 3.6 0.4 300 Skin 0.1 30 <0.1 <0.1 Whole Body 0.1 5 <0.1 <0.1 25 4

Control room skin and thyroid dose criteria _are not specified in GDC-19; values shown are taken from SRP Section 6.4.

254

3. 7 .2.3 Steam Generator Tube Rupture (SGTR)

A steam generator tube rupture (SGTR) is a break in a tube carrying primary coolant through the steam generator. This postulated break allows primary liquid to leak to the secondary side of the steam generator with an assumed release to the environment through the steam generator Power Operated Relief Valves (PORVs) or the steam generator safety valves. Steam is assumed to be discharged from the affected generator to the environment for 30 minutes until the generator is isolated. As required by the NRC Standard Review Plan, the SGTR analysis was performed* assuming both a pre-accident iodine spike and a -concurrent -accident iodine spike.

In a SGTR, the release point for all three steam generators is the same as for the unaffected steam generators in the MSLB. However, since there is a short time delay between the tube rupture and isolation of the control room inlet during a SGTR, a control room x/Q for the normal inlet also had to be calculated. The control room x/Qs used after isolation for the SGTR are the same as those used for releases from the unaffected steam generators during a MSLB (Section 3. 7.2.2) .

  • 3.7.2.3.1 SGTR Analysis As.mm.ptions Virginia Power recognized in 1988 that tube bundle uncovery could impact doses from a Steam Generator Tube Rupture (SGTR). In a letter from D. S. Cruden (Virginia Power) to NRC (3.7.2-1), Virginia Power committed to analyze SGTR doses with tube bundle uncovery and submit this analysis for NRC review after the Westinghouse Owners Group (WOG) developed a methodology for this analysis. This methodology was submitted to NRC in March 1992 (3.7.2-2). As indicated in this evaluation methodology, STGR releases consist of four components:
1) Releases from secondary liquid boiling including allowance for a partition factor of 0.01 for iodine between secondary liquid and steam.
2) Releases from the fraction of primary liquid break flow that flashes to steam. A partition .

factor of 1 is assumed for this flashing fraction.

3) Releases from primary liquid bypassing the secondary side.
4) Releases caused by secondary moisture carryover.
  • 255

As shown in Reference (3.7-2), releases from a SGTR are dominated by the first two terms above for a case with a stuck open PORV. A stuck open PORV also produces a larger

  • radionuclide release than a cycling PORV or a PORV that fails closed and causes the steam generator safety valves to open to relieve secondary side pressure.

Uncovery of the tube bundle in a SGTR does not significantly increase radionuclide releases for the stuck open PORV case. If the tube bundle is uncovered in a SGTR and the PORV is stuck open, the third release term described above increases, but it is still only a small part of the total .

release.

The LOCADOSE computer models for the SGTR analysis shown below are based on the methodology developed by the Westinghouse Owner's group (3. 7-2). These models include only the first two terms discussed above. This does not significantly affect the model results because these two terms dominate the releases for the stuck open PORV case, which is the limiting case

,for radionuclide releases.

3.7.2.3.2 Initial Radioisotope Concentrations *

  • Initial radionuclide concentrations of the primary and secondary systems for the SGTR accident are the same as those for the MSLB. The analyses of both the SGTR and the MSLB accidents indicate that no additional fuel rod failures occur as a result of these transients. Thus, radioactive material releases are determined by the radionuclide concentrations initially present in primary liquid, secondary liquid and secondary steam, plus any releases from fuel rods that have failed before the transient. These radionuclide inventories and concentrations are shown in Tables 3.7.2.2-1 and 3.7.2.2-2.
3. 7.2.3.3 Determination of x/Q values During a SGTR with loss of offsite power, the steam generators release steam through the secondary system PORVs. The control room x/Q values for releases from the steam generator PORVs to the control room emergency air inlet are discussed in Section 3.7.2.2.3 and shown in Table 3.7.2.2-4.

256

The distance from the closest PORV to the control room normal air inlet is shorter than the distance to the emergency inlet, so a different x/Q value is applicable for releases when the

  • normal control room ventilation system is in use. Based on the Reference (3.7-8) methodology, the control room x/Q for the normal inlet was determined to be 7.71 x 10-3 sec/m3
  • This x/Q is only used for the short time (247 seconds) before the control room is isolated from the normal inlet air by a SI signal.

3.7.2.3.4 Steam Generator Tube Rupture WCADOSE Models The LOCADOSE computer code system (3.7-3) (3.7-4) (3.7-5) was used to model the SGTR.

Models were developed for both a pre-accident iodine spike case and a concurrent accident iodine spike case. The two models are identical except for the initial radioisotope inventories and the inclusion of modeling of iodine release from the fuel rods for four hours for the

  • concurrent accident case.

The primary system, steam generator and control room volumes for the SGTR are the same as for the MSLB (Table 3.7.2.2-3). The liquid properties are also the same. As for the MSLB

  • analysis, the release of the radionuclides contained in the steam from all three steam generators was modeled as essentially a puff release occurring when the PORVs open.

The primary coolant leakage to the unaffected steam generators was based on the maximum leakage allowed by Technical Specifications. The maximum leakage allowed from all three generators in Surry Technical Specification 3 .1. C-6 is 1 GPM.

For conservatism, all of this leakage was assumed to occur into the two unaffected steam generators. This assumption is conservative because the unaffected generators release steam to the environment for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> compared to 30 minutes for the affected generator.

The break flow rates through the ruptured tube to the affected steam generator were based on the thermal hydraulic analysis of a complete double ended tube rupture presented in Section 3.5.9. To be consistent with the regulatory guidance in SRP Section 15.6.3 (3.7-6), the liquid and steam break flows are modeled separately. The break flow rates and release rates to the environment are summarized in Table 3.7.2.3-1.

257

The liquid break flow from the primary system is modeled as mixing with the secondary liquid in the affected steam generator. The flow from the secondary liquid to the secondary steam is

  • then modeled assuming a partition factor of 0.01 for iodine. This technique for modeling a SGTR with uncovery of the tube bundle was developed in a generic study by the Westinghouse Owners Group (3. 7-2).

The fraction of the break flow that flashes to steam is modeled as being transferred to the affected steam generator steam space. Once in the steam generator steam space, the radionuclides in* this part of -the- break-are-almost -immediately-released -to. the- environment.

The primary and secondary system releases are replaced with safety injection and auxiliary feedwater flows. Therefore, the volume of the primary and secondary liquids remains relatively constant during this transient.

The flow from the affected generator through the condenser was represented for the time interval between the tube rupture and the opening of the PORV. During this period, there is some build-up of radionuclide inventory in the affected generator liquid and steam volumes. A very .

small volume and a large return flow to the steam generator liquid space was used for the condenser. This conservatively ignores the dilution and retention *of radionuclides in the condenser. The flow through the condenser for the unaffected generators is not modeled because there is no rapid build-up of radionuclides in these generators. The radionuclide inventory in these generators is modeled based on the initial inventory and the primary to secondary leakage:

The model for the control room ventilation system for the SGTR is similar to that used for the LOCA and MSLB analyses, with some differences incorporated to more accurately model the timing of the sequence of events of the SGTR. The start of the accident is the tube rupture itself. The PORV on the faulted steam generator was determined to open 88 seconds after the break, and the SI signal is generated at 247 seconds. The timing of these events was extracted from the thermal-hydraulic analysis presented in Section 3.5.9. During this time, the control room is being supplied via the normal ventilation system, with a 3000 cfm intake air flow rate.

The control room isolates automatically on initiation of the SI signal and is then assumed to be on bottled air until 1.0 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> after the tube rupture. From 1.0 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> until the end of the accident,

  • the control room is provided with a filtered air supply of 1000 cfm. An unfiltered inleakage of 258

10 cfm was assumed for the entire time the control room is isolated. The control room intake filter efficiency assumed was 90% and 30% for elemental and organic iodine respectively .

  • 3.7.2.3.5 Results of Dose Calculations for SGTR Both pre-accident and concurrent accident iodine spike cases were analyzed for the steam generator tube rupture. The skin and whole body doses for both cases were below 0.1 Rem.

These low doses are well below the regulatory criteria.

The. limiting case for the control room thyroid doses was determined to. be for a pre-accident iodine spike. The calculated thyroid dose for this case is less than the value reported to the NRC in Reference (3.7-10). A comparison of the doses calculated for the limiting SGTR accident scenario with the GDC-19 criteria is shown in Table 3.7.2.3-2. All calculated control room doses* for the Surry. steam generator tube rupture remain below the GDC-19 criteria.

As discussed in Reference 3.7-2.7-1, the BAB doses reported in the Surry UFSAR did not consider tube uncovery. As noted in this reference, tube uncovery has the potential to increase

  • BAB doses. The revised doses shown in Table 3.7.2.3-2 are greater than the values shown in Surry UFSAR Section 14.3.1, but these doses are less than the 10 CFR 100 limits and meet the SRP 15.6.3 review criteria of less than a small fraction (10%) of 10 CFR 100.

259

Table 3.7.2.3-1 Steam Generator Tube Rupture Break Flow Rates and Release*

Affected Steam Generator RCS to SG RCS to SG SG Liquid Steam Time Liquid Flow Steam Flow to Steam Release (sec} (lbm} (cfm} {lbm) (cfm} (cfm} (cfm}

0 88 6238 94.1 501 7.55 1330 *o 88 247 9997 83.4 82 0.68 145 4036 247 - 1800 90270 77.1 677 0.58 113 3156 SG Liquid to SG Steam to Time Steam Flow Condenser Flow (sec) (cfm) (cfm}

0 - 88 37080 Unaffected Steam Generators Steam Mass Flow Rate Time Period (lbml (cfm}

0 sec - 88 sec 0 0 88 sec - 393 sec 43315 177 393 sec - 30 min 0 0 30 min - 2 hr 179398 41

  • 2 hr - 8 hr 632579 37 Table 3.7.2.3-2 Steam Generator Tube Rupture Control Room and Offsite Dose*

Control Room 30-day GDC-19 5 EAB 2-hour *LPZ 30-Day 10 CFR 100 Dose Dose Criteria Dose Dose Limit

~ (Rem} (Rem} (Rem) (Rem) (Rem}

Thyroid 8.1 30 3.8 0.2 300 Skin <0.1 30 <0.1 <0.1 Whole <0.1 5 <0.1 <0.1 Body 5

Control room skin and thyroid dose criteria are not specified in GDC-19; values shown are taken from SRP Section 6.4.

260

3. 7.2.4 Locked Rotor Accident (LRA)
  • The Locked Rotor Accident (LRA) evaluates the consequences of the sudden seizure of the rotor of one of the reactor coolant pumps. Similar results would be expected for a shear failure of a shaft in the reactor coolant pump. In these types of accidents, flow through the affected loop reduces rapidly while the core is still at power, and some degree of reverse flow would be expected through the affected loop. The low flow in the affected loop leads to a reactor and turbine trip, but the partial loss of flow while the core is at power results in a degradation in heat transfer which could in tum result-in fuel damage.

Although there is no increase in the leakage of primary coolant to the secondary side in the LRA, activity (from the failed fuel) may be transported to the secondary side via any preexisting leaks in the steam generators. If there is a loss of offsite power, activity is released to the atmosphere through the steam generator safety valves and/or the power operated relief valves (PORVs) until the plant cools down and the reactor is secured in a safe condition.

3.7.2.4.1 LRA Analysis Assumptions

  • The Locked Rotor Accident (LRA) is discussed in Section 15 .3.3-15 .3.4 of the NRC' s Standard Review Plan (3. 7-6). In accordance with the SRP, the reactor is initially assumed to be operating at 102 % of the uprated power level for this analysis. A turbine trip and coincident loss of offsite power are incorporated into the analysis, which is consistent with the conditions given by Section 15.3.3-15.3.4 of the SRP. With the assumed loss of offsite power, releases are through the steam generator PORVs and safety valves.

Both primary and secondary side coolant activities are set at the maximum levels permitted by the plant Technical Specifications. The primary coolant activity level also assumes a pre-accident iodine spike to the maximum level allowed by the Surry Technical Specifications as well as the contribution due to fuel failures that could result from the LRA. Preexisting primary to secondary leakage is modeled at the maximum levels permitted by the Technical Specifications .

  • 261

The possibility of uncovery of the upper portion of the steam generator tube bundle (based on collapsed liquid levels) during a LRA was not considered in previous LRA dose calculations.

For the current evaluation, the approach taken was that developed by the Westinghouse Owners Group (3.7-2). This approach considers that the probability of coincidental occurrence of a LRA, a pre-existing steam generator tube leak above the collapsed liquid level and condenser unavailability due to a loss of offsite power is sufficiently small (3. 7-2) that it is not necessary to evaluate this combination of conditions. Therefore, any leaks in the steam generator tube bundle were assumed to remain covered throughout the accident.

When the tubes are covered, the secondary side water provides a scrubbing action, trapping some of the activity from iodine in the primary fluid in the secondary liquid. The noble gases are unaffected by this process. Whenever the steam generator tubes are covered, this analysis uses an iodine partitioning factor of 0.01 to account for this effect. The value of this partitioning factor is consistent with that used in previous LRA analyses and is also given in Section 15.6.3 of the SRP for the Steam Generator Tube Rupture (SGTR), which has a release mechanism similar to that seen in the LRA.

For a LRA where the PORVs cycle open and closed as they are designed to do, conditions

  • which would generate an SI signal are not created. Without an SI signal, the Surry control room is not automatically isolated. Allowing an operator action time (assumed to be 20 minutes, as recommended in Section 6.4 of Reference (3.7-6)) means that for a period of time prior to isolation, control room air is drawn in through the normal intakes. The normal ventilation intakes are closer to the release point than the emergency ventilation intakes, do not have iodine filtration and supply air to the control room at a greater flow rate than the emergency ventilation system. Therefore, this scenario is more conservative for control room dose calculations.

A stuck open PORV produces higher steam releases during the first two hours after a LRA which gives slightly higher EAB doses. Therefore, the LRA was analyzed based on the steam

  • releases expected for the first two hours with a stuck open PORV for conservatism in calculation of EAB doses, but assuming no SI signal for conservatism in calculation of control room doses.

Briefly, the assumed sequence of events used in this current dose evaluation for a LRA at Surry is as follows. The accident is initiated when one reactor coolant pump rotor locks. Power to the 262

other two r~ctor coolant pumps is assumed to be lost shortly thereafter, after the reactor trips.

Assuming the steam condensers are unavailable due to loss of offsite power, the PORVs on the

  • two unaffected steam generators open within seconds of the accident, and the PORV on the steam generator in the affected loop also opens within one minute. Most of the releases in the first minute are through the unaffected steam generators; after the third PORV opens, the steam release through all three steam generators is assumed to be essentially identical. Releases are conservatively modeled as starting immediately.

These releases -are-assumed-to occur for- 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />,- by which time- the- Reactor Coolant System (RCS) temperature has been decreased to 350°F. At this point the Residual Heat Removal (RHR) System is activated, and releases to the atmosphere through the steam generator PORVs cease.

3~7~2.4.2 Initial Radioisotope Concentrations The amount of activity released is dependent on both the amount of activity in the coolant at the time of the accident and the activity released due to fuel failures. As for the MSLB and SGTR

  • accident analyses, the amount of activity in the primary and secondary coolant at the initiation of the locked rotor accident is assumed to be the maximum levels allowed by the plant Technical Specifications.

The LRA analysis assumes a pre-accident iodine spike, so the primary coolant iodine levels at the start of the accident are conservatively set at the short term limit of 10 µCi/gram, rather than at the 1.0 µCi/gram limit for normal operation. An additional source of activity in the primary coolant is the releases due to additional fuel failures. The Locked Rotor Accident analysis is based on 5 % failed fuel (Surry UFSAR) - that is, 5 % of the fuel in the core (briefly) enters DNB during the accident and is therefore assumed to fail. These fuel failures are assumed to occur instantaneously at the start of the accident. The total amount of activity in the primary coolant at the start of the LRA is then the Technical Specification activity level plus the activity due to failed fuel. Table 3. 7 .2.4-1 gives the primary and secondary side radionuclide inventories for the LRA. It should be noted that the thermal/hydraulic analysis of Section 3.5.8 predicts no fuel failure as a result of a locked rotor accident.

263

3. 7.2.4.3 Locked Rotor Accident LOCADOSE Model
  • . The LOCADOSE computer code system, which is documented in References (3. 7-3) through (3.7-5), is used to calculate the doses for the LRA. The primary and secondary system volumes used in this analysis are the same as those used in the MSLB and are given in Table 3. 7.2.2-3.

The leakage from the primary coolant to the secondary system through the steam generators was set at the maximum leakage allowed by the Surry Technical Specifications, or 1 gpm through all three steam generators. As discussed in Section 3.7.2.4.1, the LRA was modeled assuming that any leaks in the-steam generator-tube bundle-remain covered-throughout the accident. The primary coolant was therefore modeled as leaking to the steam generator liquid volume. The flow from the secondary liquid to the secondary steam assumes a partition factor of 0.01 for iodine.

In the LRA, most of .the releases in the first minute are through steam releases from the two unaffected steam generators. After the third PORVopens (within one minute), the steam release through all three steam generators is assumed to be essentially identical. To simplify the modeling of this accident, the releases were treated as being identical through all three steam generators for the entire release period. The releases are also modeled as starting immediately, rather than a few seconds after initiation of the accident (when the PORVs open), and continue for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The steam releases for the LRA are given in Table 3.7.2.4-2.

As noted above, if the PORVs cycle normally during a LRA, no SI signal is generated to isolate the control room and initiate the flow of bottled air. The analysis therefore models normal control room ventilation (at a 3000 cfm flow rate) at the beginning of the LRA, until it is manually isolated. As noted in section 3.7.2.1, 20 minutes are allowed for this operator action time. The air into the. control room is supplied by banks of bottled air for the next 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. At the end of the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period (1.33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> after initiation of the. accident), the control room is supplied via an emergency ventilation system, which provides the control room with filtered air drawn from the turbine building. There are 4 fan/filter trains, rated at 1000 cfm capacity each, which can provide intake to the control room pressure envelope. Only one of these fans is assumed to be supplying the control room after the bottled air supply is depleted (i.e. 1 1000 cfm filtered intake). The iodine removal efficiency for the emergency ventilation air supply filters is assumed to be 90%, in accordance with Regulatory Guide 1.52 (3. 7-9). This emergency 264

ventilation supply is assumed to be used for the remainder of the 30-day period for which control room doses are calculated .

  • There is also a 10 cfm unfiltered inleakage into the control room starting when the control room is isolated and again continuing until the end of the 30-day dose calculation period. This unfiltered inleakage is intended to simulate the effects of personnel entries to (and exits from) the control room pressure envelope as required by emergency operating procedures. The value of 10 cfm was taken from SRP Section 6.4 (3.7-6).

As for the SGTR analysis, two different atmospheric dispersion factors were needed for the LRA control room dose calculations. Whenever the control room was isolated, the same x/Q values used for venting from the steam generators during the MSLB were used (fable 3.7.2.2-3).

These values are also applicable to this analysis because both scenarios involve the same release and receptor points~*. Prior to isolation of the control room, a different x/Q value (7.71 x lQ*3 sec/m3) was used which reflected the shorter distance between the release point and the normal control room ventilation intake. Control room occupancy factors were also incorporated into the dose calculations to reflect that personnel would not be exposed to the released activity 100%

of the time over the entire 30-day period. The factors which were used were determined based on the Reference (3.7-8) methodology and are given in Table 3.7.2.1-2. The breathing rate used for the control room dose calculations was 3.47 x 10_. m3/sec, which again is consistent with the Murphy and Campe paper.

3. 7.2.4.4 Results of Dose Calculations for LRA The dose calculations for a LRA with the model and assumptions described above are summarized in Table 3.7.2.4-3. The thyroid doses reported are inhalation doses, and the skin doses are immersion doses. The whole body doses given in Table 3.7.2.4-3 include the whole body doses due to both inhalation and immersion.

The doses for a LRA have not been previously reported to the NRC. The calculated control room doses for a LRA are less than the criteria specified by SRP Section 6.4 and GDC-19, and the offsite doses are below the limits specified in 10 CFR 100. Note again that these doses are based on a bounding, conservative assumption of the amount of fuel failure which results from a locked rotor event.

265

Table 3.7.2.4-1 Primary Coolant and Secondary Side Radionuclide Inventories: Technical Specification Limits Plus Pre-Accident Iodine Spike and 51 Failed Fuel Priinary Coolant Secondary Side Activities Activity Liquid (3 SG) Steam (3 SG)

Isotope (Curies) (Curies) (Curies) 5 10...

Kr-85m 1.685 X 10 1.465 X 4

Kr-85 1.618 X 104 3.111 X 10 5

Kr-87 3.033 X 10 1.003 X 10...

Kr-88 4.157 X 105 3.612 X 10..c 4

Xe-133m 1.812 X 10 2.404 X 10...

5 Xe-133 7.454 X 10 2.417 X 10-2 5

Xe-135m 2.022 X 10 1.671 X 10-5 5 10-4 .

Xe-135 6.968 X 10 6.685 X 5

Xe-138 6.201 X 10 4.499 X 10-5 5 1 10-3 I-131 3 *. 270 X 10 1.097 X 10 7.458 X I-132 4.947 X 10 5

5.005 ~ 100 3.403 X 10-3 I-133 7.~322 X 10 5

1.238 X 101 8.414 X 10-3 5 10...

I-134 8.541 X 10 3.061 X 10-1 2.081 X I-135 6.638 X 10 5

4.457 X 10° 3.030 X 10-3

  • 266

Table 3.7.2.4-2 Steam Generator Volumes Released During a Locked Rotor Accident

  • Time Period (hours) 0.00 0.25 0.33 0.25 0.33 1.00 Time Averaged Flow Rate Liguid(CFM) Steam (CFM) 245 116 65 6840 3225 1807
1. 00 - 2. 00 43 1211 2.00 - 8.00 35 963 Table 3.7.2.4-3 LRA Control Rooa and Offaite Doaea Control Room 30-day GDC-19 EAB 2-hour LPZ 30-Day 10 CFR 6

100 Dose Dose Criteria Dose Dose Limit

~ (Rem) (Rem) (Rem) (Rem) (Rem)

Thyroid 10.6 30 2.1 0.7 300 Skin 1.0 30 0.2 <0.1 Whole Body 0.2 5 0.3 <0.1 6

Control room skin and thyroid dose criteria are not specified in GDC-19; values shown are taken from SRP Section 6.4.

267

3. 7.2.5 Fuel Handling Accident (FHA)

A Fuel* Handling Accident (FHA) inside of containment or* in the fuel building could damage a fuel assembly and release some of the fission product inventory to the environment. An illustrative accident sequence consists of: drop of a fuel assembly; breach of the fuel rod cladding; release of a portion of the volatile fission gases .from the damaged fuel rods; absorption of water soluble gases in and transport of soluble and insoluble gases through the water to the air space over the water; air :filtration prior to release into the environment; and dispersion of the released fission products into the atmosphere.

If this accident sequence occurs when handling a fuel assembly inside of containment, either the manipulator crane area, containment gas or containment particulate radiation monitor would automatically isolate the containment to prevent further releases to the environment. For the "design*basis .-case; *this automatic isolation is assumed to fail, and the radioactive material reaching the containment atmosphere is assumed to be released through the ventilation system filters.

To determine the quantity of radioactive material available for release, it is conservatively assumed that the fuel assembly with the peak fission product inventory is the one damaged. The inventory is based on maximum full power operation at the end of core life immediately preceding shutdown and a conservative radial peaking factor which is applied to all fuel rods in the assembly. Only that fraction of the fission products which migrates from the fuel matrix to the gap and plenum regions of the fuel rods during normal operation is considered to be available for immediate release into the water in the event of clad damage. The quantity of radioactive material released subsequent to the immediate release is considered to be negligible compared to the quantity released immediately after the FHA.

The fuel radionuclide inventory was based on a core power level of 2605 MWt. This core power level is conservative compared to 102% of the uprated power level of 2546 MWt (i.e.,

2597 MWt).

268

3.7.2.5.1 FHA Analysis Assumptions The Fuel Handling Accident (FHA) is discussed in Section 15.7.4 of the NRC's Standard Review Plan (3.7-6) and Regulatory Guide 1.25 (Safety Guide 25; (3.7-12)). Consistent with these guidelines, the following assumptions were made for the evaluation of the Surry control room and offsite doses due to a FHA.

(1) The accident occurs 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> after shutdown. Surry Technical Specification 4.2 requires a minimum 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> period between the shutdown of a unit and initiation of fuel movement, so the-use of a 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> time period is conservative.-- Radioactive decay of the fission product inventory during the 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> interval between shutdown and the assumed commencement of fuel handling is incorporated into the analysis.

(2) The maximum fuel rod pressurization is 1200 psig.

(3) The minimum water depth between the top of the damaged fuel rods and the water surface is 23 feet.

(4) All of the gap activity in the damaged rods is released and consists of 10 % of the total noble gases other than Kr-85, 30% of the Kr-85 and 10% of the total radioactive iodine in the rods at the time of the accident.

  • (5) The values assumed for individual fission product inventories are calculated assuming full power operation at the end of core life immediately preceding shutdown. A radial peaking factor of 1. 65 was used.

(6) The iodine gap inventory is composed of 99. 75 % inorganic species and O. 25 % organic species.

(7) The pool decontamination factors for the inorganic and organic species are 133 and 1, respectively, giving an overall decontamination factor of 100 (i.e., 99% of the total iodine released from the damaged rods is retained by the water). This difference in decontamination factors for inorganic and organic iodine species results in the iodine above the fuel pool being composed of 75 % inorganic and 25 % organic species.

(8) The retention of the noble gases in the water is negligible.

(9) The radioactive material that escapes from the water to the fuel building or containment is released over less than a two hour time period.

(10) The fuel building or containment atmosphere is exhausted through absorbers designed to remove iodine. The removal efficiency assumed for these iodine absorbers is 90 % for inorganic species and 70 % for organic species.

269

(11) The effluent from the filter system passes directly to the emergency exhaust system without mixing in the surrounding building atmosphere and is then released.

3. 7.2.5.2 Determination of Activity Released The 100-hour core inventory was calculated for Surry assuming operation at 2605 mwt, which is conservative with respect to 102 % of uprated power. The core inventory for this analysis was determined using the source terms for the LOCADOSE computer code system (3.7-3) (3.7-4)

(3. 7-5). The effects of a -100 hour period of decay on this core -inventory were then assessed.*

This evaluation included the contribution of iodine and noble gases which result from decay of Te isotopes.

The amount of radioactive material which is released to the fuel building or containment during a FHA at 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> is determined from this core inventory using the following assumptions:

(1) All rods in one fuel assembly are damaged.

(2) There are 157 fuel assemblies in the* Surry core.

(3) The peak assembly operated at a radial peaking factor of 1.65 relative to the core average power during the most recent cycle of operation.

(4) Gap fractions as defined in Section 3.7.2.5.1.

(5) Decontamination factors as defined in section 3.7.2.5.1.

The resulting activities released to the fuel building or containment are given in Table 3. 7 .2.5-1.

3.7.2.5.3 Fuel Handling Accident WCADOSE Model The LOCADOSE computer code system (3.7-3) (3.7-4) (3.7-5) was used to calculate doses for the FHA. The model for this accident considered three distinct volumes: the environment, the spent fuel building (note that the fuel building volume and ventilation flow rates are used because these are conservative compared with those for the containment) and the control room. The Spent Fuel Building volume assumed is a conservatively small value, which minimizes mixing of the radioactive material with the building atmosphere. The following volumes were used in the FHA control room dose calculations:

270

Spent Fuel Building Volume 1.11 X lOS ft' Control Room Volume 2.23 X lOS ft' These dose calculations considered the initial activity in the containment or spent fuel building which is shown in Table 3.7.2.5-1 and flow out into the environment at the normal ventilation rate for the fuel building (3.5 x 10' cfm). This exhaust is filtered prior to release to the environment. The assumed charcoal filter iodine decontamination factors were 90 % for inorganic and 70 % for organic iodines, consistent with the regulatory guidelines.

The transit time for any released activity from the radiation detection point at the water surface to the control room normal ventilation system intake is assumed to be several minutes.

Therefore, control room manual isolation was modeled as occurring before any radioactive material reached the control room air iniet. The control room is then manually isolated and supplied with bottled air for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after the isolation.

At the end of one hour, the control room emergency ventilation system provides a filtered air supply to the control room pressure envelope. This analysis considered that only one fan was operational which provides a control room intake flow rate of 1000 cfm from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> through the end of the 30-day dose calculation period. A summary of the control room ventilation system flow rates for the FHA is given in Table 3.7.2.5-2.

The fuel building and containment ventilation systems exhaust to the atmosphere through the same filters and ventilation stack are used by the ECCS ventilation system. Therefore, the control room x!Q values used in this analysis are the same as those used for ECCS releases in the evaluation of control room doses following a LOCA (Table 3.7.2.1-1). The control room occupancy factors in Table 3.7.2.1-2 were also incorporated into the dose calculations to reflect that personnel would not be exposed to the released activity 100% of the time over the entire 30-day period. As in the evaluation of other accidents, the breathing rate used for the control room dose calculations for the FHA was 3.47 x 1Q-4 m3/sec, which is consistent with Reference (3.7-8) .

  • 271
3. 7.2.5.4 Results of Dose Calculations for FHA

. The* dose calculations due to a fuel handling accident in the containment or spent fuel pool using the model and assumptions described above are summarized in Table 3.7.2.5-1. The calculated control room skin dose and whole body doses are approximately the same as the values previously reported to the NRC (3. 7-10). The thyroid dose has increased from the Reference (3.7-10) value, but remains well below the GDC-19 criteria as shown in' Table 3.7.2.5-3.

The BAB and LPZ- doses for.a FHA-are below the-10 CFR--100-limits as shown in Table 3.7.2.5-3 and meet the SRP 15.7.4 criteria of being less than 25% of the 10 CFR.100 limit.

The thyroid dose is less than the value reported in Surry UFSAR Section 14.4.1 for a FHA in the fuel building.

272

  • Isotope Table 3.7.2.5-1 Activity Released to the Containment or Fuel Building Activity Released (Curies}

I-131 (Elemental) 2 3.697 X 10 I-131 (Organic) 1.232 X 102 I-132 (Elemental) 2 3.358 X 10 I-132 (Organic) 2 1.119 X 10 I-133 1 (Elemental) 4.272 X 10 I-133 (Organic) 1 1.424 X 10 I-135 (Elemental) 3.476 X 10*2 I-135 (Organic) 1.159 X 10*2 Kr-85 3 3.374 X 10 Xe-131m 2 6.915 X 10 Xe-133m 3 1.692 X 10 Xe-133 5 1.061 X 10 Xe-135m 7.966 X 10*1 Xe-135 2 2.260 X 10 Table 3.7.2.5-2 Fuel Handling Accident Control Rooa Ventilation Flow Rate*

  • Description Unfiltered inleakage when control room is isolated Emergency ventilation rate (cfm}

10 1000 Flow Rate Applicability Whenever control room is isolated (0 - 30 days) 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to 30 days

  • 273

Table 3.7.2.5-3 FHA Control Room and Offsita Doaaa

  • Dose TYJ2e Thyroid Control Room 30-day Dose (Rem}

2.4 GDC-19 Criteria7 (Rem}

30 EAB 2-hour (Rem}

Dose

  • 55. 0 LPZ 30-Day Dose (Rem}

2.4 10 CFR 100 Limit (Rem}

300 Skin 0.1 30 1.8 0.1 Whole Body 0.1 5 1.6 0.1 25

  • *-~.--,..

.....;.\If~

7 Control room skin dose and thyroid dose crite~ia are not specified in GDC-19; values shown are-taken from SRP Section 6.4.

274

3.7.2.6 Waste Gas Decay Tank (WGDn Rupture

  • Surry has two Waste Gas Decay Tanks that collect the gasses stripped from the primary coolant system by the primary coolant clean-up systems. One tank is charged with waste gasses being removed from the primary system while the other tank is used to hold up the gasses for decay and controlled release. Surry Technical Specification 3 .11 limits the maximum inventory of noble gas in a Waste Gas Decay Tank to no more than 24,600 curies of noble gasses (considered as Xe-133). The analysis of doses from rupture of a WGDT assumes rupture of a WGDT with the release of the-maximum--inventory allowed-by Technical Specifications.

3.7.2.6.1 WGDT Analysis Assumptions The whole body EAB dose from the rupture of a WGDT was determined based on a puff release as the product of the (1) curies released, (2) dose conversion factor for Xe-133 and (3) EAB x/Q. This analysis does not require any computer code. A control room dose analysis for a WGDT rupture was reported to the NRC in Reference (3.7-10), and this WGDT control room dose analysis was not repeated here .

  • 3.7.2.6.2 Dose Analysis for WGDT Rupture The maximum WGDT inventory allowed by Surry Technical Specification 3.11 is 24,600 curies (considered as Xe-133). The x/Q for the EAB is 1.16 X 10*3 sec/m3
  • The whole body dose conversion factor for Xenon-133 is 9.316 X 103 Rem-m*3/Ci-sec. A puff release of the maximum WGDT inventory allowed by Technical Specifications results in a whole body BAB dose less than 0.5 Rem.

3.7.2.6.3 Results of Dose Analysis for WGDT Rupture The whole body EAB dose from rupture of a WGDT containing the maximum inventory allowed by Surry Technical Specifications is less than 0.5 Rem. This is less than a small fraction (10%)

of the 10 CPR 100 limit of 25 rem and is consistent with the requirements of Branch Technical Position ETSB 11-5 in NUREG-0800 as discussed in the basis section of Surry Technical Specification 3.11.

275

As reported in Reference (3.7-10), control room doses from a WGDT rupture have been l

evaluated and shown to meet the design criteria specified in 10 CFR 50, Appendix A, GDC 19.

This control room dose analysis was not repeated here .

  • 276

3.7.3 Summary of Dose Analysis Results All five accidents that could potentially produce significant doses to control room operators, at the BAB or at the LPZ were analyzed to ensure that a complete and consistent set of dose analyses is available. In addition, an analysis of the potential BAB dose from a WGDT rupture was performed to show that the failure of a WGDT tank would not challenge the 10 CFR 100 dose limits. The following analyses were performed:

1) Loss of Coolant Accident (LOCA)
2) Main Steam Line Break (MSLB)
3) Steam Generator Tube Rupture (SGTR)
4) Locked Rotor Accident (LRA)
5) Fuel Handling Accident (FHA)
6) Waste Gas Decay Tank (wGDTJ Rupture The control room and offsite doses that have been reported to the NRC in either the Surry UFSAR or References 10 and 11 are shown in Table 3.7.3-1. Control room and offsite (i.e.,

BAB and LPZ) dose calculations from Section 2 are summarized in Table 3.7.3-2.

Compared to the control room doses previously reported to the NRC in Reference (3.7-10), the thyroid doses have increased in three cases (LOCA, MSLB and FHA). No changes have been made to Surry systems, operating procedures or specifications that would impact the analysis of control room doses from these accidents. The changes in control room doses result from the use of a revised dose analysis methodology and changes in input assumptions to ensure consistency with SRP guidelines. All control room operator doses were determined to meet the regulatory criteria specified by GDC-19.

Compared to the BAB and LPZ doses previously reported to the NRC, the LOCA whole body dose has increased slightly at the BAB, and the thyroid dose is increased for the SGTR. The increase in calculated LOCA whole body dose results from the use of a revised dose analysis methodology, changes in assumed atmospheric dispersion factors (x/Q) and changes in input assumptions made to ensure consistency with SRP guidelines. The SGTR analysis shown in the UFSAR did not consider the potential for tube bundle uncovery. The analysis performed here does consider tube bundle uncovery based on the WOG methodology (3. 7-2). This thyroid dose 277

is higher than the value shown in the Surry UFSAR, but it is less than a small fraction (10 %)

of the 10 CFR 100 limit.

  • 278

!rahle 3.7.3-1 Control Room and Off Site Doses Previously Reported to :NRC CONTROL ROOM Thyroid Whole Body Skin Accident Dose (Rem) Dose (Rem) Dose (Rem)

LOCA 26.6 o.s 1.3 MSLB 1. 7 <0.1 <0.1 SGTR 16.2 <0.1 0.3 FHA 0.9 <0.1 0.1 WGDT o.s 19.7 EXCLUSION AREA BOUNDARY Thyroid. Whole Body Accident Dose (Rem) Dose (Rem)

LOCA 248.0 s.o MSLB 12.3 SGTR b.3 0.3 FHA 171.2 7.5 8

WGDT 0.1 3. 7 LOW POPULATION ZONE Thyroid Whole Body Accident Dose (Rem) Dose (Rem)

LOCA 23.3 0.4

  • 8 Based on a postulated tank content of 95,400 Ci of Xe-133 279

Table J.7.l-2 SWIIIIUlry of Control Room and Offaite Doae*

CONTROL ROOM Thyroid Whole Body Skin Accident Dose (Rem) Dose (Rem) Dose (Rem)

LOCA 29.0 0.2 0.1 MSLB 3.6 <0.1 <0.1 SGTR 8.1 <0.1 <0.1 LRA 10.6 0.2 1.0 RHA 2.4 0.1 0.1 EXCLUSION AREA BOUNDARY Accident Thyroid Whole Body Skin Dose (Rem) Dose (Rem) Dose (Rem)

LOCA 224.0 6.0 3.0 MSLB 3.6 <0.1 <0.1 SGTR 3.8 <0.1 <0.1 LRA 2.1 0.3 0.2 RHA 55.0 1.6 1.8 WGDT <0.5 LOW POPULATION ZONE Accident Thyroid Whole Body Skin Dose (Rem) Dose (Rem) Dose (Rem)

LOCA 12.0 0.3 0.2 MSLB 0.4 <0.1 <0.1 SGTR 0.2 <O.l <0.1 LRA 0.7 <0.1 <0.1 FHA 2.4 0.1 <0.1 280

References (3.7-1) Letter from D. S. Cruden (Virginia Power) to NRC, "Virginia Electric and power Company, Surry Power Station Units 1 and 2, Safety Evaluation of Steam Generator Tube Rupture Accidents," Serial No.88-229, May 5, 1988.

(3.7-2) Letter from L. A. Walsh (Westinghouse Owner's Group Steam Generator Tube Uncovery Task Team) to R. C. Jones NRC, "Westinghouse Owner's Group Steam

. Generator Tube Uncovery Issue," OG-92-25, March 31, 1992.

(3.7-3) "LOCADOSE NE319, A Computer Code System for Multi-Region Radioactive

    • . *Transport-and --Dose- Calculation; "--Theoretical- -Manual,- -Revision 3, July 1990, Bechtel Power Corporation, San Francisco, CA.

(3.7-4) "LOCADOSE NE319, A Computer Code System for Multi-Region Radioactive Transport and Dose Calculation," User's Manual, Revision 3, July 1990, Bechtel Power Corporation, San Francisco, CA.

  • * (3.7-5) "LOCADOSE NE319, A Computer Code System for Multi-Region Radioactive Transport and Dose Calculation," Validation Manual, Revision 3, July 1990, Bechtel Power Corporation, San Francisco, CA.

(3.7-6) U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, "Standard Review Plan," NUREG-0800, Revision 2, July 1981.

(3.7-7) Regulatory Guide 1.4, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Pressurized Water Reactors, "

Rev. 2, June 1974.

(3. 7-8) K. G. Murphy and K. M. Campe, "Nuclear Power Plant Control Room Ventilation System Design for Meeting General Design Criterion 19," 13th ABC Air Cleaning Conference, August 1974.

(3.7-9) U.S. Nuclear Regulatory Commission, office of Standards Development, "Design, Testing, and Maintenance Criteria for Post Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light-Water-Cooled Nuclear Power Plants," Regulatory Guide 1.52, Revision 2, March 1978.

(3.7-10) Letter from W. L. Stewart (Virginia Power) to U.S. Nuclear Regulatory Commission, "Virginia Electric and Power Company, Surry Power Station Units 1 and 2, Control Room Habitability, Operator Dose Assessment," Serial Number 89-381, June 1989.

281

(3.7-11) Letter from C. M. Stalling (Virginia Power) to U.S. Nuclear Regulatory commission, "Response to Request for Additional Information," Serial Number

  • (3.7-12) 045A/020177, May 1977.

U.S. Nuclear Regulatory Commission, Regulatory Guide 1.25 (Safety Guide 25),

"Assumptions Used for Evaluating the Potential Radiological Consequences of a Fuel Handling Accident in the Fuel Handling and Storage Facility for Boiling and Pressurized Water Reactors," March 23, 1972 .

. (3. 7-13) "Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents

  • for the* Purpose*- of Compliance *-with -lOGFR *Part 50,, Appendix I,'" ,Regulatory Guide 1.109, Revision 1, October 1977.

282

3.8 Additional Design Basis & Programmatic Evaluations 3.8.1 Limiting PSV Inlet Conditions During Feedline Break The analysis of a main feedline break accident is not described in the UFSAR since Surry Power Station was licensed prior to the issuance of Regulatory guide 1.70, Rev. 1; this event was not included in the original licensing basis analysis. However, there is a possibility of an extended period of water discharge through the pressurizer safety and relief valves following this transient, and NUREG-0737, Item Il.D.1 requires that all plants consider this accident in determining the-limiting-valve inlet-fluid conditions;*Thus,:-Virginia Power analyzed the Feedline Break accident in response to an August 13, 1985 NRC request for additional information related to NUREG-0737, Item Il.D.1 - Performance Testing of Relief and Safety Valves. The results of those analyses (3.8.1-1) are summarized below.

A main feedline break is defined as a break in the main feedwater piping which: a) interrupts the addition of main feed water to the steam generators and b) results in the discharge of secondary inventory from the affected generator to the containment. A main feedline break is basically a loss of heat sink transient but can have some of the characteristics of a steam line

  • break, i.e., an initial cooldown resulting from the secondary depressurization prior to the faulted steam generator drying out. The feedline break accident for Surry has been analyzed using the Surry two loop model developed for use with the RETRAN code (3.8.1-2). Two cases were analyzed:

Case I: Main Feedline Break without Power Operated Relief Valves and without Safety Injection Case II: Main Feedline Break with Power Operated Relief Valves and with Safety Injection Case I was used to define the limiting inlet fluid conditions for the safety valves since it did not take credit for operation of the PORVs. Both cases were considered in defining the limiting conditions for the PORVs. The EPRI test results were used to define conservative critical flow models for the safety and power operated relief valves. The opening and closing characteristics observed in the test were also factored into the definition of conservative valve characteristics 283

for the analysis. The result of the analysis demonstrated that both the pressurizer safety and relief valves experience transient pressure and fluid conditions much less severe than those to which the valves in the EPRI test program were exposed. This analysis was performed at 102%

of the uprated core rated power of 2546 MWt, and thus bounds the proposed condition.

References (3.8.1-1) Letter from W. L. Stewart (VP) to the USNRC, "Virginia Electric and Power Company, Surry Power Station Units 1 and 2, Status of NUREG-0737, Item 11.D.1 ", Serial No.87-608, November 13, 1987.

(3.8.1-2) ** VEP-FRD-41A;--***!!Reactor-,System --Transient-*-Analysis

  • Using the* RETRAN Computer Code," Virginia Electric and Power Company, May 1985.

(3.8.1-3) EPRI-NP-2628-LD, "PWR Safety and Relief Valve Test Program, Safety and Relief Valve Test Report, " September 1982

  • 284

3.8.2 Analyses For Compliance With 10 CFR SO, Appendix R

  • The* Virginia Power calculations which have been performed in support of the Appendix R evaluation (Ref. 3.8.2-1) have been reviewed for potential impact from the proposed core uprating. The calculations involve: boration requirements for bringing the reactor to a shutdown condition, assumptions regarding RWST concentration, values of boron worth and core reactivity (as functions of temperature), available auxiliary feedwater volume until RHR can be initiated, loss of charging pump scenarios. Each calculation assumed key safety parameter values which bound the core and-system characteristics under- the-uprated-conditions.

This evaluation has confirmed that the existing Virginia Power NSSS transient analyses associated with Appendix R fire protection assume conditions which bound those associated with the uprating and thus remain applicable for the proposed conditions.

References:

(3.8.2-1) 10 CFR 50 Appendix R Report, Surry Power Station Units 1 and 2, Revision 11, November 1993 .

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3.8.3 Mitigation of Anticipated Transient Without Scram In order to comply with the ATWS Rule, 10 CFR 50.62, Surry Power Station installed ATWS Mitigating System Actuation Circuitry (AMSAC). AMSAC provides initiation of auxiliary feedwater and turbine trip on low-low steam generator level via circuitry that is diverse from the reactor protection system.

Based on a review of the generic AMSAC System design basis, it is concluded that the existing AMSAC design -is -adequate- for- uprated- conditions.*-** The-AMSAG arming setpoint of-37 % will be rescaled, if necessary, to reflect the equivalent first stage pressure for nominal uprate conditions, consistent with the current design philosophy .

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3.8.4 Shutdown Operations

  • An evaluation of the impact of the proposed core uprating conditions upon the technical basis for shutdown operations has been performed. Virginia Power has responded to the issues raised in Generic Letters 87-12 and 88-17 (3. 8 .4-1 )(3. 8.4-2) and in NUREG-1449 (3. 8.4-3) concerning loss of decay heat removal by implementing an extensive set of administrative controls and abnormal procedures to ensure adequate decay heat removal capability during shutdown conditions. These changes include upgraded abnormal procedures and detailed operations surveillance* procedures which-define- the-minimum configuration requirements for minimizing the potential for as well as dealing with the consequences of a loss of the Residual Heat Removal system at shutdown conditions.

These procedures are supported by a detailed series of thermal-hydraulic calculations related to various *loss of* RHR .. phenomena. Core decay heat is a key safety parameter in these calculations. The calculations are based on a conservative application of the 1979 ANS decay heat standard. Initial reviews indicate that there is adequate conservatism in the implementation of the decay heat values used to absorb the effects of power uprate on the decay heat levels.

This will be confirmed with a more detailed review prior to uprating implementation, and any

  • required changes to the technical calculations and the supported procedures will be made at that time.

References (3.8.4-1) USNRC Generic Letter 87-12, "Loss of Residual Heat Removal (RHR) While the .

Reactor Coolant System is Partially Filled," July 9, 1987.

(3.8.4-2) USNRC Generic Letter 88-17, "Loss of Decay Heat Removal," October 1988.

(3.8.4-3) NUREG-1449, "Shutdown and Low-Power Operation at Commercial Nuclear Power Plants in the United States, Final Report", September 1, 1993 .

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3.8.5 Emergency Condensate Storage Tank Sizing Evaluation

  • The current Basis Section for Technical Specification 3.6 states that the minimum ECST volume of 96,000 gallons established in TS 3.6.B.2 is adequate to maintain the unit at hot shutdown for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This basis is also stated in UFSAR Section 10.3.5. The adequacy of the 96,000 gallons in meeting this 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> criterion has been reconfirmed for the uprated core power of 2546 MWt.

In Reference (3.8.5-1), it was stated that the ECST volume is also adequate to support 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at hot shutdown followed by- a -6 hour-cooldown -to -residual -heat -removal system (RHRS) operating conditions, i.e. 350°F. The revalidation calculation also examined the cooldown and concluded that the current TS volume will support 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at hot shutdown followed by a 4 hour-cooldown for core uprate conditions. This represents a 50°F/hr cooldown rate, which is within current administrative cooldown limits.

The Basis for Technical Specifications 3.6 is being revised to indicate that the specified minimum volume is sufficient for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of residual heat removal or will maintain one unit at hot shutdown for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, followed by a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> cooldown to 350°F. There is presently no

  • cooldown capability stated in the Technical Specification basis.

The resulting cooldown capability is consistent with that documented for the North Anna units.

The approach of determining a revised capability (assuming the same minimum tank volume) was chosen versus increasing the required minimum volume.

References (3.8.5-1) Letter from R.H. Leasburg (Vepco) to H. R. Denton (USNRC), Serial No. 367A, "Virginia Electric and Power Company, NUREG-0737 Response- Revision 3 Corrections," Attachment B, "Auxiliary Feedwater System Design Basis, Surry Units 1 and 2," July 13, 1982.

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3.8.6 RWST Boron Concentration Requirements

  • Consideration was given to the effects of an increased core power level on the following safety criteria related to RWST boron concentration for Surry Unit 1 and 2:

(a) The Boric Acid Storage Tank inventory must be sufficient to bring the unit to Cold Shutdown under postulated adverse conditions.

(b) The Containment Spray (CS) and Recirculation Spray (RS) pH must be within the range of the current licensing analyses to ensure adequate post-LOCA iodine removal from the containment atmosphere,- *and

  • to -avoid* -stress** corrosion *cracking
  • of equipment within containment.

(c) Following a LOCA, the boron concentration of the sump must be sufficient to ensure the reactor core remains shutdown following the blowdown and reflood phases of the event.

(d) The Emergency Operating Procedures must specify a conservative hot-to-cold leg Safety Injection (SI) recirculation switchover interval to avoid reaching the solubility limit of boric acid in the core water, and potential deposition of the boric acid on the core.

The existing calculations which demonstrate that each key criterion is met have been evaluated for potential effect from the proposed uprating. The key safety parameters in each calculation have been validated to equal or bound the value associated with uprated operation. The existing calculations thus remain valid for uprated operation of Surry Unit 1 and 2 .

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3.8. 7 Analyses for Compliance with Station Blackout Rule, 10CFR50.63 In order to comply with 10CFR50.63, work is currently in progress at Surry Power Station installing an Alternate AC (AAC) diesel-generator and supporting equipment. Once completed, Surry will be in compliance with I0CFR50.63.

The analyses which have been performed in support of the design have been reviewed to evaluate the impact of core uprating on compliance with the SBO rule. This evaluation included a review of 10CFR50.63, Reg.-Guide-l-.155,-NUMARC-87-00, *and *Surry Design Change Package 92-052-3, Alternate AC (AAC} Diesel Generator Installation.

The evaluations reviewed the affects of loss of ventilation both inside and outside containment, the availability of instrumentation and controls, the ability to isolate containment, the factors which determine offsite power design characteristic group, the factors which determine the classification of the emergency AC power configuration, procedure impact, required condensate inventory, station battery capacity, and the availability of compressed air.

This evaluation confirmed that core uprating will not adversely impact the station's compliance with I0CFR50.63 .

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4.0 Systems, Structures and Components Evaluation 4.1 RCS Component and Fluid Systems Evaluation 4.1.1 Reactor Ves.sel To assess the impact of the core uprating on the reactor vessel design and operation, the vessel design specification, stress report, and fracture mechanics analyses were reviewed. The review verified that the existing reactor vessel design specification remains bounding and the only change which affects the reactor vessel stress report is the reduction in vessel/core inlet temperature (TcoJ from*543.0°F to-54Q.4C?F. *The vessel outlet-temperature remains at 605.6°F and the zero load temperature remains at 547.0°F. Therefore, the regions of the vessel which are not in contact with -the reactor coolant at the vessel/core inlet temperature during normal plant operation (i.e. outlet nozzles) are unaffected by the uprating. The regions of the reactor vessel which are in contact with the reactor coolant at T cold during normal plant operation were evaluated for the effects of the reduction in TCXJ!d, These regions were the main closure, control rod drive mechanism (CRDM) housings, inlet nozzles, vessel shell, core support pads and instrumentation tubes .

  • The reduction in T cold manifests itself as a modification to the plant loading and plant unloading design transients. These transients are defined as the variations encountered as the reactor cycles between no load conditions and full power. During the plant loading transient, the temperature of the reactor coolant in the reactor vessel is assumed to vary from the initial zero load temperature (547°F) to normal operating temperature (either Toold or TmJ. The plant unloading transient is the reverse of the plant loading transient as the temperatures in the vessel vary from normal operating temperature back to no load temperature. Therefore, the reduction in Toold from 543.0°F to 540.4 °F increases the temperature change in the Toold regions of the vessel during the plant loading and plant unloading from 4.0°F to 6.6°F so that the transients become more severe.

Evaluations to assess the effects of the Toold reduction were performed in two parts: 1) primary plus secondary stress intensity range evaluation and 2) fatigue analysis. The primary plus secondary stress intensity ranges for the Toold reduction were evaluated for each region by comparison of the plant loading and unloading transients with the plant heatup and cooldown transients which are analyzed in the Surry reactor vessel final ~tress report.- Since plant loading 291

and unloading with the reduced Toold constitutes a 6.6°F temperature change in a twenty minute period, the rate of change of temperature is only 20°F/hr. The plant heatup and cooldown

  • transients exhibit a temperature change of 477°F at a rate of change of 100°F/Hr. With such a disparity in the magnitudes and rates of temperature change, the plant heatup and cooldown primary plus secondary stresses envelope the corresponding plant loading and unloading stresses.

Therefore, there is no change in the reported maximum range of primary plus secondary stress intensity in any of the affected regions.

The maximum ranges of stress intensity in the affected regions of the reactor vessel remain as follows:

Table 4 .1.1-1 Location Maximum Range ASME Code Limit 1P.§.il (psi) 1968 Winter Main Closure

1. Stud 84,540 110,250
2. Closure head flange 53,564 80,100 3
  • Vessel flange 40,720 80,100 CRDM Housing 53,812 69,900 Inlet Nozzle 53,757 80,100 Shell Wall Transition 32,488 80,100 Bottom Head-to-shell Juncture 32,736 80,100 Core Support Pads 27,177 69,900 Shell Adjacent to Core 29,567 80,100 Support Pads Instrumentation Tubes 56,531 69,900 The fatigue analysis was performed by calculating the 'skin effect' thermal stresses for the critical locations and multiplying the stresses by an appropriate stress concentration factor and an additional factor of 2.0 to account for temperature decrease and increase during plant loading and plant unloading, respectively. Since there is no pressure variation associated with the transients, the 'skin effect' thermal stresses calculated are assumed to makeup an entire peak stress range. The resulting alternating stresses for the calculated ranges were then compared to 292

the endurance limits defined by the fatigue curves in Section m of the ASME B&PV Code, 1968 Winter. This comparison confirmed that the cumulative fatigue usage factors reported in the original Surry Reactor Vessel stress report remain bounding.

The maximum usage factors for the affected regions remain as follows:

!rable 4.1.1-2 Location Maximum Ranqe ASME Code Limit 1968 Winter Main Closure

1. Stud 0.6365 1.0
2. Closure head flange 0.0052 1.0
3. Vessel flange 0.0058 1.0 CRDM Housing 0.1951 1.0 Inlet Nozzle 0.01122 1.0 Shell Wall Transition 0.00067 1.0 Bottom Head-to-shell Juncture 0.00187 1.0
  • Core Support Pads Shell Adjacent to Core
  • Support Pads Instrumentation Tubes 0.0000 0.01029 0.06146 1.0 1.0 1.0 A separate review was performed to assess the reactor vessel fracture mechanics. It was based on the following inputs:
1) The design fluence was based on a core power of 2546 MWt.
2) Design transients are those contained in Westinghouse System Standard Design Criteria.
3) The same licensing basis that was ~riginally applied is applicable. Originally, heatup and cooldown curves per ASME ill Appendix G were generated, but an Appendix G analysis to cover the balance of the normal and upset conditions was not required.

As a result, the new operating conditions were judged to have no significant effect on the structural integrity of the reactor vessel, and it continues to comply with all applicable design criteria.

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4.1.2 Reactor Ves.sel Internals

  • The reactor vessel internals were reviewed and found to be acceptable for the uprated core power operating conditions as part of the previous evaluation performed to assess the Surry Improved Fuel design.

4.1.3 Control Rod Drive Mechanism The Control Rod Drive-Mechanism-(CRDM) original design specification and'stress report were reviewed to determine if the uprated operating conditions impacted the function or integrity of the CRDMs. The uprating reduces the cold leg temperature by 2.6°F and has no affect on the hot leg or zero load temperatures. Based on these insignificant temperature changes and the continued applicability of Westinghouse Design Criteria 1.3, Rev. 1, the present thermal and structural analysis bound the uprated conditions, and the CRDMs continue to be in compliance with codes and standards under which the Surry Units are currently licensed.

4.1.4 Reactor Coolant Pumps At the uprated core power, the pump inlet temperature at 100 percent power will decrease from 543.0°F to 540.1 °F. A change in the Reactor Coolant Pump (RCP) inlet temperature of this magnitude (2.9°F) while maintainin~ the currently applicable design transients has an insignificant effect on the pressure boundary stresses. A review of the existing design specification verified continued compliance with the Westinghouse and industry codes and standards in effect when Surry was originally licensed. No modifications to equipment or operating limits are needed to operate the pump at the uprated conditions. The Design Specification and the RCP Outline Drawing were reconciled to the uprated conditions with 7 %

steam generator tube plugging.

4.1.5 Steam Generators The steam generator evaluation for the core power uprating was divided into three sections - a structural evaluation, a thermal hydraulic evaluation and a corrosion evaluation.

294

The structural analysis performed for the Model 5 lF steam generators during the Steam Generator Replacement Program were based on the applicable Westinghouse Design Criteria.

,Review of this analysis for the uprated core power with 7% tube plugging verified that the components continue to remain in compliance with the ASME Code, Section m requirements.

A revised equipment specification was issued to document the uprated operating conditions.

A thermal hydraulic analysis was performed to evaluate the effects of the core uprating with 7 %

tube plugging on the performance of the Surry Units 1. and 2 steam generators. The higher power.level and tube plugging*willincrease the loading on-the moisture'separators significantly..

While this is not a safety concern, hardware modifications have been performed on separators in Unit 1 to meet the Westinghouse recommendation of 0.25 % moisture carryover at full uprated power. Moisture separator modifications were also performed on the Unit 2 "A" steam generator; however, no modifications have been made to the ~B" and "C" generators. A moisture carryover test has been performed to obtain performance information on the Unit 2 moisture separators. Based on the results of the tests, hardware modifications to the "B" and "C" steam generators may also be necessary to ineet the recommended 0.25 weight percent moisture carryover at full uprated power.

Tube plugging and the accompanying reduction in steam pressure tend to enhance the stability of the steam generators slightly while the increased power level has the opposite effect. The s~bili_ty factor calculated for the steam generator with the uprated operating parameters and tube plugging is similar to that for the steam generators with the original operating conditions. Based on these factors, the Surry 1 and 2 steam generators will operate in a stable manner after core uprating.

Recently, Surry Unit 2 steam generator "C" experienced some operational limitations related to

. tube support plate broach hole blockage. These limitations were manifested as level oscillations which occurred during higher power operations. The oscillations subsided when power level was reduced. For a time, this condition prevented Unit 2 from reaching* 100% (existing license) power. Inspections of Unit 1 steam generators. revealed a similar, although less advanced blockage condition.

295

To restore stable full power operation, Steam Generator Chemical Cleaning (SGCC) has been performed on the Unit 2 steam generators. Unit 1 performance is being monitored .

. The propensity for a steam generator tube rupture due to flow induced vibration (such as the North Anna tube rupture) was specifically evaluated for the Surry steam generators at the uprated conditions. The 51F steam generators currently installed in Surry Units 1 and 2 have stainless steel the support plates which essentially eliminate the potential for tube denting at the support plates. Since tube denting is a prerequisite for the flow vibration type tube failure which occurred at North Anna, the propensity Jor this kind of rupture in *the Surry steam generators is not significant for either the current or uprated operating conditions.

The uprating for Surry Units 1 and 2 was evaluated with regard to steam generator corrosion.

The evaluation indicated that operation at the uprated condition within chemistry guidelines would* not affect the propensity for steam generator corrosion.

In summary, the evaluations verified that uprated operation with tube plugging will not significantly affect the operating characteristics of the steam generators with respect to flow

  • distribution, flow induced vibration, structural integrity and corrosion. Therefore, the Surry steam generators remain in compliance with all currently established safety criteria at the uprated conditions. The moisture carryover at the uprated conditions is expected to increase, but this ope~tional issue is being addressed by moisture separator modifications.

4.1.6 Pressurizer The pressurizer was reviewed to identify any impact from the uprated conditions. The review verified that the* existing pressurizer stress report bounds the operating conditions, and the existing analyses remain applicable for the pressurizer components; A separate review was performed to assess the adequacy of the pressurizer spray, safety and power operated relief valves for operation at uprated core power. Results indicate that the presently installed valve capacities are sufficient to perform their intended functions at the

.uprated condition .

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Reviews of the pressurizer surge line and the pressurizer safety valve discharge piping, and the pressurizer relief tank indicated that all three remain in compliance with the currently established criteria.

4.1. 7 Piping and Supports A review of the thermal and fatigue-related structural analysis for the Surry reactor coolant loop piping and supports at uprated core power was conducted. It was determined that:

1. All piping loads, displacements and.stresses resulting.from the normal,-thermal and OBE seismic loadings on the loop remain within engineering tolerances of the current values.
2. All support loads are within engineering tolerances of the loads originally transmitted.

The main loop isolation valves and the pressurizer safety and relief System Valves were evaluated for operation at the uprated conditions. Since the uprated transients are bounded by the original equipment specifications, there are no adverse effects on the integrity, operability and qualification of the valves, and the requirements of the applicable original codes and standards are met.

Therefore, the Reactor Coolant Loop piping and supports continue to comply with all currently established criteria for Surry Units 1 and 2.

4.1.8 Auxiliary Valves and Pumps The Surry Units 1 and 2 auxiliary valves and pumps (RHR, CVCS, and SI Systems) listed below were procured to the requirements of equipment specifications which incorporated the original Surry design transients. Since these transients continue to bound the uprated conditions, the effect of the uprating on these components is already bounded. Therefore, the uprated pressure and temperature requirements are already enveloped relative to the integrity, operability and qualification of the auxiliary valves and pumps.

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Table 4.1 8-1 AUXILIARY PUMPS AND VALVES VALVES PUMPS Manual "T" and "Y" Globe Valves Boric Acid Transfer Pumps Diaphragm Valves High Head SI (Charging)

Pumps Gas Process Valves Residual Heat Removal Pumps Manual Gate and Self-Actuated Check Low Head SI Pumps Valves Auxiliary Relief Valves Hydrotest Pumps Motor Operated Valves Control Valves Butterfly Valves 3/4 to 2 Inch Manual Globe and Check Valves Volume Control Tank Valves Self-Contained Nitrogen and Hydrogen Pressure Regulators 4.1.9 Auxiliary Heat Exchangers and Tanks A review was made to verify that auxiliary heat exchangers (RHR, CVCS, and SI systems) will meet their original functional requirements with the plant operating at uprated core power. The analysis was made using design data for equipment that is currently* installed in the plant. On this basis, the flow rates and heat transfer capability of heat exchangers rejecting heat into the component COQling water were assumed

  • to be the same for uprated core power operating conditions as for the current core power operating conditions. It was also assumed that component cooling water would be provided at the same temperatures for uprated core power operations as for similar operations at the current core power.

The review verified that the heat exchanger heat duties at the uprate conditions are bounded by the current design load. Results of the review were also used to establish Component Cooling System heat loads for the Balance of Plant review.

The Surry Units 1 and 2 auxiliary tanks were also verified to be adequate based on a comparison

.. of the original design parameters and transients and the uprated parameters. Since the changes in the parameters were insignificant, it is concluded that the auxiliary tanks are adequate and will 298

perform as originally designed for the safe operation of Surry Units 1 and 2 at the uprated conditions.

4.1.10 Chemical and Volume Control System The eves is comprised of two subsystems: 1) charging and letdown and 2) makeup. The purpose of the charging_and letdown subsystem is to remove, purify and return borated.reactor coolant or demineralized (primary grade) water to the RCS to control the RCS water volume.

The makeup subsystem provides the means to maintain, dilute or concentrate the boric acid solution entering the RCS via the charging and letdown subsystem.

-The letdown line in the Chemical and Volume Control System is designed for a reactor coolant loop cold leg temperature as high as 560°F. This exceeds the steam generator outlet temperature for the uprated power level (540.2°F). Therefore, the existing design conditions represent an upper bound for the CVCS piping and heat exchangers, and the existing equipment is therefore adequate for the uprated conditions. Also, the currently applicable Technical Specifications and setpoints for the boric acid tanks remain acceptable for uprated operation; the refueling water storage tank level setpoint limits for recirculation mode transfer are being changed. These setpoints guarantee that adequate shutdown margins can be provided for the reactor at the uprated conditions, since the original boration requirements for reactor shutdown

  • remain applicable.

In summary, the impact of the core uprating on the Surry Units 1 and 2 CVCS is* negligible, and the system will continue to comply with the currently applicable codes, standards and criteria.

4.1.11 Residual Heat Removal and Safety Injection Systems The Safety Injection System (SI) is composed of three major components: accumulators, high-head safety injection pumps and low-head safety injection pumps. The purpose of the system 299

... is to provide emergency borated cooling water to the RCS in the event of a small or large break in the RCS system.

The Residual Heat Removal (RHR) System is a low pressure, low temperature system used to remove decay heat, generated in the core, during plant cooldown and refueling operations. The RHR System is also used to transfer water from the refueling cavity and transfer canal to the refueling water storage tank following a refueling operation.

The cooldown analysis for the RHR System is not significantly affected by the uprating. The cooldown of the RCS from 350°F at four hours after reactor shutdown to 140°F can be achieved at 11.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after shutdown with two RHR trains operating at 4000 gpm each, and the cooldown from 350°F at four hours after reactor shutdown to 200°F can be achieved in 21. 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after shutdown with a single RHR train operating. These results are very similar to the previous analysis results and are within the design and licensing bases of the Surry plant.

Therefore, the RHR System is acceptable for use as is at the core uprate power level.

Safety injection flow.rates used for the accident analyses reflect the as-built safety injection system, including any modifications which have been made since initial plant operation.

Acceptable results for the large break LOCA accident analyses at the core uprate power level were obtained using this SI flow data, hence no changes to the safety injection system are

, required in order to implement the uprating of the core. The small break LOCA analysis has been completed to confirm this conclusion.

4.1.12 Auxiliary Feedwater System The Auxiliary Feedwater (AFW) System is used to prevent core damage and RCS overpressurization in the event of loss of normal feedwater by automatically providing a reserve source of feedwater to the steam generators. The system also provides a means of cooldown for the RCS following plant transients that result in the initiation of safety injection.

300

For the uprated conditions, the minimum flow requirement for the Auxiliary Feedwater (AFW)

System is 500 gpm at a pressure of 1133 psia. The applicable safety analyses were reviewed and were determined to bound the limiting case (loss of normal feedwater scenario). This analysis was based on the unit operating at 102 % of the uprated power. Therefore, the core uprating has no impact on the AFW system.

4.1.13 Sampling Systems The Primary Sampling System is used to monitor the chemical and radiochemical content of the RCS and other primary systems. The system is divided into normal and post-accident subsystems and allows sampling of various points in the RCS, RHR, Boron Recovery and

.. Primary Grade Water Systems.

The Sampling Systems were reviewed and found to be in compliance with all applicable codes and standards. The change in RCS temperature is negligible and has no significant effect on the sampling systems piping and components. No plant or procedure modifications will be required.

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4.2 Balance of Plant Systems Evaluation 4.2.1 Ma~ Steam System The main steam design pressure of 1085 psig and design temperature of 560°P bound the uprated steam generator outlet condition of 785 psig and 516°P and the safety valve setpoint of 1085 psig and 560°F.

The main steam safety valves (MSSVs) have a total relieving capacity of 11,527,362 lb/hr. The Westinghouse engineering safeguards core uprate design steam flow is 11.26 x 1()6 lb/hr. For compliance of R.G. 1.49, this steam flow is increased by 2 percent. The required relieving capacity of the MSSVs is therefore 11,485,200 lb/hr (11.26 x 106 x 1.02). The MSSVs have adequate capacity to relieve the core uprate steam flow plus a 2 percent margin.

The uprated steam flow of 3,753,333 lb/hr per steam generator steam header is less than 1.2 percent above the design flow of 3,711,100 lb/hr for the main steam trip valve and main steam nonretum valve. The present steam generator main steam outlet design condition of 785 psia and 516°P is essentially unchanged as a result of the core uprate (reference Table 2.1-1). The small increase in steam flow will produce a less than 1 psi increase in pressure drop across the valves. These valves remain adequate for the uprated conditions.

4.2.2 Extraction Steam System The uprat~ operating temperature for the third point extraction line is above the design value.

The design value for temperature is 325°P. The uprated third point extraction line temperature is 368 °P. Pipe stress analysis verified that at the uprated temperature, sufficient offset of piping is available to absorb the increased temperature. The uprated operating pressure and temperature for the first point extraction lines are 1 psig and 1°P, respectively, above design. The stress analysis was reviewed and operation at uprated conditions is acceptable. The uprated operating pressures and temperatures for the second, fourth, fifth, and sixth point extraction lines were all below their pipe stress design values.

302

The nonretum valves (NRVs) installed in the first through fourth point extraction lines are adequate for the uprated pressures, temperature and flow. The design flow rate for the first

  • point extraction NRV is 815,000 lb/hr. The uprated first point extraction flow is 880,564 lb/hr.

Correspondence with the NRV vendor indicates that the uprated steam flow will increase the pressure drop across the valve by 0.3 psi. This pressure drop is minimal and, therefore, the valve is adequate for the uprated* conditions.

The uprated extraction pressures are within the shell side design pressures for all of the feedwater heaters. It 'Yas conservatively assumed that the pressure at the turbine extraction nozzle was equivalent to the operating pressure at the feedwater heater shell without considering pressure drop in the extraction lines.

Refer to Table 4.2.2-1 for a summary of design and core uprate conditions for the extraction steam piping as related to pipe stress. Table 4~2.2-2 compares the design and core uprate conditions for temperature, pressure and flow for the NRVs. Table 4.2.2-3 shows the shell side pressures for design and core uprate conditions for *the first through sixth point heaters.

TABLE 4.2.2-1 EXTRACTION STEAM PIPING STRESS ANALYSIS DESIGN CONDITIONS Design Core Uprate Extraction Line Conditions Conditions T (OF) p (psig) T (OF) p (psiq)

I.st Point Heater 450 410 451 411 2nd Point Heater 385 195 383 187 3rd Point Heater 325 85 368 79 4th Point Heater 275 30 269 26
  • 5th Point Heater 215 1 214 1 6th Point Heater 180 -7.2 178 -7.5
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Desicm Conditions Core Uprate Conditions Line T(°F) p (psig) Flow T (OF) p (psig) Flow (lb/hr) (lb/hr) lat Point 450 410 815,000 445 392 880,564 2nd Point 382 195 652,000 378 177 623,610 3rd Point 325 82 235,250 368 75 230,778 4th Point 272 28 236,000 265 24 236,286 5th Point NO NRV INSTALLED 6th Point NO NRV INSTALLED TABLE 4.2.2-3 FEEDWATER BEATER SHELL SIDE PRESSURES Feedwater Shell Design Core Uprate Heater Pressure* System Pressure Cosig) Cosig) 1st Point 475 411 2nd Point 225 187 3rd Point 110 79 4th Point 50 26 5th Point -14.7 to so 1 6th Point -14.7 to 50 -7.5

  • Shell design pressure based on new heater design. All new heaters to be installed prior to core uprating.

4.2.3 Auxiliary Steam System Auxiliary steam is normally obtained from the second point extraction line during plant operation and from the main steam system when the second point extraction pressure drops below the setpoint of the pressure reducing valve from the main steam system.

304

The pressure and temperature ratings of the piping and manual valves indicates that the second point extraction steam pressure and temperature, as determined by the uprated core heat balance,

  • are below the design ratings.

4.2.4 Condensate and Feedwater Systems The condensate/feedwater systems pressures__ and temperatures at uprate conditions were compared to present operating and design pressure and temperatures. There are insignificant changes to condensate/feedwater system pressure and temperature due to the uprating and these small changes are within the design capacities of the current system. The decrease in pressure is due to condensate/feedwater pump head characteristics and increased pressure drop at

  • increased flow rates.

The total Condensate and Feedwater System resistance was evaluated for the new flow rates pertaining to the core uprate. The steam generator pressure did not change. The overall increases are due to the greater friction losses at increased flow rates. However, it has been determined from the Condensate/Feedwater System calculation at uprated conditions that the existing pumps have sufficient head to overcome the increased total system resistance with two condensate and two steam generator feed pumps in operation at the uprated condition.

  • The net positive suction head available (NPSHA) at the suction of the condensate and feedwater pumps was evaluated at the uprated conditions. It was determined that sufficient NPSHA exists to allow acceptable operation at the uprated flow.

4.2.5 Feedwater Heaters Prior to the implementation of the Surry Core Uprate, the first through sixth point feedwater heaters and external drain coolers will have been replaced.

  • The evaluation of the feedwater heaters for the uprated conditions uses the design data of the new heat exchangers. The temperatures, pressures and flow rates used in the feedwater heater review were calculated.

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. The tube side pressures and temperatures at uprate conditions are below the design values. The tube side flows of the first through fourth point heaters and the external drain coolers are

  • -- approximately 1 percent above design flow. The increase in tube side velocities due to the increased flow is insignificant. The tube side flows of the fifth and sixth point heaters are below design flow.

The shell side design of the heat exchangers is acceptable for the uprated conditions. Reference Section 4.2.2.

The high and low pressure heater drain systems associated with the feedwater heaters are discussed in Sections 4.2.7 and 4.2.8.

4.2.6 Main Turbine An analysis was made of critical components of the turbine to determine their suitability for operation at the uprated conditions, which correspond to the original maximum calculated condition for the Surry units. The uprating was considered for a nominal turbine throttle pressure of 740 psia (essentially the same as the original design conditions) and an increased throttle pressure of 820 psia. The analysis consisted of performing calculations and a detailed review of all critical components with respect to design acceptance criteria to verify the mechanical integrity under the conditions imposed by the uprating.

The stationary parts reviewed included the high pressure and low pressure cylinders, blade rings, nozzle blocks, steam chests, high pressure blading, low pressure blading, piping and valves. The individual components suitability was reviewed for the uprated pressures, increased flows and higher pressure drops. A complete review of rotating components including high pressure and low pressure rotors and rotating reaction blading was conducted in both the high pressure and low pressure turbines .

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The results of the evaluation showed that for the:

1. Stationary Components - The design requirements for pressure vessels have not changed since the original design of these units. Therefore, the only significant impact on the pressure vessel parts related to the uprating is on the high pressure turbine for the case where the steam generator pressure is increased. The increased pressure for the HP turbine is less than the peak acceptable pressure for vessels of this type. The main steam inlet piping was also reviewed and found acceptable for the increased pressure.
2. Moisture Separator-Reheater - The moisture separator reheater vessel integrity should not be affected by the uprating or the increase in throttle pressure.
3. Control Stage Blading - The control stage stress levels were evaluated, and the overall results show that the uprating is acceptable.
4. High Pressure Turbine Reaction Blading - The high pressure turbine reaction blade stresses were calculated for the uprated conditions and were found to be acceptable.
5. Low Pressure Turbine Reaction Blading - The original design calculations for the Surry LP turbine blading established 2546 MWt as the maximum steam flow recommended for reliable operation. Westinghouse has completed a safety evaluation for operation of the units at the full uprated power. This evaluation showed that there would be no increase in the probability of turbine overspeed nor associated turbine missile production due to the uprating, and hence the turbines could continue to be operated safely at the uprated power levels.

4.2. 7 Moisture Separator and High Pressure Heater Drain System The high pressure heater drain pumps have been shown to develop sufficient total dynamic head (TDH) to operate at the uprated conditions. Uprated NPSHA has been evaluated at the pump suction and has been determined to be acceptable for pump operation.

The pressure drop (.u>) across the HP heater drain pump discharge level control valve (LCV) was calculated at uprated conditions. Using the t.P across the LCV and the system flow rate, it was determined that the LCV is adequate for the uprated flows .

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Table 4.2.7-1 compares the HP heater drain pump design data to the core uprate conditions and the required NPSH of the pumps to actual pump NPSH.

~ABLB 4.2.7-1 H.P. HEATER.DRAIN PUMPS

-Desicm. - Uprate Pumping Temp (PT) 380°F 378°F Specific Gravity at .872 .874 PT

.Vapor Pressure at PT 196 psia 191 psia Capacity at PT 7700 crom 7212 OPm Press .at Discharge 523 psia 553 psia Nozzle Press at Suction 198 psia 193 psia Nozzle TOH 325 PSi 360 psi

  • NPSHR 2.0 ft NPSHA - 26.02 ft 4.2.8 Low Pressure Heater Drain System The low pressure heater drain pumps have been shown to develop sufficient total dynamic head

- (fDH) to operate at the uprated conditions. Uprated NPSHA has been evaluated at the pump suction and has b~n determined to be acceptable for pump operation.

The pressure drop (AP) across the LP heater drain pump discharge level control valve (LCV) was calculated at uprated conditions. Using the AP across the LCV and the system flow rate, it was determined that the LCV is adequate for the uprated flows.

Table 4.2.8-1 compares the LP heater drain pump design data to the core uprate conditions and .

the required NPSH of the pumps to actual pump NPSH.

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  • TABLE 4.2.8-1 L.P. BEATER DRAIN PUMP Desion Uprate Pumping Temp (PT) 267 DF 265 DF Specific Gravity at .934 ~936 P.T.

Vapor Pressure at P.T. 40 psia 39 psia Capacity at P.T. 1155 onm 998 qpm Press at Disc Nozzle 542 psia 572 psia Press at Suction 42 psia 42 psia Nozzle TDH 500 psi 530 psi NPSHR - 2.0 ft NPSHA - 26.02 ft 4.2.9 Circulating Water System

  • The high turbine throttle flow occurring at uprated core conditions will result in higher low pressure turbine exhaust flows and resultant increased levels of heat rejection to the circulating water system. The outlet circulating water temperature increases less than 1 °F at uprated

. conditions. Heat rejection levels at the uprated 2546 MWt power level are 6 percent above the present 2441 MWt core power. The existing Virginia Power discharge permit will not be invalidated. The increase in rejected heat to the James River is within the current discharge permit limits.

4.2.10 Service Water System The Service Water System (SW) provides cooling water to the Component Cooling, Bearing Cooling and Recirculation Spray Systems heat exchangers, and other station heat loads such as air conditioning and Charging Pump cooling. The component and system reviews and accident

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analysis for the uprate are based on the existing service water flow rates, pressures and temperatures. The Component Cooling Water System normal operation heat load will be subjected to a minimal increase over the original design heat load from the Chemical and Volume Control System heat exchangers. The existing equipment is capable of rejecting the additional load. The Bearing Cooling Water System is not impacted by the core uprated conditions. The chilled water condenser, control room air-conditioning, and charging pump lube oil cooler are not subjected to increased heat load under the uprated conditions.

4.2.11 Component Cooling Water System

. The Component Cooling System (CC) is an intermediate cooling system that transfers heat from heat exchangers containing reactor coolant or other radioactive fluids to the Service Water System (SW). The major heat loads on the system are from the following sources:

  • Fuel Pit Cooling System
  • Chemical and Volume Control System Removes heat from letdown flow during power operation.

a Reactor Coolant Pump Seal Water Return

  • Neutron Shield Tank The review of the component cooling water system determined that the only increase in heat load during normal plant operation at uprate conditions was from the Chemical and Volume Control System (CVCS) heat exchangers. The maximum total heat load of the CVCS system is 20.2 x 1()6 Btu/hr for the uprate which is slightly higher than the existing maximum design heat load of 20.12 x 106 Btu/hr. The existing Component Cooling Water System heat removal capacity was designed to include additional loads which are no longer in use and therefore the system is adequate to accept the minimal increase in eves heat load.

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Virginia Power has replaced the original component cooling heat exchangers with new component cooling heat exchangers fabricated with titanium tubes. The new exchanger heat removal capacity is equal to the original exchangers (50,300,000 Btu/hr at specification data sheet design conditions).

4.2.12 Bearing Cooling Water System Based on data provided by Westinghouse, the existing cooling water design requirements for the turbine generator are adequate for the core uprating. The remaining bearing cooling water loads are not directly impacted by the core uprating. Therefore, the core uprating will not require an increase in the bearing cooling water design capacity.

The bearing cooling water heat exchangers were recently replaced with heat exchangers of larger heat removal capacity. The original heat exchangers were rated at 27,000,000 Btu/hr. The replacement heat exchangers are rated at 37,000,000 Btu/hr.

  • -4.2.13 Water Treatment System The purpose of the Water Treatment System is to produce, store and distribute high purity water for use in the primary and secondary systems. The Units makeup flow rates will remain unchanged for the uprated conditions.

The Units 1 and 2 flash evaporators have been decommissioned. The flash evaporators have been replaced with the reverse osmosis units. The reverse osmosis units are capable of providing the normal makeup during two-unit operation.

4.2.14 Boron Recovery System The Units 1 and 2 letdown flow rates remain unchanged for the uprated conditions. The boron recovery system is not impacted by the uprating .

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4.2.15 Fuel Pit Cooling System The fuel pit cooling system* consists of two 100 percent redundant capacity cooling loops, each loop has a design water flow rate of 4,200 gpm. Each fuel pit cooling heat exchanger removes

34. 75 x 1()6 Btu/hr while maintaining the pool at 170°F when provided with 1322 gpm of
  • component cooling water at 105°F.

The heat load for the fuel pit cooling system was calculated in association with the replacement of the component cooling water heat exchangers. The total heat load calculated in accordance with Standard Review Plan 9.13 equals 19.56 x 1()6 Btu/hr for the uprated conditions. The core uprate will not impact the fuel pit cooling system.

4.2.16 Containment Depresmrization.

Containment pressure following a Loss of Coolant Accident (LOCA) is controlled and reduced by the Containment Spray (CS) and Recirculation Spray (RS) Systems. The CS system, in conjunction with the RS system, depressurize the containment to subatmospheric and remove iodine from the containment atmosphere during a LOCA. Major components in the CS system include the pumps, spray nozzles, and the refueling water storage tank. The purposes of the RS system are to aid the CS system in cooling and depressurizing the containment during and

.following a LOCA, assisting the containment vacuum system in maintaining containment pressure subatmospheric indefinitely after a LOCA, and providing long-term cooling for the emergency core cooling system water for effective core cooling.

A review of the containment LOCA analyses, based on system design and existing component capacities, verified that the containment peak pressures and depressurization times are within acceptable levels. The core uprate conditions will not require any plant modifications or operating restrictions.

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4.2.17 Steam Generator Blowdown System The current maximum blowdown rate of 70 gpm per generator (80,800 lb/hr total for three generators) was used in calculations for the uprated conditions. The uprate conditions (steam generator blowdown outlet nozzles) are 770 psig and 516°F. The current conditions are 775 psig and 515°F. The design of the piping is 1085 psig and 560~F. Therefore, the uprate will have no impact on the Steam Generator BlowdoWil System ..

4.2.18 Containment Air Recirculation and Plant HVAC The original design basis of the Containment Air Recirculation System was for a heat load of 3.6 x 1()6 Btu/hr. However, as part of the Containment Cooling System modification package, the heat load is presently identified as 6.7 x 1()6 Btu/hr, which assumes:

1. 2 gpm continuous reactor coolant leakage
2. 1000 lb/hr continuous main steam leak.
3. Full power operation Each mechanical chiller unit is rated at 6.6 x 1()6 Btu/hr, when supplied with 95°F service water.

Thus, when the mechanical chilled water system is in operation and is using the intermediate chilled component cooling water coolers (as is the standard mode of operation), a containment average air temperature of 1 l 7°F is obtained with one chilled water cooler and 107°F when using two chilled water coolers.

Approximately 70 percent of the containment heat load is attributed to sensible heat loads from various piping and equipment inside the containment. Westinghouse estimated that the core uprate will result in a less than 1 percent increase in these loads as a result of the reactor coolant temperature.

The Control Rod Drive Mechanism (CRDM) Recirculation Air System includes three pairs of fans to provide direct cooling for the CRDMs. One fan of each pair takes suction in the vicinity

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of the CRDMs and directs air through a cooling coil to the reactor coolant pump room. A review of the sources of heat loads and ventilation requirements indicates that power uprating will not have any effect on this system. Therefore, the existing CRDM Recirculation Air System is adequate to support power rerating.

The Containment Dome Air Recirculation System consists of four fans that operate to prevent stratification of hot _air in the top _of the contain,:n.ent ~tructure. A review of_the system design and operation indicates that power uprating will not have any effect on this system. Therefore, the existing containment dome air recirculation system can support power uprating.

The Containment Ventilation Purge System supplies fresh air to the containment when the reactor is shut down and entry to the containment is required. Fresh outside air is supplied by the containment purge supply fans and exhausted by the safety-related filtration system exhaust fans via a filter unit and then vented to the atmosphere under monitored conditions. The safety-related design bases of the system include containment isolation design provisions applicable to the purge isolation valves. However, the inside and outside isolation valves in the containment ventilation purge system are maintained closed per Technical Specifications whenever the Reactor Coolant System temperature exceeds 200°F. The functions of the purge system are not significantly affected by power rerate, as they are dependent upon the cold shutdown containment ambient conditions. Thus, the Containment Ventilation Purge System is adequate

  • for power rerate.

The Fuel Building* Heating, Ventilating, and Air Conditioning (HVAC) System provides conditioned outside air for ventilation, cooling and heating of the fuel building, collects and processes airborne particulates following a postulated fuel handling accident, provides* a suitable ambient temperature for the fuel pit cooling water pump motors and provides supplemental fuel building heating. A review of the sources of heat loads, ventilation requirements, heating requirements and fission product source terms indicates that power uprating will not adversely impact this system. Therefore, the existing Fuel Building HVAC System is adequate to support power uprating to the proposed reactor power level.

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The Auxiliary Building HVAC System provides conditioned outside air for ventilation and cooling and heating of various areas of the auxiliary building, collects and processes airborne

    • particulates during normal operation and post-LOCA, provides a suitable ambient environment for the electric motor drives for safety-related pumps and provides supplemental building heating when required. A review of the sources of heat loads, ventilation requirements and heating requirements indicates that power uprating will not have any effect on this system. Therefore, the existing auxiliary building HVAC system is adequate to support power uprating.

The iodine filtration system consists of a safety-related filter assembly with fans and two separate banks of filters that are common to other systems. The filter banks have a roughing filter, high efficiency particulate activity (HEPA) filter and charcoal filter section. The safety-related filters and fans remove airborne radioactive contaminants from the air being discharged to the environment by any of the primary ventilation subsystems, except the auxiliary building general area exhaust system. The auxiliary building general area exhaust air is filtered by a non-safety related filter bank and fan train. A review of the system design and operation conditions indicates that power rerating will not have any effect on this system. Therefore, the existing iodine filtration system is adequate to support power rerating.

The following additional HVAC systems have been evaluated and it has been concluded that power uprating will have no direct impact on these systems: *

1. Decontamination Building Heating and Ventilation System
2. Safeguards Building Ventilation System
3. . Turbine Building Ventilation System *
4. Mechanical Equipment Room No. 5 HVAC System
5. Main Control/ Emergency Switchgear Room Ventilation and Bottled Air Systems
6. Station Service Switchgear / Cable Tray Room Ventilation System
7. Service Building Central Ventilation System
8. Miscellaneous Service Building Ventilation System .
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4.2.19 Flow-Accelerated Corrosion The piping systems susceptible to flow-accelerated corrosion (FAC) were reviewed to assess the impact of the core uprate project. Originally FAC was called erosion/corrosion (EiC), but the industry has moved to the more appropriate term in recent years.

The thermodynamic conditions at the current power level were compared to the conditions at the projected core uprate power level, using heat balance runs provided for each condition. This comparison was utilized as the temperatures/quality and flow rates in susceptible piping systems are the key parameters for determining the core uprate impact on F AC wear rates in single and two-phase flow. The differences in operating temperatures/qualities at 100 and 104.3 percent of current power levels would not tend to increase or decrease the F AC wear rates significantly.

The percentage of change in flow rates is approximately proportional to the percentage of change in FAC wear rates with all the other variables affecting FAC wear rates remaining constant.

This conclusion is based on available industry information and the experience of engineering in computer modelling of susceptible systems to produce a wear rate analysis.

The FAC program for Surry Power Station requires the preparation of a piping inspection list for any given refueling outage which reflects any changes in operating conditions, such as an increase in the mass flow rate. The means of determining the extent of F AC degradation is through the evaluation of ultrasonic thickness (UT) measurements of susceptible components.

UT data of susceptible components will be available when each unit has experienced at least one fuel cycle at the core uprate power level. At that time any actual increases in F AC wear will be programmatically determined and evaluated.

There are numerous other operating parameters unrelated to core uprate which can have an affect on FAC wear rates. Any predictions of future FAC wear rates must also take these parameters into account. Surry Power Station is currently evaluating increasing the pH of the secondary water chemistry. It is possible that any increase in FAC wear due to core uprate could be offset by an increase in the pH of the secondary water chemistry.

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In summary, industry information and engineering experience indicates that the flow rate and temperature/quality of the media are the two factors involved in the core uprate project which

  • could affect single or two-phase F AC. As these two parameters will not be significantly increased in the F AC susceptible systems, there should be little impact on current programmatic component wear rate predictions. The Secondary Piping and Component Inspection Program provides the tracking, trending and inspection scope for the Surry FAC effort. Therefore, any impact which does occur as a result of the core __uprate_project will automatically be factored into future FAC wear rate prediction models.

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4.3 Electrical Systems 4.3.1 Main Generator At the core uprate power the generator gross output based on the heat balance is 852,333 KW.

The generator is rated 941.7 MVA at .90 power factor. In order to produce the 852,333 KW, the calculated power factor will be .9051, lagging. It should be noted that the KW output must be reduced if the generator is required to operate outside a predetermined power factor range. .

4.3.2 Generator Isophase Bus Duct

. The generator leads are rated at 26,000 amps and are therefore sized to handle the rated output

.current of the generator. Generators are required to be capable of operating at rated MVA (941. 7), frequency and power factor at +/- 5 *percent of rated voltage. Therefore, at -5 percent voltage (20.9KV) the generator current is 26,013 amperes. The maximum generator output current at the core uprate condition will not exceed the rated generator output. Therefore, the main section of the bus duct carrying generator output current is* acceptable for core uprate loading.

The three taps to the 3-300 MVA transformer bank making up the main transformers are rated at 15,000 amps. The rated current of each of these 300 MVA transformers is 14,354 ampsat

  • 20.9KV.

The taps to each .of the main transformers are capable of handling the rated current of the transformer. and, as explained later* in this report, the main transformer is sized adequately to handle the additional load due to core uprate. Therefore, these taps are adequately sized to handle the core uprate loads.

The taps to each station service transformer are rated at 1,200 amps. The rated transformer current to each station service transformer is 618 amps at 20.9KV.

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The taps to the Station Service Transformers are sized to carry the rated transformer current and, as explained later in this report, these transformers are adequately sized to handle the

'additional load due* to core* uprate. Therefore, there is more than sufficient ampacity in these taps to handle the additional core uprate load.

The delta branch, which carries the combined three phase loads of the three station service transformers and the single phase loads of one of the three main s~up transformers, is rated at 17,000 amps. The combined rated current of one single-phase main step-up and the three station service transformer loads is 16,208 amps at 20.9KV. Both transformers are sized adequately for the additional core uprate loads* and, therefore, the delta branch of the isolated phase bus duct is adequate for the additional core uprate loads.

The portion of the isolated phase bus duct from the main transformers .to the station service transformer is rated at 1,650 amps. This portion of the bus duct is not rated to carry the maximum rated current of 1,856 amps for all three station service transformers operating at 65 °C rise. The maximum station service core uprate load calculated by adding the maximum load on each station service transformer is approximately 48 MVA. .The bus duct current at this load is 1,326 amps at 20.9KV, which is less than .the rated current of 1,650 amps, therefore, this portion of the bus duct is acceptable for core uprate.

,. 4.3.3 Station Service Transformers A station service transformer loading study determined the transformers worst-case core uprate loads to be less than the transformer rating. Therefore, the transformers are adequately sized for core .uprate.

The secondary feeders from the station service transformers are 3-1/C-1500 MCM AL 5 KV*

power cable per phase for transformers lA, lB, lC and 2A and 3-1/C-2000 MCM AL 5 KV cable per phase for transformers 2B and 2C. The cables are routed in cable tray and maintain a spacing of 1.25 times cable diameter. Therefore, there is no required derating factor. The 319

ampacity of these cables in tray is 3,264 and 3,885 for the 3-1/C-1500 MCM and 3-1/C-2000 MCM, respectively. The maximum rated secondary output current of the station service

  • transformer at 65°C rise, 22.4 MVA and 4,160 volts is 3,108 amps.

Therefore, both cable types have sufficient ampacity to carry both the rated transformer and the smaller core uprate load.

4.3.4 Reserve. Station Service Transformers Utilizing the station loading from the previous GDC-17 studies and the revised core uprate

  • 1oading, a RSST load study was performed.

For the transformers, the worst-case loading is less than the transformer ratings. Therefore, the transformers are adequately sized for core uprate -loads.

The 4 KV transfer bus and its incoming feeder breakers have been Upgraded to 4,000 amp by

  • addition of cooling. The RSST worst-case loadings are less than 4,000 amps and, therefore, the transfer bus and its incoming breaker are adequate for increased loads due to core uprate.

In DCP-82-42, the RSST feeders to the switchgear were upgraded to a minimum ampacity of 4,000 amps. Therefore, they are adequately sized for the core uprate loads.

4.3.5 Main Transformers The main step-up transformer (MSUT) was analyzed utilizing SWEC standard transformer worksheets and a simple circuit model which neglects transformer exciting current and core losses. Neglecting transforming core losses and exciting currents results in a slightly larger transformer rating. However, since the purpose of these calculations is to demonstrate the adequacy of the existing transformer, it is considered a reasonable approach .

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. The simple circuit model was used to assess the output MVA of the transformer at maximum generator MW output and power factors from approximately .90 PF lag to .95 PF lead and to

  • compare the results with SWEC standard transformer worksheets. The voltage of the generator was varied +5 percent from its nameplate voltage of 22 KV depending on whether the generator was supplying or taking in MVARS from the system. The most limiting case for transformer sizing occurs at a leading power factor and maximum: MW output.

Analysis of the main step-up transformer (MSUT) has shown that the 3-300 MVA MSUT are adequately sized for th~ additional core uprate load of 852.3 MW from approximately .905 PF lag to .96 PF lead on Unit 1 and .905 PF lag to slightly less than .97 PF lead on Unit 2. These conditions are within the normal operating range of the generator.

4.3~6 Motor Feeders Feeders to the feedwater, condensate, and high and low pressure heater drain pump motors were reviewed to determine if any changes are required as a result of the additional BHP for these

. motors at the core uprate conditions. It has been determined that all of the feeders are capable of handling the *additional loading due to core uprate. See Table 4. 3. 6-1.

-TABLE 4.3.6-1 PUMP BHP Motor Calculated Core Pump Rated Uprate (BHP) Title 1-FWP-lA,lB 2-3000 2984 ea Steam ea/pump Generator Feed 1-CN-P- 3000 2871 Condensate 1A,1B,1C 1-SD-P-lA,lB 2000 1801 High Pressure Heater Drain l-SD-2A,2B 500 433 Low Pressure NOTE: Unit 2 pumps have similar ratings 321

The intent of the study was to show that the KVAR loading on each transformer is smaller under the core uprate loads than under the GDC-17 loads even though the total KW and KVA loading is larger for the core uprate.

The study concluded that the voltage profile for all RSSTs for core uprate will be either slightly improved or at least the same as the GDC-17 cases due to the decrease in the KVAR loading.

4.3.8 Protective Relaying The relay settings on the feeders to the feedwater condensate, high and low pressure heater drain pump motors were reviewed and it was determined that no revisions to the relay settings for these motor feeders are required as a result of the core uprate.

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4.4 Structures The only structural loads subject to change as a result of the uprate were those resulting from peak containment pressure subsequent to a loss of coolant accident (LOCA) (Reference 3.6.2.2, Containment LOCA Analysis). The new post LOCA peak containment pressures of 44.44 psig for the hot leg double ended rupture (DER) and 43. 70 psig for the reactor coolant pump suction DER are below the 45 psig containment. design pressure. There is no effect on the structural integrity of the reactor containment or other safety-related structures (Auxiliary Building, Main Steam Valve House, Fuel Building, Safeguards Building) due to the uprate .

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4.5 Pipe Stress and Supports The existing stress analyses for the BOP systems identified in Table 4.5-1 were reviewed to evaluate the impact of the uprated system temperatures and pressures. The heat balance provided to uprated temperatures and pressures for the pipe stress and support evaluation.

The NSSS uprate of the Surry Station basically involves the increase of the 4 T across the Reactor Coolant System, RCS. This increase in AT is developed by decreasing the RCS cold leg temperature with the RCS hot leg remaining at its present temperature. Therefore with no reactor coolant (RC) loop temperature increase, the present stress analysis for the RCS system and systems associated with the RCS system (CVCS, safety injection, etc) is bounding.

The steam generator outlet pressure and temperature remain at the present operating condition of 784 psia and 515. 9 °F, respectively. The steam generator design flow rate is increased from 10.66 x 106 lb/hr to 11.26 x 1()6 lb/hr for the uprate. The changes in the BOP systems temperatures and pressures for the uprate conditions can be attributed to the increased steam flow and improved system efficiencies. System efficiencies have been improved by the replacement of feed water heaters and the retubing of the moisture separator reheater.

The approach of the BOP system review was to compare the uprated operating conditions to the existing stress analysis design parameters. The comparison determined that the temperature of the 3rd Point Extraction Steam Piping and 5th Point Heater Drain Piping exceeds the design requirements of the system. All of the remaining systems reviewed at this uprated operating conditions are below design temperature and pressure requirements and are bound by existing stress analysis.

The 3rd point extraction steam and fifth point heater drain piping systems were reevaluated for uprated temperatures. The evaluation considered the thermal effects as being proportional to the change in the thermal expansion which has an associated increase with increased system operating temperature.

324

Because thermal loading and stresses are essentially proportional to thermal expansion, the effect of the temperature increase can be evaluated by applying the thermal expansion increase ratio to the maximum existing thermal stress levels for each affected system. The resulting increased stresses are then compared to the appropriate code allowables and design criteria to determine acceptability.

The stress analysis performed for the 3rd point extraction steam ~d 5th point heater drain piping verified that the existing piping and support configuration is adequate to withstand effects from the increased temperature. However, the analysis determined that the 5th point heater drain piping nozzle loads exceed the existing nozzle load stress allowable. The nozzle will require reinforcement for operation at the uprated temperature .

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~-4.5-1 COMPARISON OF SYSTEM PRESSURE AHD TEMPERATURE Operating Operating Condition* Condition*

svstem Present UpratinQ' DesiQ'D Main steam 785 psia 784 psia 1085 psig 516°F 516°F 505°F- 555°F Condensate 440-585 psia 404-573 psia 610-915 psig 75°F - 372°F 76°F - 376°F 125°F-400°F Feedwater *800-1127* psia - 800 - **1078* psia '1680 psig 374°F - 437°F 377°F - 442°F 450°F Extraction Steam let pt. heater 376 psig 411 psig 410 psig 446°F 451°F 450°F 2nd pt. heater 172 psig 187 psig 195 psig 380°F 383°F 385°F

. *3rd pt. *;heater .73 psig 79 psig 85 psig 358°F 368°F 325°F 4th pt. heater 24 psig 26 psig 30 psig 264°F 269°F 275°F 5th pt. heater 0 psig 1 psig 1 psig 212°F 214°F 215°F 6th pt. heater -8 psig -7.5 psig -7.2 psig 177°F 178°F 180°F H.P. Heater 519 psig 539psig 915 psig Drains 377°F 379°F 400°F L.P. Heater 551 psig 586 psig 515 psig Drains 266°F 266°F 270°F Reactor Coolant 2250 psig 2250 psia 2485 psig

. ~ ' \

. . . .542.8°F - 605.6°F 540.4°F - 60S.6°F 650°.F

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4.6 Control Systems and Instrumentation A review of the core uprate heat balance was performed to determine the effect on BOP instrumentation and control valves for the following systems:

Condensate Feedwater Main Steam Extraction Steam Heater Drains The following specifications were reviewed for the core uprate along with corresponding vendor catalogs:

NUS-69-2 Instrument & Controls - Electronic Pneumatic Transmitters NUS-69-4 Instruments & Controls - Venturi Flow Nozzles NUS-69-6 Instruments & Controls - Orifice Plates NUS-69-15 Instruments & Controls - Pressure Indicators NUS-80 Air Operated Control Valves NUS-80-3 Safety & Relief Valves NUS-86 Main Steam Line Safety Valves The review of the level control valves (LCVs), located in the normal and alternate drain lines of the first through fifth point feedwater heaters, was performed. This review determined that at the uprated normal drain flow rates and worst case single failure flow rates certain valves are

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undersized. Discussions with site personnel indicate that under present conditions the first point feedwater heater drain LCVs were 90-100% open. The above review and discussion with site

  • personnel indicates the replacement of the first point heater LCVs is required to enhance control under current plant conditions. Replacement on Unit 1 is complete; Unit 2 replacement will be complete prior to uprating the core. New LCVs have been sized to accommodate core uprate normal and ASME turbine water induction worst case single failure flow rates. The new valve sizes shall provide for an effective range of flow control at uprated conditions.

The evaluation of the Feedwater Regulating Valves (FRVs) determined if the valves are suitable for the uprated conditions. The calculation is based on data obtained from the heat balance, valve nameplate data and data sheets obtained from Copes Vulcan. The Condensate and Feedwater System review, Section 4.2.4, indicates the feedwater pump discharge pressure provides for sufficient AP across the FRVs. At the 100% uprated condition, the AP across the FRVs will be 103 psi. At this AP, the calculated Cv value of the valve is 810. The actual total Cv of the valve as determined from the data sheets is 1350. With a Cv value of 810 the valve is at 60 % of its full capacity. The results of the above review indicate the FRYs will be acceptable for service at the uprated conditions.

The total relieving capacity of the main steam safety valves (MSSVs) under ASME VIlI was calculated and equals 11,527,362 lb/hr. The uprated steam flow is 11,260,000 lb/hr. Allowing for an increase in the MSSV capacity to bound the 2 percent instrument error margin relevant to R.G. 1.49 will require a total MSSV relieving capacity of 11,485,200 (11,260,000 lb/hr x 1.02). The calculated total relieving capacity for the MSSVs is adequate for the core uprate conditions .

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4. 7 Validation of Instrumentation & Control Systems Setpoints
4. 7 .1 Reactor Protection & Engineered Safety Features Systems Setpoints The NSSS accident analyses evaluation effort included the validation of existing setpoint values for actuation of Reactor Protection System and Engineered Safety Features System functions.

The objective of the validation is to ensure that these protective circuits will continue to perform their required design functions with the assumed setpoints. In certain cases, this assurance could be provided only if the analyses assume revised values for these setpoints. Such changes are specified in this license amendment request as proposed changes to the setpoints in the appropriate section of Surry Units 1 and 2 Technical Specifications. Table 4.7.1-1 presents the Reactor Protection and Engineered Safety Features system functions, current limiting settings and setpoints assumed in the NSSS accident analyses.

The NSSS accident analyses have demonstrated that all events meet the applicable acceptance criteria, assuming the setpoints given in Table 4. 7 .1-1. This conclusion is dependent upon operation with the proposed Technical Specifications changes for certain functions. The affected functions are noted on Table 4.7.1-1 and the basis for the proposed changes is described below.

Overtemperature 4 T & Overpower 4 T Virginia Power has performed the core thermal-hydraulic assessment for uprated operation of Surry Unit 1 and 2 using the COBRA code (4. 7-1). As part of this effort, revised core thermal limits were generated. In addition, the Overtemperature & T and Overpower* 4 T protection setpoints were generated, using the approved Westinghouse methodology (4. 7-2). These analyses have confirmed that the existing Technical Specifications setpoint values provide adequate protection for operation under the proposed uprated conditions. This has been validated by a dynamic simulation of the rod withdrawal at power accident in Section 3.5.2. The only required change in the existing setpoint equations is the T' term, which represents the reference average RCS temperature for full power operation. The value of T' is reduced to 573.0°F from the existing value of 574.4°F .

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Automatic Recirculation Mode Transfer <RMI)

The containment integrity and safeguards equipment analyses, documented in Section 3.6.2, have confirmed that all applicable design criteria are met for operation at the uprated conditions. In order to confirm the existence of acceptable analysis margins, the analyses have assumed that the RWST level setpoint for automatic recirculation mode transfer (RMT) is reduced from its

. current nominal value of 18.93%. span. The proposed nominal setpoint is .13.5% span.

References (4.7-1) VEP-FRD-33-A, "Vepco Reactor Core Thermal/Hydraulic Analysis Using the COBRA illC/MIT Computer Code," October 1983 (4.7-2) WCAP-8746, "Design Bases for the Thermal Overpower AT and Thermal Overtemperature AT Trip Functions," March 1977.

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~able 4.7.1-1 Assumed Reactor Protection & Engineered Safety Features Settings for Surry Core Rated Power of 2546 MWt Parameter Values Current Uprating Function Limiting Settings Analysis Engineered Safeguards Turbine Trip Reactor Trip High-High SG Level (% NRS) 75 80 Feedwater Isolation High-High SG Level(% NRS) 75 80 Safety Injection Accumulator N2 Pressure (psia) 600 580 Safety Injection Low Pressurizer Pressure (psia) 1715 1715 High Containment Pressure (psia) 19 *. 7 21. 7 Reactor Trips High Flux - Hi Setting(% RTP) 109 118

  • High Flux - Lo Setting(% RTP)

Low Pressurizer Pressure (psia)

High Pressurizer Pressure (psia)

High Pressuri'zer Level (% span)

Low RCS Flow(% nominal) 25 1875 2400 92 90 35 1865 2425 96 87 1

RCP Underfrequency (Hz) 57.5 not credited RCP Undervoltage (% nominal) 70 not credited 2

Overtemperature AT Ki=l.135 K1=1. 232 2

Overpower AT K.i=l. 089 not credited Low-low SG Level (% NRS) 5 0 1

Analysis assumes 87% of minimum RCS Total Flowrate of 91000 gpm/loop 2

Analysis supports existing TS values for Kand T constants; T'=573.0°F to reflect nominal full power Tav&

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4. 7.2 Reactor Control Systems Setpoints The NSSS accident analysis methodology accommodates the actions of various reactor control systems. These systems provide the means to maintain key reactor parameters within desirable

. values. Actions of control systems are applied in the following manner. Control system actions which maintain reactor parameters within Technical Specifications limits are credited. The NSSS accident analyses thus assume a set of initial conditions which satisfies the applicabJe Technical Specifications limits. Control system actions are not credited in NSSS accident analysis if their activation during the transient tends to mitigate the system transient behavior. However, if control system actuation (or a postulated failure mode) makes the transient more severe, such actions are accounted for in the analysis. This approach was applied in the NSSS accident

, analyses for the proposed uprating.

Westinghouse performed studies to assess operating margin and control system capability, based on the Reactor Coolant System operating parameters for the proposed uprating. These studies identified minor revisions in the control system setpoints for steam dump control, pressurizer level control and the Tref program which feeds the Rod Control System. The NSSS accident analyses and evaluations have assumed the proposed values for these system setpoints, consistent with the accident analysis methodology described above. The proposed control system setpoints .

have been determined to be acceptable when treated in this manner.

332

5.0 D~wnents Affected by NSSS Accident Evaluations 5.1 Technical Specifications The Surry Unit 1 and 2 Technical Specifications have been reviewed to determine the changes which are required .for operation at the proposed uprated conditions. The required changes can be assigned to the following categories:

cor~ rated po~er change in the definitions and in the operating license and other changes associated with the revised plant nominal operating conditions changes whi~h reflect the safety limits and limiting safety system settings associated with revised accident analyses (NSSS events, containment analyses and radiological consequences analyses) changes* in limiting conditions for operation associated .with revised analyses oi: .

evaluations A discussion of the proposed changes and the affected Technical Specifications pages are included as separate attachments within this license amendment application.

Operating License Changes Operating License No. DPR-32 (Unit 1), DPR-37 (Unit 2) - Condition 3.A:

Maximum Power Level - revise to read 'steady state reactor core heat output of 2546 MWt' to reflect uprated power level*

Operating License No. DPR-32 (Unit 1), DPR-37 (Unit 2) - Condition 3.N:

Delete this condition which refers to control room dose calculations which are being superseded by analyses contained in this license amendment application.

Technical Specifications Changes Page TS 1.0.A (TS 1.0.A) - Definition of RATED POWER - revise to state 2546 MWt Page TS 2.1-3 (Basis for Figure 2.1-1)- Delete sentence 'The three loop operation ... to 100%

of design flow.' This refers to densification effects no longer included in the analysis basis .

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TS Figure 2.1-1 (Reactor Core Thermal and Hydraulic Safety Limits) - Replace with figure of limits which reflect operation at uprated conditions (4.1-1).

Page TS 2.1-4 (Basis for Figure 2.1-1) - Revise to reflect relationship between deterministic and statistical analysis basis incorporated into the figure.

  • Page TS 2.1-5 (Basis for Reactor Control & Protection.System) - Revise stated nominal RCS temperature to 573.0°F. Delete* footnote which allows Unit 2 Cycle 12 RCS nominal operating
  • pressure to be reduced to 2135 psig.

Page TS 2.2-2 (Basis for TS 2.2) - Delete

  • and ** footnotes which refer to reduced PORV and high pressure reactor trip settings for Unit 2 Cycle 12.

Page TS 2.3-2 (TS 2.3.A.2(b)) - High Pressurizer Pressure Reactor Trip - Delete

  • footnote which refers to a reduced trip setting for Unit 2 Cycle 12.

Page TS 2.3-2 (TS 2.3.A.2(d)) - Overtemperature AT - revise T' to equal 573.0°F, the proposed nominal RCS average temperature.

. Page 2.3-7 (Basis for Low Flow Reactor Trip) .,. This paragraph is being revised to emphasize that the low flow trip is the primary trip and that undervoltage and underfrequency trips are considered back-up protection. This reflects the assumptions of the revised complete loss of flow analysis.

Page TS 3.1-1 (TS 3.1.A.1.a) - LCO for Number of Reactor Coolant Pumps - Revise to read

'A reactor shall not be brought critical with less than three pumps, in non-isolated loops, in operation.' This change reflects the revised analysis of uncontrolled rod withdrawal from a subcritical condition.

334

Page TS 3.1.3 (TS 3.1.A.3.b) - Pressurizer Safety Valve Lift Settings - Delete the

  • footnote
  • which refers to expanded pressurizer safety valve lift setting tolerance for the remainder of Cycle 10 and 11 for both units.

TS Page 3.1-16 to 3.1-17a (Basis for Coolant Activity Limits) - The description on these pages has been rewritten, based upon the revised steam generator tube rupture radiological consequence~ analysis.

Page TS 3.3-7 (Basis for Accumulator Valves) - Delete the* footnote which refers to a reduced nominal operating pressure for Unit 2 Cycle 12.

Page 3.6-2 (TS 3.6.E) - SG Secondary I-131 Activity - Delete the sentence 'The iodine-131 activity in the secondary side of any steam generator, in an unisolated reactor coolant loop, shall not exceed 9 curies,' and revise the next sentence to begin 'The specific activity ... ' This change reflects the secondary activity assumed in the revised main steamline break radiological analysis, which is a specific activity of 0.10 µ.Ci/cc. A separate limit on total activity is redundant and is not required by the revised analysis.

Page TS 3.6-4 (Basis for ECST Capacity) - Revise basis statement to read 'The specified minimum water volume in the 110,000-gallon protected condensate storage tank is sufficient for 8, hours of residual heat removal ... ' Add a sentence which reads 'It is also sufficient to maintain one unit at hot shutdown for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, followed by a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> cooldown from 547°F to 350°F (i.e.

RHR operating conditions).' This reflects the cooldown capability for operation at uprated conditions.

Page TS 3.6-4 (Basis for Main Steam Safety Valve Capacity) - Revise the statement of main steam safety valve flow capacity to read ' ... total combined capacity of 3,842,454 pounds per hour at their individual relieving pressure; the total combined capacity of all fifteen main steam code safety valves is 11,527,362 pounds per hour.' Revise the second sentence to read 'The 335

nominal rating steam flow is 11,260,000.' These changes reflect a revised calculation of valve relief capacity and the increased nominal steam flow associated with uprating.

Page TS 3.6-5 (Basis for SG Secondary Activity) - Delete the text starting with 'The limit on steam generator ... ' through the sentence which ends with '... the specific iodine-131 limit would be .089 µCi/cc.' Replace with the following:

'The limit .on steam generator secondary side Iodine-131 activity is based on limiting the inhalation dose at the site boundary following a postulated steam line break accident to a small fraction of the 10 CFR 100 limits. The accident analysis, which is performed based on the guidance of NUREG-0800 Section 15.1-5, assumes the release of the entire contents of the

.faulted steam generator to the atmosphere.'

These changes replace the previous description which provided a basis for comparison between the total and the specific activity limits. Since the total activity limit (TS 3. 6.E) is being deleted, and the revised analysis does not require a specific total activity, this discussion is not relevant.

Page TS 3.7-26 (Table 3.7-4) - Recirculation Mode Transfer - Revise the RWST Level-Low setting limits to be as follows:~ 11.25% ands 15.75%. These revised settings reflect the values assumed in the LOCA containment analyses. The setpoint value has been validated by the analyses as providing adequate margin for containment depressuriz.ation while ensuring that the low head safety injection pumps will have adequate net positive suction head for operation in sump recirculation mode.

Page TS 3. 8-4 (Basis for Figure 3. 8-1) - Revise the description of the figure characteristics and numerical ranges to be consistent with the replacement figure.

TS Figure 3.8-1 (Allowable Air Partial Pressure) - This figure, which presents operating limitations for containment air partial pressure, containment bulk average temperature and

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service water temperature, has been revised in conjunction with the containment integrity analysis. The revised figure allows operation over a range of air partial pressure from 9.0 psia -

10.3 psia and over a temperature range of 75°F to 125°F.

Page TS 3.10-7 (Basis for Activity Assumed in Fuel Handling Accident) - Revise the description to state that this accident has been analyzed based on the methodology in Regulatory Guide 1.25, assuming that 100% of the gap activity of the highest powered ~sembly is released after 100 day decay following operation at 2605 MWt. This reflects the revised radiological dose consequences analysis. Delete the

  • footnote which compares the fuel rod gap activity of 15x15 and 17xl 7 demonstration assemblies. This information is not relevant to any fuel assemblies currently in Surry cores. Any potential future use of demonstration assemblies will be addressed on a case-specific basis.

Page TS 3.12-12 (TS 3.12.F.1) - DNB Parameters - Revise the temperature limit to state

'Reactor Coolant System T_ s 577°F.' This reflects the proposed nominal operating temperature, plus uncertainties which have been accommodated in the revised thermal-hydraulic analyses(4 .1-2). Delete the

  • footnote which refers to reduced nominal pressurizer pressure for Unit 2 Cycle 12.

Page TS 4.1-lOa (Table 4.1-2B) - Minimum Frequencies for Sampling Tests - Delete the words

'9 Curie' which appears *in both Note (4) and (8). This reflects the deletion of the 9 curie total activity limit and thereby makes only a general reference to Specification 3.6.E, which contains the limit.

Page TS 4.4-3 (Basis for Containment Air Partial Pressure Limits) - Revise statement of containment pressure range to read 'The containment is maintained at a subatmospheric air partial pressure consistent with TS Figure 3. 8-1 depending upon ... ' This refers to the applicable figure which presents the range assumed in the containment integrity analysis .

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Page TS 5.2-3 (TS 5.2.C.l) - Containment Systems - Revise the stated Recirculation Spray Subsystems flow to be 'at least 3000 gpm of water from the containment sump.' This reflects the flowrate assumed in the revised containment analysis.

338

5.2 Desien Document Impact (DRP, EOP, Procedures, UFSAR)

The proposed uprating was evaluated for potential impact upon various plant design documents.

Changes have been identified which affect these documents: Design Reference Procedures (DRPs), Emergency Operating Procedures (EOPs), Plant Procedures and Updated Final Safety Evaluation Report (UFSAR). _The general _changes required are discussed below. Specific changes will be identified and included in the core uprating implementation design change package.

Setpoint Documents (DRP Documents)

Operation under the proposed conditions requires changing certain plant setpoints appearing in the Design Reference Procedures (DRPs). These setpoint changes are categorized in one of these areas: items which reflect the revised nominal operating conditions or items which reflect assumptions made in the NSSS accident analyses .

Nominal Operating Conditions items RCS Tavg program Pressurizer level program Steam Dump actuation NSSS Accident Analysis Items RWST Recirculation Mode Transfer (RMT) setpoint RWST low level alarm RWST empty alarm Revised reference T avr. term in Overtemperature 4 T function Revised reference T av& term in Overpower 4 T function 339

Emergency Operating Procedures (EOPs)

A review of .the Emergency Operating Procedure setpoint database was conducted to determine the setpoints affected by core uprating. All but seven setpoints were unaffected by the uprating.

Four of those seven setpoints changed only in the basis discussion, the setpoint value was unchanged (two RCS pressure setpoints and two SG level setpoints). The remaining three setpoints were 1) transfer to recirculation mode alarm setpoint, 2) transfer to recirculation mode actuation setpoint and 3) minimum SI flow versus time after trip curve. The revised setpoints were added to the setpoint database-with applicability-limited to post-upgrade*operation.**Each Emergency Operating Procedure will be* reviewed to identify any other changes (in addition to setpoints). The normal design crumge process will implement appropriate setpoint and necessary procedure changes prior to operation at uprated conditions.

Of particular interest regarding unaffected setpoints, the C-series setpoints (heatup/cooldown curves) were unaffected because the basis calculations assumed uprated power. The setpoint for time to transfer to hot leg recirculation was unaffected for the same reason. And the AFW flow setpoints were unaffected because their bases assumed a power level which bounded the uprated condition.

Core Physics Related Key Analysis Parameters The NSSS accident reanalyses performed for the Surry core uprating either require or support changes in the limit values for several core physics related key analysis parameters. These changes will be incorporated after implementation of core uprating in accordance with the normal reload core safety evaluation process (4.2-1).

Surveillance and Periodic Test Procedures The containment integrity analyses in Section 3.6.2 makes a number of assumptions regarding values of key safety parameters. These include the following: containment temperature and air partial pressure, service water temperature and RWST temperature. The operating limits for these parameters which the analysis supports is provided in Table 2.2-1. In order to justify these parameter values, the analysis has taken credit for the inherent uncertainty of plant instrumentation and also made key assumptions concerning surveillance actions of plant 340

operators. The specific assumptions used which require surveillance procedures or actions to be modified will be incorporated into the uprating implementation design change package. Each of these items may not necessarily represent a change from existing procedures, but each must be performed as indicated to maintain operating conditions which are consistent with the assumptions in the containment analysis.

Updated Final Safety Analysis Re.port The revised NSSS-accident analyses-and evaluations-performed-for operation of Surry Units 1 and 2 at the core rated power of 2546 MWt will require revisions to the UFSAR. Appropriate changes will be developed and incorporated into the Surry Power Station UFSAR in accordance with the requirements of 10 CFR 50.71(e). These changes will be implemented consistent with the annual UFSAR update program, following approval of the uprating license amendment request.

References (4.2-1) VEP-FRD-42, Rev. 1-A, "Reload Nuclear Design Methodology," September 1986.

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6.0 Conclusions The aspects of plant design considered in this report have been evaluated with respect to the safety criteria of 10 CFR 50.59. The conclusions of this evaluation may be summarized as follows:

The proposed increase in the licensed power rating of Surry Units 1 and 2 has been reviewed in detail with respect to its impact on the following aspects of plant design and operation:

1. NSSS Accident Analyses
2. NSSS Components and Systems
3. Balance of Plant Components and Systems
4. LOCA Mass and Energy Release Analysis, Containment Integrity &

Safeguards Equipment Analysis

5. Plant Design Documentation
6. Technical Specifications and Plant Procedures
7. Existence of any Unreviewed Safety Questions The review o( items in this report has demonstrated that Surry Units 1 and 2 are capable, with minor modifications, of operating at the proposed power rating while remaining in compliance with the applicable design criteria and safety limits. This conclusion is valid provided the plant is operated in accordance with the Technical Specification changes proposed in this report. The review has verified the following:
1. The probability of an accident previously evaluated in the UFSAR will not be increased. Operation at the uprated conditions does not affect the probability of any known initiating events for the evaluations described herein. The event probabilities would therefore not be increased.
2. The radiological consequences of certain accidents previously evaluated in the UFSAR will be increased. As discussed in 342

Section 3. 7. 3, the calculated doses remain within the regulatory limits.

3. The possibility of an accident which is different than any already evaluated in the UFSAR will not be created.
4. The margin of safety as defined in the basis to any technical specification will not be reduced by operation at the uprated power. The evaluations *presented in *this supplement* have demonstrated that the event results continue to meet the

....~

applicable acceptance criteria, which preserves the existing margin of safety.

It has been concluded that operation of Surry Units 1 and 2 at the increased power rating does not reduce the plant safety margins, nor increase the probability of an accident previously evaluated. The increase in radiological dose consequences for certain accident events does create an unreviewed safety question. However, as indicated in Section 3. 7. 3, the calculated doses of all events remain within the regulatory limits .

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