ML17353A506
| ML17353A506 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 12/31/1995 |
| From: | Deblasio J WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP. |
| To: | |
| Shared Package | |
| ML17353A502 | List: |
| References | |
| WCAP-14276, WCAP-14276-R01, WCAP-14276-R1, NUDOCS 9512270316 | |
| Download: ML17353A506 (444) | |
Text
WESTINGHOUSE NON-PROPRIETARY CLASS 3 WCAP-14276 Rev. 1 FLORIDA POWER AND LIGHT COMPANY TURKEY POINT UNITS 3 AND 4 UPRATING LICENSING REPORT'ecember 1995 INTEGRATED:
APPROVED:
Work Performed Under Shop Order FYNP 4708 WESTINGHOUSE ELECTRIC CORPORATION Nuclear Technology Division P. O. Box 355 Pittsburgh, Pennsylvania 15230-355 1995 Westinghouse Electric Corporation All Rights Reserved 9512270316 951218
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WESTINGHOUSE NON-PROPRIETARY CLASS 3 TABLE OF CONTENTS Section Title ~Pa e Executive Summary Xvll 1.0 PROGRAM DESCRIPTION 1.1 Licensing Perspective 1.2 Purpose and Objectives ..
1.3 Design and Licensing Criteria 1.4 Scope Summary .. 1'-2 2.0 DETERMINATION OF NUCLEAR STEAM SUPPLY SYSTEM (NSSS) DESIGN OPERATING CONDITIONS 2-1 2.1 Discussion of Design Parameters 2-1 2.2 Conclusions 2-1 3.0 ACCIDENT ANALYSES AND EVALUATIONS . 3-1 3.1 Introduction 3-1 3.2 Non-Loss of Coolant Accident (Non-LOCA) Events and Standby Safety Features Analyses ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
3.2.1 Uncontrolled Rod Cluster Control Assembly (RCCA) Withdrawal from a Subcritical Condition . 3-3 3.2.2 Uncontrolled RCCA Withdrawal at Power 3-13 3.2.3 RCCA Drop 3-26 3.2.4 Chemical and Volume Control System (CVCS) Malfunction 3-31 3.2.5 Startup of an Inactive Reactor Coolant Loop .. 3-38 3.2.6 Excessive Heat Removal Due to Feedwater System Malfunctions 3-38 3.2.7 Excessive Load Increase Incident 3%7 3.2.8 Loss of Reactor Coolant Flow 3-60 3.2.8.1 Partial/Complete Loss of Forced Reactor Coolant Flow . 3-60 3.2.8.2 Locked Rotor/Shaft Break ........ ~ . 3-63 3.2.9 Loss of External Electrical Load and/or Turbine Trip .. 3-84 mA1 &OSwtoc.wpf:IM81195
Vi/ES'TINGHOUSE NON-PROPRI].:TARY CLASS 3 TABLE OF COM'EN]3S (cont)
Section 'Titlle Pa~e 3.2.10 Loss of Norfnal Feedwater .. .......... 3-103 3.2.11 Loss of Non.Emergenc,y AC:Power to the ]Plant Auxiiliaries ... .......... 3-110 3.2.12 Fuel Handling Accident/Radiological Consequences . '..
'-117'........
3.2.13 Dropped Spe,nt ]Fuel Transfer Cask Radiological Consequences . J 3-122 3.2.14 Volume Control Tank Rupture Radiolol~jcal Consequences.... ........., 3-125 3.2.15 Gas Decaiy Tank Ruptttre Raclio]ogical Consequences .......... 3-I28 3.2.16 Main Steam Line Break Core Resportse . . ....... 3-131 3.2.17 Rupture of a Control Rod Drive Mechamsm Housing RCCA Ejection . . 3-133 3.3 LOCA and LOCA-related Events . 3-148 3.3.1 Large Break LOCA.. ........... l 3-'148 3.3.2 3.3.3 3.3.4 Small Break LOCA..
LOCA H;ydraulic Hot Leg .'Switchover ..
Cob]i'.......
Forcfa...........
...... i .. 3-209
...... i ..
3-241 3-244 3.3.5 Post-L.OCA ]~wng Term Core .. 3-245 3.4 Steam Generator Tube Rupture ......,....i ..3-246 3.5 Containment Integrity Anal yses .......... i .. 3-253 3.5.1 Main Steam Line Break QUASI.B) Mass,and Energy gd&E)
Releases . .. i .. 3-253 3.5.2 Steamline, Break Radiologiical COnsequenceh 3-262 3.5.3 LOCA M&E Releases ... 3-265 3.5.4 Contaiinment Response............,...........,.... i .. 3-293 3.6 Additional Design Basis and Programmatic Eva]uations ,... 3-020 3.6.1 Equipment Qtualification Events i .. 3-320 3.6.2 Hydrogen Generation Rates ........... .. 3-320 3.6.3 Plant Programs . ......,... 3-320 3.7 Conclusions of Acciclent. AnalysmKvaluatioi1s . . 3-324 3.8 Summary of UFSAR Assessment ...... 3-325 mA1808whtoc.wpf:1M8 1295
WESTINGHOUSE NON-PROPRIETARY CLASS 3 TABLE OF CONTENTS (cont)
Section Title ~Pa e 4.0 NSSS AND TURBINE GENERATOR (TG) COMPONENTS REVIEW ....... 4-1 4.1 Introduction 4-1 4.2 NSSS Design Transients 4-2 4.3 Reactor Vessel . 4-3 4.3.1 Reactor Vessel Integrity 4-3 4.3.2 Structural Evaluations 4-6 4.4 Reactor Internals 4.5 Reactor Coolant Pumps ... ~ 4-10 4.6 Control Rod Drive Mechanisms . 4-12 4.7 Reactor Coolant Piping and Supports 4-14 4.8 Pressurizer 4-17 4.9 Steam Generators .
4.10 Fuel 4-22 4.11 NSSS Auxiliary,Systems Components 4-24 4.12 Turbine Generator (TG) Components 4-26 4.13 Conclusions .. 4-26 5.0 NSSS AND TURBINE GENERATOR (TG) SYSTEMS REVIEW 5-1 5.1 Introduction .. 5-1 5.2 NSSS Fluid Systems 5-1 5.2.1 Reactor Coolant System . 5-1 5.2.2 Chemical and Volume Control System 5-5 5.2.3 Safety Injection System/Containment Spray System . 5-7 5.2.4 Residual Heat Removal System 5-9 5.2.5 NSSS Sampling System ..... 5-12 5.2.6 Head Vent/Pressurizer Vent .. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 5 14 5.3 Control Systems .. 5-16 5.4 Reactor Protection System/ESFAS Setpoints 5-17 IA1808wtoc.wpf: IM81195
WESTINGHO1'JSB NON-PROPRIETARY CLASS 3 TA.BLE OF CORI'EN'TS (cont)
'-24 Section Title P~ae 5.5 NSSS/Balance-of-Plant (BOP) Interface Systems 5-22 5.5.1 Auxiliary Feedwater System/Cohdehsate Storage Tank 5.5.2 ComIponent Cooling Water System N'ormal Containment Cooling System '.5.3
'. 5-28 Emergency Containment Cooling and Filtering Systems '.5.4
. 5-30 5.5.5 Serpent Fuel:Pit Cooling System 5-32 5.6 TG Systems 5-35 5.7 Conclusions 5-36 6.0. BALANCE OF PLANT. (BOP) EVALUA'TIONS 6-]
6.1 Introduction 6-1 6.2 BOP Systems 6-1 6.2.1 Main Steam System .. 6-1 6.2.2 Steam Dump System . 6-2, 6.2.3 Condensate andI Feedwater System 6-3 6.2.4 Steam Generator Blowdown System 6-3 6.2.5 Extraction Steam System 6.2.6 Circulating Water System . 6P 6.2.7 'Dzbine Plant Cooling Water System ..... 6P 6.2.8 Intake Cooling Water System . 6-5 6.2.9 Instrumentation and Control 6-5 Valises'.2.10 Electricajl Systems 6-6 6.2.11 Heating, Ventilation, and Air Conditioning . 6-6 6.2.12 Miscellaneous Systems 6-7 6.3 Balance of Plant (BOP) Components .. 6-8 6.4 Additional BOP Reviews . 6-12 7.0 ENVIRONMENTALEVAN.IJATION '7-1 mhl808w'ex wpf:1bl082595 1v
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF TABLES Table Title ~Pa e 2.1-1 Design Performance Capability Parameters for Turkey Point Units 3 and 4 2-2 3.2.1-1 Sequence of Events - Uncontrolled RCCA Withdrawal from Subcritical Event .. 3-8 3.2.2-1 Sequence of Events - Uncontrolled RCCA Bank Withdrawal at Power Analysis . 3-17 3.2.4-1 Sequence of Events - Uncontrolled Boron Dilution 3-36 3.2.4-2 Summary of Boron Dilution Analysis Results and Analysis Assumptions....... 3-37 3.2.6-1 Time Sequence of Events Excessive Feedwater Flow at Full Power (Automatic Rod Control) 3%3 3.2.7-1 Time Sequence of Events for Excessive Load Increase Incident 3-51 3.2.8-1 Sequence of Events Loss of Flow Events . 3-69 3.2.8-2 Summary of Results for the Locked Rotor Transient .. 3-70 3.2.8-3 Assumptions Used for Locked Rotor Dose Analysis 3-71 3.2;9-1 Sequence of Events Loss of Load/Turbine Trip Event .. 3-90 3.2.10-1 Time Sequence of Events for Loss of Normal Feedwater Flow .. 3-107 3.2.11-1 Time Sequence of Events for Loss of Non-Emergency AC Power Flow........ 3-114 3.2.12-1 Assumptions Used for Fuel Handling Accident Dose Analysis 3-120 3.2.12-2 Dose Conversion Factors, Breathing Rates and Atmospheric Dispersion Factors .. ... 3-121 3.2.13-1 Assumptions Used for Dropped Cask Dose Analysis 3-124 3.2.14-1 Assumptions Used for Volume Control Tank Rupture Dose Analysis 3-126 3.2.14-2 Noble Gas Average Gamma Energy .. .. 3-127 3.2.15-1 Assumptions Used for Gas Decay Tank Rupture Dose Analysis 3-129 3.2.15-2 Noble Gas Average Gamma Energy and Atmospheric Dispersion Factors 3-130 3.2.17-1 Results of the Rod Cluster Control Assembly Ejection Accident Analysis ... 3-142 3.2.17-2 Sequence of Events RCCA Ejection Accident .. ... 3-143 3.2.17-3 Assumptions Used for Rod Ejection Accident Dose Analysis .. . ~ . 3-144 3.3.1-1 Input Parameters Used in the Large Break LOCA Analysis . 3-158 3.3.1-2 Large Break LOCA Containment Data for PCT Calculation . 3-159 3.3.1-3 Large Break LOCA Fuel Cladding Results .. 3-160 3.3.1C Large Break LOCA Analysis Time Sequence of Events . 3-161 3.3.1-5 Assumptions Used for Large Break LOCA Dose Analysis ~ 3-162 3.3.2-1 Input Parameters Used in the Small Break LOCA Analysis . 3-217 3.3.2-2 Small Break LOCA Analysis Fuel Cladding Results 3-218 3.3.2-3 Small Break LOCA Analysis Time Sequence of Events ~ .. 3-219 3.4-1 SGTR Thermal/Hydraulic Results for Radiological Analysis .. ..... 3-251 3.4-2 Assumptions for SGTR Dose Analysis .. ... 3-252 mA1808wloc.wpf: tb/091295
WESTINGHOUSE NON-PROPRijETMY'LAS,S 3 I.IST OF TA]SLY (cont)
Table Title 3.5.1-1 Nominal Plant Parameters and ituti88 Condition Assumptions for (MSLB MAE Release,s) . 3-261 3.5.2-1 Assumptions Used for SLB Dose Analysis . . 3-'264 3.5.3-1 System Parameters Initial Conditions ...,....... J...... ,. 3-'277 3.5.3-2 Safety Injection Flow Diesel Failure, (Single T'rain) .. ,. 3-278 3.5.3-3 Double-Ended Hot Leg Brealc Bilowdown Mass and Ene'rgy Releases i 3-279 3.5.3< Double-Ended IIot Leg Mass Balance .. ...........,.. , 3-:281 3.5.3-5 Double-Ended iiot Leg Energy Balance . ..'. '...'. '.... ,. 3-'.282 3.5.3-6 Double-Ended Pump Suction Break Blowdown Mash and Energy Relleases ......., . 3-l283 3.5.3-7 Double-Ended Pump Suction Break with Diesel Faihire Reflood Mass and Energy Releases ......................,......,........... . 3-285 3.5;3-8 Double-Ended Pump Suction Break with Diesel Faihire Principle Parameters During Reflood 3-:287 3.5.3-9 Double-Ended Pump Suction Break with Diesel Faihire Post-Reflood Mass and Energy Release,s ., 3-.289 3.5.3-10 Double-Ended Pump Suction Break with Dies>'.I Failure Mass Balance....,...'. '.. .',
3-091,
3.5.3-11 Double-Ended Pump Suction Break with Diesel Failure Energy Balance 3-092'-302 3.5.4-1 Containment Analysis Parameters 3.5.4-2 Containment Heat Sinlc Data.............., . ~ 3-:303 3.5A-3 Thermal Properties of.Contaijnment Heat S.'inks . 3-305 3.5.4-4 Containment Spray Pump Flow .. . 3-:306 3.5.4-5 Emergency Contairunent Cooler Performance Contairunent Integrity Analyses . 3-307 3.5.4-6 1.4 ft'SLB Hot Zero Power with MSCV Failure Sequence Of Events 3-308 3.5A-7 Double-Ended Pump Suction Break Events I +0.'.3 psig with Diesel Failure Sequence
'f i 3-'.309 3.5 4-8 Double-Ended Pump Suction Break I +0.:3 psig with Diesel Failure (Only-'1 ECC)' .'-310' 3.5.4-9 Double-Ended Hot Leg Break Sequence Of'Events .....,........... ...... 3-311 3.5.4-10 Containment Integrity Results ................................. ...... . 3-312 5.4-1 Summary Of The Reactor Protection System Setpoint Changes .
5-18'-20 5.4-2 Summary of'he Engineered Safety Feature. Acttuatiorl System Setpoint, Changes....
mhl808wtoc.wpfu M61295 ,vi
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF FIGURES
~Fi ere Title ~Pa e 3.2.1-1 Nuclear Power Transient During Uncontrolled RCCA Withdrawal From Subcritical 3-9 3.2.1-2 Heat Flux Transient During Uncontrolled RCCA Withdrawal From Subcritical 3-10 3.2.1-3 Hot Spot Average Fuel Temperature Transient During Uncontrolled RCCA Withdrawal From Subcritical 3-11 3.2.1-4 Hot Spot Clad Inner Temperature During Uncontrolled RCCA Withdrawal From Subcritical 3-12 3.2.2-1 Uncontrolled RCCA Withdrawal 60% Power, Minimum Feedback (75 pcm/sec withdrawal rate) 3-18 3.2.2-2 Uncontrolled RCCA Withdrawal 60% Power, Minimum Feedback (75 pcm/sec withdrawal rate) 3-19 3.2.2-3 Uncontrolled RCCA Withdrawal 60% Power, Mnimum Feedback (1 pcm/sec withdrawal rate) 3-20 3.2.2-4 Uncontrolled RCCA Withdrawal 60% Power, Mnimum Feedback (1 pcm/sec withdrawal rate) 3-21 3.2.2-5 Mnimum DNBR vs Reactivity Insertion Rate for Rod Withdrawal at 100% Power .. 3-22 3.2.2-6 Minimum DNBR vs Reactivity Insertion Rate for Rod Withdrawal at,80% Power 3-23 3.2.2-7 Mnimum DNBR vs Reactivity Insertion Rate for Rod Withdrawal at 60% Power .. 3-24 3.2.2-8 Minimum DNBR vs Reactivity Insertion Rate for Rod Withdrawal at 10% Power .. 3-25 3.2.3-1 Dropped RCCA Nuclear Power and Core Heat Flux 3-29 3.2.3-2 Dropped RCCA Pressurizer Pressure and Vessel Average Temperature 3-30 3.2.6-1 Feedwater Control Valve Malfunction Nuclear Power and Core Heat Flux versus Time 3.2.6-2 Feedwater Control Valve Malfunction Pressurizer Pressure and Loop Delta-T versus Time .. 3<5 3.2.6-3 Feedwater Control Valve Malfunction Core Average'emperature and DNBR versus Time ................................... 3-46 3.2.7-1 10% Step Load Increase Mnimum Moderator Feedback, Manual Rod Control 3-52 mA1808wtoc.wpf:1M82595 V11
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF FIGURBi (cont)
~Fi ere Title P~ae 3.2.7-2 10% Step Load Increase Minimum Moderator Feedback, Manual Rod Control 3-.553 3.2.7-3 10% Step Load Increase Meorimum Moderator Feedback, Manual Rod Control 3-54 3.2.7X 10% Step Load Increase Maximum Moderator Feedback, Manual Rod Contrail 3-55 3.2.7-5 10% Step Load Increase Minimum Moderator Feedback, Automatic Rod Control 3-56 3.2.7-6 10% Step Load Increase Minimum Moderator Feedback, Automatic Rod Control 3-57 3.2.7-7 10% Step Load Increase Maxirnumi Moderator Feedback, Automatic Rod Control 3-58 3.2.7-8 10% Step Load Increase Maximum Mioderator Feedback, Automatic Rod Control 3 59 3.2.8-1 Core Flow vs. Time, Complete Loss of Forced Reactor Coolant Flow, (All loops operating, all loops coasting down) . 3-72 3.2.8-2 Nuclear Power and Pressurizer Pre!5sure Transients, Complete Loss o.f Forced Reactor Coolarlt Flow, (All loops bpeIratihg, all Loops coasting down)....... 3-73 3.2.8-3 Average and Hot Channel Heat Flux Transients, Complete Lo!is of Forced Reactor Coolant Flo, (Alll loops opI:rating, all loops coasting down),...... 3-74 3.2.8P DNBR Versus Time, Complete Loss of Forced Reactor Coolant F1ow, (All loops operating, all loops coasting down)......., 3-75 3.2.8-5 Flow Coastdown versus Time, Partial Losis of Fdrced R'eactor Coolant Flowe (All loops initially operating, two loops coasting down) 3-76 3.2.8-6 Nuclear Power and Pressurizer Pressure Transients, Parlkal Loss of Forced Reactor Coolant Fiiow, (All loops initially o+ra6ng, twla loops coasting down) 3-77 3.2.8-7 Average and Hot Channel Heat Flux Transients, Partial Loss of Fiorced Reactor Coolant Flow, (All loops initir!ily'olxIrating,'woldops coasting down) 3-78 3.2.8-8 DNBR versus Time, Partial Loss of Forced Reactor Cot)lant Flow, (All loops initially operating, two loops coasting doikn) ~
3-79 3.2.8-9 Flow Coastdown versus Time, Reactor Coolant Pump Shaft Seizure, (All loops initially operatinge one locked toto') 5-80 3.2.8-10 Nuclear Power ancl RCS Pressure Transients, iReactor C'oolant Pump Shaft Seizure, (All loops initially operating, one 1locked rotor) m:51808wltoc.wpf:tb/082595 vril
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF FIGURES (cont)
~Fi ere Title ~Pa e 3.2.8-1 I Average and Hot Channel Heat Flux Transients, Reactor Coolant Pump Shaft Seizure, (All loops initially operating, one locked rotor) 3-82 3.2.8-12 Clad Inner Diameter Temperature versus Time, Reactor Coolant Pump Shaft Seizure, (All loops initially operating, one locked rotor) 3-83 3.2.9-1 Total Loss of External Electrical Load with Pressure Control, Minimum Reactivity Feedback . 3-91 3.2.9-2 Total Loss of External Electrical Load with Pressure Control, Minimum Reactivity Feedback . 3-92 3.2.9-3 Total Loss of External Electrical Load with Pressure Control, Minimum Reactivity Feedback.........................'.................... 3-93 3.2.9A Total Loss of External Electrical Load with Pressure Control, Maximum Reactivity Feedback........................................... 3-94 3.2.9-5 Total Loss of External Electrical Load with Pressure Control, Maximum Reactivity Feedback 3-95 3.2.9-6 Total Loss of External Electrical Load with Pressure Control, Maximum Reactivity Feedback 3-96 3.2.9-7 Total Loss of External Electrical Load without Pressure Control, Minimum Reactivity Feedback 3-97 3.2.9-8 Total Loss of External Electrical Load without. Pressure Control, Minimum Reactivity Feedback 3-98 3.2.9-9 Total Loss of External Electrical Load without Pressure Control, Minimum Reactivity Feedback .3-99 3.2.9-10 Total Loss of External Electrical Load without Pressure Control, Maximum Reactivity Feedback .. 3-100 3.2.9-11 Total Loss of External Electrical Load without Pressure Control, Maximum Reactivity Feedback . ........ 3-101 3.2.9-12 Total Loss of External Electrical Load without Pressure Control, Maximum Reactivity Feedback . .... 3-102 3.2.10-1 Pressurizer Pressure and Water Volume Transients for Loss of Normal Feedwater ... 3-108 3.2.10-2 Loop Temperatures and Steam Generator Pressure for Loss of Normal Feedwater .... 3-109 3.2.11-1 Pressurizer Pressure and Water Volume Transients for Loss of Offsite Power... .... 3-115 3.2.1 1-2 Loop Temperatures and Steam Generator Pressure for Loss of Offsite Power ... .... 3-116 3.2.17-1 Rod Ejection Transient Beginning of Life, Full Power .. .. 3-146 3.2.17-2 Rod Ejection Transient Beginning of Life, Zero Power .... 3-147 3.3.1-1 Large Break Pumped Safety Injection Flow Rate - 1 HHSI and 1 LHSI Pump .. .... 3-165 mh1808whoc.wpf:1M81295 1X
WESTIiNGHOUSE NON-l?ROPRKTARY CLASS 3 LIST OF .FIGURES (cont)
~Fi ure Title ]~~ae 3.3.1-2 Code Interface Description f'or the Large Break I.OCA Model ..... 3-165 3.3.1-3 Peak Cladding Temperature for Cp>>=OA, Liow Tl<< e... 3-16'7 3.3.1-4 Cladding Temperature at Fuel Rod Burst Location for Cp=0.4 Low TAyo 3g168 3.3.1-5 Local Fluid. Temperature at PCT Ellevation for Cp=0l.4, Low Tokyo....,....... i... 3i169 3.3.1-6 Local Heat Transfer Coefflciient at PCT ElevktioIi fdr Op=0.4 Low TAyp . .... 3~170 3.3.1-7 Local Mass Flllx at PCT Elevatiion for Cp~0.4, Low T)G .... 3-171 3.3.1-8 Local Qualiity at P'CT Elevation for Cp=0.4, Low T<< .... 3-172 3.3.1-9 RCS Pressure During Blowdown for C'p 04 Low TAyp 3A173 3.3.1-10 Decay Heat Dming Blowdown for Cp=4.4, Low T<< . 3-174 3.3.1-1 1 Break Flow During Blowdown for Cp==0.4, Low T<< . 3-17!)
3.3.1-12 Break Energy l..low D~uring Blowdown for, Cp=OA, L'ow TAyo.......... e....' 3A176 3.3.1-13 Core Flow .During Blowdown for Cp+) 4 Low~ TAyo~ .. 3-177 3.3.1-14 Accumulator Flow Dtiring Blowdown for Cp=:0.4, Low Typ . 3-178 3.3.1-15 Core Reflooding Rate for C,;-0.4, I.ow TAya 3-179 3.3.]-16 Core and Downcomer Mxture Ievels iDuring Reflood for Cp=OA>>, Low TAyo... .... 3-180 3.3.1-17 ECCS Flows D~uring Reflood for Cp=0.4, Low Thyo .... 3-181 3.3;1-18 Containment Pressure Truisient for Cp:=OA, Low T<< 3-182 3.3.1-19 Peak Clad Temperature for Cp=0.4, High Tyo ...,........ 3-183 3.3.1-20 Local Fluid TefnPeraeore at PCT Elevation for Cp=0,.4, Kigh TgyG 3-184 3.3.1-21 Local Heat Transfer Coefficient at PCT Elevation for Cp=0.4, Higll TAya 3i185 3.3.1-22 Local Mass Flux at PCT.Elevation .for Cp=-0.4, High T<< 3-186 3.3.1-23 RCS Pressure Dufi,ng Blowdown for C~;-0.4, High 3-187 3.3.1-24 Heat During Bilowdown f'r Cp=0.4,, High T<<
TAyo'ecay 3-188 3.3.1-25 Core Flow During Blowdown for Cp=0.4, High TAyo 3-189 3.3.1-26 Accumulator Flow During Bllowdown f'r Cp=0.4>> Hiigh Typ .. i 3-190 3.3.1-27 Core Reflooding Rate for Cp--OA, High Tokyo . 3-191 3.3.1-28 Core and Downcofner Mixture Levels During Refloo'd f()r Cp=OA>> Higll TAyo '...'. 3-192, 3.3.1-29 Peak Cladding Temperature for Cp=:0.4, LOW Ty'~, 8.5 ft Skewed Power Shape .. .. 3-193 ~
3.3.1-30 Cladding Temperature at.'Fuel Rood Burst Lacsltiofi folr Cp=0.4, Low Typ, 8.5 ft Skewed Power Shape 3-194 3.3.1-31 Local Fluid Ternperattire at PCT Elevation fot'p;-0.'4, Imw TAyo, 8.5 ft Skewed Power Shape . 3-195 3.3.1-32 Local Heat Transfer Coefficient at PCT Elevation foi'=0.4, Iww T~
yo, 8.5 ft Skewed Power Shape 3-196
~,
m:L1808wtoc.wpf:1M81295
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF FIGURES (cont)
~Fi ere Title ~Pa e 3.3.1-33 Local Mass Flux at PCT Elevation for Cp=0.4, Low T>>p 8 5 ft Skewed Power Shape....................... .. 3-197 3.3.1-34 Local Quality at PCT Elevation for Cp=0.4, Low T>>p, 8.5 ft Skewed Power Shape .. 3-198 3.3.1-35 RCS Pressure During Blowdown for Cp=0.4, Low T>>p 8.5 ft Skewed Power Shape . 3-199 3.3.1-36 Decay Heat During Blowdown for Cp=0.4, Low T>>p, 8.5 ft Skewed Power Shape... 3-200 3.3.1-37 Break Flow During Blowdown for Cp=0.4, Low T>>G, 8.5 ft Skewed Power Shape... 3-201 3.3.1-38 Break Energy Flow During Blowdown for Cp=04 Low T>>p 8.5 ft Skewed Power Shape 3-202 3;3.1-39 Core Flow During Blowdown for Cp=0.4, Low T>>0, 8.5 ft Skewed Power Shape ... 3-203 3.3.1%0 Accumulator Flow During Blowdown for Cp=0.4, Low TAya 8,5 ft Skewed Power Shape .. 3-204 3.3.1-41 Core Reflooding Rate for Cp=0.4, Low T>>p, 8.5 ft Skewed Power Shape ..... ... 3-205 3.3.1%2 Core and Downcomer Mixture Levels During Reflood for Cp=0.4, Low TAyG, 8.5 ft Skewed Power Shape 3-206 3.3.1%3 ECCS Flows During.Reflood for Cp=0.4, Low T>>p, 8.5 ft Skewed Power Shape .... 3-207 3.3.1~ Containment Pressure Transient for Cp=0.4, Low Tyo, 8.5 ft Skewed Power Shap e .. 3-208 3.3.2-1 Small Break Hot Rod Power Shape .. 3-220 3.3.2-2 Small Break Pumped Safety Injection Flow Rate - 1 HHSI Pump . .. 3-221 3.3.2-3 Code Interface Description for the Small Break LOCA Model .. 3-222 3.3.2-4 RCS Depressurization Transient, Limiting 3-Inch Break, High TyG 3-223 3.3.2-5 Core Mxture Level; 3-Inch Break, High T>>o .. 3-224 3.3.2-6 Peak Cladding Temperature - Hot Rod, 3-Inch Break, High T>>p 3-225 3.3.2-7 Top Core Node Vapor Temperature, 3-Inch Break, High T>>o 3-226 3.3.2-8 ECCS Pumped Safety Injection - Intact Loop, 3-Inch Break, Higll TAyG 3-227 3.3.2-9 ECCS Pumped Safety Injection - Broken Loop, 3-Inch Break, High T>>o .. 3-228 3.3.2-10 Cold Leg Break Mass Flow, 3-Inch Break, High TAyG .. 3-229 3.3.2-11 Hot Rod Surface Heat Transfer Coefficient - Hot Spot, 3-Inch Break, Higll T>>G .... 3-230 3.3.2-12 Fluid Temperature - Hot Spot, 3-Inch Break, High T>>o............ 3-231 3.3.2-13 RCS Depressurization Transient, 2-Inch Break, High T>>o 3-232 3.3.2-14 Core Mxture Level, 2-Inch Break, Higll T>>G............. 3-233 3.3.2-15 Peak Cladding Temperature - Hot Rod, 2-Inch Break, High TyG 3-234 3.3.2-16 RCS Depressurization Transient, 4-Inch Break, High T>>o 3-235 3.3.2-17 Core Mxture Level, 4-Inch Break, High TAyG . .. 3-236 3.3.2-18 Peak Cladding Temperature - Hot Rod, 4-Inch Break, High TyG .. 3-237 3.3.2-19 RCS Depressurization Transient, 3-Inch Break, Low T>>G .. 3-238 mhl 808whoc.wpf: I M81295
WESTINGHOUSE NON-PRO.PRIETARY CLASS 3 L IST OF FIGURES (cont)
~Fi ere Title 3.3.2-20 Core Mixture Level, 3-Inch Break, .Low TAyo ... 3-239 3.3.2-21 Peak Cladding Temperature - Hot Rod, 3-Inch Break, Low Tyo . ... 3-240 3.5.4-1 DEPS: Diesel Failure Case with 1CSS and 2ECC at PINIT = 0.3 psig Containment Pressure . 3-313 3.5.4-2 DEPS: Die. el Failure Case with 1CSS and 2ECC at PINIT = 0.3 psig Containment Stieam Temperature .. ...... 3-314 3.5.4-3 DEHL: Case with PINIT = 0.3 psig Cont'unment Pressure I 3 'I(151 3.5.4< ,DEHL: Case with PINIT = 0.3 psig Cont unment Steam Temperature ...... 3-316 3.5A-5 DEPS: Diesel Failure w/1CSS and 1ECC at PINIT -'- 0.3 psig Containment Pressure.............. ....... 3-317 3.5A-6 DEPS: Diesel Failure w/1CSS and 1ECC at PINIT m 0.3 psig Containment Steam Temperature .. ..., 3-31S 3.5.4-7 1.4 ft'ZP Steamline Break, MSCV Failure, 2ECCs and Containment Sprays-- Containment Pressure 3-319 mh1808wboc.wpf:IM81295
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF ACRONYMS AC Alternating Current ADV Atmospheric Dump Valves Auxiliary Feedwater ANS American Nuclear Society ART Adjusted Reference Temperature ASME American Society of Mechanical Engineers BAST Boric Acid Storage Tank BELOCA Best Estimate Loss-of-Coolant Accident BOC Beginning of Cycle BOCREC Bottom of Core Recovery BOL Beginning of Life BOP Balance of Plant CCWS Component Cooling Water System CD Discharge Coefficient CDV Condenser Dump Valves CFR Code of Federal Regulations COLR Core Operating Limits Reports CR Control Room CRDM Control Rod Drive Mechanism CSS Containment Spray System CVCS Chemical.and Volume Control System CW Circulating Water DE Dose Equivalent DECL Double-Ended Cold Leg DECLG Double-Ended Cold Leg Guillotine DEG Double-Ended Guillotine DEHL Double-Ended Hot Leg DEHLG Double-Ended Hot Leg Guillotine DEPS Double-Ended Pump Suction DEPSG Double-Ended Pump Suction Guillotine DER Double-Ended Rupture DF Decontamination Factors DNB Departure from Nucleate Boiling DNBR Departure from Nucleate Boiling Ratio DRFA Debris Resistant Fuel Assembly E/C Erosion/Corrosion ECC Emergency Containment Coolers mA1808wtoc.wpf:1b/082595
NtEclTINGHOIJSE NON-PROPRIETARY CLASS 3 LIST'OF ACRONYMS (cont)
ECCFS Emergency C,'ontainment Cooling and Filtering 'Systems ECCS Emergency C,'ore Cooling System ECF Emergency C,'ontainment Filters EFPY Effective Full Power Years EOL End of Life EOP Emergency Operating Procedure EQ Environment ii Qualification Extraction Steam ESF Engineered Safety Feaetires FES Final Envirorunental', Statement FHA Fuel Handling Accident FW Feed water GDC General Design Criteria, HELB High Energy Line Break HHSI High Head Safety Injection HLSO Hot Leg Switchover Horsepower:
HVAC Heating, Ventilation and Air Conditioning ~
ICW Intake Cooling Water LBB Leak Before .Break LBLOCA Large Break Loss of Coola,nt A,ccident LHSI Low Head Safety Injeclion LOCA Loss of Coolant Accident LOMF Loss of Main Feedwater LOOP Loss of Offsite Power LPZ Lowest Popujlation one LTCC Long Term Core Cooling MCC Motor Control Center M&E Mass & Energy '.Release MFS Main Feedwa,ter MS Main Steam MSBV Main Steam Bypass Valve MSCV Main Steam Check Valve MSIV Main Steam Isolation Valve MSLB Main Steam I~ne Break MSR Moisture Separator-Reheater MSSV Main Steam Safety Valve m&1 808'pf:1bt091195 X1V
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF ACRONYMS (cont)
MWD/MTUMegawatt Days/Metric Ton Uranium MWt Megawatt Thermal NCCS Normal Containment Cooling System NEMA National Electrical Manufacturers Association NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission NRV Non-Return Valve NSSS Nuclear Steam Supply System OFA Optimized Fuel Assembly OTET Overtemperature 6 Temperature OPET Overpower 6 Temperature PCT Peak Clad Temperature PDP Positive Displacement Pump PINIT Initial Containment Pressure PLS Precautions, Limitations and Setpoint PORV Power Operated Relief Valve PRT Pressurizer Relief Tank PSV Pressurizer Safety Valve PTS Pressurized Thermal Shock PWR Pressurized Water Reactor RCCA Rod Cluster Control Assembly RCL Reactor Coolant Loop RCP Reactor Coolant Pump RCPB Reactor Coolant Pressure Boundary RCS Reactor Coolant System RHRS Residual Heat Removal System RPV Reactor Pressure Vessel RTDP Revised 'Ihermal Design Procedure RV Reactor Vessel RVHVS Reactor Vessel Heat Vent System RWST Refueling Water Storage Tank SBLOCA SmaH Break Loss of Coolant Accident SFP Spent Fuel Pool SG Steam Generator SGBD Steam Generator Blowdown SGTP Steam Generator Tube Plugging SGTR Steam Generator Tube. Rupture mh1808wtoc.wpf:1M81895 xv
WESTINGHOUSE NON-PROPRIETARY CLASS 3 LIST OF ACR.OMQCS (cont)
SI Safety Injectiori SIS Safety Injection System SLB Steamline Break SFPCS Spent Fuel Pit Cooling System SRV Safety Relief Valve:
STDP Standard Thermal Design Procedure TDF Thermal Design Flow TG Aubine Generator TPCW Turbine Plant Cooliing Waiter UFSAR Updated Final Safety Analysis Report VCT Volume Control Tank WOG Westinghouse Owners Group mh1808w~wpn1b/082595 xvl
WESTINGHOUSE NON-PROPRIETARY CLASS 3 EXECUTIVE
SUMMARY
This report summarizes the evaluations performed to justify the acceptability of increasing the NSSS power rating from the, present level of 2208 MWt to 2308 MWt (2300 MWt core power). Florida Power and Light Company has undertaken a program to uprate Turkey Point Units 3 and 4 to a maximum NSSS power level of 2308.MWt. The originally licensed maximum core power level is 2200 MWt, which corresponds to an NSSS-power output of 2208 MWt when reactor coolant pump thermal output is included. Therefore, the uprating program is designed to increase licensed core power to 2300 MWt, with a total NSSS power output of 2308 MWt. Unless otherwise noted, 100%
power. in this report refers to a core power level of 2300 MWt. The report follows the format and contains similar content to those previously submitted to the NRC on several approved PWR uprate licensing reports. The capability of the NSSS of Turkey Point Units 3 and 4 to operate at uprated conditions was verified in accordance with guidelines contained in Westinghouse topical report WCAP-10263, "A Review Plan for Uprating the Licensed Power of a Pressurized Water Reactor Power Plant." This WCAP methodology was followed by North Anna, Salem, Indian Point ¹2, Callaway and Vogtle for their core power upratings. Gus topical report provided the following criteria which formed the basis for the Turkey Point review:
The review encompassed all aspects of NSSS design and operation which are impacted by the power uprating. The scope of this review included the NSSS safety analyses, the functional capability, of the systems for normal and abnormal plant operations, and the mechanical design of NSSS components and structures.
- 2. Safety analyses were performed to FSAR quality standards, and evaluated in accordance with criteria and standards that apply to the current Turkey Point Units 3 and 4 operating licenses.
- 3. Equipment structural designs were evaluated in accordance with the regulatory requirements, codes, and standards to which the equipment was originally built.
- 4. In general, current NRC approved analytical techniques were used wherever practical to perform analyses required during conduct of the review.
Turkey Point Units 3 and 4, like most PWR plants as originally licensed, have as-designed equipment and system capability to accommodate steam flow rates of at least 5% above the original rating. The increase to higher power is obtained by effective utilization of existing system and equipment margin.
Detailed evaluations of the Nuclear Steam Supply System, engineered safety features, power conversion, emergency power, support systems, environmental issues, design basis accident analyses mh1808whtoc.wpf:tb/082595 xvii
WESTINGHOUSE N()N-PROPRIETAR'Y CLASS 3 and previous licensing evaluations were performed. 'DiiS repurt demonstrates 1hat the, 'IEirkely Point Units 3 and 4 can safely operate at the requested NSSS powet level of 2308 lvtWt.
The approach used was based on comparing the predicted uprating conditions to the original NSSS 2208 MWt licensed conditions to determine system capabi~lity'nd, where available, the remaining margin in the original plant design at the uprated conditions (i.e., did the original desiign "envelope"'he uprate). To assure that the revIiew was based on cutrrent information, the plant modificafionh arid calculations for each, system were reviewed for app]Iicability and inhere included in the anIilydis aIs appropriate. Key plant personnel were consulted and c'urr6nt bperating data was obtained to gain a perspective on plant performance and operating difficulties that could affect. the. capability of the plant at the uprated power level. These concerns were acldressed in the various task evaluatioiis.
Implementing the uprating at 'Dirkey Point will,only requif.e a feiv minor physical modiflcatio& to the plant. Operating parameters are mainly increased in th6 p6weIr 6)nversion systems (e.g., main steam, feedwater and condensate, extraction steam, etc) and then by only approximately (I%, which is Wigan the, systems and equipment capability. Where required,, setpoints will be adjus1ed, plant prodcdhres revised, and tests performed to ensure the safe and reliable'peration of 'the units at the uprated conditions. In addition, the safety analyses provided in'he. FSAR will be updated as refl'eclat.d Lith'his licensing report.
In. accordance with IOCFR50.92, thds uprating evaluation has reviewed the predominant Plant lide&ing challenges, and demonstrates that the new condilions cd be supported without"
~ A significant increase in the probability or consequences of an accident previously evaluated,
~ Creating the possibility of a new or different kind of accident from any accident preliojislg evaluated, or
~ Resulting in a significant reduction in a maf'gi6 of safety.'his thermal power uprating involves no significant ha2Iards e6nsideration.
mh1808wtoc.wpf:1b/D82595 xviii
CHAPTER 1 PROGRAM DESCMPTION
0 0
4l
1.0 PROGRAM DESCRIPTION 1.1 LICENSING 'PERSPECTIVE Florida Power Ec Light Company has undertaken a program to uprate the Turkey Point Nuclear Units 3 and 4 to a maximum NSSS power level of 2308 MWt. 'Ilm original plant was evaluated in most cases for operation at an NSSS power level of 2308 MWt, however, the plant was licensed to operate at an NSSS power level of 2208 MWt. The uprating program is intended to permit operation at the maximum original power level of 2308 MWt.
In addition to uprating, a number of other issues are incorporated in this submittal:
Steam generator tube plugging of 20% (this would be permitted following approval of Best Estimate LOCA methodology)
Allow operation within a+3'F Tavg Increase MSSV and PSV tolerance Turkey Point was licensed in the early 70's as a Westinghouse 3-loop PWR. The review performed shows that the plant continues to meet its licensing basis at the uprated conditions. In many cases the methods and analyses used to demonstrate compliance were upgraded to meet more stringent current NRC criteria. 'Ilie licensing report clearly shows that operation at 2308 MWt will not affect the health and safety of the public.
1.2 PURPOSE AND OBJECTIVES The purpose of this licensing report is to provide the basis for the determination that continued safe plant operation can be achieved at the uprated condition. The licensing basis assessment includes a review of the accident analyses, component design issues related to safety, emergency response guidelines, BOP Systems, Technical Specifications and appropriate sections of the Turkey Point Units 3 and 4 UFSAR.
The objective of this review was to provide the technical bases for the uprating.
1.3 DESIGN AND LICENSING CRITERIA The analyses and evaluations performed in support of the Turkey Point Units 3 and 4 uprating program have been completed in accordance with Westinghouse quality assurance requirements defined in WCAP-8370-A/7800-A, FPL Topical Quality Assurance Report (FPLTQAR 1-76A), and Stone & Webster quality assurance requirements defined in the Stone 2 Webster Standard Nuclear Quality Assurance Program (SWSNQAP 1-74A), which comply with 10 CFR 50 Appendix B criteria.
Equipment reviews and evaluations have been performed in accordance with Westinghouse and industry codes, standards, and regulatory requirements applicable to Turkey Point Units 3 and 4.
mA1808wkhl.wpf:1M81195
Assumptions and acceptance criteria for the various 'accident analyses are addressed in the r6spedtiIe sections in Chapter 3.0.
1.4 SCOPE
SUMMARY
In order to support uprating of I'urkey Point Ltnits 3 and 4 to an NSSS power of 2308 MWt, the NSSS performance pzmneters for the uprating were'calculated for a range of temperature an'd steam generator tube plugging conditions, as described jin Chapter'. Subsequent to development of th'e SG performance parameter, evaluatiion<>> or analyses (dependinp on the extent of the uprating's impact in each area) were performed fair accident analyses, NSSS ancl BOP systems, and NSSS md BOP in the areas listed bielow. For safety-related efforts, the analysts considered the M<j: ok
'omponents, cases most conservative for their re<'pective areas. The basis fOr these determinations and the results of these evaluations and anal yses are presented within this uprating licensing report The list)ng below follows the order in wjhich the topics addressed are presented in this report:
'Ihe following accident analyses were addressni:
~ Non-LOCA
~ Large and Small Break LOCA
~ Steam Generator Tube Rupture
~ Containment Integrity
~ Equipment Qualification
~ Hydrogen Generation The NSSS and Turbine Generator components were addressed as follows:
~ Reactor Vessel
~ Reactor Internals
~ Reactor Coolant Pumps
~ Control Rod Drive Mechanisms
~ Reactor Coolant Piping and Supports
~ Pressurizer
~ Fuel
~ NSSS Auxiliary Systems iComponents
~ 'Brine Generator Components
'Ihe NSSS and Turbine Generator systems were addrkased as f611o~ws:
NSSS Fiuid Systems
~ Control Systems
~ Protection Systems m:u808wwl.wpf:1M81195 1-2
~ NSSS/BOP Interface Systems
~ Turbine Generator Systems The BOP systems and components were addressed as follows:
~ Main Steam System
~ Steam Dump System
~ Condensate and Feedwater System
~ Feedwater Heaters
~ Steam Generator Blowdown System
~ Condensate Polishing, System
~ Feedwater Heater Vent and Drain System Extraction Steam System
~ Turbine Plant Cooling Water System
~ Intake Cooling Water System
~ Control Systems
~ Electrical Systems
~ HVAC Systems
~ Miscellaneous Systems
~ BOP Components The. goal of the analyses.and evaluations presented in this report is to demonstrate that Turkey Point Units 3 and 4 continue to comply with the applicable industry codes, standards, and licensing criteria at. the uprated conditions.
mA1808wMl.wpf:1bN91195'-3
~ll Ol
CHAPTER 2 DETERMINATIONOF NUCLEAR STEAM SUPPLY SYSTEM (NSSS)
DESIGN OPERATING CONDITIONS
ig) 2.0 DETERMINATIONOF NUCLEAR STEAM SUPPLY SYSTEM (NSSS) DESIGN OPERATING PARAMETERS 2.1 DISCUSSION OF DESIGN PARAMETERS 2.1.1 Introduction and Discussion of Input Parameters Design performance capability parameters were developed for the Turkey Point Units 3 and 4 Thermal.
Uprate Program to encompass the following features:
~ NSSS uprated power level of 2308 MWt;
~ A range of primary temperatures, based on the current licensed T,, value of 574.2 + 3'F;
~ A range of steam generator tube plugging-level of 0-20%. (Although, the LBLOCA BASH used a 5% maximum tube plugging level, following approval by the NRC of the Best Estimate LOCA (BELOCA) Methodology, FPL plans to make a submittal to the NRC to take credit for the 20%
tube plugging level.)
To support the uprating for the Turkey Point units, the parameters set(s) used were the most conservative for the affected evaluations and analyses.
2.12 Discussion of Parameter Cases Table 2.1-1 presents the various cases that were provided for use in the uprating analysis. These cases were developed to optimize plant operation and flexibility while at the same time maximizing electrical production. The column labeled "current" reflects the current design conditions at 0% tube plugging, and is provided for comparison only. Cases 1 and 2 provide parameters over the range of reactor vessel T,, values from 571.2 - 577.2'F, with a steam generator tube plugging level of 0%, and a maximum feedwater temperature value of 443'F. Cases 3 and 4 are identical to cases 1 and 2,
.except that the steam generator-tube plugging level assumed is 20% (the effect of this change can be seen in the steam generator parameters).
2.2 CONCL'USIONS The design performance capability parameters which provide RCS parameters for the uprating analyses and evaluations are provided in Table 2.1-1. The set(s) of parameters which were most conservative for the particular analyses or evaluations were used, in order to bound the range of conditions specified in'able 2.1-1.
mh1808wkhl.wpf:1M81195 2-1
TABjlE 2.1-1 Klesign Perfonnance Capability Parameters for Turkey Po,int Uniits 3 and 4 THERMAL DESIGN PARAMEI'ERS Current 6~rated Ca~ 1<
NSSS Power, % 100 104.5 MWt 2208 2308 10'TU/hr 7534 7875.2 Reactor Power, MWt 2200 2300 10 BTU/hr 7506.7 7847'.9 Thermal Design Flow, Loop gpm 89/00 85,000 Reactor Coolant Pressure, psia 2250 2250 Core Bypass, % 4'i (5.0 Case '1 Case 2 Case 4, Reactor Coolant Temperature, "F Core Outlet 604.7 . 611.,3 605.6 '611.3 605.6; Vessel Outlet 602.3 .607.8 .602.0 607.8 602.0 Core Average 576.6 580.5 574A 580.5 574.4 Vessel Average 574.2 577.2 571.2 577.2 571.2 VesseVCore Inlet 546.2 546.6 540A 546.6 540.4 Steam Generator Outlet 546.0 546.4 540.1 546.4 540.1 Stcam Generator Plugging Level % 0 0 0 20 20 Steam Temperature, 'F 516.0 522.8 516.3 515.2 508.6 Steam Pressure, psia 785 832 787 779 736 Steam Flow. 10'b/hr total 9.(io ,10.17 10.1(i 10.16 10.14 Feed Temperature, 'F 436.5 443 443 443 443 Moisture, % max. 0~5 0.25 025 025 005 App. Fouling Factor, h'r. sq. ft. 'F/BTU 0.(6021 0.00005 O.SXX5 0.00005 0.(XXX5 Zero Load Temperature, 'F 547 547 ".i47 547 HYDRAULICDESIGN PAK&HHERS 547'ump Design Point, Flow (gpm)/Head (ft.), 88,500/266 Mechanical Design Flo, gpm .100,400 Minimum'easured Flow, gpm tot:d '264,000 264,000 264,000 264,000 Best Estimate Flow, gpm 93,600 93,600 89,(X)0 89,000 mA1808wtchl.wpf:1b/(81195 2-2
CHAPTER 3 ACCIDENT ANALYSES AND EVALUATIONS
3.1 INTRODUCTION
'111e accident analyses have been re-analyzed or evaluated for the Turkey Point Units to support operation at the uprated NSSS power level of up to 2308 MWt. The thermal design parameters assumed in these analyses may be found in Table 2.1-1. The computer codes and methods utilized for these analyses have all been previously approved by the NRC unless otherwise noted.
3.2 NON-LOSS OF COOLANT ACCIDENT (NON-LOCA) EVENTS AND STANDBY SAFETY FEATURES ANALYSES All of the UFSAR Chapter 14 non-LOCA analyses applicable to the Turkey Point Units 3 and 4 were reviewed to determine their continued acceptability based upon plant operation at the uprated conditions. The following non-LOCA events were either reanalyzed or evaluated for the Dykey Point Units 3 and 4 conditions consistent with the uprated conditions identified in Table 2.1-1.
- 1. Uncontrolled Rod Cluster Control Assembly (RCCA) Withdrawal from a Subcritical Condition (Section 3.2.1)
- 2. Uncontrolled RCCA Withdrawal at Power (Section 3.2.2)
- 3. RCCA Drop (Section 3.2.3)
- 4. Chemical and Volume Control System (CVCS) Malfunction (Section 3.2.4)
- 5. Startup of an Inactive Reactor Coolant Loop (Section 3.2.5)
- 6. Excessive Heat Removal Due To Feedwater System Malfunctions (Section 3.2.6)
- 7. Excessive Load Increase Incident (Section 3.2.7)
- 8. Loss of Reactor Coolant Flow (Section 3.2.8)
Partial/Complete Loss of Forced Reactor Coolant Flow (Section 3.2.8.1)
Locked Rotor/Shaft Break (Section 3.2.8.2)
- 9. Loss of External Electrical Load and/or Turbine Trip (Section 3.2.9)
- 10. Loss of Normal Feedwater (Section 3.2.10)
- 11. Loss of Non-Emergency AC Power to the Plant Auxiliaries (Section 3;2.11)
- 12. Main Steam Line Break Core Response (Section 3.2.16)
- 13. Rupture of a Control Rod Drive Mechanism Housing - RCCA Ejection (Section 3.2.17)
All of the above events were reanalyzed except for those detailed in Sections 3.2.5 and 3.2.16. The evaluations of all events are detailed in their respective licensing report sections. The analyses incorporating Revised Thermal Design Procedure (RTDP) (References 1 and 2), are the current licensing basis analysis for Turkey Point Units 3 and 4. Startup of an Inactive Coolant Loop was considered in the original design bases for the plant. However, subsequent to initial plant operation, a change to the allowable plant operating conditions was made to prohibit operation at power with a loop out of service (i.e., N-1 loop operation). The current Technical Specifications require that all three (3) reactor coolant pumps be operating for reactor power operation and prohibits operation with an inactive loop. Therefore, since N-1 loop operation is prohibited at power, the startup of an inactive reactor coolant loop event as considered in the original plant design bases is precluded. The main mA1808wM3a.wpf:1bt091195 3-1
steam line break core response limiting event was analyzed at hot. zero power conditions, and is therefore not affected by uprating. AN)
All non-LOCA licensing basis anal yses have been analyzed using NRC approved methods and computer codes. 'lite results of all'of, the analyses and evaluafions demonstrate that applicable safety analysis acceptance criteria ltave been, satisfied at th6 Vprated cotiditions detailed in Table 2.1-1.
References
- 1. Friedland, A. J. 8utd Ray, S., "Revised Tiher1nal Desigh Pt.oct'Jure," WCAP-11397-P-A WCAP-11397-A (Non Prolprietary), April 1989. 'Proprietary),
- 2. NRC Letter, T. F. Plunkett (FPL) to, USNRC, "Proposed License Amendments - Implementation of the Revised Tlhertnal Design Procedure and Steam Generator Water Level Low-Low SetIpoiht,"'-95-131, dated iNiay 5, 1995.
m:u 808wkh3awpf: Ib$82195 3-)
3.2.1 Uncontrolled RCCA Withdrawal From A Subcritical Condition 3.2.1.1 Identification of Causes and Accident Description A rod cluster control assembly (RCCA) withdrawal incident is defined as an uncontrolled addition of reactivity to the reactor core by withdrawal of rod cluster control assemblies resulting in power excursion. While the probability of a transient of this type is extremely low, such a transient could be caused by operator action or a malfunction of the reactor control rod drive system. This could occur with the reactor either subcritical or at power. The "at power" case is discussed in Section 3.2.2.
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 RCCA withdrawal or by reducing the core boron concentration. RCCA motion can cause much faster changes in reactivity than can be made by changing boron concentration.
'Ihe rods are physically prevented from withdrawing 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 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 analyzed in the detailed plant analysis assuming the simultaneous withdrawal of the combination of the two rod banks with the maximum combined worth at maximum speed which is well within'the.capability of the protection'ystem to prevent core damage.
Should a continuous RCCA withdrawal be initiated and assuming the source and intermediate range indication and annunciators are ignored, the transient will be terminated by the following automatic protective functions.
A. 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. It is automatically blocked when either the intermediate or power range flux channel indicates a flux level above the source range cutoff level. It is automatically reinstated when both intermediate and power range channels indicate a flux level below the source range cutoff power level and the bypass switch is returned to the normal position.
B. Intermediate range rod stop - actuated when either of two independent intermediate range channels indicates a flux level above a preselected, manually adjustable value. This rod stop may be manually bypassed when two out of the four power range channels indicate a flux level above approximately 10 percent of the full-power flux. It is automatically reinstated when three of the t
four power range channels are below this value.
C. 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 m:11808wlch3a.wpf:1bj'081895 3-3
may be manually bypassed, when two of the four power ange channels are reading abo've 10 perceint of the full-power flux. and is automatically reinstated when three of the
'pproximately channels inclicate a, flux level below this value.
'our D. Power range flux. level trip (low setti:ng) - actuated when two out of the four power range channels indicate a flux level above approximately'25'percen't of the full-power flIux. 'Htus trip function may be mainually Ibypassed when two of the four power range channels indicate a flux level above approximately 10 percent of the full-power flux and is automatically reinstated when three of the four channels indicate a flux level below this value.
E. Power range flux. level trip (hi,gh settiing) - actuated when two out of the four povver range channels indicate a power level above a preset setpoint, usually <169 percent of the full-power flux. This trip function is always active.
The neutron flux response to a continuous reactivity insertion is characterized by a very fast flux increase terminated by the reactiviep feedback effect of the negative Doppler coefficient. This self-limitation of the initial power increase, results from a fast negative fuel temperature feedback (Doppler effect) and i:s of'riime impoiitance during a suirtup transiient since iit liinits the power tO a tolerable level prior to external control action., After the initial power increase, the nuclear power is momentarily reduced and then if the incident is not terntiinated by a reactor trip the nuclear power increases again, but at a'much slower rate.
Termination of the startup transient by the above protection channels prevents core damage. In addition, the reactor trip from high pressurizer pressure serves as backup to terminate the event before an overpressure condition could occur.
32.12 Input Parameters and Assumptions The accident analysis em]ploys the Standard Thermal Design Procedure (STDP) methodology The RTDP methodology does not apply to zero power events because the DNBR sensitivitiies used to define the design limit DNBR value do not extend to the zero povver condition. The use of STDP methodology stipulates that the iReactor Coolant System (RCS) flow rate will be based on a fraction of the Thermal Design Flow for two RCPs operating and that the RCS pressure is at a conservatively low value which accounts for uncertainty due to iiistotiment l:rror. Sinew the event is analyzed from hot ~
zero power, the steady-state STDP uncertainties on core power and RCS average temperature're! not considered in defining the initial conditions.
In order to obtain conservative results for the analysis of the uncontrolled RCCA bank withdrawal from subcritical event the following assumptions are. made concerning the initial reactor conditions:
mxi 808w~a.wpf:1bf081895
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 power reactivity coefficient, the least negative design value is used.
B. 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 moderator is much longer than the nuclear flux response time constant. However, after the initial neutron flux peak, the succeeding rate of power increase is affected by the moderator reactivity coefficient.
Accordingly, the most-positive moderator temperature coefficient is used since this yields the maximum rate of power increase.
The analysis assumes the reactor to be at hot zero power conditions with a nominal temperature of 547'F. This assumption is more conservative than that of a lower initial system temperature (i.e, shutdown conditions). The higher initial system temperature yields a larger fuel-to-moderator heat transfer coefficient, a larger specific heat of the moderator and.fuel, and a less-negative (smaller absolute magnitude) Doppler coefficient. The less-negative Doppler coefficient reduces the Doppler feedback effect, thereby increasing the neutron flux peak. The high neutron flux peak combined with a high fuel specific heat and larger heat transfer coefficient yields a larger peak heat flux. The analysis assumes the initial effective. multiplication factor (Ke<f) to be 1.0 since this results in the maximum neutron flux peak.
D. Reactor trip is assumed on power range high neutron. flux (low setting). The most adverse combination of instrumentation error, setpoint error, delay for trip signal actuation, and delay for control rod assembly release is taken into account. The analysis assumes a 10 percent uncertainty in the power range flux trip setpoint (low setting), raising it from the nominal value of 25 percent to a value of 35 percent; no credit is taken for the source and intermediate range protection.
Figure 3.2.1-1 shows that the rise in nuclear power is so rapid that the effect of error in the trip setpoint on the actual time at which the rods release is negligible. In addition, the total reactor trip reactivity is based on the assumption that the highest worth rod cluster control assembly is stuck in its fully withdrawn position.
The maximum positive reactivity insertion rate assumed is greater than that for the simultaneous withdrawal of the two sequential control banks having the greatest combined worth at the maximum speed (45 in/min, which corresponds to 72 steps/min).
The DNB analysis assumes the most-limiting axial and radial power shapes possible during the fuel cycle associated with having the two highest combined worth banks in their highest worth position.
The analysis assumes the initial power level to be below the power level expected for any shutdown condition (10 ~ fraction of nominal power). The combination of highest reactivity insertion rate and low initial power produces the highest peak heat flux.
m:u808wkh3a.wpf: Ib/081895 3-5
3.2.13 Description of Analysis The analysis of the uncontro'lied. RCCA bank withdrawal ftom subcriticality is performed in thr~:e stages. First, a spatial neutron ldnetics computer code, TWIN]KLE(Reference 1),:is used to 'cah~ulaite the core average nuclear power transient, i,ncluding the various core feedback effects, .i.e., DOppler And moderator reactivity. Next, the FACTIVE computer etude'(R~!fer'enc'e 2) uses the average nuclear power calculated by I'WINKLEand performs a fuel rod tnnsient heat transfer calculation to determine the average heat flux and temperatulre Iransients. Finally, the Itveiagd heat flux calculated by FACIRAN is used in the, TIIINC-IVcomputer code (References 3 &; 4) for transient DNBR calculations.
3.2.1.4 Acceptance Criteria The uncontrolled rod cluster controii assembly baink witlltdratwai fromm subcritical event is considered an ANS Condition II event, a fault of moderate frequency, land is ~analyzed to ensure that the core and reactor coolant system are not adversely aIXected. This is demonstrated by showing that there is litIIe likelihood of DNB and core endamage. It must also be shown stat the peak hot spot.'fuel and clacl temperatures remain within acceptable limits, although f'r this event, the heat up is relatively sntaH 32.1$ Results The calculated sequence of events'is shown in Table 3.2.1-1. The'ransient results are shown in Figures 3.2.1-1 through 3.2.1P. The results of the analysis determined that the DNBR safety analysis limit was met and that the peak fuell centerline te.mperaeure was less than the temperauttre at which fuel melt occurs. The peak clad surface temperature is considerably less than 2700 F.
3.2.1.6 Conclusions In the event of an RCCA withdrawal event from the subcriIical condition, the core and the RCS are not adversely affected since the combination of thermal power,and coolant temperature result's i6 a DNBR greater than the safety analysis limIit vttlud. Furthermore, since the maximum fuel 'inimum temperatures predicted to occur during this event are mtfch Iles'horn those required for clad clamage (2700'F) or fuel (4800'F) melting to occur, no cladding'r fue1l damage is predicted as a result of ttus transient at the uprated conditions.
mh1808wM3a.wpf:1bj'081895 3-6
3.2.1.7 References
- 1. Barry, R. F., Jr. and.Risher, D. H., "TWINKLE, a Multi-dimensional Neutron Kinetics Computer Code," WCAP-7979-P-A, January 1975 (Proprietary) and WCAP-8028-A, January 1975 (Non-proprietary).
- 2. Hargrove, H. G., "FACTRAN - A FORTRAN-IV Code for Thermal Transients in a UO> Fuel Rod," WCAP-7908, December 1989.
- 3. Chelemer, H., and Hochreiter, L. E., "Application of the THINC-IVProgram to PWR Design,"
WCAP-8195, February 1989.
- 4. Chelemer, H., Chu, P. T., and Hochreiter, L. E., "THINC-IV- An Improved Program for
'dermal-Hydraulic Analysis of Rod Bundle Cores, "WCAP-7956, February 1989.
i mh1808wkh3a.wpf:1bj'081895'-7
Table 3.2.1-1 Sequence of Events - Uncontrolled RCCA Withdrawal from Subcritical Event Event Ti mense Initiation of Uncontrolled RCCA %ithdraival 0.0 Power Range High Neutron Flux, Low Setpoint Reached 10.:31 Peak Nuclear Power Oc'ctirs 10.45 Rods Begin to Fall 10.81 Mnimum DNBR occurs 12.:38 Peak Average Clad Temperature Occurs 12.156 Peak Average Fuel Temperature Occunl 12.!36 Peak Fuel Centerline Temperature Occurs 14.41 IA1808wMh3awpf: Ib/081595 3-8
2 10 1
10 IC Z 0 QJ g
pp 10 Q. .IL IL p 4 Z 5p 10 Z 4 C
10 10 20 TIME (SECONDS)
Figure 3.2.1-1 Nuclear Power Transient During, Uncontrolled RCCA Withdrawal From Subcritical mh I 808w~a.wpf: I b/08 I 595 3-9
.S z4 X p Z
- g. L
.I P C.Z Ill p X I 0
fc
~ ~ ~ ~ I I I I ~ '
0 .1IO 1I5 BIO TlMIE (SECONDS)
Figure 32.X-2 Heat Flux Transient During UncontrOlled RCCA Withdrawal Subcritical 'From mhl808wM3a.wpf:1b/081595 3-10
I IC I- cl III ~
ao C
0' 5, 10 l5 20 TIME (SECONDS)
Figure 3.2.1-3 Hot Spot Average Fuel Temperature Transient During Uncontrolled RCCA Withdrawal From Subcritical m:II808w4%3a.wpf: I b/081595 3-11
W L
D I
C C
W W CI C 0 W
Z z
D 500 0
~ ~ I ~
~ ~ ~ ~
~, 10
~, ~, t, ~
~ ~ ~ ~
~ a,, ~, ~
TIIVIE (SECOIND!W)
Figure 3.2.]!-4 Hot Spot Clad Inner Temperature During uncontrolled RCCA Withdrawal Fr(lm Subcritical mhl808wMh3a.wpf: Ib/08 I 595 3-12
3.2.2 Uncontrolled RCCA Bank Withdrawal At Power 3.22.1 Identification of Causes and Accident Description An uncontrolled RCCA withdrawal at power which causes an increase in core heat flux may result from faulty operator action or a malfunction in the rod control system. Immediately following the initiation of the accident, steam generator heat removal rate lags behind the core power generation rate until the steam generator pressure reaches the setpoints of the steam generator relief or safety valves.
This imbalance between heat removal and heat generation rate causes the reactor coolant temperature to rise. Unless terminated, the power mismatch and resultant coolant temperature rise could eventually result in DNB and/or fuel centerline melt. Therefore, to avoid damage to the core, the reactor protection system is designed to automatically terminate any such transient before the DNBR falls below the safety analysis limit value or the fuel rod linear heat generation rate (kw/ft) limit is exceeded.
The automatic features of the reactor protection system which prevent core damage in an RCCA bank withdrawal incident at power include the following.
A. Power range high neutron flux instrumentation actuates a reactor trip on neutron fiux if two-out-of-four channels exceed an overpower setpoint.
B. Reactor trip actuates if any two-out-of-three hT channels exceed an overtemperature hT setpoint.
This setpoint is automatically varied with axial power distribution, coolant average temperature, and coolant average pressure to protect against DNB.
C. Reactor trip actuates if any two-out-of-three bT channels exceed an overpower hT setpoint. IMs setpoint is automatically varied with coolant average temperature so that the. allowable heat generation rate (kw/ft) is not exceeded.
D. A high pressurizer pressure reactor trip, actuated from any two-out-of-three pressure channels, is set at a fixed point. 'Ihis reactor trip on high pressurizer pressure is less than the set pressure for the pressurizer safety valves.
E. A high pressurizer water level reactor trip actuates if any two-out-of-three level channels exceed a fixed setpoint.
Besides the above-listed reactor trips, there are the following RCCA withdrawal blocks. These are not credited in accident analyses.
A. Kgh neutron flux (one-out-of-four power range)
B. Overpower hT (two-out-of-three)
C. Overtemperature bT (two-out-of-three) mh1808wM3a.wpf:1W081895 3-13
3.222 Input Parameter and Assumptions A number of cases were analyzed assuming a range of reactivity insertion for both minimum and maximum reactivity feedback at various power levels. Yhe'cases presented in Section 3.2.2.5 are representative for this event.
For an uncontrolled RCCA bank withdrawal at power ac'rid'ent,'he analysis assumes the following conservative assumptions:
A. IMs accident is analyzed with the Revised Thermal Dit.sign Prob:dute (Reference 2). Therefore, initial reactor power, pressure, and RCS temperatures are assumed th be at their nominal valueC.
Uncertainties in initial conditions are .included in the limit DNBR.
B. For reactivity coefficients, two cases are ana'iyzed.
- 1. Minimum Reactivit~Feedback A+7 pcm/'F tnoderator,'temperature coefficient and a least-negative Doppler-only power coefliicient form the basis of the beginning-of-life minimum reactivity feedback assumption.
- 2. Maximum Reactivit~Feedback A conservatively large positive moderator density coefficient of 0.5 bR/gni/cc (corresponding to a large negative~ m'ode'rator temperature coefficien) and a most-negative Doppler-only power coefficient form the basis of the end-of-life maximum reactivity feedback assumption.
C. The reactor trip on high neutron flux is assumed to~be ~actuated at a conservative value of 118%
of nominal full power. The, bT trips include all advers'e insta'>mt!ntation and setpoint errors,, while the delays for the trip signal actuation are assumed 'at their mhxirnum values.
D. The RCCA trip insertion characteristic is based on the assumption that the highest-worth.
assembly is stuck in its fully withdrawn position.
E. A range of reactivity insertion rates are exMiuned. Vhtt; maxiitnum positive reactivity insertion rate is greater than that which would be obtained from the simultaneous withdrawal of the two control rod banks having the maximum combined worth at a conservative speed (45 in/~n, which corresponds to 72 steps/min).
F. Power levels of 10%, 60%, 80%, and 100% are considered.
The effect of RCCA movement on the axial core power distribtition is accounted for by causing a decrease in overtemperature RENT trip setpoint proportional to a decree in margin to DNB.
mh1808wM3a.wpf:lb'081895 3-14
3.2.29 Description of Analysis The purpose of this analysis is to demonstrate the manner in which the protection functions described above actuate for various combinations of reactivity insertion rates and initial conditions. Insertion rate and initial conditions determine which trip function occurs first.
The rod withdrawal at power event is analyzed with the LOFTRAN computer code (Reference 1).
The program simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and main steam safety valves. The program computes pertinent plant variables including temperatures, pressures, power level, and departure from nucleate boiling ratio (DNBR).
3.22.4 Acceptance Criteria Based on its frequency of occurrence, the uncontrolled RCCA bank withdrawal at power accident is considered a Condition II event as defined by the American Nuclear Society. The following items summarize the acceptance criteria associated with this event.
The critical heat flux should not be exceeded. This is ensured by demonstrating that the minimum DNBR does not go below the limit value at any time during the transient.
Pressure in the reactor coolant and main steam systems should be maintained below 110% of the design pressures. With respect to peak pressure, the uncontrolled RCCA bank withdrawal at power accident is bounded by the loss of load/turbine trip analysis. The loss of load/turbine trip analysis is described in Section 3.2.9.
The protection features presented in Section 3.2.2.1 provide mitigation of the uncontrolled RCCA bank withdrawal at power transient such that the above criteria are satisfied.
3.229 Results Figures 3.2.2-1 and 3.2.2-2 show the transient response for a rapid RCCA bank withdrawal incident (75 pcm/sec) starting from 60% power with minimum feedback. Reactor trip on high neutron flux occurs shortly after the start of the accident. Because of the rapid reactor trip with respect to the thermal time constants of the plant, small changes in T,pg and pressure result in the margin to DNB being maintained.
The transient response for a slow RCCA bank withdrawal (1 pcm/sec) from 60% power with minimum feedback is shown in Figures 3.2.2-3 and 3.2.2-4. Reactor trip on overtemperature bT occurs after a longer period and the rise in temperature is consequently larger than for rapid RCCA bank withdrawal.
Again, the minimum DNBR is greater than the safety analysis limit value.
mh1808wM3a.wpf: IbN81895 3-15
Figure 3.2.2-5 shows the minimum DNBR as a function of reactivity insertion rate from 100% power.
for both minimum aod maxiimum reactivity feedback. it dan he keen that the two reactor utp fitnctiont (high neutron flux and overtemperature AT) pro vide DNB protection over the whole ange of reactiivity insertion rates. The minimum DNBR is never less than tlte safety attalgsis limit value.
Figures 3.2.2-6, 3.2.2-7, andi 3.2.2-8 show the minimum DNBR ais a function of reactivity ittsertion'ate for RCCA bank withdrawal-incidents starting at 8()%, 60%, and 10% power, respectively. The results are similar to the 100% power case; however, as the initial power decreases, the range o'ver which the overtemperature AT trip is effective is increased. Ih nOne of these cases does the DHBIII.
fall below the safety analysis liimit value (typical cell 1.43,, thimble cell 1.42).
A typical calculated I:quence of events for two cases iS shown oh Table 3.2.2-1. With the reactor tripped, the plant eventually returns to a stable conclition. The plant may substguently be cooled, down further by following nor1nal plant shutdown promdureS.
3.22.6 Conclusions The high neutron flux and ovevtemperature AT reactor trip functions prctvide adequate protection over the entire range of possible reactivity i,nsertion rates (i.e., the minimum value of DNBR is always larger than the safety analysis li,mit value). '1>e RCS and main steain systems are maintained below 110% of the design pressures. 'Therefore, the results of. th6 any'sis show tlhat an uncontrolled RCCA withdrawal at power idoes not adversely affect the core,', the RCS,'r the main steam system and all applicable criteria are met.
3.22.7 References
- 1. Burnett, T. W. T., et alta "LOI'TR~I Code Description," WCAP-7907-P-A (Proprietary),
WCAP-7907-A (Non-proprietary), April 1984.
- 2. Friedland, A.J. and Ray, S, "Revised Thermal Design Procedure," WCAP-11397-P-A (Proprietary), WCAIP-11397-A (Non-proprietary), April 1986.
I:u808wM3a.wpf:tb/08259!i 3-16
Table 3.22-1 Sequence of Events - Uncontrolled RCCA Bank Withdrawal at Power Analysis Case Event Time sec 60% Power Initiation of Withdrawal 0.0 Minimum Feedback High Neutron Flux Setpoint Reached 5.11 75 pcm/sec Rods Begin to Fall 5.61
.Minimum DNBR Reached 7.20 60% Power Initiation of Withdrawal 0.0 Minimum Feedback Overtemperature AT Setpoint Reached 100.14 1 pcm/sec Rods Begin to Fall 102.14 Minimum DNBR Reached 103.2 mA1808w4k3awpf:1b/082595 3-17
1.4 1.2 fg Z W CD cD Z .8
.6
.4
.2 4 8 8 10 TBK (SECONDS).
2380 2360 g 2340
- p. 2320 2300 2280 2260 2240 4'
10 T1IME (SEC01mS)
Figure 3.22-1 Uncontrolled RCCik Withdrawal 60% Power, Miniimum Feedback (75 pcm/sec wiithdrawal rate) mhl808wW3a.wpf: l b%82595 3-18
6 1'0 800 590 580 570 560 550 6 10 T1ME (sgcoms) 3.5 2 '
2 1,.5 0 10 T1ME (smcoms)
Figure 3.22-2 Uncontrolled RCCA 'Withdrawal:60% Power, Minimum Feedback (75 pcm/sec withdrawal rate)
.mhl808w'4%3@.Ntpf: I bi'082595 3-19
1 '
1.2 gg K gX Cl ~ .8 faa O
6'2 20 40 50 80 100 120 TIME (SECONDS) 2400 2350 2300 g.' 2250 2200 g
2150"
.2100 2050 0
I ~
20
~
~40. ~
50 50 100 120 I
TEIL (SECONDS)
Figure 3.22-3 1Uncontrolled RCCAi Withdrawall 69% Power,, Minimum Feedback (I pcm/sec witlhdrawal rate) mA1808wM3a.wpf: I bl08259!i 3-20
620 810 g
'600 500
'I
~m 58O gg 570 C)
O 560 550 0 20 80 '80 100 120 TQtE (SECONDS) 3.5 2.5 2,
1.5 0 20 80 8'0 100 120 nm. (SECONDS)
Figure 3.22M Uncontrolled RCCA Withdrawal 60% Power, Minimum.Feedback (1 pcm/sec withdrawal rate) mhl808whh3a.wpf: lb/082595 3-21
2.1 2
A 1.9 OTI)T TRP l.8 1.7 0 8 10 10 10 10 REACTIVITY INSERTION (PCM//SEC) 2.1 HIGH KUX TRD~
1.9 1.8 1.7 I ~ ~ ~
I
~
ll 0 8 10 10 10 10 REACTIVTTY INSERTION (PCM/SEC)
Figure 322-Ei Minimum DNBR vs Reactivity Insertion Rate For Rod Withdrawal at 100% Power mal 808wkh3a.wpf: I b/08259S 3-22
2.8 A
2.4 hd'Q>
2 1.8 I.B 0 0 1
10 10 10 10 REACTIVI'IY'NSERTION (PCM/SEC) 2.
8'L aCl h4 lQ A
Cal 2.2 Cae HIGH .FLUX TRIP K
1.8 1.8 I 0 1 0 10 10 10 10 REhCTIVI'Pl INSERTION (PCM/SEC)
Figure 3.22-6 Minimum DNBR vs Reactivity Insertion Rate For Rod Withdrawal at S0% Power mAI808wkh3a.wpf: lb/082595 3-23
3.2 K 2.8 A
h4 2.6 2.2 . OTDT TRIP 5i
'1.8 1.6
.0 8 10 10 10 10 HEACTIVlTY INSERTION (PCM/SBC) 3.
2
2.8 hd 2.6 Pl W
2.4 Cae OTDT TRIP 2.2 IIIGII FLUX TEHP K
1.8 f
1.8 ~ ~
~~~
0 1 10 10 10 10 Rmermm IMZarrON (PCM/SBC)
Figure 3.22-7 Minimum!DNBR vs Reactivity Insertion Rate For Rod Withdrawal at 60% Power mhl808wMh3a.wpf: I b/082595 3 24
Ch.
h4 3.5 2.5 1.5 10 1
10 0
1'0'0 REACTIVITY INSERTION (PCM/SEC) 2 4
3.5 3
K 2.5 1.5 1 0 8 10 10 10 10 REACTIVITY INSERTION'PCM/SEC)
Figure 3.22-8 Minimum DNBR vs Reactivity Insertion Rate For Rod Withdrawal at 10% Power mhl808w'eh3a.wpfnb/082595 3-25
323 Rod Cluster Control Assembly (RCCA) Drop 3.29.1 Identification of Causes and Accident Description Dropping of a full-length RC',CA is assumed to be initiated by a siingle elIectrical or mechanical failure which causes any number and combination of rods from the same group of a given control bank to ~
drop to the bottom of the core. The resul1ing negatiive IIeadtivity inse'rtio'n causes nuclear poAer 'to decrease. An increase in thee hot channel factor may occut due tO the skewed power 'apidly distribution representative, of a dropped rod amQguration. For this cvenl' it must be shown that the DNB design basis is met for the combination of Ipower, hot channel factor, and other system which exist fojllowing dropped rod., 'onditions If an RCCA drops into the core during power operation,, it may be detected by,a rod bottom signal, an excore detector, a rod position indication, or the NIS inStruimentatiion. The rod bottom signal device provides an indication signal for each RCCA. The other independent indication of a dlropped RCCA is~
obtained by using the out-of-core power rtuige channel signals! This rod drop detection circuit is actuated upon sensing a rapid decrease in local flux and is designed such that normal load va~riations do not cause it to be actuated.
3232 Input Parameters and Assumptions For a RCCA(s) Drop, the analysis assumes the following chnsil.rvdtive assumptions,.
A. This event is anajlyzcd with the Revised Thermal Design Procedure (Reference 3). 'Iherlefote, initial reactor power, prcssure, and RCS temperature ate assumed at their nominal valueS.
Uncertainties in i.nitial conditions are inclIudcd in the limit. DNBR.
B. A range of moderator temperature coefficients from 0 pcrn/'F to -35 pcm/'F was analyzed. An evaluation was performed to bound a+1 pcrn/'I -MTC at hot full power conditions.
C. A range of negative reactiviity insertions from 100 Penh'to 1000 pcm are assumed to simulate the Dropped RCCA event.
D. Automatic rod withdrawal is disabled at Turikey Point IUrdts 0 and 4. Therefore, the RCCA drop event for Turkey Point is analyzedl assunIung m8uiu'il rhd control.
3.293 Description of the Anallysis The transient following a dropped RCC'A event is determined by a, detailni digital simulation of the plant. The dropped rod causes a step decrease in reactivity and the core power generation is determined using the LOFTRAN code (Reference 1). TIIie code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief andI safety valves, pressuriZer Spray, Steam generator, and steam'genera'tor 3-215 'h1808wkh3a.wpf:1bf08249$
safety valves. The code computes pertinent plant variables including temperatures, pressures, and power level. Since LOFTP~ employs a point neutron kinetics model, a dropped rod event is modeled as a.negative reactivity insertion corresponding to the reactivity worth of the dropped rod(s) regardless of the actual configuration of the rod(s) that drop. The system transient is calculated by assuming a constant turbine load demand at the initial value (no turbine runback) and no control bank withdrawal. Because the plant is assumed to be in manual rod control (i.e., automatic rod withdrawal is disabled), the plant will establish a new equilibrium condition. The equilibrium process is monotonic in that there is no significant power overshoot without control bank withdrawal.
Statepoints are calculated and nuclear models are used to obtain a hot channel factor consistent with the primary system conditions and reactor power. By incorporating the primary conditions from the transient and the hot channel factor from the nuclear analysis, the DNB design basis is shown to be met. The transient response, nuclear peaking factor analysis, and DNB design basis confirmation are performed in accordance with the dropped rod methodology described in WCAP-11394 (Reference 2).
329.4 Acceptance Criteria Based on its f'requency of occurrence, the RCCA(s) drop event is considered a Condition II event as defined by the American Nuclear Society. The primary acceptance criterion for the RCCA(s) drop event is that the critical heat flux should not be exceeded. This is demonstrated by precluding Departure from Nucleate Boiling (DNB).
3.23$ Results For the dropped RCCA event, with no automatic rod-withdrawal, power may be reestablished by reactivity feedback.
Following.a dropped RCCA(s) event, with no automatic rod withdrawal, the plant will establish a new equilibrium condition. Figures 3.2.3-1 and 3.2.3-2 show the transient response for representative dropped RCCA(s) case. Uncertainties in the initial conditions are included in the DNB evaluation as described in Reference 2. In all cases, the minimum DNBR remains greater than the limit value, therefore the acceptance criteria is met.
3.23.6 Conclusions Following a dropped RCCA(s) event, without automatic rod withdrawal, the, plant will return to a stabilized condition at less than or equal to the initial power. Results of the analysis show that a dropped RCCA event does not adversely affect the core, since the DNBR remains above the limit value for a range of dropped RCCA worths.
mA1808wMBa.wpf:Ib/082495 3-27
3.23.7 References
- 1. Burnett, T. W. T'., et al,'"LOE'TRAN Code Description", WCAP-7907-P-A (Proprietary),.
(Non-BI'oprietary); April 1984 'CAP-7907-A
- 2. Haessler, R.L., et al'Methodology for the Anrdys'is of the Dropped Rod Event", WCAP-11394 (Proprietary) and WCA:P-,.11395 (Non-Proprietary), April 1987.
- 3. Friedland, A3., and Ray, S., "Revised Thermal Delsigti Prbceklurh", WCAP-11397-P-A (Proprietary), WCAP-1 Jl397-A (Non-'.Proprietary), April 1989.
m%1 808 wM3a.wpf:tb/082095 3-28
1.4 1.2 1
gS
.8 mm .6
.2 50 100 150 200 mZ (SECONDS) 1.4 1.2
.2 50 100 150 200 TGK (SECONDS)
Figure 3.23-1 Dropped RCCA Nuclear Power and Core Heat Flux mhl808wRh3a.wpf: Ib/08 895 1 3-29
2600 ga 2400 g
g Pn 2200 2000 1800 0 50 100 150 200 TBE (SECONDS)l 660 640 g
620 gu 600 p 580 560 540
~ p
+
50 100 150 200 nm (SXCONZlS)
Figure 3.23-2 Dropped RCCA Pressurizer PreSsulre And Vessell Average Teimperaturk mhl 808wkh3a.wpf: I bf081895 3-3O
3.2.4 Chemical And Volume Control System (CVCS) Malfunction 3.2.4.1 Identification of Causes and Accident Description Reactivity can be added to the core by feeding primary grade water into the Reactor Coolant System (RCS) via the reactor makeup portion of the Chemical and Volume Control System (CVCS). 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 the RCS boron concentration. 'Ilie CVCS is designed to limit, even under various 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.
There is only a single, common source of primary water makeup to the RCS Rom the primary water makeup system, and inadvertent dilution can be readily terminated by isolating this single source. The operation of pumps which take suction Rom the primary water makeup tank provides the only supply of makeup water to the RCS. In order for makeup water to be added to the RCS, the. charging pumps must be running in addition to the primary water makeup pumps. The primary water makeup pumps are operating continuously.
'he rate of addition of unborated water makeup to the RCS is assumed to be equal to the capacity of the three charging pumps.
The boric acid from the boric acid tank is blended with primary grade water in the blender and the composition is determined by the preset fiow rates of boric acid and primary grade water on the control board. In order to dilute, two separate operations are required. The operator must switch from the automatic makeup mode to the dilute or alternate dilute mode, and the start. switch must be placed in the start position. Omitting either step would prevent dilution.
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 CVCS. Alarms are actuated to warn the operator if boric acid or makeup water flow rates deviate from preset values as a result of system malfunction.
3.2.42 Input Assumptions and Description of Analysis 3.2.42;1 Dilution During Refueling t
During refueling, the following assumptions are made.
A. One residual heat removal (RHR) pump is operating to ensure continuous mixing in the reactor vessel.
mM808wM3a.wpf:tb/081895 3-31
B. The dilute mode addls water in the Volume Control Tank where the primary water is mixed with letdown before it is pumped back into the system. 'Ihe alte&ate dilute mode adds water in the Volume Control 'I'ank and to the charging pump su,ction lieader. Either mode can be asSumed in the analysis.
C. The valves on the suction side of the charging pumps are adjusted for addition of concentrated boric acid.
D. The boron concentration in the refueling water is absuined to be 1950 ppm corresponding to a shutdown margin of at least 5% ~k/k with a]ll RCCAs in; periodic sampling ensures that this concentration is rnaintmned.
A minimum RCS water volume is considered. The valtte assutned corresponds to the volumet necessary to fill the reactor vessel above the nozzles to ensure mixing via the RHR loop. A maximum dilution flow and uniform mixing are assumed.
The operator has prompt and defmite indication of any boron dilution Rom the audible count rat&
instrumentation. The high count rate a1larm is actuated in the reactor containment and the control room. The count rate increare is proportional to the inverse multiplication factor.
For dilution during refueling, the boron concentration must be reduced from greater than 1950 ppm to approximately 1400 ppm 'before the reactor will go critical. It must be shown that there is at least 30 minutes Rom event initiation to when criticality is reached. W(thin this tiime, the operator~ must ~
recognize the high count ate signal and isolate the primary water. tnakeuli source by closing any one of several valves and stopping the reactor makeup water pumps.
3.2.422 Dilution During Startup In this mode, the plant is being taken from one long-terrtt rriod0 of operationhot standby, to hnothek, power. Typically, the plant is maintained ]in the startup anode denly for the purpose of startup 'testing't beginning of each cycle. During this mode of operation, rod control is in manual. All normal
'he actions required to charige power level, either up or down, dequlire operator initiation. Conditions assumed for the analysis are:
A. The dilution flow is the maximum capacity of the Primi~ water makeup pumps; B. A minimum RCS water volume, corresponding to the active RCS volume minus the pressurizer; C. The Mode 2 initial boron concentration is assumed to be 20M) ppm which is a conservative maximum value f'or the conditions of hot zero power, rods at the insertion limits and no:xenon.
The minimum change in boron concentration following a reactor trip, 200 ppm, results i6 tht:
maximum critical concentration for the condiitions of hot zero power,, all rods Inserted. except the mA1808w443a.wpf:1b/082495 3-32
most-reactive RCCA, and no xenon. The critical concentration at hot-zero-power conditions is thus 1800 ppm.
The startup mode of operation is a transitory operational mode in which the operator intentionally dilutes and withdraws control rods to achieve criticality. During this mode, the rods are in manual control with the operator required to maintain a high awareness of the plant status. For a normal approach to criticality, the operator must manually initiate a limited dilution and subsequently manually withdraw the control rods. The operator determines the estimated critical position of the control rods prior to approaching criticality, thus ensuring that the reactor does not go critical with the control rods below the insertion limits. Once critical, the power escalation must be sufficiently slow to allow the operator to manually block the source range reactor trip after receiving P-6 from the intermediate range (nominally at 10'ps). Too fast of a power escalation (due to an unknown dilution) would result in reaching P-6 unexpectedly, leaving insufficient time to manually block the source range reactor trip, and the reactor would immediately shut down.
However, in the event of an unplanned approach to criticality or dilution during power escalation while in the startup mode, the plant status is such that minimal impact will result. The plant will slowly escalate in power until the power range high neutron flux low setpoint is reached and a reactor trip occurs. From the initiation of the event, there is greater than 15 minutes available for operator action prior to return to criticality.
32.423 Dilution at Power In this mode, the plant may be operated in either automatic or manual rod control. Conditions assumed for this analysis are the following.
A. With the units at power and the RCS at pressure, the dilution rate is limited by the capacity of the charging pumps. Although less charging pumps are normally in operation, the analysis is performed assuming the dilution flow is the maximum capacity of the charging pumps.
B. A minimum RCS water volume, corresponding to the active RCS volume minus the pressurizer, is assumed.
C. '111e Mode 1 initial boron concentration is assumed to be 1900 ppm which is a conservative maximum value for the conditions of hot full power, rods at the insertion limits and no xenon.
The minimum change in boron concentration following a reactor trip, 350 ppm, results in the maximum critical concentration for the conditions of hot zero power, all rods inserted except the most-reactive RCCA, and no xenon. The critical concentration at hot-zero-power conditions is t
thus 1550 ppm.
With the reactor in automatic rod control the power and temperature increase from the boron dilution results in insertion of the control rods and a decrease in available shutdown margin. The rod insertion mh1808wkh3a.wpf:1b/082495 3-33
limit alarms (Low and Low-Low settings) alert the operator to the dilution. Thiis is sufficient time to determine the cause of dilution, isolate the reactor makeup sourceand initiate boration before the available shutdown margin is lost.
With the reactor in manual control and no operator actidn taken to ter'minate the transient the power and temperature rise will cause the reactor to reach the bverteiiiperature ~T trip setpoint resulting in a reactor trip. The boron dilut'ion traiisient in aliis case is essentially equivalent to an uncontrolled'CCA bank withdrawal at power. 'The: maximum reactivity insertion rate for a boron dilution is conservatively estimated to be 3.1 pcm/sec, which is within the range of insertion rates analyzed, Thus, the effects of dilution prior to reactor trip are bounded by the uncontrolled RCCA bank withdrawal at power aiial ysis (Section 3.2.2 of this report). Following reactor trip, there is greater than 15 minutes prior to cr!iticality. J3us is sufficient time for the operator to determine the cause of dilution, isolate the reactor water makeup source, and initiate boration before the available shiit down margin is lost.
3.2.49 Acceptance Criteria A CVCS malfunction is classified as an ANS Condition II event, a fault of moderate frequency.
established for Condiition II events are as follows. 'riteria
~ The critical heat flux should not be exceeded. This is ensured by demonstiating that the, minimum DNBR does not go below the limit value at any time during the transient.
~ Pressure in the reactor coolant and main steam systems should be maintained below 110% of the design pressures.
~ Fuel temperature and fuel clad str un limits should not~be ~exceeded. The peak linear heat generation rate should not exceed a value wliich would-cause fuel centerline melt.
This event is analyzed to ensure that there is sufficient time foiI mitigation of an inadvertent boron dilution prior to the complete laiss of shutdown margin. A complete loss of plant shutdown margin results in a return of the core to the critical condition causing an increase in the RCS temperature: and heat flux. 'Ibis could viojlate the, safety analysis limit DjVBR value and challenge the fuel anti fuhl cladding integrity. A complete loss of plant shutdown margin could also result in a return of the core to the critical condition causi.ng an increase in RCS pressure. This could challenge the prmsure design limit for the reactor coolant system.
If the minimum allowable shutdown margin is shown not to be lost, the condition of the plant at'an/
point in the transient is within the bounds of those ctdculated for other Condition II transients. By showing that the above criterIia are met for those ConditIion II e,vents, .it can lie concluded that they are also met for the boron dilution event.
mA1808w'443a.wpf:1bf081895 :3-34
To preclude a complete loss of plant shutdown margin, operator action is relied upon. The analysis of the boron dilution event is only performed, in accordance with Regulatory Guide 1.70 Rev. 1, in Modes 1, 2, and 6 (plant modes of full-power operation, plant startup, and refueling, respectively).
The required operator action times are:
Mode 1: 15 minutes from time of alarm Mode 2: 15 minutes from time. of dilution Mode 6: 30 minutes from time of dilution 32.4.4 Results Plant operation during refueling, startup, and power operation is considered in this analysis.
Table 3.2.4-1 contains the time sequence of events of the boron dilution analysis for refueling, startup and power operation. Table 3.2.4-2 presents results of the boron dilution analysis for refueling, startup, and power operation. Also included in this table are pertinent analysis assumptions. Perfect mixing is assumed in the analysis. This assumption results in a conservative rate of RCS boron dilution.
32.4$ Conclusions Ifan unintentional dilution of boron in the reactor coolant system does occur, numerous alarms and indications are available to alert the operator to the condition. The maximum reactivity addition due to the dilution is slow enough to allow. the operator sufficient time to determine the cause of the addition and take corrective action before shutdown margin'is lost. The acceptance criteria as specified in Section 3.2.4.3 are met.
mA1808wlch3a.wpf:tb/OS2495 3-35
Table 3.2A-1 Sequence of Events - Uncontrolled Boron Dilution Mode of 0 ration E.vent Timbre'secondly During Refueling Dilution begins 0 Shutdown, margin lost. (if dilution >1800.0 continues)
During Startup Power range - low setpoint 0 reactor trip due to dilution Shutdown margin lost.(if dilution >900 continues)
During Full-Power Operation
- a. Automatic Rod Control Operator receives low-low rod 0.
insertiion limit alarm due to dilution Shutdown margiin lost (if dilution >900 continues)
- b. Manual Rod Control Reactor trip on OTihT due to 0 dilution Shutdown marglin is lost (if >900 dilution continues) mfu808wM3a.wpf:1 bl081895 3-36
a Table 3.2.4-2 Summary of Boron Dilution Analysis Results and Analysis Assumptions Assumed Active Initial Assumed Critical Average Core Operation Dilution Flow Volume Boron Conc. Boron Conc. Coolant Action time Mode of 0 eration ~Rate;pmm ~cubic feet ~m ~m Tem erature 'F ~minutes Power Opention Auto Rod Control 252 7308.2 1900 1550 583.2 31.5 Manual Rod Control 252 7308.2 1900 1550 583.2 30.3 Startup 252 7308.2 2000 1800 554.5 17.0 Refueling 252 3204.6 1950 1400 140.0 31.0
3.2S Startup of an Inactive Reactor Coolant I,oop The current Turkey Pojint Technical Specificatiions preclude operation with an inactive loop. This event was originally included in the UFSAR licensing bdis when operation with a loop out of service was considered. Basedl on the current Tecluiical Specifications 'which prohibit at. power operation with a loop out of service as indicated abiove, it is concluded that. this event should be deleted fi'om the if'.2.6 current UFSAR licensing basis.
Excessive Heat Removal )Due To Feedwater Sys't em M'alfunctions 3.2.6.1 Identification of tmuLses and Accident Description Reductions in feedwater temperature or excessiive feedwater additions are means of increasing core power above full power. Such transiients are attenuate:d by the thermal capaciity of the RCS and the secondary side of the plant. The overpower/overtemperature protection functiions (neutron high hT, and oveqoower,dT trips) prevent an) p~liwelr inlcrease 'that could leNi to a DNBR.
fi'ux,'vertemperature that is less than the limit value.
An example of excessive feedwater flow would be. a full opening of a feedwater control valve due to a feedwater control system malfunction or an operator err'. At QWr, this exr~s flow causes 'a greater demand on the. RCS due to increased subcooling in the'steam 'generator. With the plant at 'oad no-load conditions, the addlition of cold feedwater may cause a decrease in RCS temperature a'nd thus a reactivity insertion due to the effects of the negative moderator temperature coefficient of rehctiVitg.
Continuous excessive feedwater addition, is prevented by the steam generator high-high water level tIlp.
A second example of excess heat removal is the transient associated with the accidental opening of the low-pressure heater bypass valve which diverts flow around the low-pressure feedwater heaters.
of this valve is to maintain net positive suction head on the main feedwater pump in the event The'unction that the heater drain pump flow is lost; e.g., following a largle Idad decreaSe. At power, this increased subcooling will create a, greater load demand on the RCSI 3.2.62 Input Parameters and Assumptions The reactivity insertion rate following a feedwater system malfunction, attributed to the cooldown of the RCS, is calculated with the following assumptions.
A. This accident is analyzed with the Reviised Tljiermal .Design Procedure as described in WCAP-11397-P-A (Reference 1). '.Iherefore, the initial reactor power, pressure,, and RCS average temperature are assumed to be at the nominal values. Unckitainties in initial conditions are included in the DNIBR linet calculated using the .methodology described in Reference 1.
0, mh1808w~a.wpf:ib/081895 3-38
B. For the feedwater control valve accident at full-power conditions, one feedwater control valve is assumed to malfunction resulting in a step increase to 200% of nominal feedwater flow to one steam generator.
C. The initial water level in all the steam generators is a conservatively low level.
D. No credit is taken for the heat capacity of the RCS and steam generator thick metal in attenuating the resulting plant cooldown.
E. The feedwater flow resulting from a fully open control valve is terminated by the steam generator high-high water level signal that closes all feedwater main control and feedwater control-bypass valves, indirectly closes all feedwater pump discharge valves, and trips the main feedwater pumps and.turbine generator.
The reactor protection systems, including Power-Range High Neutron Flux, Overpower hT, and Turbine Trip on High-High Steam Generator Water Level features are available to provide mitigation of the feedwater system malfunction transient.
Normal reactor control systems and engineered safety systems (e.g., SQ are not assumed to function.
The reactor protection system may actuate to trip the reactor due to an overpower condition. No single active failure in any system or component required for mitigation will adversely affect the consequences of this event.
3.2.63 Description of Analysis The excessive heat removal due to a feedwater system malfunction transient is analyzed with the LOFTB~ (Reference 2) computer code. This code simulates a multiloop system, neutron kinetics, the pressurizer,.pressurizer relief and safety valves, pressurizer spray, steam generator, and main steam safety valves. The code computes pertinent plant variables including temperatures, pressures, and power level.
The system is analyzed to demonstrate acceptable consequences in the event of a feedwater system malfunction. Feedwater temperature reduction due to low-pressure heater bypass valve actuation in conjunction with an inadvertent trip of the heater drain pump is considered. Additionally, excessive feedwater addition due to a control system malfunction or operator error that allows a feedwater control valve to open fully is considered.
The excessive feedwater flow event assumes an accidental opening of one feedwater control valve with the reactor at full-power conditions with both automatic and manual rod control. Both the automatic and manual rod control cases assume a conservatively large moderator density coefficient characteristic of EOL conditions.
mhl808wlch3a.wpf: Ib/082095 3-39
The plant conditions representative of zero-load operatidn alee Oot Wected by the power uprating at Turkey Point. Therefore, the analysis of the Feedwater MalfunctiOn event with the reactor jutst driti<t:al at zero-load conditions was not perf'ormed in support of the plant change to the uprated power level The results and conclusions presented in Section 14.1.7 of the 'UFSAR remain valid for the zero-load excessive feedwater addition transient.
3.2.6.4 Acceptance Criteria Based on its frequency of occurrence, the feedwater system malfunction event is considered a Condition II event as defined by the Arneriican Nuclear Society. Even though DNB is the primary concern in the analysis of the Feedwater Mtalfunction event,, the following 3 items summarize the criteria associated with this transient.
~ The critical heat flux shall not be exceeded. This i0 e11stu'ed by demon<1trafing that the minimum DNBR does not go below the limit value at any time during )he transient.
~ Pressure in the reactor coolant and m8un steam systems shall be maintained below 110% of the design pressures.
~ Fuel temperature and fuel clad strain limits shaHI not be exceeded. The peak linear heat generation rate should not exceed a value wl;uch would cause fuel centerline melt.
~
3.2.6S Results Opening of a low-pressure heater bypass valve, and trip Of the heather drait1 pumps causes a reductiorl in the feedwater temperature which increases the thermal load on the primary system. The reduction in the feedwater temperature is less than 60'F, resulting in an increase in the hmt load on the ptjimary system of less than 10 percent of full power. The increased thermal load due to the opening I0f t6e low-pressure heater bypass valve would result in a transient very siimijjar (but of reduced magnitude) to the Excessive Load Increase incident presented in Section 3,.2.7. Thus, the results of tltls event are bounded by the Excessive Load increase event and, thert:for'c, r'1ot j'presented here.
The full-power case (EOL mmin1um reactivity feedback with automatic rod control) gives thk laf gelt reactivity feedback and re<>ults in the greatest power increase. A turbine txipwhich results in a reactor trip, is actuated when the steam generator water level in the afft:ckd steam generator reaches the high-high level-setpoint. Assuming the reactor to be in manual rod control results in a slightly less-severe transient. The rod control system is not required to futIjction for this event; howevjer, assuming that the rod control system is operable yields a. slightly. more limiting transient.
For all cases of excessive feedwater flow, continuous addition of cold feedwater is prevented by automatic closure of all feedwater control valves, closure of all feedwater byjpass valves, a trip of the feedwater pumps, and a turbine tldp on Jjugh-high steajm generator water level. In addition,, thh mh180&wMh3a.wpf:1V082495 3<0
feedwater discharge isolation valves will automatically close upon receipt of the feedwater pump trip signal.
Following turbine trip, the reactor will automatically be tripped, either directly due to the turbine trip or due to one of the reactor trip signals discussed in Section 3.2.9 (Loss of External Electrical Load and/or Turbine Trip). If the reactor was in automatic rod control, the control rods would be inserted at the maximum rate following the turbine trip, and the resulting transient would not be limiting in terms of peak RCS pressure.
Transient results (see Figures 3.2.6-1 through 3.2.6-3) show the core heat flux, pressurizer pressure, core average temperature, and DNBR, as well as the increase in nuclear power and loop hT associated with the increased thermal'load on the reactor. Steam generator water level rises until the feedwater addition is terminated as a result of the high-high steam generator water level trip. The DNBR does not drop below the limit value at any time.
Since the power level rises during this event, the fuel temperature will also rise until the reactor trip occurs. The core heat flux lags behind the neutron flux due to the fuel rod thermal time constant and, as a result, the peak core heat flux value does not exceed 118% of nominal. Thus, the peak fuel melting temperature will remain well below the fuel melting point.
The calculated sequence of events is shown in Table 3.2.6-1. The transient results show that the DNBR does not fall below the limit value at any time during the feedwater flow increase transient; thus, the ability of the primary coolant to remove heat from the fuel rods is not reduced. Therefore, the fuel cladding temperature does not rise significantly above its initial value during the transient.
3.2.6.6 Conclusions The decrease in feedwater temperature transient due to an opening of the low-pressure heater bypass valve is less severe than the excessive load increase event (see Section 3.2.7). Based on the results presented in Section 3.2.7, the applicable acceptance criteria for the decrease in feedwater temperature event have been met.
For the excessive feedwater addition at power transient, the results show that the DNBRs encountered are above the limit value; hence, no fuel damage is predicted.
The protection features presented in Section 3.2.6.2 provide mitigation of the feedwater system malfunction transient such that the above criteria are satisfled.
As documented in Section 14.1.7 of the UFSAR, the analysis at hot zero power demonstrated that the minimum DNBR remained greater than the limit value for a maximum reactivity insertion rate corresponding to an excessive feedwater addition at no-load conditions. This conclusion is unaffected by the uprated power conditions.
mal 808wM3a.wpr:ib/081895 3-41
3.2.6.7 References
- 1. Friedland, A. J., and Ray,,'S., "Revised Thecal Design Procedure,"
WCAP-11397-P-A'Proprietary),
WCAP-11397-A (Non-proprietary), April 1989'.
Burnett, T. W. T. et al., "LOH3V& Code Description," WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Non-proprietaty)", April 1984 mh1808w498a.wpf:IM$ 1895 3%2
Table 3.2.6-1
'Time Sequence of Events Excessive Feedwater Flow at Full Power (Automatic Rod Control)
Event Time sec One main feedwater control valve fails fully open 0.0 High-high SG'ater level signal generated 35.0 Minimum DNBR occurs 37.0 Turbine trip occurs due to high-high SG water level 37.5 Reactor trip due to turbine trip (rod motion begins) 39.5 Feedwater control valves fully closed 44.0 mh1808wkh3a.wpf:Ibf081895 3-43
1.4 1.2 0
50 100 150 200 TBK (SECONDS) 1.4 1.2
~55
.2 0
0 50 100 150 TIE (SIECONDS)
Figure 32.6-1 Feedwater Control Valve Ma1function Nuclear Power and Core Eleat Flux versus Tiirne mhl808wMh3a.wpf:1b/081895 3-44
2 4 0'0 2'300 g Pn 2200 2100 2000 5'0 1 5'0 200 100'QCE (SECONDS) 100 80 eo f4 ~
A pg.
g,A 40 3
20 5'0 100 150 200 viz (sEcoms)
Figure 3.2.6-2 'Feedwater'Control Valve Malfunction Pressurizer Pressure and Loop Delta-T versus Time mhl808w'4ch3a.wpf:1b%81S95 3<5
590 560 570 560 Pp 550 540 0 50 100 150 200 TIME (SBCONDS) 1 0 50 100 150 200 T1ME (SECO:NDS)
Figure 32.6-3 Feedwater control Valve Malfunction Core Average Temperature and DNBR versus Time mhl808wMh3a.wpf:1b(081895 'l46i
3.2.7
~ ~ Excessive Load Increase Incident 3.2.7.1 Identification of Cause and Accident Description 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% step-load increase or a 5% per minute ramp-load increase in the range of 15 to 100% of full power. Any loading rate in excess of these values may cause a reactor trip actuated by the reactor protection system. If the load increase exceeds the capability of the reactor control system, the transient would be terminated in sufficient time to prevent the DNB.design basis from being violated.
This accident could result from either an administrative violation such as excessive loading by the operator or an equipment malfunction, in the steam bypass control or turbine speed control.
During power operation, steam dump to the condenser is controlled by comparing the RCS temperature to a reference temperature based on turbine power, where a high temperature difference in conjunction with a loss of load or turbine trip indicates a need for steam dump. A single controller malfunction does not cause steam dump valves to open. Interlocks are provided to block the opening of the valves unless a large turbine load decrease or a turbine trip has occurred. In addition, the reference temperature and loss of load signals are developed by independent sensors.
Regardless of the rate of load increase, the reactor protection system will trip the reactor in time to prevent the DNBR from going below the limit value. Increases in steam load to more than design flow are analyzed as the steam line rupture event in Section 3.2.16.
Protection against an excessive load increase accident is provided by the following reactor protection system signals.
Overtemperature ~T Overpower a T Power range high neutron flux Low pressurizer pressure 3.2.72 Input Parameters and Assumptions
~ This accident is analyzed with the Revised Thermal Design Procedure as described in WCAP-11397-P-A (Reference 1). Initial reactor power, RCS pressure and temperature are assumed to be at their nominal values. Uncertainties in initial conditions. are included in the DNBR limit as described in Reference 1.
mh180SwMh3a.wpf: Ib/081895 3Q7
~ The evaluation is performed for a step load increase of 10 percent steam fiow from 100 perceiit of Rated Thermal Power.
This event is analyzed in both automatic and manual i'od ,'control.
~ The excessive load increase event is anajlyzed for both th< beginning-of-life (minimum reactivity feedback) and end-of-life (maumum reactivity feedback) 'conditi'ons. A small (zero) moderator density coefficient at beginning of life and a large value at end of life are used. A positive moderator temperature coefficient is not assumed since this would provide a transient benefit.
For all cases, a small (absolute value) Doppler coefficient of reactivity is assumed.
3.2.79 Description of Analysis Four cases are analyzed to demonstrate. the plant behavior followihg a 10%,step-load increase from rated load. These cases are as follows.
Reactor in manual rod control with BOL (minimum moderator) ~eactivity feedback Reactor in manual rod control with EOL (maximum moderator) reactivity:feedback Reactor in automatic: rod control with BOL (minimum moderator) reactivity feedback Reactor in automatic rod control with EOL (maximum moderator) reactivity feedback This accident is analyzed using the LOFHMll (Reference 2) computer code to determine the plant transient conditions following the excessive load incre&e. P11id cue models the core neutrofjI kihetics, RCS including natural circulation, pressurizerpr<asurizitr FORIVs ~and sprays, steam generators, main steam safety valves, and the auxiliary feedwater system.~ The code computes pertinent plant Variables including DNBR, temperatures, pressures, and power level. ~
At BOL, minimum moderator feedback: cases, the core has the leaSt-negative moderator temperauire coefficient of reactivity and the least-negative Doppler only power coefficient curve; therefore, the least-inherent transient response capability., S.ince a positiv<'. moderator temperature coefficient would provide a transient benefit, a zero moderator. temperature coefficient was assumed in the minimum feedback cases. For the EOI. maximuin moderator feedback cases, the moderator temperature coefficient of reactivity has its most-negative vahie and the most-negafive Doppler only power coefficient curve. This results in the largest amount of Inactivity feedback due to changes in'coolaitt temperature. Normal reactor control systems and engineered safety systems are not required to function. A 10% step increase in steam demand is assumed and the analysis does not take credit for the operation of the pressurizer heaters., The cases which assuine automatic rod control are a'nal~ to ensure that the worst case, is presented. The automatic function is not required. The reactor
'protection'ystem is assumed to be operable; however, reactor trip ~is riot f.ncountered for the uses analyzed. No active failure in any system or component required fOr itiitigation will adversely affect the 'ingle consequences of this'accident.
mh1808w433a.wpf: Ibf081895 3P8
3.2.7.4 Acceptance Criteria Based on its frequency of occurrence, the excessive load increase accident is considered a Condition II event as defined by the American Nuclear Society. The following items summarize the acceptance criteria associated with this event.
Me critical heat flux should not be exceeded. This is ensured by demonstrating that the minimum DNBR does not go below the limit value at any time during the transient.
Pressure in the reactor coolant and main steam systems should be maintained below 110% of the design pressures. With respect to peak pressure, the excessive load increase accident is bounded by the loss of electrical load/turbine trip analysis. The loss of electrical load/turbine trip analysis is described in Section 3.2.9.
Fuel temperature and fuel clad strain limits should not be exceeded. The peak linear heat generation rate (expressed in kw/ft) should not exceed a value which would cause fuel centerline melt.
The protection features presented in Section 3.2.7.1 provide mitigation of the excessive load increase transient such that the above criteria are satisfied.
Figures 3.2.7-1 through 3.2.7-4 illustrate the transient with the reactor in the manual rod control mode.
As expected, for the BOL case, there is a slight power increase and the average core temperature shows a decrease. 'Ihis results in a DNBR which increases (after a slight decrease) above its initial value. For the EOL manual rod control case, there is a larger increase in reactor power due to the moderator feedback. A reduction in DNBR is experienced but DNBR remains above the safety analysis limit value.
Figures 3.2.7-5 through 3.2.7-8 illustrate the transient assuming the reactor is in the automatic rod control mode. Both the BOL and EOL cases show that core power increases. The BOL case shows the core average temperature to stabilize, due to the action of the rod control system, at a slightly higher value from the initial temperature. The EOL case shows that after a slight increase the core average temperature stabilizes, again due to the action of the rod control system, at a value approximately equal to the initial temperature. For both of these cases the DNBR remains above the safety analysis limit value.
The calculated time sequence of events for the excessive load increase incident is shown on Table 3.2.7-1. Note that a reactor trip signal was not generated for any of the four cases.
mh1808wMh3a.wpHbf081895 3C9
3.2.7.6 Conclusions It has been demonstrated that for an excessive load increase, the minimu'm DNBR during the transient will not go below the safety analysis limit valIue thus ensuring'the'pplicable acceptance criter for critical heat flux and fuel centerline, melt are met. Following the initial loadI increase, the plant reaches, a stabilized condition. In addition, RCS pressure and main steam system does not exceed. 110% of design as described in Section 3.2.9.
3.2.7.7 References
- 1. Friedland, A. J., and Ray, S., "Re vised Thermal Design Procedure", WCAP-11397-P-A, (Proprietary), WC-11397-A (Nonproprietary), April 1989.
- 2. Burnett, T. W. T, et:al., "L.OFTRAN Code'.Description," WCAP-7907-:P-A (Proprietarpf) ahd WCAP-7907-A (Nonproprietary), April 1984.
mh1808wMQa.wpf:1b/08249$ 3-50
Table 3.2.7-1 Time Sequence of Events for Excessive Load Increase Incident Accident Event Time sec Rod 10% step-load increase 0.0 'anual Control (minimum moderator feedback) Equilibrium conditions reached (approx. time) 170.0 Manual Rod 10% step-load increase 0.0 Control (maximum moderator feedback) Equilibrium conditions reached (approx. time) 90.0 Automatic Rod 10% step-load increase 0.0 Control (minimum moderator feedback) Equilibrium conditions reached (approx. time) 140.0 Automatic Rod 10% step-load increase 0.0 Control (maximum moderator feedback) Equilibrium conditions reached (approx. time) 40.0 mh1808wM3a.wpf:tb/081895 3-51
1.3 1.2 1.1 R
1
,9 j8 .8
~ 7 50 100 150 200 250 300 TIME (SECONOS) 2300 2200 2100 2000 1900 50 100 150 200 250 300
- nm (sEcomis) 1400 1200 1000 800 600 400 50 100 150 2',00 250 300 TiXQQ~ (SECONIIS)
Figure 30.7-1 10% Step Load Increase Minimum Moderator Feedback, Manual Rod Controll mhl808wMh3a.wpf:1M$ 2095 3-52
'620 600 5 8.0
~ cL 560
~W A 5 4.0 520
'500 50 100 150 200 250 3.0 0 ma (seconds) 3.,5 2.5
'1. 5 50 100 150 200 250 300 mes (szcoms)
Figure 3.2.7-2 10% Step, Load Increase Minimum Moderator Feedback Manual Rod Control mhl 808wkh3a.wpf:1bl082095 3-53
~I 1.3 1.2 1.1 1
.9
.8
.7 50 100 ]l 50 200 250 300 TDIZ (SECONDS) 2300 2200 2100 2000 1900 50 100 150 TBIZ (SECONDS) 200 250 '3 0',
1400 1200 1000 800 600 l
400 ~
~0
~ ~
0 50 100 150 200 250 3 0 TGE (SECONDS)i Figure 32.7-3 1~0% Step Load Increase Maximum Moderator Feedbadc Manuals Rod Coritrol mhl808wMQa.wpf: Lb/082095 3-54
620 600
~ cL 560 540 520 500 0 50 1 0 0 1 5 0 2 0!0 250 300 TIME (SECOWuS)
'3. 5 2.5 1.5 50 100 150 200 250 300 me (sacoms)
Figure 32.7A 10% Step Load Increase Maximum Moderator Feedback Manual Rod Control mhl808wMh3a.wpf:1b/082095'-55
1.3 1.2 gS 1;1 1
.9 j6 .8
.7 50 100 150 200 250 300 rruE (SECOmOS)
.2300 2200 2100 2000 1900 0 50 100 150 200 250 300 TIME (SECONjDS) 1400 1200 1000 800 600 400 I I I~ ~
0 Ci 0 100 150 200 250 300 TIMB (SECONDS)
Figure 32..7-5 10% Step Load Increase Mini'mu'm Moderator Feedback Automatic ]Rod Ciontrol mh1808wMh3a.wpf:1b/082095 3-56
620 600 560
'~q cL 560-540 520 500 50 100 150 200 250 300 T1ME (SECONnS) 3.5
- 2 ~ 5 1.5 50 100 150 200 250 300 TIME (SZCOmS)
Figure 3.2.7-6 10% Step Load Increase Minimum Moderator Feedback Automatic Rod Control mA1808w4ch3a.wpf:1b/082095 3-57
1.3 l4 5 1.2 gX ,1.
O g 1 1
.9 j6 '8
.7 0 50 100 150 200 250 300 TGK (SBCONDS) 2300 2200 2100 2000 1900 50 100 150 200 250 300 TDa (SBiCOhrnS) 1.400 1200 1000 800 600 400 0 50 100 150 200 ,250 30,0 TIIZE (SECOhYDS)
Figure 3~!.7-7 10%~ Step Load Increa!>e Maximum Moderator Feedback Automatic Rod, Control mh1808wMh3a.wpf:1b/082095 3-58
620 600 580
,560 5.4 0 520
- 5'0 0
'50 . 100 150 2 0 0 2 5 0 3 0 0 mu (sacoms) 3.5 2.5 1.5 0 50 100 150 200 250 300 TIME (sEcoms)
Figure 3.2.7-8 10% Step Load Increase Maximum Moderator Feedback Automatic Rod Control mA1808wMh3a.wpf: 1bf082095 3-59
3.2.S Loss of Reactor Coolant Flow 3.2.S.I Partial / Complete I.oss of'orced Reactor COolant Flok 3.2$ .1.1 Identification of Causes and Accidlent Descrtiption A loss of forced coolant flow incident may result from 6, mkch&dal or electrical failure in one or more reactor coolant pumps (RCPs), or from a fault in the power supply to these pumps. If the reactor is at power at the time of the event,, the inunediate effect of loss of forced coolant flow iS a increase in the coolant temperature. '.Promplly tripjiing the reactor ensures that this rapid in&else 'apid
'n coolant temperature does not violate DNB.
Normal power supplies for the RCP pumps are A an(1 B 4.16 kV buses supplied from the auxiliary transformer, one of which supplies power to one of the three pumps and the other of which supplies power to two of the three pumps,. V&en a generator trip occurs, the buses automatically fast transfer to the startup transformer supplied from external power lines so that the pumps will continue ito forced coolant flow to the core. 'rovide The following signals provide the necessary protection Qairist h loIss of coolant flow incident
~ Undervoltage (4 16 kV bus A or B) or underfrequency on reactor coolant pump power supply buses
~ Underfrequency R.CP breaker trips Low reactor coolant loop flow Pump circuit breaker opening The reactor trip on undervoltage of 4.16 kV bus A or B is provided to protect against conclitions which can cause a loss of voltage to all reactor coolant pumps, i.e., loss of offsite power. This function is blocked below approximately 10 percent pow>r (Peainis!sive P-7).
The underfrequency RCP breaker trip is provided to trip the reaktok for an underfrequency condition resulting from frequency disturbances on the power grid. The ri'eactor coolant pump underfrequency reactor trip function. is lblocked below P-7. In addition, the underfrequency function wfll open all RCP breakers whenever an underfrequency, condi,tion occurs (no P-7 or P-S interlock) to ensure adequate RCP coastdown.
The reactor trip on low prima1y coolant loop flow is provided to protect against loss of flow conditions which affect one or two reactor coolant loops. It also serves as a backup to the undervoltage and underfrequency trips for the loss of all threte rkactbr t'.oolant pumps case. This mA1808wkh3a.wpf:1b/091295 3-60
function is generated by two-out-of-three low flow signals per reactor coolant loop. Above Permissive P-8, low fiow in any loop will actuate a reactor trip. Between approximately 10 percent power (Permissive P-7) and the power level corresponding to Permissive P-8 (which is - 45% R'IP),
low fiow in any two loops will actuate a reactor trip. Reactor trip on low flow is blocked below Permissive P-7.
A reactor trip from pump breaker position is provided as a backup to the low flow signal. Similar to the low flow trip, above P-8, a breaker open signal Qom any pump will actuate a reactor trip, and between P-7 and P-8a breaker open signal from any two pumps will actuate a reactor trip. Reactor trip on RCP breakers. open is blocked below Permissive P-7.
3.2.8.1.2 Input Parameters and Assumptions This accident is analyzed using the Revised Thermal Design Procedure (Reference 1). Initial core power, reactor coolant temperature, and pressure are assumed to be at their nominal values consistent with steady-state full-power operation. Uncertainties in initial conditions are included in the departure from nucleate boiling ratio (DNBR) limit value as described in Reference 1'.
A conservatively large absolute value of the Doppler only power coefficient is used. The most-positive moderator temperature coefficient is assumed since this results in the maximum core power and hot spot heat flux.during the initial part of the transient when the minimum DNBR is reached.
Normal reactor control systems and engineered safety systems (e.g., SI) are not required to function.
No single active failure in any system or component required for mitigation will adversely affect the consequences of this event.
3.2.8.1.3 Description of Analysis The following loss of flow cases are analyzed:
- 1. Loss of all three reactor coolant pumps with three loops in operation.
- 2. Loss of two reactor coolant pumps with three loops in operation.
'Ihese transients are analyzed by three digital computer codes. First, the LOFTRAN code (Reference 2) is used to calculate the loop and core flow transients, the nuclear power transient, and the primary system pressure and temperature transients. This code simulates a multiloop system, neutron kinetics, the pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and main steam safety valves. The flow coastdown analysis performed by LOFTRAN is based on a momentum balance around each reactor coolant loop and across the reactor core. This momentum balance is combined with the continuity equation, a pump momentum balance, and the as-built pump characteristics and is based on high estimates of system pressure losses.
mA1808wMh3a.wpf:ib/081895 3-61
The FACTRAN code (Reference 3) is then used to calculate the,.heat flux transient based on the nuclear power and flow from LOFTRAN. Finally, the THINC (Reference 6) code is used to calculate the DNBR during the transient based on the heat flux Rom .FACTRAN and the flow from LOFTRAN.
The DNBR transient presented represents the minimum of the typical and thimble cells.
3.2.8.1.4 Acceptance. Criteria Partial Loss of Flow is an ANS Condition II event and Complete Loss of Flow is an ANS Condition III event. Both are analyzed to Condition II criteria. The immediate effect of either a partial or complete loss of forced reactor coolant flow is a rapid increase .in the reactor coolartt temperature and subsequent increase in reactor coolant system (RCS) pressure. The following 3 items summarize the criteria associated with tjhis event.
~ The critical heat flux should. not be exceeded. 1&s is ensured by demonstrating that the minimum. DNBR does not go below the limit value at any time during the transient.
~ Pressure in the reactor coolant and main stealni systems should be maintained below 110% of the design pressures.
~ Fuel temperature and fuel clad strain limits should not be exceed+i; The peak linear heat generation rate should not exceed a value which wohld cattse Ifuel centerline melt.
3.2$ .1.5 Results The complete loss of flow event .is the most DNB limitiitg df the tiIo cases presented in Reference 4.
'Ihe reactor is assumed to trip on an undervoltage reactor trip signal for the complete loss of flowj caI'e resulting f'rom a loss of power to the RCPs., Reactor trip for the partial loss of flow case occurs on a low flow signal. The 'l3iINC-IV(Reference 7) analyses for the'se scenarios confirm that the minimum DNBR values are greater than the safety analysis jlimit value. Fuel clad damtige criteria are not
)
challenged in either the partiajl or complete loss of'orced reactor coolant flow events, since the DNB criterion is met.
'Ihe analyses of the partial and complete loss of flow events alsl0 demonstrate that the peak RCS and Main Steam system pressures are well below acceptable limits.
The calculated sequence of events for the cases presented in Section 14.1.!3 of the UFSAR (Reference 4) is shown in Table,3.2.8-L Figures 3.2.8-1 through 3.2.8-4 show the traiu>ient response for the loss of power to all reactor coolant pumps. Figures 3.2.8-5 through 3.2.8-8 show the Ambient response for the loss of two reactor coolant pumps with threl: loopk initially in operation.
mA1808wM3a.wpnib/082495 3-62
3.2.8.1.6 Conclusions The analyses performed at the uprated conditions demonstrate that for the above loss of flow incidents, the DNBR does not decrease below the safety analysis limit value at any time during the transient; thus, no fuel or clad damage is predicted. The peak primary and secondary pressure remain below 100% of design at all times. All applicable acceptance criteria are therefore met.
The protection features presented in Section 3.2.8.1.1 provide mitigation for the loss of forced reactor coolant flow transients such that the above criteria are satisfied.
3.2.82 Locked Rotor/Shaft Break 3.2.82.1 Identification of Causes and Accident Description The event postulated is an instantaneous seizure of a reactor coolant pgmp rotor or the sudden break of the shaft of the reactor coolant pump (RCP). Flow through the affected reactor coolant loop is rapidly reduced, leading to initiation of a reactor trip on a low Reactor Coolant System (RCS) flow signal.
Following initiation of the reactor trip, heat stored in the fuel rods continues to be transferred to the coolant causing the coolant to expand. At the same time, heat transfer to the shell side of the steam generators is reduced, first because the reduced flow results in a decreased tube-side film coefficient and then because the reactor coolant in the tubes cools down while the shell-side temperature increases (turbine steam flow is reduced to zero upon plant trip due to turbine trip on reactor trip). The rapid expansion of the coolant in the reactor core, combined with reduced heat transfer in the steam generators, causes an insurge into the pressurizer and a pressure increase-throughout the RCS. The insurge into the pressurizer compresses the steam volume, actuates the automatic spray system, opens the power-operated relief valves, and opens the pressurizer safety valves, in that sequence. The two power-operated relief valves are designed for reliable operation and would be expected to function properly during the event. However, for conservatism, their pressure-reducing effect as well as the pressure-reducing effect of the spray is not included in the analysis.
The consequences of a locked rotor (i.e., an instantaneous seizure of a pump. shaft) are very similar to those of a pump shaft break. The initial rate of the reduction in coolant flow is slightly greater for the locked rotor event. However, with a broken shaft, the impeller could conceivably be free to spin in the reverse direction. The effect of reverse spinning is to decrease the steady-state core flow when compared to the locked rotor scenario. The analysis considers only one of the two scenarios; it represents the most-limiting condition for the locked rotor and pump shaft break event.
3.2.82.2 Input Parameters and Assumptions Two cases are evaluated in the analysis. Both assume one locked rotor/shaft break with a total of three loops in operation. The first case is aimed at maximizing the RCS pressure transient. This is mh1808wM3a.wpf:1bf082495 3-63
done using the Standard Thennial Design Procedure. Initial corte power, reactor coolant temperaoire, and pressure are assumed to be at their ma:eimum values consistent with the uprated full-power conditions including allowances for cali'bration and instrument errors. This assumplion results in a conservative calculation of the coolant insurge into the pressurizer which .in turn results in a inaximum peak RCS pressure,. 'alculated The second case is an evaluation of:DNB in the core during the transient. 1his case is analyzed using the Revised 'Ihermal Design Procedure. Initial core power, reactor coolant temperature, and pressure are assumed to be at their nominal values consistent with steady-state full-power operation.
Uncertainties in initial conditions are, inclucled in the departure from nucleate boiiling ratio (DNBR) limit value as described in Reference 1.
The reactivity coefficients assumed in bioth cases include~ a positive moderator temperature coeffiCient and a conservatively large (absolute value) of the .Dopplelr-otily po4er'coelffieient. For this aitalylsis, the negative reactivity!insertion upon trip is based on a 4% lxip reactivity from full power.
The transient is evaluated with no loss of offsite power. The two unaffected RCPs continue to operate ~
through the duration of the: event.,
Normal reactor control systems and engiineered safety syStenls (e.g.', Si) are not required to function.
No single active failure: in any system or component required for iiutigation will adversely affect of this event. 'the'onsequences The offsite doses following a locked rotor event reflect the uprated power level of 2346 MWt (102%
of 2300 core power), 10% failed fueil, and a pre-accident iodine spike (Reference 8). 'Ihe ass)i'!itious used for the locked rotor analysis are: sumrnari ~~d in Tawe 3.2.8.3.
3.2.82.3 Description of Analysis
'Ihe pressure case is analyzed using two digital computer codes., The LOFTRAN code (Referent: 2) is used to calculate the resulting loop and core flow time ients following the pump seiziire, theI tiitie *f reactor trip based on the loop flow transieni~s, the nuclear power following reactor trip, arid. the pe,ak RCS pressure. The reactor coolant flow coastdown analysis peiformed by LOFI.'RAN iis based on a momentum balance around each reactor coolant loop and across the reactor core. This momentum balance is combined with the icontinxuty equation, a pump momhntttun balance, the as-built pump characteristics, and is based on high estimates of system pressure losses. 'The thermal behavior of the fuel located at the core hot spot is investigated using the FACT1RA1% code (Reference 3) which u~ses core flow and the nuclear power values calculated by LOFTRAÃ. The FACTRAN code includes a
'he film boiling heat transfer coefficient.
The case analyzed to esalnate core DNB uses LOFIIIAN,FACIRAN and TIIINC (Reference 6),. The LQFTP~ and FACTE4Q4 codes arte ussed in the, same manner as iin the previous case. The THINO i
~
mA1808WttCh3a.WPf:1M$ 2595 3-64
code is used:to calculate the DNBR during the transient based on the heat flux from FACTRAN and the flow from LOFIRAN (Reference 6);
For the peak RCS pressure evaluation, the initial pressure is conservatively estimated as 60 psi above the nominal pressure of 2250 psia to allow for errors in the pressurizer pressure measurement and control channels. This is done to obtain the highest possible rise in the coolant pressure during the transient. To obtain the maximum pressure in the primary side, conservatively high loop pressure drops are added to the calculated pressurizer pressure. The pressure response shown in Figure 3.2.8-10 is at the point in the RCS having the maximum pressure (i.e., the outlet of the faulted loop's RCP).
For a conservative analysis of fuel rod behavior, the hot spot evaluation assumes that DNB occurs at the initiation of the transient and continues throughout the event. This assumption reduces heat transfer to the coolant and results in conservatively high hot spot temperatures.
Evaluation of the Pressure Transient After pump seizure, the neutron flux rises due to the temperature increase and.positive MTC and then is rapidly reduced by control rod insertion. Rod motion is assumed to begin one second after the flow in the affected loop reaches 84.5 percent of nominal flow. No credit is taken for the pressure-reducing effect of the pressurizer relief valves, pressurizer spray, steam dump or controlled feedwater flow after plant trip. Although these systems are expected to function and would result in a lower peak pressure, an additional degree of conservatism is provided by ignoring their effect.
The pressurizer safety valves are modelled including the effects of the pressurizer safety valve loop seals using WOG methodology (Reference 5). 'IIie pressurizer safety valve includes a 4% uncertainty (1% set pressure shift and a 3% set pressure tolerance) over the nominal setpoint of 2500 psia.
Additionally, no steam flow is assumed until the valve loop seals are purged.
Evaluation of DNB in the Core Durin the Event For this event, DNB is assumed to occur in the core and therefore, an evaluation of the consequences with respect to fuel rod thermal transients is performed. Results obtained Rom analysis of this "hot spot" condition represent the. upper limit with respect to clad temperature and zirconium-water reaction. In the evaluation, the rod power at the hot spot is assumed to be 2.5 times the value at the initial core power level. The number of rods-in-DNB are conservatively calculated for use in dose consequence evaluations.
Film Boilin Coefficient The film boiling coeffiicient is calculated in the FACTRAN code using the Bishop-Sandberg-Tong film boiling correlation (Reference 3). 'Ice fluid properties are evaluated at the film temperature (average mM808wM3a.wpf:thf082495 3-65
between the wall and bulk ternperattires). 'Ihe program calculates the film coefficient at every time based upon the actual heat tnnsfer conditiom> at the time. The neutron flux, system pressure, 'tep bulk density, and mass flow rate as a function of time arIe used as program input.
For this analysis, the iiiitial value,s of the pressure and the bulk defisity are used throughout tlie transient since they are the most conservative with respect tti thle clad temperature response. As indicated earlier, DNB was assumed to start at the beginning of the transient, Fuel Clad Ga Coefficient-The magnitude and time dependence of the heat transfer'coefficient between the fuel and clad (gap has a pronounced influence on the thermal results. The larger the value of the gap 'oefficient) coefficient, the more heat is transferred between the pellet and clad. For the initial portion of the transient, a high gap coefficient produces higher clad temperatures since the heat stored and generated'n the fuel redistributes itself .in the coo',ler icladding. Based on investigations on the effect of the gap coefficient upon the maximum clad temperature during the transient, the gap coefficient was assumed to increase from a steady-state value consistent with initial fuel temperatures to 10,000 Btti/hr-ft -0F at the initiation of the tmnsient. Thus, the large amount of'energy stored iri the fuel is> released to the clad at the initiation of'he trzmient.
Zirconium-Steam Reaction The zirconium-steam reaction can become sigruficant above 1800'F (clad temperature). The Baker-Just parabolic rate equation (Reference 3) shown below i's used to define the rate of the zirconium-steam reaction.
2'>
33 3 ~ QQ6 e t45500'/1.986T) dt where: W = amount Zr reacted, mg/cm t = time, sec T = temperature, 'K The reaction heat is 1510 cal/gm,. The effectof zirconium-steam reaction is incjluded i:n the calculation of the "hot spot" clad temperature transi:ent.
3.252.4 Acceptance Criteria An RCP locked rotor i,s an AINS Condition IV event. An RCP locked rotor results in a rapidreduction 'n forced reactor coolant loop flow which incrmses the iIeactor Coolant temperatiire and subs+ueIntlg causes the fuel cladding temperature and RCS pressmfe to increase. The'following .items summaitize the criteria associated with thiis event.
mh1808w&Qa.wpf:Ib/081895 :3-66
~ Fuel cladding damage (including:melting), due to increased reactor coolant temperatures and.the Zirconium-water reaction, must, be shown not to.occur.
~ Pressure in the reactor coolant system should be maintained. below 110% of the design pressures.
~ Fuel temperature and fuel clad strain limits should not be exceeded even for rods experiencing DNB. The, peak linear heat generation rate should not exceed a value which would cause fuel centerline melt.,
~ Rods-in DNB (dose calculation) should be less than or equal to 10%.
~ Dose limit for a locked rotor is a "small fraction of" or 10% of the 10 CFR 100 guideline values.
The protection features described in Section 3.2.8.2.3-provide mitigation for a locked rotor transient such that the above criteria are satisfied.
32828 Results The calculated sequence of events is shown in Table 3.2.8-1. The transient results are shown in Figures 3.2.8-9 through 3.2.8-12. The-peak RCS pressure reached during the transient is less than that which would cause stresses to exceed the faulted condition stress limits. Also, the, peak clad surface temperature is, considerably less than 2700'F. It should be noted that the clad temperature,was conservatively calculated assuming that DNB occurs at the initiation of the transient. The results of these calculations (peak pressure, peak clad temperature, and zirconium-steam reaction) are also summarized in Table 3.2.8-2. The rods-in-DNB design criteria of less thani10% has been met.
The calculated thyroid and y-body, doses (rem) at the. exclusion boundary and low population zone outer boundary as follows:
EB (0-2 Hr) LPZ (0-24 Hr)
Tllyroid 1.0 EO 4.0 E-1 y-Body 9.9 E-2 1.5 E-2.
3252.6 Conclusions The analysis performed at the uprated conditions demonstrates that for the above locked rotor event, since the peak clad surface temperature calculated for the hot spot during. the worst'transient remains
.considerably less than 2700'F and the amount of zirconium-water reaction is small, the core will remain in place and intact with no loss*of core cooling capability.
mh1808wMBa.wpf:tb/092595 3-67
The analysis also conQrms that the peak RCS pressure reached during the transient is less than that which would cause stresses to exceed the faullted condition'strauss limits, the integrity of the primary coolant system is not endangered. 'The, rods-in-DNB design criteria is also met. The offsite dose criterion were met and the locked rotor event does not present unacceptable risk to the public.
The offsite thyroid and y-body doses are within the acceptance criteria of 10 CE'R 100,.
3.283 References
- 1. Friedland, A. J. and Ray, S.,"Revised Thermal Design Procedure", WCAP-11397-P-A, April 1989.
- 2. Burnett, T.W.T et al, "I.OFTEN Code Description", WCAP-7907-P-A (Proprietary),
WCAP-7907-A (Non-proprietary), April 1984.
- 3. Hargrove, H.G., "FACTRAN A FORTRAN-IV Code for Thermal Transients in a UO,, Fuel Rod", WCAP-7908-A, December 1989.
- 4. Turkey Point Plant Units 3 and 4 Updated Final Safety Anal)sis Report, Revision 12.
- 5. Barrett, G.O., et al.,"Pressmdzer Safety Valve Set Preslurd, Shift", WCAP-12910, March 1991.
6.. Shefchek, J., "Application of the THINC Program to PWR Deign," WCAP-7359-L, August 1969.
- 7. Chelemer, H., Chu, P. T., FIochreiter, L. E., "TEIINC-IV- A6 Improved Program for Thermal-Hydraulic Analysis of Rod Bundle, Cores," WCAP-7956, February 1989.
mA1808w~a.wpf:lb/091895 3-68
Table 3.2.8-1 Sequence of Events - Loss of Flow Events Case Event Time sec Complete Loss of Reactor coolant pump undervoltage trip 0.0 Forced Reactor setpoint reached, all pumps lose power and Coolant Flow begin coasting down Rods. begin to drop 2.0 Minimum DNBR occurs 3.8 Maximum RCS pressure 5.1 Partial Loss of Two reactor coolant pumps lose power and begin 0.0 Forced Reactor coasting down Coolant Flow Low flow reactor trip setpoint reached 2.0 Rods begin to drop 3.0 Minimum DNBR occurs 47 Maximum RCS pressure 5.8 Reactor Coolant Rotor on one pump locks 0.0 Pump Shaft Seizure (Locked Rotor) Low flow reactor trip setpoint 0.05 reached Rods begin to drop 1.05 Maximum clad temperature occurs 3.5 Maximum RCS pressure occurs 3.8 mA1808wM3a.wpf:tb/082495 3-69
Table 3.,2.8-2 Smnmary. of Results for the Locked Rotor Transient 3 D)ops Initially Criteria ~Operating One Locked Rotor Maximum RCS Pressure (psia) 2690'.906 Maximum Clad Temperanue at Core Hot Spot ('I')
Zr-H20 Reaction at Core Hot Spot (wt. %) 0.4 mA1808w&8a.wpf:1bf081895 3-70
Table 3.2.8-3 Assumptions Used for Locked Rotor Dose Analysis Power 2346 MWt Reactor Coolant Noble Gas Activity Prior to Accident 1.0% Fuel Defect Level Reactor. Coolant Iodine Activity Prior to Accident 60 pCi/gm of DE I-131 Activity Released to Reactor Coolant from Failed Fuel .............. 10.0% of Core Gap (Noble Gas & Iodine)
Fraction of Core Activity in Gap (Noble. Gas & Iodine) 0.10 Secondary Coolant Activity Prior to, Accident 0.10 pCi/gm of DE I-131 Total SG Tube Leak Rate During Accident . 1.0 gpm SG Iodine Partition Factor 0.01'4 Duration of Activity Release from Secondary System hr Offsite Power Lost*
Steam Release from SGs to Environment . 521,000 lb (0-2 hr) 448,400 lb (2-8 hr) 1,196,000 lb (8-24 hr)
- Assumption of a loss of offsite power is conservative for the locked rotor dose analysis.
mA1808wMQa.wpf:tb/091895 3-71
1 ~ 2 0
0 4 6 re (szco>los)
Figure.'3D.'8-1 Core Flow vs. Time Complete Loss of'orced Reai.tor Coolant Flow (All loops operating,.all loops coasting down) mhl808wMh3awpf:1b/081895 3-72
1.4 1.2 1
Iw ,6
'II .6
.2, 0
0 6 TBK (SECONDS) 2400 2300 2200 I 2000 1900 1600 6
VmZ (SECONDS)
Figure 3.2S-2 Nuclear Power and Pressurizer Pressure Transients Complete Loss. of Forced Reactor Coolant Flow (All loops operating, all loops coasting down) mal 808wM3a.wpHb/081895 3-73
1.4 1.2
.2 8
TBK (SECONDS) 1 '
1 '
1 MI CI 6
4
.2 II I
.0 6 T1ME (PiECONDS)
Figure 3.2',8-3 Average and Hot Channel Heat Flux,Transients Comjolete Loss, of Forced Reactor Coolant Flow (All loops operating, all loops coasting down) mh1808w~a.wpf:1b/081895 3-74
2.;2 1.6 1 .'6 1 . 4 1 . 2 6
T1ME (SECONDS)
Figure 32$ C DNBR versus Time Complete Loss of Forced Reactor Coolant Flow (All loops operating, alliloops coasting down) mA1808wkh3a.wpf:18081895 3-75
.2 0
0 6 TBK (SECOND,S) 1.4 1.2
.2
.0
.0 4 '6 T1ME (Sl<CONDS)
Figure 3,.2S-5 Flow Countdown ver+as 'jaime Partial Loss of Forced Reactor Coolant Flow
'(All loops initiallly operating, two loops coasting down) m:u808wM3a.wpf:1b(081s95 3-7(i
1 ~ 4 1.2 1
Kg
.8 Im .6
.2 6 8 T1ME {SZCOmS) 2400 2300 2200 QPo 21'00 I 2000 1900 1 8'0 0 0 4 6 T1ME (SECTS)
Figure.32$ -6 Nuclear Power and Pressurizer Pressure Transients Partial Loss of Forced Reactor Coolant Flow (All loops initially operating, two loops coasting down) mal 808w1ch3a.wpf:1b/081895 3-77
1.4 1.2 0
0 4 6 TBK (SECOhTDS) 1.4 1.2 1
E o
6 5F 4.
.2 0
0 TDIE (SECONDS)
Figure 3.2S-7 Average and Hot Channel Heat Flitx Transients, Partial Loss of Forced Reactor Coolant, Flow (All loops i'nitiially operating, two loops coasting down) m:11808 wMh3a.wpf:1b/081895 3-78
2 '
2.4 2 '
1.8 1,6 1 '
1.2 0 4 6 TlMz (sacoms)
Figure 328-8 DNBR versus Time Partial Loss of Forced Reactor Coolant Flow (All loops initially operating, two loops coasting down) mhl808wM3a.wpf:1b/081895 3-79
1.4 1.2
.2 6
TILIZ (SBCONDS) 1.5
~g O
Bo CI g 0
a(
.5 nm (SWCONDS) iFigure 30!4-9 Flow C'oastdown versus Tiinie Reactor ICoolant Pump Shaft Seizure (All loops iinitlall~y operating, one looked rotor) mhl808wMh3a.wpf: IM$1895 3-80
1.4 1.2 1
gg R gX .8 mm .6 Hg
.4
.2 i
,2 4 6 T1ME (SECONDS) 2800 2600 H 2400 p
2 2'0 0 2 0 0 0 0'1ME (SECONDS)
Figure 32$ -10 Nuclear Power and RCS Pressure Transients Reactor Coolant Pump Shaft Seizure (All loops initially operating, one, locked rotor) m."11808w1ch3a.wpf:1M51895 3-81
1.4 4 8 TQK (SBCONDS) 1.4 1.2
.2 0
0 I I I
~ I I ~
TQK (SECOR)S)
Figure 3~!8-11 Average andi Hot Channel Heat Flux Transients Reactor Coolant P'ump ShaIR Seizure (All loops initially operating, one lodceil rotor) mhl808wkh3a.wpf:1b/081895 3-82.
3000 2500'000'500 10'00 500 0 4 6 vatz (szcoms)
Figure 3.24-12 Clad Inner Diameter Temperature versus Time Reactor Coolant Pump Shaft Seizure (All loops initially operating, one locked rotor) mM808wkh3a.wpHbN81895 3-&3
3.2.9 Loss of External Electrical Load and/or Turbine Trip 3.2.9.1 Identification of Causes arid Accident Description A major load loss on the plant can result fiom either a loss of external electrical load or from a turbine trip. A loss of external electrical load may result from an abnormal variation in network freqiienky 6r other adverse network operating condition. Fair either case, offsite power is avaiilable for the icontinued operation of plant components such as the reactor coolant pumps. The care of loss of all non-emergency AC power is presented in Section 3.2.11.
For a loss of external electrical load without subsequent turbine trip, no direct reactor trip sighal 'would 'e generated. The station is designed to accept a 50% step loss of load without actuating a reactor trip with all NSSS control, systems in automatic (reactor control ,'system, pressurizer pressure and level, steam generator water level control, and steam dumps). The automatic steam dump system, with'7%
dump capacity to the condenser, together with the rod control system, is able to accormrnodate the 50%
load rejection. Reactor power is reduced to a new equilibrium value consistent with the capability of the rod control system.
For a turbine or generator tripi, thie reactor would be tripped ~dirtictlg from a signal derived. from the turbine autostop oil pressure l,"a two out of three signal). Reactor coolant temperatures and pressure do significantly increase if the steam dump system and Pres'surizer'ressure control system are
'ot functioning properly.
In the event the steam dump valves:Fail to open following a large loss of load, the steam generator safety valves may lift and the reactor may be tripped by the high press~er pressure signal, the high pressurizer water level signal or the ioverternperature AT,signal. In the event of feedwater flow also being lost, the reactor may also be tripped by a steam generator low-low water level signal. The steam generator shell-siide pressure and reactor coolant temperatures will increase rapidly. The pressurizer safety valves and steam generator safety valves are sized to protect the RCS and steam generator against overpres!iurei for allI load losses withouti assuming ithe'peration of the steam dump system, pressurizer spray, pressurizer power-operated relief valves, iautomatic rod control, or the direct reactor trip on turbine trip.
The pressurizer safety valve capacity is sized based on a complete Iloss of heat sink with the gant initially operating at the maximum calculated 0iirbine load along with operation of the steam generator safety valves. The pressurizer and steam generator safety valves are then able to maintain thei RCS i and Main Steam System pressures withi.n 110% of'he corresponding design pressure without a direct reactor trip on turbine trip actiion.
The Turkey Point Units 3 and 4 Reactor Protection System in conjunction with the primary and secondary system designs preclude overpressurization without requiring the automatic rod control, pressurizer pressure control and/or turbine bypass control system.
mh1808wMh3a.wpf:1b/081895 3-84
3.2.92 Input Parameters and Assumptions
~ ~
Four cases are analyzed for a total loss of load from full power conditions: a) minimum reactivity feedback with pressure control, b) maximum reactivity feedback with pressure control, c) minimum reactivity feedback without pressure control and d) maximum reactivity feedback without pressure control. The primary concern for the cases analyzed with pressure control is minimum DNBR; the primary concern for the cases analyzed without pressure control is maintaining reactor coolant and main steam system pressure below 110% of the design pressure.
The major assumptions used in the analysis. are summarized in the following.
Initial Operating Conditions The cases with pressure control are analyzed using the Revised Thermal Design Procedure. Initial core power, reactor coolant temperature, and pressure are assumed to be at their nominal values consistent with steady-state full power operation. Uncertainties in initial conditions are included in the departure from nucleate boiling ratio (DNBR) limit as described in Reference 1.
'Ihe cases without pressure control are analyzed using the Standard Thermal Design Procedure. Initial uncertainties on core power, reactor coolant temperature, and pressure are applied in the most conservative direction to obtain the initial plant conditions for the beginning of the transient.
Reactivity Coefficients The total loss of load transient is analyzed with both minimum and maximum reactivity feedback.
The minimum feedback (BOL) cases assume a positive moderator temperature coefficient and the least-negative Doppler coefficient. The maximum feedback (EOL) cases assume a large (absolute value) negative moderator temperature coefficient and the most-negative Doppler power coefficient.
Reactor Control From the standpoint of the maximum pressures attained, it is conservative to assume that the reactor is in manual rod control. Ifthe reactor were in automatic rod control, the control rod banks would move prior to trip and reduce the severity of the transient.
Pressurizer Spray and Power-Operated Relief Valves The loss of load event is analyzed both with and without pressurizer pressure control (for both minimum and maximum reactivity feedback). The pressurizer PORVs and sprays are assumed operable for the cases with pressure control. The cases with pressure control minimize the increase in primary pressure which is conservative for the DNBR transient. The cases without pressure control mh1808wMh3a.wpf:tb/081895 3-85
maximize the pressure increase which is conservative fo1. thb RCS overpressurization criterion. In a11 cases the steam generator and pressttrizer safety valves are operable.
The pressurizer safety valves are modelled including the'effectst of'the pressurizer safety valve loop ~
seals using WOG methodology (]Reference 3). A total pressurixwr safety valve setpoint tolerance of
-3%, +2% is supported in the analysis. For those cases ChiCh @re analyzed primarily for DNBR pressure control cases), the negative tolerance is applied to conservatively reduce the 'pressurizer setpoint. For those cases which are analyzed primarily for peak RCS pressure, the posiitive tolerance is applied to conservatively increase the setpoint pressure. In the peak RCS pressure cases, the pressurizer safety valve includes a 3% uncertainty (1% set pressure shift utd a 2% set pressure tolerance) over the nomina) setpoint of 2500 psia. Additionally, no steam flow is assumed until the water in the valve loop seals is purg!A.
Feedwater Flow Main feedwater flow to the steam generators is assumed to be lost at the time of turbine trip. No credit is taken for auxiliary feedwater flow; however, evdntulally attxiliary feedwater flow would be initiated and a stabilized plant condition would be reached.
Reactor Trip Only the overtemperature hT, high pressurizer pressure, and~ low-low steam generator water level reactor trips are assumed operable for th!e purposes of this analysis. No credit is taken for a react'or on high pressurizer level or the dire'ct reactor trip on turbink trilp. 'rip Steam Release No credit is taken for the operation of the steam dump system or steam generator power-operated relief valves. This assumption maximizes secondary pre<sure. 'Ihe main steam safety valves are to lift and be full open at 6% above their respec!tive; setpoints. This 6% includes 3% each-for 'ssumed safety valve setpoint uncertainty and accumulation.
3.2.93 Description of Analyses For the Loss of External Electrical Load/Turbine Trip analysis, the behavior of the mit is evaluate'.d a complete loss of steam load from full power without a direct reactor trip. This assumption is
'or made to show the adequacy of the pressure-relieving devices and to demonstrate core protection margins, by delaying reactor ttip until a)ndjitions i,n the RCS result in a trip due to other signals.
Thus, the analysis assumes a worst-case tra11sient. In addition, no credit is taken for steam duinp.'ain feedwater flow is terminated at the time of t!!1rbine trip, wIith no credit taken for auxiliary feedwater (except for long-term recovery) to mitigate the! cokseguehces of the transient.
mh1808wkh3a.wpf:IM51895 3-86
A.detailed analysis using the LOFTRAN (Reference 2) computer code is performed to determine the plant transient conditions following a total loss of load. The code models the core neutron kinetics, RCS including natural circulation, pressurizer, pressurizer PORVs and sprays, steam generators, main steam safety valves, and the auxiliary feedwater system; and computes pertinent variables, including the pressurizer pressure, steam generator pressure, steam generator mass, and reactor coolant average temperature.
3.2.9.4 Acceptance Criteria Based on its frequency of occurrence, the Loss of External Electrical Load/Turbine Trip accident is considered a Condition II event as defined by the American Nuclear-Society. The criteria are as follows:
~ The critical heat flux shall not be exceeded. This is ensured by demonstrating that the minimum DNBR does not go below the limit value at any time during the transient.
~ Pressure in the reactor coolant and main steam systems should be maintained below 110% of the design pressures.
~ Fuel temperature and fuel clad strain limits should not be exceeded. 'Ihe peak linear heat generation rate should not exceed-a value which would cause fuel centerline melt.
3.2.9$ Results The calculated sequence of events for the four Loss of External Electrical Load/Turbine Trip cases is presented in Table 3.2.9-1.
Case 1:
Figures 3.2.9-1 through 3.2.9-3 show the transient response for the total loss of steam load event under BOL conditions, including a positive moderator temperature coefficient, with pressure control. The reactor is tripped on overtemperature dT. The neutron flux increases until the reactor is tripped, and although the DNBR value decreases below the initial value, it remains well above the safety analysis limit throughout the entire transient. The pressurizer relief valves and sprays maintain primary pressure below 110% of the design value. The main steam safety valves are also actuated and maintain secondary pressure below 110% of the design value.
Case 2:
t Figures 3.2.9-4 through 3.2.9-6 show the transient response for the total loss of steam load event under EOL conditions, assuming a conservatively large positive moderator density coefficient (corresponding to a large negative moderator temperature coefficient) and a most-negative Doppler only power mA1808w~a.wpf:ib/082495 3-87
coefficient, with pressure control. The reactor trip does not occur under these conditio,ns. The plant stabilizes at a power level established by the relief capacity of the main steam safety valves. Without operator intervention, the system would eventually reach' low-low steam generator water ~level reactor condition as the secondary system inventory decreases. 'Ihe DNBR increases tluoughout the 'rip transient and never drops lbelow the initial value. The pi'essuri2'er 1'elief valves and sprays maintain primary pressure below 110% of the, design value. The pressurizer pressure remains below the safety valve setpoint during the transient. 'The actuation of the ~main Stea1n safety valves also maintain secondary pressure below 110% of the desiign value.
Case 3:
Figures 3.2.9-7 through 3.2.9-9 show the transiient response .for the tot Q loss of steam load event under BOL conditions, including a positive moderator temperature coefficient, without pressure control. The reactor is tripped on high pressurizer pressure. The neuamn flux remaiins essentially const mt at full power until the reactor is tripped, and the DNBR remains above the initial value for the duration of the transient. The pressuriizer safety valves are: actuated and madnt un primary pressure below 110% of the design value. 'he maiin steam safety valves are also acttiatdd and maintain secondary greSs~
below 110% of the design value.
Case 4:
Figures 3.2.9-10 through 3.2.9-12 show the transient response for the total loss of steam load ~vent under EOL conditions, assuming a conservatively large positive m6derhtoi density coefficient (corresponding to a large negative moderator temperature coefficient) Md'a most-negative ~Doppler only power coefficient, without pressure, control. 'The, relictdr is'ripped oi1 high pressurize~ pressure.
The DNBR increases tliroughout the transient and never drolis below'he initial value. Thg pressurizer safety valves are actuated,and mountain primary pressure below 110% of the design value. 'Hte ntiaiit
~
steam safety valves are also actuated and maintain secondary pressiire below 110% of the design value.
3.2.9.6 Conclusions The results of this analysis show that the plant design is such that a tot< loss of external eieckckl load without a direct reactor hip presents no hazard to the integrity of the RCS or the maitre s&ai6 system. All of the applicable acceptance criteria are met, The minimum DNBR for each case is greater than the safety anajlysis liinit value. The peak prison~ ahd Secondary pressures ren'1ain below 110% of design at all tIimes. The protection features presented in Section 3.2,.9.2. provide mitigation of Loss of External Electrical Load/Turbine Trip trar5ient such'hat the above criteria are satisfidd.
'he mA1808wkh3a.wpf:1bf082495 3-88
3.2.9.7 References
- 1. Friedland, A. J. and Ray, S., "Revised Thermal Design Procedure," WCAP-11397 (Proprietary),
April 1989.
- 2. Burnett, T. W. T., et al., "LOFTRAN Code Description,"'WCAP-7907-P-A (Proprietary),
WCAP-7907-A (Non-proprietary), April 1984.
- 3. Barrett, G. O., et al., "Pressurizer Safety Valve Set Pressure Shift," WCAP-12910, March 1991.
mal 808wM3a.wpf:1b/082495 3-89
Table 32.9-1 Sequence of Events - Loss of Load/Turbine Trip Event Case Event Ti me ~SE~C
- 1. With pressurizer Turbine Trip 0.0 pressure control (minimum reactivity feedback) Overtemperature, 'hT Se'tpoint reached 1'r?.0
'eak pressurizer pressure occurs 13.8
'4.0 Rods begin to drop Mimmum DNBR occurs 15.2
- 2. With pressurizer Turbine Trip 0.0 pressure control (maximum reactivity feedback) Peak pressurizer pressme occurs 7'6
'See Note 1) Minimum DNBR occurs
- 3. Without pressurizer Turbine Trip 0,.0 pressure control (minIimum reactivity feedbac)c) High P'ressurizerIPressulre Setpoint reached 7,'.2 Rods begi:n to drop 9,.2
.Peak pressurizer pressure occurs 10.2 Mitumum DNBR. occurs, '.
Without pressurizer 'Turbine Trip 0.,0 pressure control (maximum reactivity feedbaclc) .High Pressurizer Pressure Setpoint reached 7.,4
.Rods begin to drop 94
- Peak pressurizer pressure occurs 10.6 '
Mimmum DNBR. occurs Never falls below initial value
'Note l., A reactor trip condition is never rc,ached in the analysis. The reactor stabilizes at~ a power level established by the relief capacity of MSSVs. Evcntu:dly, a low-low ste un genaator water level r~r kp j<voull ooIatr. 'he 3-90 'fu808wteh3a.wpf:1b/081895
1,4 1.2
.2 20 40 60 80 100 ma (szcoms) 1100 1000 900 800 g~
700 600 500 400 20 40 60 80 100 Tan (sacoms)
Figure 32.9-1 Total Loss of External Electrical:Load with Pressure Control, Minimum Reactivity Feedback mhl808wkh3a.wpf:1b/081895 3-91
610 600
/5 590 5,80
/ /
L COBB AVIRLGB 570
/
/
/
560 / COBB INIXED
/
/
550 /
540 2'0 40 60 80 100 TOPAZ'SECONDS) 4-.
5'.5 3
2.5 1.5 ~ l 0 20 40 60 80 100 TDN (I~VCONDS)
Figure 3.2.9-2 Totall Loss of External Electric& Load withe Pressure Control, Minimum Reactivity Feedback mhl808wlch3a.wpf: Ib/081895 3-5I2
2800 2600 2400 i 2'0 0 0 1.8 0 0 1 6 0 0 2'0 40 60 80 100 TBK (SECONDS) 1400 1200 Qc 1000 600 4.0 0
,0 20 40 60. 80 100 T1ME (SZCONDS)
Figure 32.9-3 Total Loss of External Electrical Load with Pressure. Control, Minimum Reactivity Feedback mA1808wkh3a.wpf:1b/081895 3-93
1 '
1.2 20 40 60 80 100 TIME (SEOONDS) 1100 1000 900 800 700 600 I
500 ~
I
~ ~
20 40 60 80 100
'TGIZ (SECONDS)
Figure 3.2.9~$ Tot@ Loss of Exteri1al Electrical Load with P'ressure.Control, Maximum Reactivity Feedback mA1808w4ch3a.wpf:1bf081895 3-94
61:0 600 CORE kVERLGE 590 580
/ I
'570 / CORE INLET
/
/
560 /
/
/
550 /
540
,0 20 40 60 80 100 MME (seconds) 4 '
3 ~ 5 a 3 2 ~ 5 1.5 I I I 0 20 40- 60 80 100 xaam (seconds)
Figure 32.9-5 Total Loss of External Electrical Load with Pressure Control, Maximum Reactivity Feedback mhl808w1ch3a.wpf:1bt081895 3-95
2800 2600 2400 i
g Pn 2200 2000 1800 1'600 0 20 40 60 80 1 0.0 TIE (SECONDS) 1 40 0 1200 g
1000 800 600 400 0 20 40 {10
~ ~ e
~
80 t ~
100 TOPAZ (SZCONDS)
Figure 32.9-4 'Total Loss of'External Electrical Load with Pressure (:ontroll, M[axiimum jReactivity Feedback mhl808wkh3a.wpf: Lb/081895 3-96
1.2
.2 0 20 40 60 80 100 TIE,(SECONDS) 1100 1000 900 800 700 600 500 20 40 60 80 100 TMZ (SECONDS)
Figure 3.2.9-7 Total Loss of External Electrical Load without Pressure Control, Minimum Reactivity Feedback
-mM808wM3a.wpf:Ib/081895 3-97
610 600 590 jX gg 580 r COBE LVERLGB
.570 / I
/
560
/ I COBE 15187 5 5 0.
540
- 20. 40 60 80 100 KhlZ (SECONDS) 4.5 3,5 3
2.5 1.5 20 40 60 80 100
'rlxe (SWCOM)S)
Figure 32.9-'8 Total .Loss of External Electri& IJoad w/thout Pressure Control; Minimum Reactivity Feedback mA1808wM3a.wpf:1bf081895 3-!98
2800 2600 2400 g Pn 2200 I 2000 1800 1600.
20 4Q 6Q 80 1 0,0 nME (sacoms) 1400 1200 1000
'6'0 0 400 0 20 40 80 80 100 T1ME (SECONDS)
Figure 3.2.9-9 Total'Loss of External Electrical Load without Pressure Control, Minimum Reactivity Feedback m:u 808'.wpf: I b/081895 3-99
~ 2 20 40 60 80 100 TQK4 (SEC05H) S')
1 1 0,0 1 0 0 0 9 0 0 8 0 0 8 700 600 500 ~
~
20 4 I 40 60 80 100 VatE (SECOarnS)
Figure 32.9-10 Totall:Loss of External Electrical Lo'ad without Pressure Control, Maximum Inactivity Feedback mA1808w&8awpf:Ibl081895 3-100
610 600 590
'580
/
/
COBE kVERLGE
/
570 /
/
580
/
/ CORE INIBT
/
'550 540
'0 20 40 80 80 100 TIME (SECONIIS) 4.5 3.5 2 '
1.5 0 '20 40 80 80 100 T1Mz (sacoms)
Figure 3.2.9-11 Total Loss of External Electrical Load without Pressure Control,
-Maximum Reactivity Feedback mhl808w~a.wpf: Ib/081895 3-101
2800 26QQ 2400 gl 2200 g
i 2000 1800 1800 20 40 60 80 100 Trm (szcowns) 1400 1200 1000 800 600 I
400 ~
+
20 40 80 80 100 T1ME (SZICONDS)
Figure 3.2.9-12! Total Loss of External Electrical Load without Pressure Control, Maxlimum reactivity Feedback mhl808w'eh3awpfu bf081895 3-1O2
34.10 Loss of Normal Feedwater 32.10.1 IdentiTication of Causes and Accident Description A loss of normal feedwater (from pump failures, valve malfunctions, or loss of offsite AC power) results in a reduction in capability of the secondary system to remove the heat generated in the reactor core. If the reactor is not tripped during this accident, core damage would possibly occur as a result of the loss of heat sink while at power. If an alternative supply of feedwater is not supplied to the plant, residual heat following a reactor trip may heat the primary system water to the point where water relief from the pressurizer could occur. A significant loss of water from the RCS could lead to core uncovery and subsequent core damage. However, since a reactor trip occurs well before the steam generator heat transfer capability is reduced, the primary system conditions never approach those that would result in a DNB condition.
'Ihe loss of normal feedwater that occurs as a result of the loss of AC power is discussed in Section 3.2.11.
The following events occur following the reactor trip for the loss of normal feedwater as a result of main feedwater pump failures or valve malfunctions:
A. As the steam system pressure rises following the trip, the steam system atmospheric dump valves are automatically opened to the atmosphere. Steam dump to the condenser is assumed not to be available. If the atmospheric dump valves are not available, the self-actuated main steam safety valves will lift to dissipate the sensible heat of the fuel and coolant plus the residual-heat produced in the reactor.
B. As the no-load temperature is approached, the steam system atmospheric dump valves (or the self-actuated safety valves, if the atmospheric dump valves are not available) are used to dissipate the residual heat and to maintain the plant at the hot standby condition.
The following provide the necessary protection against core damage in the event of a loss of normal feedwater.
A. Reactor trip on low-low water level in any steam generator.
B. Reactor trip on steam flow-feedwater flow mismatch coincident with low steam generator water level in any loop.
C. Three turbine-driven auxiliary feedwater (AFW) pumps, shared by Turkey Point Units 3 and 4, start automatically on any of the following:
- 1. Low-low water level in any steam generator m:I1808wMh3b.wpf:Ibf081995 3-103
- 2. Any safety injiectiion signal
- 3. Loss of offsite power (automatic umsfer to diesel pent:rators)
- 4. Loss of voltage to A and B 4.16 kV bus
- 5. Trip of both unit maiin feedwater pumps
'Ihe analysis shows. that following a loss of normal feedwater, the AFW, System is capable of removing the stored and residual heat thus preventing overpressurization of the RCS, overpressurization of the seconda~ side, water.rellief.frotn.the.iIIreSsurizer,.and.uncovery of the r1Iactior core.
32.102 Input Parameters and Assumptiion<s
'Ihe following assumptions are made in the analysis.
A. The plant is initially cooperating at 102% of the NSSS power of 2311.4 h'PVt, which includes a maximum reactor coolant pump heat of 11.4 MWt. '111e RCPs are assutned to continuously operate throughout the transiient providing a constant reactor coolant volumetric flow equal:to the Thermal Design value. Although not assumed in the analysis the reactor coolant pumps could be manually tripped at some later time in the transient 'to r'educe the heat addition to the RCS caus:d by the operation of the pumps.
B. The initial reactor vessel average coolant temperature iC cdnse~rvatively assumed to be 6.0'F higher than the nominal value (Ihigh) to account for the tert1peNture uncertainty on nominal temperature. The initial pressurizer press11re uncertainty is 60 psi and is conservatively s'obttacthd the nominal pressure. value.
,'rom C. Reactor trip occurs on steam genenhor low-low water level at 4.0% of narrow range span.
D. It is assumed that only one A&Vpump is available ~to <lushly 'a xxQnimum of 310 gpm to three steam generators, 120 seconds fbllowing a low-low steam generator water level. signal.
E. The pressurizer sprays and PORVs are assumed opetable. This maximizes the pressurizer watetI volume. Ifthese consol systems did not operate, the pressurizer safety valves would preVent th6 RCS pressure from exceeding, the RCS design pressure limit during tlhis trartsient.
F. Secondary system steam relief is achieved through the Self-'actuate main sb~ safety valves.
Note that steam relief wilIl, in fact, be through the steaai gdnedator atmospheiic dump val ves or condenser dump valves for most cases of:ioss.of notjmat feedvIater. However, since these valves are not safety gradle, they have been assumed unavailable.
Ib/082495 3-104
':u808w4h3b.wpf:
e G. The main steam safety valves are assumed to lift and be full open at 6% above their respective setpoint pressures. This 6% includes 3% each for safety valve setpoint uncertainty and accumulation.
H. The AFW line purge volume is conservatively assumed to be the maximum average value of the two Units.
I. Core residual heat generation is based on the 1979 version of ANS 5.1 (Reference 2).
ANSVANS-5.1-1979 is a conservative representation of the decay energy release rates.
Long-term operation at the initial power level preceding the trip is. assumed.
3.2.103 Description of Analysis A detailed analysis using the LOFTRAN (Reference 1) computer code is performed in order to determine the plant transient conditions following a loss of normal feedwater. The code models the core neutron kinetics, RCS including natural circulation, pressurizer, pressurizer PORVs and sprays, steam generators, main steam safety valves, and the auxiliary feedwater system; and computes pertinent variables, including the pressurizer pressure, pressurizer water level, steam generator mass, and reactor coolant average temperature.
Based on its frequency of occurrence, the loss of normal feedwater accident is considered a Condition II event as defined by the American Nuclear Society. The following items summarize the acceptance criteria associated with this event:
~ The critical heat flux shall not be exceeded. This is typically demonstrated by precluding Departure, from Nucleate Boiling (DNB).
~ Pressure in the reactor coolant and-main steam systems shall be maintained below 110% of the design pressures.
~ The pressurizer should not reach a water-solid condition.
3.2.10$ Results
'Ihe calculated. sequence of events for this accident is listed in Table 3.2.10-1. Figures 3.2.10-1 and 3.2.10-2 show the significant plant-parameters following a loss of normal feedwater with the I
t assumptions listed in Section 3.2.10.2.
Following the reactor and turbine trip from full load, the water level in the steam generators will fall due to reduction of the steam generator void fraction and because steam flow through the safety valves mfu808wMh3b.wpf:1bN91 195 3-105
continues to dissipate the stored and generated. heat. Two minutes following the initiation of the low-low level trip, the turbine-driven AFW pumps autorftatieally start consequently, reducing~ the rate at which the steam generator water level is decreasing.
'he capacity of one AjFW pump is such that the water level in the steam generator wi11l not recede below the lowest level at which sufficient heat transfer area is hvailable to dissipate core residual heat without the pressurizer reaching a water solid condition and preclu]ding any water relief through the RCS pressurizer relief or safety valves. From Figure 3.2.10-1 it can be seen that at no time does the, pressurizer go water solid. If the auxiliary feedwater delivered is greater than that of one AFW Pump, or the initial reactor power is less than 102% of the NSSS power, or the s>team generator water level in one or more steam generators is above the conservatively low 4% narrow range span level assumed ]For the low-low steam generator setpoint, the results f'r this transient will be bounded by the analysiS presented.
3.2.10.6 Conclusions With respect to DNB, the loss of normal feedwater event is bounded by the loss of load/turbine trip analysis (Section 3.2.9). The only difference between these two events is the turbine trip which is not assumed in a loss of normal feedwater until after the realctott trip. This a11ows for continued heat removal (steam flow), which is a benefit, until rod motion occurs following reactor trip. The loss of load/turbine trip analysis is described in Section 3.2.9. The results of'the analysis show:
~ Pressure in the reactor coolant and main steam system:is maintained below 110% of the design
'ressure.
~ 'Ihe pressurizer does not reach a water solid condition.
the loss of normal feedwater event does not adversely affect the core, the RCS, or the main
'herefore steam system since the AFW capacity is such that all applicable acceptance criteria are met.
3.2.10.7 References
- 1. Burnett, T. W. T., et,al, "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary),
WCAP-7907-A (Non-Proprietary), Ap]il 1984.
- 2. ANSI/ANS-5.1 - 1979, "Americ~-National Standard for Decay Heat Power in Light Water Reactors," August 1979.
m:u808wM3b.wpf:Ib/081995 3-106
Table 3.2.10-1 Time Sequence Of Events For Loss Of Normal Feedwater Flow Event Time seconds Main feedwater flow stops :10 Low-low steam generator water level reactor trip. setpoint reached 62.4 Rods begin to drop Flow. Rom one turbine driven AFW,pump is initiated 182.4 Feedwater lines are purged and cold AFW is delivered to 746.0 three Steam Generators.
Peak water level in pressurizer occurs 2956.0 m%1 808wM3b.wpf: 1 b/081995 3-107
2600 2400 2200
~
W cn M~~
g 2000 i 1600 1600 0 I 8 8 10 10 10 10 10 TahtE (SaCO>eS) 1400 1200 1000 600 600 Ig 400 200
~ ~ ~ ~
~ ~l ~ I ~ ~ ~ < I It ~
0 1 10 10 10 10 10 TDCE (SEIC05H)S)
Figure 32;10-1 PressuriIxr Pressure and Water Volume Transients for'lL,os's of Normal Feedwater mAI808 web.wpf: Ibl081995 3-108
7 0,0 i
g 6 5 0 600 COLD LEG 550 500 0 1 0 10 1.0 10 10 10 TatE (szcoms) 1200 1000 800 m
600'00 200 0
1 0 1 0 10 10 10 10 10 Tmz (smcoms)
Figure 3.2.10-2 Loop Temperatures and Steam Generator Pressure for Loss of Normal Feedwater mA1808wMh3b.wpf:1bN81995 3-109
3.2.11 Loss of Non-emergency AC Power to the Plant Auxiliariies 3.2.11.1 Identification of Causes and Acrident Description A loss of non-emergency AC power will result in a loss bf poWer to the plant auxiliaries, i.e., the reactor coolant pumps, condensate pumps, etc. The loss of poWer tnay be caused by a complete loss of the offsite grid accompsuued by a turbine generator trip oi. bj a loss of the onsite AC distributibn system. The events following a loss of AC power with turbine and reactor trips are described in the sequence listed below.
A. The plant vital instruments are supplied by emergency power sources.
B. As the steam system pressure ri,ses following the trip, the 5teafn system atmospheric dump valves are automatically. opened to the atmosphere. Steam dump to the condenser is assumed not to be, available. If the atmospheric dump valves are not available, the self-actuated main steam safety valves will lift to dissipate the sensible, heat of the Shel and coblant plus the residual heat produced in the reactor.
C. As the no-load temperature is approached, the steam system atmospheric dump valves (or'hd self-actuated safety valves, if the atmospheric dujmp valves are not available) are used to dissipate the residual heat and to maintain the plant at the hot standby condition.
D. Both emergency diiesel generators associated with the utut Sill'utomatically start followihg the loss of voltage to the A and B 4.16 kv buses of that unit. At the same tiime, these buses Sill from their normal supply and their motor supply and feed brokers will be opened. The, be'solated breaker from the emergency diesel generator to its associated 4.16 kv bus will close energizing the buses. Equipment. will-be sequentially loaded onto the 4.16 kv buses. Ibad centers And motor control centers will be energized as controlled bg th6 lohd 0equencers. All required additional manual loads will be powered by the emergency diesel generators as required by procedures.
The following provide the necesmy protection against core datnage in the event of a loss of AC power. nbn-'mergency A. Reactor trip on low-low water level in any steam generator B. Reactor trip on steam flow-fenbvater flow mismatch coincidedt with low steam generator water level in any loop C. 'Ihree turbine~ven auxilliMy feedwater (A&V)pumps, shhred by Turkey Point Units 3 and 4, start automatically on any of the following:
mh1808w~b.wpf: 1bf082495 3-110'
- 1. Low-low water level in any steam generator
- 2. Any safety injection signal
- 3. Loss of offsite power (automatic transfer to diesel generators)
- 4. Loss of voltage to A and B 4.16 kv bus
- 5. Trip of both unit main feedwater pumps
- 6. Manual actuation.
Following the loss of power to the reactor coolant pumps (RCPs), coolant flow is necessary for core cooling and the removal of residual and decay heat. Following the RCP coastdown due to the loss of AC power, the natural circulation capability of the RCS will remove decay heat from the core, aided by the AFW flow in the secondary system. Therefore, the analysis for this event is performed to demonstrate that the resultant natural circulation flow in the RCS in conjunction with the AFW flow is sufficient to remove decay heat from the core.
Turkey Point Units 3 and 4 share common electrical and AFW.systems. Thus, a loss of non-emergency AC Power to the plant auxiliaries could simultaneously affect both units. The AFW system would then be required to provide flow to both'units.
The worst single failure that may occur in the AFW system would result in the availability of only one of the three turbine driven AFW pumps. For this condition, the flow from the one AFW pump could be as low as 233.4 gpm to one of the units until the operator takes actions from the control board to realign:the fiow split to the units.
The analysis is performed for one unit, conservatively bounding both units.
3.2.112 Input Parameters and Assumptions The major assumptions used in this analysis are identical to those used in the loss of normal feedwater analysis (Section 3.2.10) with the following exceptions.
A. Loss of AC power is assumed to occur at the time of reactor trip on low-low SG water level. No credit is taken for the immediate insertion of the control rods as a result of the loss of AC power to the station auxiliaries.
B. Power is assumed to be lost to the RCPs. To maximize the amount of stored energy in the RCS, the power to the RCPs is not assumed to be lost until after the start of. rod motion.
C. A heat transfer coefficient in the steam generators associated with RCS natural circulation is assumed following the RCP coastdown.
mh1808wMQb.wpf:tb/082495 3-111
D. The RCS flow coastdown is bas>xl on a momentum balance around each reactor coolant loop and across the reactor core. I%is momentum balance is combined with the continuity equation, a, pump momentum balance, the as-built pump characteristics and conservative estimates of system pressure losses.
E. The worst single failure assutned to occur is in the AFW system. This results in the availability of only one AFW pump supplying miiiimum flow to three steam generators, 95 seconds following ~
a low-low steam generator water level signal. 'Ihe AFW flow is less than that assumed for a loss of normal feedwater because Turkey Point Units 3 and 4 have a shared AFW system and a 16ss of AC power may occur simultaneously at both units.
3.2.118 Description of Analysis A detailed analysis using the L.OFTRAN (Reference 1) computer code .is performed in order to determine the plant transient conditions following a loss af non-emeirgency AC power. The code models the core neutron kineti>x, RCS including natural circulation, pressurizer, pressurizer PORVs and sprays, steam generators, main steam safety valves>, and the, auxiliary feedwater s>ystem; and computes pertinent variables, including the pressuriizer pressure, pressurizer water level, steam generator mass, and reactor coolant average temperate.
32.11.4 Acceptance Criteria Based on its frequency of occrurence> the loss of nonwmergency AC power incident is considered a Condition II event as deflned by the American Nuclear Society. The following items summarize the acceptance criteria associated with thiis event.
The critical heat flux should not be exceeded. 'Itus is typically demonstrated by precluding Ddpatiturh from Nucleate Boiling (DNB). With respect to DNB, the loss of non-emergency AC power event is bounded by the complete loss of flow analysis since the coastdown in the loss of non-emergency AC power event does not occur until after reactor hip which is less limiting. Hence, the loss of non-emergency AC power event is bounded by the complete loss of fiow analysis described in Section 3.2.8.1.
Pressure in the reactor coolant and main steun systems shoul'd b'e maintained below 110% of the design pressures.
The pressurizer should not reach a water-solid condition.
m%1 808w'eh3b.wpf: tb/091195 3-112
Figures 3.2.11-1 and 3.2.11-2 show plant parameters following a loss of nonwmergency power with the assumptions listed in Section 3.2.11.2. The calculated sequence of events for this accident is listed in Table 3.2.11-1.
The first few seconds after the loss of non-emergency AC power to the RCPs, the flow transient for a loss of non-emergency AC power event will closely resemble a simulation of the complete loss of flow incident, where core damage due to rapidly increasing core temperatures is prevented by the reactor trip, which, for a loss of non-emergency AC power event, is on a low-low steam generator water level signal. After the reactor trip, stored and residual heat must be removed to prevent damage to the core and the reactor coolant and main steam systems. The LOFT$AN code results show that the natural circulation and AFW flow available is sufficient to provide adequate core decay heat removal following reactor trip and RCP coastdowii.
The capacity of the turbine-driven AFW pump is such that the water level in the steam generators does not recede below the lowest level at which sufficient heat transfer area is available to establish enough natural circulation flow in order to dissipate core residual heat without water release through the RCS relief or safety valves. Figure 3.2.11-1 i/lustrates that the pressurizer never reaches a water solid condition. Hence, no water relief from the pressurizer occurs.
3.2.11.6 Conclusions Results of the analysis show that, for the loss of non-emergency power to the station auxiliaries event, all applicable safety criteria are met. The DNBR transient is bounded by the complete loss of fiow event (Section 3.2.8.1) and remains above the safety analysis limit value. Assuming the worst single failure occurs in the AFW system, the available AFW capacity and the natural circulation capability of the RCS following reactor coolant pump coastdown is sufficient to prevent the pressurizer f'rom reaching a water solid condition such that sufficient long-term heat removal capability exists to prevent fuel or clad damage. Pressure in the reactor coolant and main steam systems is maintained below 110% of the design pressures.
3.2.11.7 Reference
- 1. Burnett, T. W. T., et al, "LOFTR~ Code Description," WCAP-7907-P-A (Proprietary),
WCAP-7907-A (Non-proprietary), April 1984.
mA1808wMh3b.wpf:tbf091195 3-113
Table 3.:E.11-1 Time Sequence Of Events For Loss 0'f N'on-Em'ergency AC Power Event Ti:me ~serwnd~s Main feedwater flow stops 10 Low-low steam generator water level reactor ttip setpoint reached 62.4 Rods begin to drop Reactor coolant pumps begin to coastdown 66.4 Flow from one turbine driven AFW pump is iitit1ated 157A Feedwater lines are purged and cold AFW is delivered to three Steam Generators. 906.0 Core stored and residual heat decreases to i~V heat renjtovI11 -3500 capacity Peak water level in pressurizer occtuw 3596.0-mhl808wM3b.wpf:1bf081995 3 114
2600 2400 g rn 2200 2000 1800 I 0 I 2 4 10 10 10 10 10 10 T1ME (SZCONDS) 1400
. ~ 1200 i 1000 600 gF 600 g 400 200
-I 0 I 2 10 10 10 10 10 10 T1ME (sacoms)
Figure,3.2.11-1 Pressurizer Pressure and Water Volume Transients for Loss of Offsite Power mal 808w'eh3b.wpf: Ibj'081995 3-115
700 650 HÃP LEG
,g 600 Q w pB 550 500 0 1 8 10 10 10 10 10 10 Tam (SECONDS) 1200 1000 800 Clg
~m 600 400 200
~ ~ ~ I
~t l l ~I 'Il~ ~ ~ l ~ ~ II ~ 'I ~ ~ ~ l
-1 0 1 10 10 10 10 10 10 TORE (SECONDS)
Figure'32.11-2 Loop Temperatures and Steam Generator Pressure for Loss of OEsite Power mh1808whk3b.wpf:1b/081995 3-116
3.2.12 Fuel Handling Accident Radiological Consequences 3.2.12.1 Introduction A fuel assembly is assumed to be dropped and damaged during refueling. Analysis of the accident is performed for the accident occurring either inside containment or in the spent fuel pool. Activity released from the damaged assembly'is released to the outside atmosphere through either the containment purge system or the spent fuel pool area ventilation systems. This section describes the assumptions and analyses performed to determine the amount of activity released and the offsite doses resulting from this release.
3.2.122 Input Parameters and Assumptions
'Ihe analytical methods and assumptions used to determine the offsite doses due to a fuel handling accident (FHA) are primarily those outlined in References 3 and 4. Also addressed are the uprated power level of 2346 MWt, and a 12% I-131 gap fraction (20% increase over recommendation of Reference 3) for high burnup fuel (References 1 and 2).
Two cases are analyzed with respect to the amount of damage suffered by the dropped assembly. For the first case, it is. assumed that all of. the fuel rods in the equivalent of one assembly are damaged to the extent that all their gap activity is released. In the second case, only the fuel rods in one row of the assembly (i.e., 15 fuel rods) are damaged sufficiently to cause their gap activity to be released.
Since, per Technical Specifications, the reactor has to be subcritical for 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> before fuel is moved, 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> of radioactive decay is assumed in the analysis. The Technical Specifications require at least 23 feet of water to be above the reactor vessel flange while in refueling (mode 6).
This is consistent with the guidance contained in Regulatory Guide 1.25 (Reference 3). With this water depth, decontamination factors (DF) of 133 for elemental iodine and 1 for methyl iodine are used for pool scrubbing (Reference 3). The iodine activity in the fuel rod gap is assumed to be 99.75% elemental and 0.25% methyl (Reference 3). The resulting overall pool scrubbing DF for iodine is 100.
All of the noble gas released Rom the damaged assembly is assumed to be released from the pool water (i.e., the pool scrubbing DF is 1) (Reference 3).
A conservatively high radial peaking factor of 1.7 is assumed for the damaged assembly.
No credit is taken for Qltration of iodine for either the FHA inside containment or the FHA in the spent fuel pool. Although the containment purge will be automatically isolated on a containment high radiation alarm, isolation is not modeled in the analysis. The activity released from the damaged assembly is assumed to be immediately released to the outside atmosphere.
m:u 808'.wpf:ibI091195 3-117
The major assumptions and parumeters used in the analysis are itemizixl in Table 3.,2.1'2-1. The thyroid dose conversion factors, 'breathing rates, and atmospheric dispersion factors used in the dIise calculations are given. in Table 3.2.12-2. Since the assumptions and parameters for a FHA insideI containment are identical to those fair a FHA in the spent fuel pool, the offsite doses are the same regardless of the location of the acci:dertt.
30.129 Description of Analyses F'erformed The activity releases and offsite doses are determined. foi both a FHA inside contaimnent and'a FHA in the spent fuel pool. Offsite doses are calculated for bbth one damaged'ssembly and one damaged row of rods.
3.2.12.4 Acceptance Criteri,a The dose limits for a FHA are "well within" the guideline values of 10 CFR 100, or 75 rem thyrOid'nd 6 rem y-body.
3.2.12$ Results The calculated thyroid and y-body. doses (rem) at the exclusion boundary and low population Ironic outer boundary are as follows:
Damaged Fuel EB (0-2 Hr) LE'Z (0-2 Hr)
- 1. Thyroid One Assembly 3.3 E!+1 3.2 EO One Row 2.4 E!0 2.4 E-1
- 2. y-Body One Assembly 9,.3 Ei-2 9.0 E-3 One Row 6,.8 E':3 6.6 E-4 3.2.12.6 Conclusions The offsite thyroid and y-body doses due toi the FHA are within the acceptance criteria in Section 3.2.12.4.
m:iil808wkh3b.wpf: Ibf091895 3-118
3.2.12.7
~ ~ ~ References
- 1. NUREG/CR-5009, "Assessment of the Use of Extended Burnup Fuel in Light Water Power Reactors", D. A. Baker, et. al., February 1988.
- 2. Federal Register/Vol.'3, No. 39/ February 29, 1988/pages 6040 through 6043.
- 3. USAEC Safety Guide 1.25, "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", 3/23/72.
mh1808wMh3b.wpf: Ib/091195 3-119
Table 32.12-1 Assumptions Used For Fuel Handling Accident Dose Anaiysiis Power .... . 2346 MWt Radial Peaking Factor ....... 1.7 Damaged Fuel Case 1 . ...,1 Fuel Assembly Case 2 15 Rods Fuel Rod Gap Fractions ...... 0.10 for iodines and noble gases, except 0.12 for I-131 0.30 for )Q-85 Percent of Gap Activity Released ......,. 100%
Pool Decontamination Factors Elemental Iodine...,..... 133 Methyl Iodine ..
Noble Gas Iodine Species in Fuel Rod Gap Elemental Iodine 99.75Fo Methyl Iodine . 0.25'%%uo Minimum Water Depth Above the -Reactor Vessel Flange ..... 23 feet Filter Efficiency .. no filtrati.on assumed Containment Isolation ... no contairunent isolation mA1808wM3b.wpf:tb/091895 3-120
Table 32.12-2 Dose Conversion Factors, Breathing Rates and Atmospheric Dispersion Factors Isoto e Dose. Conversion Factor '"
rem/curie I-131 1.07E6 1-132 6.29E3 I-133 1;81E5 I-134 1.07E3 I-135 3.14E4 Time Period Breathing Rate hr "'~/sec 0-8 3.47E-4 Atmospheric Dispersion Factors sec/m3 Exdusion Bounda 0-2 hr 1.54'.5E-5 L'ow Po ulation Zone 0-2 hr
'"ICRP Publication 30
"'Regulatory Guide 1.4 mh1808w~b.wpf:1bf082595 3-121
3.2.13 Dropped Spent Fuel Tran~>fer'ask Radiologilcal Cottseguences 3.2.13.1 Introduction It is assumed that a spent fuel transfer cask is dropped into 'the six!nt fuel pool and damages fuel assemblies stored there. Activity released from the damaged assernbliies is released to the outside atmosphere through the spent fuel pool area ventilation systera>. This section describes the assumptions and analyses performed to deterntlne the amount of activity released and the offsite doses resulting from this release.
3.2.13'nput Parameters and A!>sumptions
'Ihe input parameters and assumlptions for the cask drop dose analysis are the same as those for the fuel handling accident (Section 3.2.12) with the following exceptions:
The offsite doses are determined on a per core: basis. Thus,'ht> base case doses are, for 157 fuel assemblies (i.e., the total number of fuel assemblies in ohe dork) bj:ing damaged by the dropped cask.
It is assumed that the gap activity in every fuel rod in each 'damaged fuel assembly is released.
Since, the Technical Speciifications prevent ca1>k moveml!nt into th1! spent fuel pool until all the spent fuel in the pool has decayed for,a minimum of 1525 hours0.0177 days <br />0.424 hours <br />0.00252 weeks <br />5.802625e-4 months <br />, 1525 hours0.0177 days <br />0.424 hours <br />0.00252 weeks <br />5.802625e-4 months <br /> of'a>fioacti ve decay is assumed in the analysis.
A radial peaking factor of 1.0 is used for the fuel assemblies stored in the spent fuel pool.'he major assumptions and para1neters used in the analysis are itemized in Table 3.2.13-1.,
3.2.139 Description of Analyses Perf'ormed The. base case activity. releases and offsiite doses are determined for 157 fuel assemblies in the spent fuel pool being damaged by the dropped cask. Gus is equivalent to a full core.
3.2.13.4 Acceptance Criteria The dose limit assumed for a dropped cask is "well within" the guideline values of 10 CFR 100, or 75 rem thyroid and 6 rem y-body. 'Ious is )the same acceIptatjtce crit'eria assumed for the fuel handling accident.
3.2.13$ Results The base case offsite thyroid and whole body doses due to the dropped cask assuming 157 fu1Il assemblies being damaged are within, the acceptance criteria in Section, 3.2.13.4. The calculated mA1808wMh3b.wpHh/091195 3-122
e thyroid and y-body doses (rem) at the exclusion'boundary and low population zone outer boundary are as follows:
EB (0-2 Hr) LPZ (0-2 Hr)
Thyroid 1.77 El 1.73 EO y-Body 2.42 E-2 2.36, E-3 3.2.13.6 Conclusions With the number. of fuel assemblies equivalent to one core damaged, the doses are well within the acceptance criteria. The theoretical limit as to the number of fuel assemblies that would have to be damaged without exceeding the acceptance criteria is approximately 4.0 cores (or 628 fuel assemblies).
This amount. of damage due to a dropped cask is-not physically possible.
mA1808wMh3b.wpf:lb(091895 3-123
Table; 3.2.13-1 A~surnptions Used. Fair Dropped Cask Dose Analysis Power '2346 MWt Radial Peaking Factor . 1,.0 Damaged Fuel (Base Case) 157 Fuel Assemblies Fuel Rod Gap '.Fractions ... 0.10 for iodines and noble, gases, except 0.12, for 1-131 and 0.30 for IQ-85 Percent of Gap Activity Released 100%%uo Pool Decontaminajtion Factors Elemental Iodine 133 Methyl Iodine Noble Gas Iodine Species in Fuel Rod Gap Elemental Iodine ...........,.. ....,.......... 99.,75%%uo Methyl Iodine 0.25cfo Minimum Wate:r Depth Above tlhe Reactor Vessel Flang,e..... ........ 23 feI:t Filter Efficiency . .....,.... no filtration,assumed mA1808wMh3b.wpf:1W09119$ 3-124
3.2.14.1 Introduction The volume control tank (VCT) is assumed to rupture and release its noble gas contents directly to the outside atmosphere. This section describes the assumptions and analyses performed to determine the amount of activity released and the offsite doses.
3.2.142 Input Parameters and Assumptions The noble gas activity in the VCT is based on a 1% fuel defect level and a liquid level of 40%.
The major assumptions and parameters used in the analysis are itemized in'Table 3.2.14-1. The average gamma energies used in the determination of the equivalent curies of Xe-133 in the VCT are given in Table 3.2.14-2.
3.2.143 Description of Evaluation Performed The equivalent curies of Xe-133 in the VCT are calculated.
3.2.14.4 Acceptance Criteria The dose limit for a radioactive release due to a waste gas system failure is 0.5 rem y-body (Reference 1).
3.2.14$ Results There are 32,330 equivalent curies of Xe-133 released from the VCT. The offsite y-body doses (rem) due to the VCT rupture are: EB (0-2 Hr) = 3.8E-2 and LPZ (0-2 Hr) = 3.6E-3.
3.2;14.6 Conclusions The offsite y-body doses due to the VCT rupture are well below the acceptance criteria.
3.2.14.7 Reference NUREG-0800, Standard Review Plan 11.3, Gaseous Waste Managment Systems, Branch Technical Position ETSB 11.5, "Postulated Radioactive Releases Due to a Waste Gas System Leak or Failure", Rev. 0, July, 1981.
rnhl808wMh3b.wpf:1bf091395 3-125
TABLE 32.14-1 Assumptions Used For Volume Control Tank Rupture Dose Analysiis Power 2346 MWt
-Reactor Coolant Noble Gas Activity. 1% Fuel Defect Level VCT, Liquid Level 40%
VCT Liquid Volume 120 ft VCT, Vapor Volume 180 ft mM808wMQb.wpf: I b/082295 .3-'126
TABLE 32.14-2 Noble Gas Average Gamma Energy Nuclide E ev/Dis Kr-85m 0.16 Kr-85 0.0023 Kr-87 0.79 Kr-88 2.2 Xe-131m 0.0029 Xe-133m 0.02 Xe-133 0.03 Xe-135m 0.43 Xe-135 0.25 Xe-138 1.2 m."i1808w'eh3b.wpf:Ib/082295 3-127
3.2.15 Gas Decay Tank Rupture Radiological Conse11uehceIs 32.15.1 Introduction A gas decay tank is assumed to rupture and release its nt1blk ghs cbntentS directly to the outside This sectiIon describes the assumptions and analyses performed to determine the amount 'tmosphere.
of activity released and the corresponding offsite idosiw.
3.2.152 Input Parameters and Assumptions The noble gas activity in a gas decay tank is biased on a l%%ud fuel defer.t lt:vel and a letdown flow rate of 120 gpm. The inventory of noble gas activity .is assumed to be stripped from the RCS during a cold shutdown and placed in a single gas decay t u1k. There is inegligiible iodine activity in the gas decay tanks.
The major assumptions and paratneters used in the analysis are itemized in Table 32.15-1. 'Ihe noble gas average gamma energies and atmospheric dispersion factors us& in the y-body dose calculations are given in Table 3.2.15-2.
3.2.153 Description of Analyses Performed The offsite y-body doses due to the instant8uteous release to atmosphere of the entire inventory of noble gas in the ruptured gas decay tank are calculated.
Acceptance Criteriia '.2.15.4 The dose limit for a radioactive release due to a waste gas sIysteIm failure is 0.5 rem y-body (Reference 1).
3.2.15$ Results There are 55,000 curies of equivedent Xe-133 released to the: environment duie toi a postulated
'gas'ecay tank rupture. The resulting y-body doses (rem) aret.: FB (0-2 Hr) =. 6A E-2 and LPZ (0-2 Hr) = 6.2 E-3.
3.2.15.6 Conclusions The offsite y-body doses due to the gas decay tank rupture are well below the acceptance criteria.
3.2.15.7 References
- 1. NUREG-0800, Staadard Review PI<<n 11.3, Gaseous Waste~ Management Systems, Branch i
Technical Position ETSB 11.5, "Postulated Radioactive Releases Due to a Waste Gas SysIteml Leak or Failure," Rev. 0, July 1981.,
m:u 808wMb3b.wpf: I bf091895 3-128
Table 3.2.15-1 Assumptions Used For Gas Decay Tank Rupture Dose Analysis Power ....... 2346 MWt Reactor Coolant Noble Gas Activity 1% Fuel Defect Level Letdown Flow Rate............. ...................... 120 gpm Gas Decay Tank Volume .. 525 ft mh1808wM3b.wpf: I bi'082295 3-129
Table 3;:2.18)-2
.Noble Gas Average Gamijna Energy and Atrhospheric Dispersion Factors Nuclide. ~K~4ev/Di.sg Kr-85m 0.16 Kr-85 0.0023 Kr-87 0.79 Kr-88 2.2 Xe-131m 0.0029'.02 Xe-133m Xe-133 0.03 Xe-135m 0.43 Xe-135 0.25 Xe-138 1.2 Atmospheric DLspersion Factors,
~sec/rn~~
Exclusion Boundarr~O-2 her 1'.54E-4 Low Po ulation Zone 0-2 hr 1.5:E-5 2-12 hr 6.5:E-6 12-720 hr 2.4!E-7 mh1808wkh3b.wpf:1bf091895 3-130
32.16 Main Steam Line Break Core Response 30.16.1 Identification of Causes and Accident Description A rupture of a 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 valve malfunction (UFSAR Section 14.2.5.1),or due to a break in pipe line (UFSAR Section 14.2.5.2) . 'Ihe steam release results in an initial increase in steam fiow which decreases during the accident as the steam pressure falls.
The energy removal from the Reactor Coolant System causes a reduction of 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 is 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 rods inserted. A return to power following a steam pipe rupture is a potential problem only because of the high hot channel factors which may exist when the most reactive rod is assumed stuck in its fully withdrawn position. Assuming the most pessimistic combination of circumstances which could lead to power generation following a steam line break, the core is ultimately shut down by the injection of boric acid at the boric acid concentration from the refueling. water storage tank.
3.2.162 Description of Analysis The main steam line break core response. events have not been reanalyzed to support the NSSS power uprating for Turkey Point Units 3 and 4; an evaluation of the UFSAR licensing basis analyses (UFSAR Sections 14.2.5.1,and 14.2.5.2) was performed instead. The events are analyzed assuming hot zero power conditions. Since the hot zero power conditions for the NSSS power uprating as well as all other key analysis assumptions have remained unchanged, the current UFSAR steam line break core response analyses remains valid. A DNB evaluation of the statepoints obtained for the most limiting steam line break core response case was performed.
3.2.163 Acceptance Criteria The valve malfunction incident discussed in UFSAR Section 14.2.5.1 is classiflied as an ANS Condition II event. A major break in a pipe line.(UFSAR Section 14.2.5.2) is classified as an ANS Condition IV event. Minor secondary system pipe breaks are classified as ANS Condition HI events.
All of these events are analyzed to meet Condition II. criteria. The only criterion that may be challenged during this event is the one that states that the critical heat flux should not be exceeded.
The evaluation shows that this criterion is met by ensuring that the minimum DNBR does not go below the limit value at any time during the transient.
t 3.2.16.4 Results The evaluation of the limiting main steam line break core. response statepoints indicates that the minimum DNBR stays above the safety analysis limit value at all times during this event.
m:u808wlch3b.wpf:Ib/082295 3-131
3.2.16$ Conclusions
'Ihe evaluation shows that for all of the main stealm Kine break dor6 response events the DN8 desigh basis continues to be met at the uprated power level.
mh1808wMQb.wpf:1b/082295 3-132'.
3.2.17
~ ~ Rupture Of A Control Rod Drive Mechanism (CRDM) - RCCA Ejection 3.2.17.1 Identification of Causes and Accident Description This accident is deQned as a mechanical failure of a control rod drive mechanism pressure housing resulting in the ejection of the rod cluster control assembly (RCCA) and drive shaft. The consequence of this mechanical failure is a rapid positive reactivity insertion together with an adverse core power distribution,,possibly leading to localized fuel rod damage. The resultant core thermal power excursion is limited by the Doppler reactivity effect of the increased fuel temperature and terminated by reactor trip actuated by high nuclear power signals.
A failure, of a control rod mechanism housing sufficient to allow a control rod to be rapidly ejected from the core is not considered credible for the following reasons:
A. Each full-length control rod drive mechanism housing is completely assembled and shop tested at 3450 psig.
B. The mechanism housings are individually hydrotested after they are attached to the head adapters in the reactor vessel head and checked during the hydrotest of the completed Reactor Coolant System.
C. Stress levels in the mechanism are not affected by anticipated system transients at power or by the thermal movement of the coolant loops. Moments induced by the design earthquake can be accepted within the allowable primary working stress ranges specified in the ASME Code, Section III, for Class components.
1 D. The latch mechanism housing and rod travel housing are each a single length of forged type-304 stainless steel. This material exhibits excellent notch toughness at all temperatures which will be encountered.
A significant margin of strength in the elastic range, together with the large energy absorption capability in the plastic range, gives additional assurance that the gross failure of the housing will not occur. The joints between the latch mechanism housing and rod travel housing are threaded joints and reinforced by canopy-type rod welds.
The operation of a chemical shim plant is such that the severity of an ejection accident is limited. In general, the reactor is operated with the rod cluster control assemblies inserted only far enough to permit load follow. Reactivity changes caused by the core depletion are compensated by boron dilution. Further, the location and grouping of control rod banks are selected during the nuclear design to lessen the severity of a rod cluster control assembly ejection accident. Therefore, should a rod cluster control assembly be ejected from its normal position during full-power operation, only a minor reactivity excursion, at worst, could be expected to occur. The position of all rod cluster mh1808wMh3b.wpf: Ib/082295 3-133
control assemblies is contiinuously indicated in the control room. An alarm will occur if a, bank of rod cluster control assemblies approaches its inserlion limit or if one control rod assembly devil &orz!
its bank. There are low and 1low-low level insertion alarm c',irctuts for each bank. Ihe control rod monitoring and aliarm systems are described in Reference 1. 'osition 3.2.172 Input Parameters and Assumptions Input parameters for the analysis are conservative1ly selm'.ted on'he basis of values calculated for thils type of core. The more important parameters are discussed below. Table 3.'.2.17-1 presents the parameters used in this analyssis.
E ected Rod Worths and Eliot Channel Factors Standard The values for ejected rod worths and hot chajmel factors are calculated using either three-dimensional static methods or a synthesis of one-dirnent>ional and two-dimensional calculations. nuclear design codes are used .in t1be analysis. No credit is taken for the flux-flattening effects of reactivity feedback. The calculation is performed for the maximum allowed bank insejtion at a proven +we level, as determined by the rcd hxsertion limits. Ihe analysiis assumes adverse xenon diistributions to provide worst-case results.
Appropriate margins are added to the ejected rod worth and hot ch'armel factors to account for any calculational uncertainties, including an allowance for nuclear power peaking due to fuel densific'ation.
distributions before and after ejection for a "w'orst case" 'can be found in Reference 1. During
'ower plant startup physics testing, ejected rod, worths and power disuibutior5 have beien measured in the zero and full power configuratiorl and compared to values used in the analysis. Experience has shown that the ejected rod worth and power peaking factors are consistently overprnHcted in the analysis.
Dela ed Neutron Fraction g Calculations of the effective delayed neutron fraction (f3) typically yield values no less than 0.65 percent at beginning of life and 0.48 percent at end of life. The ejected rod acciident is sensitive to t5 if the ejected rod worth is equal to or greater than p,<<, as in the, zero-power transients. In order to allow for future fuel cycle flexibility, conservative estimates of f3 of 0.50 percent at beginrung of cycle and 0.42 percent at end of cycle are used in the analysis.
Reactivi Wei htin Factor
'Ihe largest temperature rises, and hence the large<st reactivity feedback', occur in channels where'ht'.
power is higher than average. Since the, weight of a region is dependent on flux, these regions have weights. IMs means that the reactivity feedback is larger than that indicated by a sirnplt! 'ig mh1808wkh3b.sNpf:1b/082295 3-134
single-channel analysis. Physics calculations have been performed for temperature changes with a flat temperature distribution and with a large number of axial and radial temperature distributions.
Reactivity changes were compared and effective weighting factors determined. These weighting factors take the form of multipliers which, when applied to single-channel feedbacks, correct them to effective whole-core feedbacks for the appropriate flux shape. In this analysis, a one-dimensional (axial) spatial kinetics method is employed, thus axial weighting is not necessary if the initial condition is made to match the ejected rod configuration. In addition, no weighting is applied to the moderator feedback. A conservative radial weighting factor is applied to the transient fuel temperature to obtain an effective fuel temperature as a function of time accounting for the missing spatial dimension. These weighting factors have also been shown to be conservative compared to three-dimensional analysis.
Moderator and Do ler Coefficient The critical boron concentrations at the beginning of life and end of life are adjusted in the nuclear code in order to obtain moderator density coefficient curves which are conservative when compared to the actual design conditions for the plant. As discussed above, no weighting factor is applied to these results. The resulting moderator temperature coefficient is at least+7 pcm/'F at the appropriate zero-or full-power nominal average temperature for the beginning-of-life cases.
The Doppler reactivity defect is determined as a function of power level using a one-dimensional steady-state computer code with a Doppler weighting factor of 1.0. The Doppler weighting factor will increase under accident conditions, as discussed above.
Heat Transfer Data The FACTRAN (Reference 2) code used to determine the hot spot transient contains standard curves of thermal conductivity versus fuel temperature. During a transient, the peak centerline fuel temperature is independent of the gap.conductances during the transient. The cladding temperature is, however, strongly dependent on the gap conductance and is highest for high gap conductances. For conservatism a high gap heat transfer coefficient value of 10,000 Btu/hr-ft -'F has been used during transients. This value corresponds to a negligible gap resistance and a further increase would have essentially no effect on the rate of heat transfer.
Coolant Mass Flow Rates When the core is operating at full power, all three coolant pumps will always be operating. [However, for zero power conditions, the system is conservatively assumed to be operating with two pumps.]
The principal effect of operating at reduced flow is to reduce the film boiling heat transfer coefficient.
This results in higher peak cladding temperatures, but does not affect the peak centerline fuel temperature. Reduced flow also lowers the critical heat flux. However, since DNB is always assumed at the hot spot, and since the heat flux rises very rapidly during the transient, this produces only mh1808wkh3b.wpf:ib/082295 3-135
second order changes in the cladding and centerline fuel temp:ratures. All zero power analyses for both average core anal the hot spot have been conducted assun2ing two plumps in operatio'n.
'ri Reactivi InsertI.on The control rods are assumed toi be released 0.5 seconds after reaChing the power range high neutron flux trip setpoint. The delay consists of 0.2 seconds for the instrumentafion to produce aisighal,i 0.15 seconds for the reactor trip breaker, to open and 0.15 seconds for coil release. In calculating the shape of the insertion versus time ciurve all the rod! are assumed to be dropped as a single bank from the fully withdrawn position. This means that the irutia1 rdoveImeht is through the low worth region at~
the extreme top of the, core, which results in a conservatively slow reactivity insertion versus'inge
'urve.
Fuel Densification Effects Fuel densification effects on rodI ejection are am>unted for'Nording to the methods described in Reference 3.
Lattice Deformations A large temperature gradient exists in the region of the hot spot. Since the fuel rods are free to move in the vertical direction, differential expansion between, individual, fuel rods icannot produtIe d)st6rtidn.
However, the temperature gradients across individual rods may produce a differential expansion tending to bow the midpoint of the rod toward the hot spot. Physics calculations indicate that the net result of this would be: a negative reactivity irlertion. In practice, no significant bowing is ahticipat'ed, since the structural rigidity o]F the core is more than, sufficient ia withstand the forces produced.
in the hot spot region wIill produce a net fluid flow away from that region. However,, the fuel 'oiling releases heat to the water slowly, and it is considered in'conceivable that cross flow is sufficieInt to produce significant latfice forces. Even if massive and rapid boiling, sufficient to distort the lattice, is hypothetically postulated, the large void fraction:in the hot 'spot re'gion would produce a miuction in the total core moderator to fuel ratio, and a large red.ucfion in this ratio at the hot spot. The net effect would therefore be a negative feedback wluch. leads to the tuni"luSion that no conceivable mechanisin exists for a net positive feedback resulting from lattice deformation. In fact, a small negative feedback'ay result. The effect is conservative and therefore not included in the following analyse's.
Radiolo ical Conse uences The major assumptiomi and pammeters used in the radiological analysis are consistent with Reference 9 and are itemized in Table 3.2.17-3.
mh1808wMh3b.wpf: Ib/082495 3-136
3.2.179 Description of Analysis
'Ilus section describes the models used in the analysis of the rod ejection accident. Only the initial few seconds of the power transient are discussed, since the long term considerations are the same as for a loss of coolant accident.
The calculation of the RCCA ejection transient is performed in two stages, erst an average core channel calculation and then a hot region calculation. The average core calculation uses spatial neutron-kinetics methods to determine the average power generation with time including the various total core feedback effects; i.e., Doppler reactivity and moderator reactivity. Enthalpy and temperature transients at the hot spot are then determined by multiplying the average core energy generation by the hot channel factor and performing a fuel rod transient heat transfer calculation. The power distribution calculated without feedback is conservatively assumed to persist throughout the transient. A detailed discussion of the method of analysis can be found in Reference 1.
Ave e Core The spatial-kinetics computer code, TWINKLE(Reference 4) is used for the average core transient analysis. This code solves the two-group neutron diffusion theory kinetic equation in one, two or three spatial dimensions (rectangular coordinates) for six delayed neutron groups and up to 2000 spatial points. The computer code includes a detailed multiregion, transient fuel-clad-coolant heat transfer model for calculation of pointwise Doppler and moderator feedback effects. This analysis uses the code as a one-dimensional axial kinetics code since it allows a more-realistic representation of the spatial effects of axial moderator feedback and RCCA movement. However, since the radial dimension is missing, it is still necessary to employ very conservative methods (described below) of calculating the ejected rod worth and hot channel factor.
Hot S ot Anal sis In the hot spot analysis, the initial heat flux is equal to the nominal times the design hot channel factor. During the transient, the heat flux hot channel factor is linearly increased to the transient value in 0.1 second, the time for full ejection of the rod. '11Ierefore, the assumption is made that the hot spot before and after ejection are coincident. This is very conservative since the peak after ejection will occur in or adjacent to the assembly with the ejected rod, and prior to ejection. the power in this region will necessarily be depressed.
The average core energy addition, calculated as described above, is multiplied by the appropriate hot channel factors. The hot spot analysis uses the detailed fuel and clad transient heat transfer computer code, FACTRAN (Reference 2). This computer code calculates the transient temperature distribution in a cross section of a metal clad UO, fuel rod, and the heat flux at the surface of the rod, using as input the nuclear power versus time and local coolant conditions. The zirconium-water reaction is mhl808w&8b.wpf:Ib/082295 3-137
explicitly represented, and all material properties are represented as functions of temperature. A parabolic radial power distribution is assumed wittun the fuet rod.
uses the Dittus-Boelte:r or Jens-LotItes correlation to determine the. film heat transfer before
'ACTRAN i
DNB, and the Bishop-Sanciberg-Tong correlation (Reference 5) to determine the film boiling coefficient after DNB. The B.ishop-Sanciberg-'I'ong correfatibn ils conservatively used assuming zero bulk fluid quality. The DNB Iheat flux is not calculated, ins~ thd code is forced into DNB by specifying a conservative DNB heat flux. The gap heat transfer coefficient can be calculated by the code; however,.it is adjusted tio force the. full-powe:r, steady-state temperature distribution to agree with fuel heat transfer design codes.
Radiolo ical Conse uences The control rod ejection accident considers two fission product release paths to the environment. ThI:
first is containment leakage of fission products released Sum the primary system to the containment ~
atmosphere. Second is leakage of fission products from tahe secendary 'system, outside containment,,
to primary-to-secondary le@age in the steam generators.
'ue 3.2.17.4 Acceptance Criteria Due to the extremely low probability of a rod cluster control'ssembly ejection accident, this event is classified as an ANS Condition P/ event. As such, some fuel dhm5ge could be considered consequence. an'cceptable Comprehensive studies of the threshold of fuel failure and of the threshold of significant conversion elf the fuel thermal energy to mechmlica~l energy have been carried out'as part of the SPERT-proje.ct by the Idaho Nuclear Corporation (Reference 6). Extensive tests of UO, zirconium-clad fuel rodj representative of those present in Ipressurized-water reactor-t~ 'cords have demonstrated failur'e thresholds in the range of 2AO to 257 cal/grn. However, other rods of a slightly different design exhibited failure as low as 225 ca1I/gm. 'Ihese results differ signifimntly from the TREAT (Reference 7) results wluch indicated a failure thresholld of 280 cal/gm. Limited results have that this thresholci decreasecl 10 percent with fuel burnup. The clad failure mechaniSm 'ndicated appears to be melting for unirradiatedl (zero burnup) rods andI brittle fracture for irracHated rodsl.
conversion ratio of thermal to mechaiucal energy is also itnpbrtant. This ratio becomes marginally detectable above 300 caVgm for unirradiatedI rods and 20O ca'Vgk fear ii'radiated rods-, catastrophic failure (large fuel dispersal large Ipressure rise), even for irradiated rods, did not occur below cal/gm.
'00 The real physical limits of this accident are that the rod ejection event and'any consequential damage to either the core or the Reactor Coolant System must not prevent long-term core cooling and any offsite dose consequences must be within the guidelines of 10 CFR 100. More-specific and restrictive criteria are applied to erasure fuel dispersal in the coolant,'gross latti'ce distortion or severe shoe:k mh1808w~b.wpf:1hl082295 3-138
waves will not occur. In view of the above experimental results, and the conclusions of WCAP-7588, Rev. I-A (Reference 1) and Reference 8, the limiting criteria are:
A. Average fuel pellet enthalpy at the hot spot must be maintained below 225 cal/gm for unirradiated and 200 cal/gm for irradiated fuel, B. Peak reactor coolant pressure must be less than that which could cause RCS stresses to exceed the faulted-condition stress limits, C. Fuel'melting is limited to less than 10 percent of the fuel volume at the hot spot even if the average fuel pellet enthalpy is below the limits of Criterion A.
D. The dose acceptance criterion for a rod ejection accident is "well within" the 10 CFR 100 guideline value, or 75 rem thyroid and 6 rem y-body.
3.2.17$ Results Results are presented for the four analyzed cases which cover beginning and end-of-life at zero and full power conditions.
A. Be innin of C cle Full Power Control bank D is assumed to be inserted to its insertion limit. The worst ejected rod worth and hot channel factor are conservatively calculated to be 0.35 percent b,K and 5.48, respectively. The peak hot spot average fuel pellet enthalpy is 190 caVgm. The peak clad average temperature is 2660'F and the peak fuel centerline temperature is 5000'F. However, fuel melting remains well below the limiting criterion of 10 percent of the pellet volume at the hot spot.
B. Be innin of C cle Zero Power For this condition, control bank D is assumed to be fully inserted with bank C at its insertion limit.
The worst ejected rod is typically located in control bank D and has a worth of 0.71 percent d K and a hot channel factor (F<) of 8.0. The peak hot spot average fuel pellet enthalpy is 116 cal/gm. The peak clad average temperature reaches 2033'F; the fuel centerline temperature is 3267'F.
C. End of C cle. Full Power Control bank D is assumed to be inserted to its insertion limit. The ejected rod worth and hot channel factors are conservatively calculated to be 0.30 percent hK and 5.52 respectively. The peak hot spot average fuel pellet enthalpy is 147 cal/gm. This results in a peak clad average temperature of 2072'F and a peak fuel centerline temperature of 4508'F.
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The ejected rod worth and, hot channel factor for this case are obtained assuming control bank D to be 0
fully inserted with bank C at its insertion limit. The remits are 0.84 percent dK and 14.3, respectively. The peak hot spot average fuel pellet enthalpy is 110 cal/gm. The peak clad av'erase fuel centerline temperatures are 1967'F and 3098'F,~ respec'tively.
'nd A summary of the cases presented albove is given in Table 3.2.17-L The nuclear power and hot 'spot fuel and clad temperattire transients for the worst cases (beginning-of-'life full and zero power cases) are presented in Figures 3.2.1'7-1 and 3.2.17-2, and a time sequence of events is given in Table 3.2.17-2.
It is conservatively assumed tihat fission products are relet.ased floe. the gaps of all rods entering DNB.
In all cases considered, less than 10 percent of the rods entered~ DNB based on a detail+i three-dimensional THINC analysis. Although the arlalysis predicts limited fuel melting at the hot spot for the BOL Full-power case, in practice, melting is not likely since the analysis conservatl.vely aSsumes that the hot spots before and after ejection were coincident.
A detailed calculation of the pressure surge for an ejecte8 rdd vtrort6 of one dollar at beginning of, lifb, hot full power, indicates that the peak pressure does not exceed that which would cause reactor pressure vessel stress to exceed the faulted condition stress limits (Reference 1). Since the severity of the present analysis does not exceed the "worst-case" analysis, the accident for this plant will .not result in an excessive pressure rise or fiirther adverse effects to the RCS.
E. Radiolo ical Consequences The calculated thyroid and y-body doses (rem) at the exclusion boundary and low population zone outer boundary are as follows.",
EB~i0-2 Hr'I LIE~0-30 D~a Thyroid 5.9 E-1 6.9 E-2 y-Body 1.6 E-2 2,.3 E-3 3.2.17.6 Conclusions Despite the conservative assumptions, the analyses indicate that the described fuel aiid clad liriuts are not exceeded. It is concluded that there is no danger of stiddbn fuel dispersal into the coolant. Since the peak pressure does not exceed that which wou1ld cause stresses to exceed the faulted condition.
stress limits, it is concluded that there is no danger of further consequential damage to the RCS. tIh6 analyses demonstrate that the 5ssion product release as a result of fuel rods entering DNB is limited'A1808wM3b.wpf:
tb/091195 3-140
to less than 10 percent of the fuel rods. in the core. The resulting.offsite doses are "well.within" 10 CFR 100 guidelines.
3.2.17.7 References
- 1. Risher, D. H., "An Evaluation-of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors using Special Kinetics Methods," WCAP-7588; Rev. 1A, January 1975.
- 2. Hargrove, H. G., "FACTRAN, a FORTRAN IV Code for Thermal Transients in a UO, Fuel Rod,'" WCAP-7908-A, December 1989.
- 3. "Fuel Densification-Turkey Point Unit No 3," WCAP-8074, February 1973.
- 4. Barry, R; F., Jr. and Risher, D. H., "TWINKLE,a Multi-dimensional Neutron Kinetics Computer Code," WCAP-7979-P-A, January 1975 (Proprietary) and WCAP-8028-A, January 1975 (Non-Proprietary).
- 5. Bishop, A. A., Sandberg, R. 0; and Tong, L. S., "Forced Convection Heat Transfer at High Pressure After the Critical Heat Flux," ASME 65-HT-31, August 1965.
- 6. Taxebius, T. G., ed., "Annual Report - SPERT Project, October 1968 - September 1969," IN-1370 Idaho Nuclear Corporation, June 1970.
- 7. Liimatainen, R. C. and Testa, F. J., "Studies in TREAT of Zircaloy 2-Clad, UO,-Core Simulated Fuel Elements," ANL-7225, P 177, November 1966.
8; Letter from W. J. Johnson of Westinghouse Electric Corporation to Mr. R. C.'Jones of the Nuclear Regulatory Commission, Letter Number NS-NRC-89-3466, "Use of 2700'F PCT Acceptance Limit in Non-LOCA Accidents," October 23,1989.
- 9. 'USAEC Regulatory Guide 1.77, "Assumptions, Used for Evaluating a Control Rod Ejection Accident for Pressurized Water Reactors," May 1974.
mal 808wM3b.wpf:1 bi'091195 3-141
Table 3.2l.l7-1 Results of the Rod Cluster Control Assembly Ejection Accident Analysis Beginning Begimj1ing End End of Cele of~Cele of C~cle . of C~cle Power level, 102 Ii02 percent'jected rod worth 0.35 0.71 0.',30 0.84 percent dK Delayed neutrori fraction, 0.50 0.50 OA2 0.42 percent Feedback reactivity 1.3 1.42 1.3 2.3'.2 weighting Trip reactivity percent ~ 4.0 ',2.0 4.0 2.i0 F9 before rod ejection 2,.694 2.694 F~ after rod ejection 5.48 8.0 5.52 14.;3 Number of operational pumps Max fuel pellet average 4286 2815 3457 2698 temperature, 'F Max fuel centerline 5000 32',67 4508 3098 temperature, 'F Max clad average 2660 2033 2072 1967 temperature, 'F Max fuel stored energy, 190 116 147 110 cal/g Fuel melt in hot pellet, /.65 0 percent mh1808wMQb.wpf:1b/082495 3-].42
Table 3.2.17-2 Sequence of Events - RCCA Ejection Accident Case Event Time sec BOL, full power Initiation of Rod Ejection 0.0 Power Range. High Neutron Flux 0.03 Setpoint Reached Peak Nuclear Power Occurs 0.13 Rods. Begin to Fall 0.53 Peak Clad Temperature Occurs 2.19 Peak Heat Flux Occurs 2.20 Peak Fuel Centerline Temperature Occurs 3.98 BOL, zero power Initiation of Rod Ejection 0.0 Power Range High Neutron Flux 0;25 Setpoint Reached Peak Nuclear Power Occurs 0.30 Rods Begin to Fall 0.75 Peak Clad Temperature Occurs 2.31 Peak Heat Flux Occurs 2.38 Peak Fuel Centerline'Temperature Occurs m:u 808wW3b.wpf:1 bf082295 3-143
Table 3 '?.17-3 Assumptiions Used for Rod Ejectiojn Accidenit Bose Analysis Power .......... 2346 MWt Reactor Coolant Noble,Gas Activity ..:.... i... 1.0% Fuel Defect Imvel Prior to Accident Reactor Coolant Iodine Activity 60 pCi/gm of DE I-131 Prior to Accident Activity Released to Reactor .. ........; 10.0% of Core Gap Activity Coolant and Containment from Failed Fuel (Noble'Gas & Iodline)
Fraction of Core Activi.ty i.n Crap .. 0.10 (Noble Gas & Iodine)
Activity Released to Reactor Coolant and Containment Rom Melted. Fuel Iodine .. .... ~......... 0.125% of Core Activity.
Noble Gas.... 0.25% of Core Activity Secondary Coolant Actiivity ......,........ 0.10 pCi/gm of DE Prior to Accident I-131'otal SG Tube Leak Rate Duting Accident........... 1.0 gprn Iodine partition Factor in SGs .. 0.01 Steam Release from SGs ..'.'.. '...'.... 281,569 lb (0-95 sec)
Iodine Removal in Containment Instantaneous -Iodine Plateout . .......,....... 50%
Elemental Iodine Deposition ... I,...... 5 95 hr" for DF < 100 0 for DF > 100 Emergency Containment Filters Start Delay T~ime . ...... 300 sec
-Number of Units .
Flow Rate per Unit .. 33,750 cfm mh1808wM3b.wpf:1&082295 3-144
Table 3.2.17-3 (cont.)
Assumptions Used for Rod Ejection Accident Dose Analysis Filter Efficiency Elemental . 90%
Methyl 30%
Particulate 95%
Operating Time 2hr Containment Free Volume 1 55 x 10'ft'ontainment Leak Rate 0-24 hr ....... 0.25%/day
>24hr . 0.125%/day mh1808wkh3b.wpf:1b/082295 3-145
1 10 10 2
T1ME (SECONDS) 8000 Hot Spot Fuel Centarlkue Hot S]~t Fuel, Amaze 4000 J
/ Hot Spot Oat Gal
. I 2000
/
0 0 2 4 6
(
~ ~ ~ I THE (SECONDS)
Figure 3~..1/-1 Rod Ejection Transient Begiinniing of Life, Full Power mA1808wkh3b.wpf:1b/082295 3-146
2
'1 0 10
.8 1.6 2.4 3..2 Vrm (SZCON1lS) 4000 Hot Spot Pnel Centerline 3000 Hot Spot Puel Average I
Hot Spot Outer Clad Ie 2000 /
/
1',000 I I
.4 6 Tmz (szcoms)
Figure 3.2.17-2 .Rod Ejection Transient Beginning of Life, Zero Power mA1808wMh3b.wpf:1b/082495 3-147
32 LOCA AND LOCA RELATED ]EV]ENTS 32.1 Large Break LOCA Acciident Analysis 32.1.1 Introduction This report contains infonnat]ion regard]ing the large brea~k Loss<of<Coolant Accident (LOCA) analysis and evaluations performed in support o]F the uprating progratn for Turkey Point Units 3 and 4I. A LOCA is the result of a pipe rupture of the: reactor coolant system (RCS) pressure boundary. For the analyses reported here> a large break is defined as a rupture of the RCS piping with a cross-sectional area greater than 1.0 fl.'. 'Gus event, is considered an American Nuclear Society (ANS) Condition IV event, which are design limiting faults 1hat are. not expected to occur during the life of a plant.
The purpose of analyz]ing the large break LOCA is to demonstrate conformailce with the 10 CFR 50.46 (Reference 1) requirements:For the conditions associated with the uprating. Important input assumptions, as well as analyt]ical models and analysis mdtho'dol'ogy for the large break LOCA, are contained in subsequent sections. Analysis results are provided in'hd form of tables and QgttreS, as well as a more detailed description of the limiting tramient. It was deternnned that no design or regulatory limit related to the large brest LOCA would be e>xcdeddd due to the uprated power and assumed plant parameters.
39.12 Input Parameters And As!>wmptions The following important plant conditions and features ark li<ted in Table 3.3.1-1. Several additional considerations. that are not identifie in Table 3.3.1-1 are discussed'e]low:
The axial power shapes modeled in the laq>e break LOCA anal ysis are the chopped cos>ine shape and a standard set of top-skewed shapes. A methodology has been implemented that explicitely comiders top-skewed power shapes in the ]large break LOCA analysis, This methodology, known as ESHAPE, has scaled a set of top-skewed power sh~e to the standard two-line segment K(Z) curve. Tlus methodology has been utilized for the FPL large break IJOQA analysis.
Figure 3.3.1-1 provides the degraded HHSI and the LHSI flow vers>us pressure curve modeled in the large break LOCA analysis.
Additional input assumptions and conditions upon which th5 large break analysis was based are listed in Tables 3.3.1-1 and 3.3.1-2. A complete list of,plant s]xcific Accident Analysis Parameters waS confirmed by FPL for,use in the large break LOCA analysis's part of the uprating program.
mh1808wM3b.wpf:Ibf082295 3-148
3.3.19 Description Of Analyses / Evaluations Performed Anal cal Model
'111e LOCA analysis presented here was performed with the BASH Westinghouse ECCS evaluation model (References 2 and 3). This version includes the BART (Reference 4) computer code which is a mechanistic core heat transfer model, and BASH which is a mechanistic reflood model.
'Ihe large break LOCA transient can be conveniently divided into three periods: blowdown, refill, and reflood. Also, three physical parts of the transient are analyzed for each period: the thermal-hydraulic transient in the reactor coolant system, the containment pressure and temperature, and the fuel and clad temperatures of the hottest rod. These considerations lead to the use of a system of computer codes designed to model the large break LOCA transient.
The SATAN-VI(Reference 5) code evaluates the thermal-hydraulic transient during blowdown. 111e REFILL (References 3 and 6) code computes, using output from the SATAN-VIcode, the time to bottom of core recovery (BOCREC) and RCS conditions at BOCREC. Since the mass flow rate to the containment depends upon the local RCS and containment conditions, the REFILL and COCO codes are interactively linked. The COCO (Reference 7) code is used to model the containment pressure transient. The containment parameters used by COCO to determine the ECCS backpressure were reviewed by FPL prior to use in the LOCA reanalysis and are summarized in Table 3.3.1-2. The BOCREC conditions calculated by REFILL are used as input to the BASH code. Data from both the SATAN-VI code and the REFILL code out to BOCREC are input to the LOCBART (Reference 4) code which calculates core average conditions at BOCREC for use by the BASH code.
BASH provides a thermal-hydraulic response of the reactor core and RCS during the reflood phase of a large break LOCA. Instantaneous values of the accumulator conditions and safety injection flow at the time of completion of lower plenum refill are provided to BASH by REFILL. A more detailed description of the BASH code is available in Reference 2. The BASH code provides a sophisticated treatment of steam/water flow phenomena in the reactor coolant system during core reflood. A dynamic interaction between core thermal-hydraulics and system behavior is expected, and experiments have shown this behavior. The BART code has been coupled with a loop model to form the BASH code and BART provides the entrainment rate for a given flooding rate. The loop model determines the loop flows and pressure drops in response to the calculated core exit flow determined by BART.
The updated inlet flow is used by BART to calculate a new entrainment rate fed back to the loop code. This process of transferring data between BART, the loop code and back to BART forms the calculational process for analyzing the reflood transient. This coupling of the BART code with a loop code produces a more dynamic flooding transient, which reflects the close coupling between core thermal-hydraulics and loop behavior. '111e BASH code is also interactively linked with COCO to utilize the local conditions at each time step to calculate the containment response.
mal 808w'4%3 b.wpHbl082295 3-149
In the BASH ECCS model, the cladding heat-up transient is calculated by LOCBART which is a combination of the LOCTA (Reference 8) code with BART'(Reference 4). A more detailed description of the LOCBART code can be found .in (Reference 2). 'G>e LOCBANT code is used throughout the transient to compute fuel and clad temperatures in the lhottest rod. During reflood, the LOCBART code provides a significant improvement in the prediction of fuel rod behavior. In LOCBART the empirical:FLE.CHT correlation has been replaced by the BART code. BART employs rigorous mechanistic models to generate heat transfer coefficients appropriate, to the actual flo4 And heat transfer regimes experienced by the fuel rods.
Figure 3.3.1.2 shows the interactiion of the BASH large break model and the relationship of the computer codes to the LOCA sequence of events.
~Anal sls Past licensing studies for break type and location were performed for a double-ended cold leg guillotine (DECLG) break wilh various values of discharge coeBicient (C,g, double-ended hot~ legt guillotine (DEHLG), double-ended pum1p suction guillotine (DEPSG), and a range of split-typ: break sizes ranging Rom a l.l0 ft'rea to a full double-ended area of the cold leg. This study determined that the DECLG type break was both the most limiting type'nd lo'cation. Furthermore, previous licensing basis analysis for Turkey Point has shown that the litniitikg discharge coefficient, CD.-=OA, is much more limiting than the non-limiting discharge coefficiknts, CJ=O,'.6 and Cn=-0.8. Tlherefore, only the limiting Moody discharge coefficient, Cn=0.4, was reIx:rtoriIned utilizing the BASH evaluation model (EM). Sensitivifies were performed of the RCS v~wsc!I a0eNge temperature as well as the power shapes.
fop'kewed The limiting single active failure used in the large break LOCA analysis is dependent upon thi'.
Maximum and Minimum ECCS scenarios. For the case of Minimum ECCS, the lirriiting single fliilu're is the loss of the LHSI puinp. F8ulure of the diesel geneNtod is nof. limiting for large break LOCA due to the loss of a contairunent spray pump. Operation 'of fill t.onfainment pressure reducing equipment is required by 10 CFR 50, Appendix K, as thi's re'sulfa i6 a:minimum lcontainment pressure transient. In addition to the loss of a LEISI pump, the large break I.OCA analysis conservajtively assumed failure of one HHSI pump, but still modeled both cOnthiiujnent spray pumps. The approval of the BASH EM (Reference 2) specificMly reqm.es consider.rafion'of the Maximum ECCS scenaho. The Maximum ECCS analysis assumes no single failure within the ECCS. The limiting single failure assumed in the Maximum ECCS analysis is the. loss of aft atlxiliary feedwater pumpThe MMmjum ECCS analysis requirement is dependent upon a full downcorner at the start of the reflood phase.
Because Turkey Point does not have a hill downcomer at th6 be'ginItiinp of reflood, t1he Maximum analysis is unnecessary. Additional ECCS injection during the Maximum ECCS analysis will 'CCS only contribute to filling the downcomer and increasing the reflood rate.
mhl808wkh3h.wpf: ib/082595 3-150
'11ie limiting time for fuel burnup in the large break LOCA analysis is at the beginning of life where maximum pellet temperatures occur. The beginning of life analysis will bound burnup conditions up to 62,000 MWD/MTU.
Prior to break initiation, the plant is assumed to be in a full power (102%) equilibrium condition, i.e.,
the heat generated in the core is being removed via the secondary system. Other initial plant conditions assumed in the analysis are given in Section 2.0 and Table 3.3.1-1. Subsequent to the break opening, a period of reactor coolant system blowdown ensues in which the heat from fission product decay, the hot reactor internals, and the reactor vessel continues to be'transferred to the RCS fluid.
Loss of Offsite Power (LOOP) is assumed to occur coincident with initiation of the large break LOCA. If a large break LOCA occur, depressurization of the RCS results in a pressure and level decrease in the pressurizer. The reactor trip signal subsequently occurs when the pressurizer low-pressure reactor trip setpoint, conservatively modeled-as 1805 psia, is reached. A safety injection signal is generated when the pressurizer low-pressure safety injection setpoint, conservatively modeled as 1615 psia, is reached. The safety injection signal may also result from the containment high signal.
Both signals are modeled in the large break LOCA analysis and the fastest initiation of safety injection is used. Safety injection is delayed 35 seconds after the occurrence of the signal. This delay accounts for signal initiation, diesel generator start up and emergency power bus loading, as well as the time involved in aligning the valves and bringing the LHSI and HHSI pump up to full speed. Finally the RCS depressurizes to below 615 psia and the accumulators begin to inject borated water. These countermeasures limit the consequences of the accident in two ways:
- 1. Reactor trip and borated water injection supplement void formation in causing a rapid reduction of nuclear power to a residual level corresponding to the delayed fission and fission product decay. No credit is taken in the large break LOCA analysis for the boron content of the injection water. However, an average RCS/sump mixed boron concentration is calculated to ensure that the post-LOCA core remains subcritical. No credit is taken for control rod insertion. The core is shut. down on only void formation during the depressurization result.
- 2. Injection of borated water ensures sufficient flooding of the core to prevent excessive cladding temperatures.
The core heat removal mechanisms associated with the large break transient include the break itself and the injected ECCS water.
Evaluations The effect of the open containment purge valves has been considered by evaluation. The Turkey Point Units 3 and 4 will have 48 and 54 inch diameter containment purge valves open for the initial seconds of the large break LOCA transient.
mh1808wMh3b.wpf:Ibf082295 3-151
3.3.1.4 Acceptance Criteria For Analyses / Evaluations
'he Acceptance Criteria for the I OCA are descrilbed in 10 CFR 50.46 (Reference '1) as follows:
- 1. The calculated maximum fuel element claddIing temperature shall not exceed 2200'F,
- 2. The calculated total oxidation of the cladding shall nowhere exceed 0.17 times the total c.laddin'g thickness before oxidlation,
- 3. The calculated total amount of hyclrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrounding th6 @el, excluding the cladding surrounding the plenum volume, were to react,
- 4. Calculated changes in core geometry shall. be such that'he core remains amenable to cooling, and
- 5. After any calculated, successful initial operation of the ECCS, the calculatecl core temperkturI:
shall be maintained at an acceptably low- value and decay lheat. shall be removed for tlhe extended period of time required by the ]long-lived radioactivity rem'aining in the core.
Criteria 1 through 3 are explicitly covered lby the large break LOCA analysis at uprated conditions.
For criterion 4), the appropriate core geometry was modeled. in the analysis. The results based o>x this geometry satisfy the PCT criterion of 10 C:FR 50.46 and conseciuentlydemonstrate the core remains amenable to cooling.
For criterion 5), Long-'Team Core Cooling lT.TCC) consiideratioins are not directly applicable to the large break LOCA transient, but are assessed in Section ',3.3.5 as pit of the evaluation of ECCS perform aIlce.
The criteria were established to provide a signIific u1t.margin in emergency core coolling system (ECCS) performance following a LOCA.
39.1$ Results In order to determine the conditions that produced the mOst limitinp large break LOCA case (as determined by the highest calculated peak cladding temperature), two uses were examined. These cases included the limiting, discharge coefficient, CD=0.4, for high and low RCS T,,, operation.. The limiting condition for tlhe Turkey PoIint Units was found to be low RCS T,, operation. The PCT attained during the low RCS T,~ transient was 2103'F, vt/hilie 6e PCT for the high RCS T.,, transient was 2082'F (refer to Table 3.',3.1-3). Table 3.3.1-4 proviides the keyj transtent event times.
mal SOSwMh3b.wpf:1b/082295 3-152
A summary of the transient response for the limiting low T,, CD=0.4 break case is shown in Figures 3.3.1-3 through 3.3.1-18.
Limitin Tem rature Conditions Reduced operating temperature sometimes results in a PCT benefit for the large break LOCA.
However, due to competing effects and the complex nature of large break LOCA transients, there have been some instances where more limiting results have been observed for the reduced operating temperature case. For this reason, a large break LOCA transient based on both a lower and upper bound RCS vessel average temperature was performed, and the lower bound was found to be more limiting. The lower bound RCS vessel temperature has a higher initial RCS mass which could prolong the blowdown period and decrease the water left in the accumulator at the end of blowdown.
The temperature window analyzed was based on a nominal vessel average temperature of 574.2'F, with ~ 3'F for an operating window and ~ 85'F to bound uncertainties. The upper bound vessel average temperature is 585.7'F, while the lower bound vessel average temperature is 562.7'F.
Plots of important parameters are given in Figures 3.3.1-19 through 3.3.1-28 at high T8 conditions.
Skewed Power Sha Large Break LOCA analyses have traditionally been performed using a symmetric, chopped cosine, core axial power shape. Under certain conditions, calculations have shown that there is a potential for top-skewed power distributions to result in PCTs greater than those calculated with a chopped cosine axial power distribution. Explicit analyses were performed in which power distributions were skewed to peak power at the 8.5, 9.5, and 10.5 ft. elevations. The analyses results demonstrated that the 9.5 and 10.5 ft. skewed power shapes are bounded by the chopped cosine power shape, while a PCT increase of 14'F was calculated for the 8.5 ft skewed power shape. This resulted in a limiting case PCT of 2117'F.
Plots of important parameters are given in Figures 29 through 44 for the 8.5 ft. top-skewed power shape.
Evaluations The Turkey Point Units will have 48 and 54 inch diameter containment purge valves open for the initial seconds of the large break LOCA transient. The open valves will reduce the containment pressure response during the large break LOCA, which is an adverse effect upon the calculated PCT.
The calculated PCT effect is an increase of 27'F. Therefore, the limiting case PCT with evaluations is 2144'F.
mA1808wMh3b.wpf: Ib/082295 3-153
The DRFA fuel stack height above the lower core plate was explicitly modeled for the various cases analyzed.
39.1.6 Conclusions A limiting discharge coefficient, Co=A, large break LOCA analysis supporting a range of vessel average temperature was performed. Piuk cladding temperatures of 2103'F and 2082'.F were calculated for the RCS low (562.,7'Eg aud high (585.7'g T,cjonditions.respectively. After assessiug, the PCT. effect for top skewed power shapes and contaiitmeht purge on the most limiting case:, the resulting PCT is 2144'F.
The analyses presented in this section show that the'Emergency Core Cooling System provide sufficient core heat removal capability to maintain the calculated peak cladding temperatures below the required limit of 10 CFR 50.46. That i,s:
- 1. The calculated peak fuel ele,ment cladding temperatjure doke tIot ~txNed 2200'F,
- 2. The localized cladding oxidation limit of 17 percent is not exceeded duiing or after quenching,
- 3. The amount of fuel element cladding that reacts chlmij:allyl kith water or steam to generate hydrogen, does not excerpt 1 percent of the total amount of fuel rod cladding,
- 4. The core remains amenable to cooling during and after the breakand
- 5. 'Ihe core temperature is reduced and decay heat is &moved fear an extended period of time, 'as by the long-jiived radioactiivit y remaiining in the core. 'equired Hence, adequate protection is afforded by the emergent code tool)ng system in the event of h large break Loss-of-Coolant Accident.
Radiological Consequences 3.3.1.7 Introduction A large pipe rupture in the, RCS iis assumed to occur. As a result of the accident, it is assumed that core damage occurs and iodine and noble gas activity is released to the containment. atmosphere. A portion of this activity .is released via containment leakage to the outside atmosphere. It is assumed that the containment purge systena is open when the accident occurs and activity is released td th6 atmosphere through this path until the cont'unment pulrge system is isolated. This section desi!ribes the and analyses performed to determiine the amount of radioactivity released and th6 offsit6 'ssumptions and control room doses resulting from these reileases.
mh1808w'413b.wpf:i bi'082295 3-154
39.18 Input Parameters and Assumptions The offsite and control room doses due to containment leakage and due to an open containment purge system following a large break loss-of-coolant accident (LOCA) are determined using the;analytical methods and assumptions of the Standard Review Plan (Reference 9). The assumptions are presented in Table 3.3.1-5.
39.1.9 Description of Analyses Performed The offsite thyroid and.y-body doses, as well as the control room thyroid, g-body and P skin doses, are determined for both the containment leak and containment purge activity release paths.
39.1.10 Acceptance Criteria The offsite doses must be within the guidelines of 10CFR100, or 300 rem thyroid and 25 rem y-body for the initial 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> period following the accident at the Exclusion, Boundary (EB) and for the duration of the accident at the LPZ. The dose criteria for control room personnel following the accident are 5 rem y-body, 30 rem thyroid, and 30 rem P skin (or 75 rem P skin with protective clothing).
39.1.11 Results The offsite and control room doses due to containment leakage and containment purge, along with the total doses due to the activity release from these paths are within the acceptance criteria. in Section 3.3.1.10.
The offsite and control room doses (rem) due to a LOCA are summarized below:
- 1. Thyroid CR 0-30Da Containment Leakage 2.33 El 2.76 EO 1.49E+1 Containment Purge 2.91 E-1 2.83 E-2 7.28 E-.2 Total 2.36 E1 2.79 EO 1.'50 El
- 2. y-Body Containment Leakage 1.04 EO 1.61 E-1 4;39 E-1 Containment Purge 6.48 E-5 6;31 E-6 1.09 E-5 Total 1.04 EO 1.61 E-1 4239 E-1 mhl808wMh3b.wpf:1b/091895 3-155
- 3. P-Skin Containment Leakage '2.0 El Containment Purge 8.9i E-4 Total 2.0 El 3.3.1.12 Conclusions The total offsite doses and the total control room doses due to the large LOCA are within the acceptance criteria.
3.3.1.13 References
- 1. "Acceptance Criteria for Emergency Core Cooling Systems for Light Water Cooled Nuclear Reactors," 10 CFR 50.46 and.Appendix K of 10 CFR 50, Federal Register, Volume 39, 'ower Number 3, January 1974, as amended in Federal Register, Volume 53, September 1988.
Kabadi, J. N., et a1l., "The 1981 Version of the Westinghouse ECCS Evaluation Model Using the BASH Code," WCAP-10266-P-A Rev. 2 (proprietary), WCAP-11524-NP-A Rev 2 (non-March 1987,, including Addendum 1-A 'Power Shape Sensitivi1y Studies'2I87i and
'roprietary),
Addendum 2-A 'BASH Methodology Improvements'nd Reliability Enhancements" May 1988.
- 3. "Change in Methodology for Execution of BASH Evaluation Model," NTD-NRC-94-4143, May 23, 1994.
- 4. Young, M., et al,,"BART-1A: A Computer Code for the Best Estimate Analyzed Reflood Transients", WCAlP-9561-P-A (proprietary), WCAP-9695-NP-A (non-proprietary), 1984; including Addendum 3 Rev I, July 1986.
- 5. Bordelon, F. M., et al., "SATAN-VIProgram: Comprehensive Space-Time Dependent Analysis of Loss-of-Coolant", 'WCAP-8302-P (proprietary), WCAP-8306-NP (non-proprietary), June 1'974.
- 6. Kelly, R. D., "Calculational Model for Core Reflooding after a Loss-of-Coolant Accident (WReflood Code)", WC-8170-P (proprietalry), WCAP-8171-NP (non-proprietary), et al.,
June 1974.
- 7. Bordelon, F. M., and:E. T. Muq3hy, "Containment Pressure Analysis Code (COCO)",
WCAP-8327-P (proprietary), WCAjP-8326-NP (non-proprietary), June 1974.
mhl808w1ch3b.wpf: 1 b/101695 3-156
8; Bordelon, F. 'M. et al., '"LOCTA-IVProgram: Loss-of-Coolant Transient Analysis", WCAP-8301 (proprietary) and WCAP-8305 (non-proprietary), June 1974.
- 9. NUREG-0800, Standard Review Plan 15.6.5, Appendix A, "Radiological Consequences of a Design Basis Loss-of-Coolant Accident Including Containment Leakage:Contribution", Rev. 1, July 1981.
mh1808wM3b.wpf:1b/082495 3-157
Table 3.'3.1-1 Input Parameters Used In The Large Breiak ILOCA. Analysis Parameter H~ih T~ ~Low T~)
Reactor core rated thermal power', (Mwt)
Peak linear power', (kw/ft) 14.0 Total peaking factor (F<"') at peak Power shape Chopped Cosine and Topi-Skewed Fm 1.64 Fuel 15x15 DRFA Accumulator water volutne, minimum (ft'/acc.)
(gpm)'300 Accumulator tank volume (ft/acc.)2 Accumulator gas pressurie, minimum (psig) 1200 600 Pumped safety injection flow See Figure 1 Steam generator tube pluggiIIg level (%)"
Thermal Design Flow/loop, 85,800 Vessel average temperature w/ uncertainties, ("F) 585'.7 (562.7)
Reactor coolant pressure w/ uncertainties, (psia) 2320 Two percent is added toi this power to account for calorimetric error.
The analysis value a!plumed the Tech Spec minirnurn and credited additional accumulator line volume.
Maximum plugging level in any one or all steam generators.
The analysis was performed at a SGTP level of 10% td bound the combined LOCA+Safe Shutdown jEarthquake tube, crush issue.,
Flowrates conservatively based on 20% steam generator tube plugging.
mh1808wMQb.wpf: Ib/082295 3-158
Table 3.3.1-2 Large-Break LOCA Containment Data for PCT Calculation Net Free Volume 1,550,000 Initial Conditions ft'ressure 12.7 psia Temperature 90 OoF RWST Temperature 35 OoF Temperature Outside Containment 39 O' Initial Spray Temperature 39 OoF
.Spray System Maximum Flow for one Spray Pump 1821.5 gpm Number of Spray Pumps Operating 2 Post-Accident Spray System Initiation Delay 26 sec Containment Fan Coolers Post-Accident Initiation Fan Coolers 26 sec Number of Fan Coolers Operating 3 mh1808w~b.wpf:lb(082295 3-159
Table 3.3.1-3 Large Break LOCA Analysis Fuel Cladding )Results Moody Discharge Coefficient, CD=0,.4 8.5-foot Peak Low T~. High Tave, :Power Sh~ae'eak Cladding Temperature ('F) 2103 2082 2117 Peak Cladding Temperature Location (ft) 8.00 8.00 8.50 Peak Cladding Temperature Time (<>ec) 1',37.5 146.3 128.9 Local Zr/H~O ReactIionMax (%) 9;32 7.34 6.48 Local Zr/H~O ReactIion Location (ft)~ -6,00 6.00 8.50 Total Zr/H,O Reaction (%) <1.0 <1.0 (Lo'4.5 Hot Rod Burst Time (sec) 41.6 49'.3 Hot.Rod Burst Location (ft)~ 6,.00 6;00 7.00 The 9.5-foot and 10.5-foot top-skewed shapes were shown to be non-limiting compared to the cosIine.
Height from bottom of active fuel.
m:u808wM3b.wpf: Ibf091895 3-160
Table 3.3.1-4 Large Break L'OCA Analysis Time Sequence of Events Moody, Discharge Coefficient, CD=0.4 8.5-foot Peak
~Hi .. *-S Start of LOCA with LOOP (sec) 0.00 '0.00 0.00 Reactor Trip Setpoint Exceeded (sec) 0.546 0.654 0.546 Safety Injection Setpoint Exceeded 1.9 1.7 1.9 (sec)'ccumulator Injection Begins. (sec) 14.4 15.4 14.3 End-of-Bypass. (sec) 33.205 29.593 33.156 End-of-Blowdown (sec) 33.205 31.389 33.156 Pump Injection Begins (sec) 36.9 36.7 36.9 Bottom of Core Recovery (sec) 53.9 50.7 53.8 Accumulator Empty (sec) 62.83 62;02 61.70 PCT Time (sec) 137.5 146.3 128.9 Safety Injection signal actuated off of containment high pressure as opposed to low pressurizer pressure.
mhl808wkh3b.wpf:1bf082295 3-161
Table 3.3.1-5 Assumptions Kfsed for Large Break LOCA Dose Analysis Containment Leakage Power 2346 MWt Iodine Chemical Species Elemental 91%
Methyl 4%
Particulate 5%
Iodine Removal in Containment Instantaneous Iodine Plateout 50%
Elemental Iodine Deposition 5.94 hr'or DF < 100 0 for DF > 100 Emergency Contaitunent Filters Start Delay Time 90 sec Number of Units 2 Flow Rate per [Jnit 33,750. cfm Filter Efficiency Elemental 90%
Met.hyl 30%
Particulate 9'5%
Operating Time 2, hr Containment Free Volume 1.55 x 10 ft Containment Leak Rate 0-24 hr 0.25%/day
)24 hr 0.125%/day mhl808wMQb.wpf:1bf091195 3-162
Table 3.3.1-5 (continued)
Assumptions Used for Large Break LOCA Dose Analysis Containment Purge Power 2346 MWt Reactor Coolant Noble Gas Activity 1.0% Fuel Defect level Prior'to Accident Reactor Coolant Iodine Activity 60 pCi/gm of DE I-131 Prior to Accident Iodine Chemical Form 100% Elemental Containment Purge System 7000 cfm Flow Rate Containment Purge System Isolation Time Containment Purge System None Filtration ECFS Filtration None Iodine Plateout/Deposition None in Containment Containment Free Volume 1.55 x 10 ft mA1808wMh3b.wpfub/091195 3-163
Table 3.3.1-5 (continued)
Assumptions Used for Larg;e Break LOCA Bose Analysis Control )Room Volume 50,301 ft'nfiltered Inleakage 10 cfm Filtered Makeup 525 cfm Filtered Recirculation. 375 cfire Filter Efficiency Elemental 95%
Methyl 95%
Particulate 95%
Occupancy Factors 0-1 day 1.0 1-4 days 0.6 4-30 days 0.4 mfu808wM3b.wpf: IbI091195 3-1'
300 250 CA I NJE TED FLOW 200 LIJ
~ 150 CO 100 SPILLEO F OW 50 0
10 20 30 40 50 60 70 80 RCS PRESSURE (psia)
Figure 3.3.1-1: Large Break Pumped Safety Injection Flow Rate - 1 HHSI and 1 LHSI Pump mA1808wkh3b.wpf:tb/091195 3-165
B LOWDO'IIII'IIV REFILL 'EFLOOD EOB BOCFIEC LOCBART CALCULATESHOT ROD, ADJ. ROD, AND CAL'CULATES HOTROD, ADJ. ROD,'ND HOTASSEMIBLYRODTEMPERATURE, HOTASSEMBLY ROD BLOCKAGE, AND HEATTRANSFER TEMPEIRATURI=, BLOCKAGEAND COEFFICIEhfT HEATTRANSFER COEFFIICIENT HOTASSEMBLY AND CORE hrlASS CORE 'Co'RE FLOODING RATE, VELOCCIY, GUAI I1Y COND moNS INLETENTHALPY
'AND PRESSURE ATBOCR,EC BASH/COCO SATAN CALCIJLATES CORE FLOODING CALCULATESRCS, CORE, RATE AND RCS CONDITilONS HOTASSEhtIBLY Fl UID DURIhiG REFLOOD(BASH).
CONDITIONS CALCIJLATENCOhITAVVBNT
, PRESSURE DURING REFLOOD (COCO).
RCS CONDITICiINS AT EO8, AND hrt ASS AND .
ENERGY RELEASI= INTO RCSI CQND fTIQNS'T CohITAINMENT BOTti Oh)I Off COFIE RECOVERY REFILL/COCO, CALCULATESFIEFILL AND BOTTOM OF CORE RECOVE'RY CONDfTIONSI'REI=ILL).
CALCULATESCohITAIINMEhTI PRESSURE DURING BLOWDOWN AND REFILL(COCO).
Figure 3.3.1-2:, Code, Interface Description for the I.arge Break LOCA Model mh1808wMQb.wpf: tb/091195 3-166
2200 2000 1800
'600 1400 n 1200 E
1000 800 6 0,0 50 100 150 200 250 Time (s)
Figure.3.3.1-3: Peak Cladding Temperature for CD=0.4, Low T,,
mh1808wlch3b.wpf:tb/091195 3-167
2200 2000 1800 1600 L
1400 CS L
n 1200 E
I 1000 800 600 50 100 150 ,'2 0 250 T ime (.;)
Figure 3.3.1P: Cladding Temperature at Fuel Rod Burst Location for CD;-0.4, Low T,'8 3-168
'h1808wMh3b.wpf:1b/091195
2500 2000 1500 cD 3 000 E
500 0
0 50 100 150 200 250 Time (s)
Figure 3.3.1-5: Local Fluid Temperature at PCT Elevation for CD=0.4, Low T,,
mA1808wMh3b.wpf:1b/091195 3'-169
8 10 Ls l 10 8
10 I
10 10,
~CD 10 2
10 10 CD' 10 L
CD -'I 10 2
10
-3 10 4
o 10
-5 10 MMJ J 0 50 100 150 200 250 Figure 3.3.1-6: Local H(at Traii18fer Coefficient at PCT Elevation for C=O.,4, Jww T,,
mh1808wlch3b.wpf:1bf091195 3-17'
700 600, 500 I
400
'2 300 OC 200 100 o
0
-100 0 '50 $ 00 150 200 250 Time (e)
Figure 3.3.1-7: Local Mass. Flux at PCT Elevation for CD=0.4, Low T,,
II ~
mA1808wkh3b.wpf:1b/091195 3-171
0 '
0 '
0 '
50 100 150 200 2j0 Time (S)
Figure 3.3.1-8: Local Quality at PCT El'eva'tiok for Co=0.4, l.ow T,,,
mh1808w4%3b.wpf:lbt091195 3-172
2500 2000
~ 1500 co 1000 l
500 10 15 20 25 30 35 Time (e)
Figure 3.3.1-9: RCS Pressure During Blowdown for CD=0.4, Low T,,
mA1808w'eh3b.wpf:1b/091195 3-173
~ 0 '
C)
CD CD LJ 0 ~ 4 CO 0 '
0 J MJ 0 1I 5 20 25 30 . '55 Time (s)
Figure 3.3.1-10: Decay Hmt Duiing Blowdown fear CD=0.4, Low T, m%1 808'.wpf:1b/091195 3-174
60000 50000 40000 30000
.20000 C) 10000
-10000
$ 0 15 20 25 30 35 Time (s)
Figure 3.3.1-11: Break Flow During Blowdown for CD=0.4, Low T,,
mh1808wMh3b.wp!:1bf091 195 3-175
0.3E+08 0 25E+08 0.2E+08 LJ 1
0 15E+08
.o 0. 1E+08.
0-0.'5E+07 LJ 0
-0 5E+07 0 5 10 15 20 25 30 35 Time (s)
Figure 3.3.1-12: Break E.nergy-During BlowI1own for ('.D=0.4, Low T,,
m%1 808wM3b.wpf:1b/091195 3-176
30000 20000 cn 10000 CORE OUTLE FLOW I
I I'
CORE INLET FLOW
-10000 0 10 $ 5 20 25 30 35 Time (sj Figure 3.3.1-13: Core Flow During Blowdown for CD=OA; Low T,8 mh1808wM3b.wpf:1b/091195 3-177
3500 3000 m 2500
~ 2000 1500 CO cn 1000 500 0
0 5 10 15 20 25 3I0 35 T irriie (s)
Figure 3.3.1-14: Accumulator Flow IDuring Blowdown for C,'n=0.4, Low T,,
mal 808w'eh3b.wpf:1hl091195 3-178
CO
~ 3 o 2 ED 0
0 50 100 150 200 Time (e)
Figure 3.3.1-15: Core Reflooding Rate for Cn&.4, Low T,s Tlnle = 0.0 seconds is Bottom Of Core Recovery Time Time from Initiation of Event = 53.9 seconds after break for CD=0.4, Low Tavg Case mhl808wM3b.wpf:1M81195 3-179
25 r
I 20 DOWI'I COME LEVEL if>"<",>If
'f)'5 r ellI I=NCAA Ws~ III l(,Il
,I "Ill I >>lill' Il(t I tl ONT LEVEL e)
IIII'y II I IIIIIII IF) 1 Ill q
QU F IQ '
llIL I It ii1] r)1]'( ei()fllIII
")JI I ihi t I]I )ir f i( t( l I"l'e'IIIII I II)II ill ]I illllllill )
<<ireeir j~%
ie@t/iTtHW>al>
II I ll IIIIII hrnI>i IY ill I it t t II
< dpi l II<lilt q
'III COL LAP'SE L I QILI I D LE EL 0
0 50 'I 00 $ 50 200 Time After Reflood (e)
Figure 3.3.1-16: Core and Downcomer MHxttxre Le4'eis Dtlring Reflood .for Cn=-OA, Low T, Time = 0.0 seconds is. Bottom Of Con Recovery, Time Time from Initiation of Event = 53.9 seconds after break for.Cn=0.4, ~Lo~v Tavg Case mh1808wtob3b.wpf:1bf091195 3-180
2500 2000 E
1500 1000 500 0
0 50 100 150 200 Time After Reflood (s)
Figure 3.3.1-17: ECCS Flows During Reflood for Co=0.4, Low T, TIIne = 0.0 seconds is Bottom Of Core Recovery Time Time from Initiation of Event = 53.9 seconds after break for Cn=0.4, Low Tavg Case mh1808wM3b.wpf:1b/091195 3-181
30 25
~20 CL
~15 L
10 L
n 5 0
-5 0 50 1,00 Il 50 200 I ITl8 I,'
)
Figure 3.3;1-18: Containment Pressure Transient for CD=0.4, tow 'T,,
mA1808wMQb.wpf:1b(091195 3-182
2200 2000 1800 1600 L
1400 lD L
n 'l200 E
1000 800 600 0 50 $ 00 150 200 250 Time (s)
Figure 3.3.1-19: Peak Cladding Temperature for CD=0.4, High T,,
mhl808wM3b.wpf:1b/091195 3-183
2000 1500 L
1000-500 0 50 $ 00 150 200 250 Time (s)
Figure 3.3.1-20:, Local Flui Temp:rat>>>>1re at PCT Elevation for C W.4, Kgh T,,
mh1808w'eh3b.wpf: Ib/091195 3-184
8 10 I 10 10 I
10 10
~
CD 10 2
10 1
cD 10 o o 10 cD -1 10 c 10 2
-3 10 o 10
-5 10 50 100 150 200 250 Time (e)
Figure 3.3.1-21: Local Heat Transfer Coefficient at PCT Elevation for CD=0.4, High T,,
mA1808wkh3b.wpf:IM81195 3-185
700'00 500 I
400 E
300 OC 200 LL 100
-100 0 50 100 150 200 250 T imie (s)
Figure 3.3.1-22: local Mas!> Flux at P'CT Elevation for CD=0.4, Eiigh T,,
mh1808w'eh3b.wpf:tb/091195 3-186
2500 2000 cx 1500
'e L co 1000' 500 0
10 15 20 25 30 Time (e)
Figure 3.3.1-23: RCS Pressure During Blowdown for CD=0.4, High T,,
mA1808wkh3b.wpf:1b/091195 3-187
0 '
LLJ C)
Q
~
C) 0 ~ 6 c~
LLJ 4
CO 0-2 0
0 5 10, 15 20 '5 30 Tilee (s)
Figure 3.:3.1-24: Decay'Heat During B1lowdown for CD=:0.4, High T, 8 m:41 808wMh3b.wpf:1b/091195 :3-188
30000
- m. 20000
) 0000 CORE OUTLE CORE I NLET M -10000
-20000 10 15 20 25 30 35 Time (s)
Figure 3.3.1-25: Core Flow During Blowdown for CD&.4, High T,~
mA1808wMQb.wpf:1M8119$ 3-189
4000 3000 LU
~ 2000 1000 0
0 5 10 20 25 30 35 T }me (s'}
Figure 3.3.1-26: Accumuiator How During Biowdown f'r CD=0.4, Hi!gh T g m&1 808w'ich3b.wpf:1b/091195 '-3-190
0 50 $ 00 150 200 Time (s)
Figure 3.3.1-27: Core Reflooding Rate for Co=0.4, High T,,
Time = 0.0 seconds is Bottom Of Core Recovery Time Time. Rom Initiation of Event = 50.7'seconds after break for CD=0.4, High Tavg Case mh1808whch3b.wpf:tb/091195 3-.191
25 LEVEL 20 15'OWINCOME I LIII qadi f I f L I))lg)I ) ))IL jjjjjtj jet jj
)L)I) ll L>jr" 15)L) )L I 1))l ( QUIENCH F ONT I EVE L
)
10 I
f le JIfLL )f III f I)LIlIL)I)~ SL)I)f $ LL
))I
)II t))l~l))
I ))I)f~ ~ 'l) 1
))IP'.
)$ II COLL'APSE LIQUID LE EL
-0 0 50 100 150 2'0 0 Time After Reflood (e)
Figure 3.3.1-28: Core and Downcomer IL/iixture Level During Reflood for Co=9.4, High T,,,
T1nle = 0.0 seconds is Bottom. Of Colre Recovered/ Time Time from Initiation of Event = 50.7 seconds after break for 6~=0.4,'High Tavg Case mA1808wLob3b.wpf:lb/09) 195 3-192
2200 2000
$ 800 1600 L
1400 L
n f200
. E I
1000 800 600 50 $ 00 $ 50 200 250 Time (s)
Figure 3.3.1-29: Peak Cladding Temperature for CD=0.4, Low T, 8.5 ft Skewed Power Shape mh1808wM3b.wpf:tbl091195 3-193
2000 1800 7
~ 1600
~ 1400' CI 1200-1000 800 600 0 50 100 150 20 0 250 T ice (a)
Figure 3.3.1-30: Cladding Tempcraei1re at Fuel R6d SWt L'ocation for C=0.4, Low T 8.5 ft Skewed E'ower!lhajpe mh1808wkh3b.wpl:1M81195 3-194
2000 1500 L
1000 C7 L
I 500 0
0 50 100 150 200 250 Time (s)
Figure 3.3.1-31: Local Fluid Temperature at PCT Elevation for C =0.4, Low T, 8.5 ft Skewed Power Shape m:u808wkh3b.wpf:1b/091195 3-195
8 10 I 10 10 I
10 10 CD 10 2
10
~ 10 1
C)
O 0 10 I
ID -1 10 2
10 L
10 4
o 10
-5 10 0 50 IOO 1,i0 l200 2!50 lime (s)
Figure 3.3.1-32: Local Heat Tramfer Coefficient kt PCT Elevation for CDWA, Low T, 8.5 ft Skewed Power Shale mh1808wMh3b.wpf:1b/091195 3-196
700 600 500 I
400 E
300 OK 200 100 C)
-100 50 $ 00 150 200 250 Time (e)
Figure 3.3.1-33: Local Mass Flux at PCT Elevation for CD=0.4, Low T,,
8.5 ft Skewed Power Shape mh1808wkh3b.wpf:1b/091195 3-197
0 ~ 8 0 '
0 '
0 0 50 ;I 00 150 ,200 250 Time (e)
Figure 3.3.,1-34: L'ocal Quality at PCT Elevation for CD=O.4, Low T, 8.5 ft Skewed Power Shape rnhl808w~b.wpf:1W091195 3-198
2500 2000 n 3500 L
co 1000 L
Q 500
$ 0 15 20 25 30 Time (s)
Figure 3.3.1-35: RCS Pressure During Blowdown for CD=0.4, Low T, 8.5 ft Skewed Power Shape mA1808w498b.wpf:Ibf091195 3-199
0 '
LaJ CO 0 ~ 6 CO CD 0,
0 5 10 15 20 25 .'i0 T i'me ('. )
Figure 3.3.1-36: Decatur Heat Dmmg Blowdown for C0=0.4, Low T, 8.5 ft Sk:ewe Power Shape mA1 808w'453b.wpf:1bf091195 3-200
60000 50000 40000 30000, 20000 CO
$ 0000
-10000 0 $ 0 15 20 25 30 Time (s)
Figure 3.3.1-37: Break Flow During Blowdown for CD=0.4, Low T, 8.5 ft Skewed Power Shape mhI808wkh3b.wpf:Ibf091 195 3-.201
0 'E+OB
~CD 0.25E+OB CA 0 'E+OB I
~
I 0.15E+08
- 0. 1E+08-CO 0- 0.5E+07 LIJ 0
-0.5E+07 ~~ 10 '$5 20 0 5 25 30 35 Tilee (e)
Figure 3.3.1-38: Break:Energy D11ring Blowdown:for Cn==OA, Low T ,
8.5 ft Skewed Power Shalpe mhl808wlch3b.wpf:1bf091195 3-202
30000 20000 ca LtJ 10000 CORE OUTLE FLOW I
la I
CORE INLET FLOW
-10000
$ 0 $ 5 20 25 30 Time (s)
Figure 3.3.1-39: Core Flow During Blowdown for CD=0.4, Low T, 8.5 ft Skewed Power Shape mhl808wkh3b.wpf:It/091195 3-203
2000
~ 1500 LJ 1000 soo 0
0 5 70 15. 20 25 30 35 Time (e)
P Figure 3.3.1~$ : Aecurnulator Flow Dming Blowdown for CD=0.4, Low T 8.5 ft Skewed Power Shape mA1808wM3b.wpf:1bt091 195 3-204
2 '
CO 0
0 '
0 50 100 150 200 Time (e)
Figure 3.3.1-41: Core Reflooding Rate for Co=0.4, Low T,,,
8;5 ft Skewed Power Shape TIIne = 0.0 seconds is Bottom Of Core Recovery Time Time from Initiation of Event = 53.8 seconds after break for Cn=0.4, Low Tavg, 8.5 ft Skewed Power Shape Case mal 808wM3b.wpf:1b/091195 3-205
25 DOltVNCOME LEVEL 20 g IIIIIIIIi ) g lI j r I f } Il I t e ) N t I eiII q II II(f r
~ III III I II r I
)II I (
Ie II r,l'Il>)II II "I<)g 15
re <IIII II IIII)I..
I Qpe)CH F ONT LE'VEL II II I I II libel I, li C9 I Illllllllllllli l I
~ 10 fl I
)~
I re II
'I IlI iII Wt'l III IIIIIIIIIII'I~II
~~4 II II II~II~I~P 1)) i~,'<( II 1 I l.r~,'I1'i)l$ I e"s "t JI <III I I ill~~
le fthm!4')l) l~qllge I I)
OOLLAPSE LIQUID LE'L 0 L J M 1 J J MM '1 0 50 100 150 200 Time After Ref ooid I (e)
Figure 3;3.1-42: Core arid Downcorner Mixture Levels During Reflood for Cn=l).4, Low T,8.5 ft Skewed Power Shape Tlnle =: 0.0 seconds is Bottom Oi: Core Recovery Time Time from Initiation of Event =: 53,.8 a~nds after br'or ~ OA, Low Tavg,.
8.5 ft Skewedi Power Shape Case mru 808wtoh3b.wpf: I b/091195 3-206
2500 2000 E
1500 1000 500 0
0 50 $ 00 150 200 Time After Reflood (e)
Figure 3.3.1<3: ECCS Flows During Reflood for Co=0.4, Low T,,
8.5 ft Skewed Power Shape Tllne = 0.0 seconds is Bottom Of Core Recovery Time Time from Initiation of Event = 53.8 seconds after break for CD=0.4, Low Tavg, 8.5 ft Skewed Power Shape Case m."tl &0&wM3b.wpf:1b/091195 3-207
25 20 15 CO 10 L'D L
CL, 0
0 50 100 1l 50 200 T ime I,'s)
Figure 3.3.14I4: Contai.ament Pressure Transient 8.5 ft Skewni Power Shape fear Co=0.4Low T, mA1808w498b.wpf:1b/091195 3-208
332 Small Break LOCA 3.32.1 Introduction This section contains information regarding the small break Loss-of-Coolant Accident (LOCA) analysis and evaluations performed in support of the uprating program for Turkey Point Units 3 and 4. The purpose of analyzing the small break LOCA is to demonstrate that conformance with the 10 CFR 50.46 (Reference 1) requirements for the conditions associated with the uprating. Important input assumptions, as well as analytical models and analysis methodology for the small break LOCA, are contained in subsequent sections. Analysis results are provided in the form of tables and Qgures, as weil as a more detailed description of the limiting transient. It was determined that no design or regulatory limit related to the small break LOCA would be exceeded due to the uprated power and assumed plant parameters. 'Ihe SBLOCA was previously submitted under ~FPL letter L-95-193, dated July 26, 1995.
3.322 Input Parameters and Assumptions The following important plant conditions and features are listed in Table 3.3.2-1. Several additional considerations that are not identified in Table 3.3.2-1 are discussed below:
Figure 3.3.2-1 depicts the hot rod axial power shape modeled in the small break LOCA analysis. This shape was chosen because it represents a distribution with power concentrated in the upper regions of the core (the axial offset'is + 20%). Such a distribution is limiting for small break LOCA since it minimizes coolant, swell while maximizing vapor superheating and fuel-rod heat generation at the uncovered elevations. The chosen power shape has been conservatively scaled to a flat K(Z) envelope based on the peaking factors given above.
Figure 3.3.2-2 provides the degraded HHSI flow versus pressure curve modeled in the small break LOCA analysis. The flow from one HHSI pump only is assumed in this analysis.
3329 Description of Analyses/Evaluations Performed Anal cal Model For small breaks, the NOTRUMP computer code (References 2 and 3) is employed to calculate the transient depressurization of the reactor coolant system (RCS), as well as to describe the mass and energy release of the fluid flow through the break. The NOTRUMP computer code is a one-dimensional general network code incorporating a number of advanced features. Among these advanced features are: calculation of thermal non-equilibrium in all fluid volumes, flow regime-dependent drift flux calculations with counter-current flooding limitations, mixture level tracking logic in multiple-stacked fluid nodes, regime-dependent drift flux calculations in multiple-stacked fluid nodes and regime-dependent heat transfer correlations. The NOTRUMP small break LOCA m:u808wM3b.wpf:Ihj'091195 3-209
Emergency Core Cooling Systein (ECCS) Evaluation Model was developed to determine the kC0 response to design basis smaill break LOCAs, and to address NRC concerns expressed in NUREG-0611 (Reference 4).
'111e RCS model is nodalized.into volumes interconnected by flow patlts. The broken loop is modeled explicitly, while the intact loops are lumped together into a second loop. Transient behavior 0f the is determined 5.'om the governing conservation equations of mass, energy, and momentum. 'ystem The multi-node capability of the program enables explicit, detailed spatial representation of'arious components whichs among other capabilities, enables a proper calculation of the behavior 'of 'ystem loop seal during a small break LOC.A. The reactor core is represented as heated control volumes
'he with associated phase separation models to permit transient mixture height calculations.
Fuel cladding thermal analyses are performed with a version. of the LOCTA-IV code (Reference 5) using the NOTRUMP calculated core pressure, fuel rod pow'er history, uncovered core steam flov'r anld heights as boundaiy conclitions (see Figure 3.3.2-3). 'ixture
~Anat sis A spectrum of 2-inch, 3-inch, anal 4-inch equivalent diameter cold leg bre& was performed usin( the analytical model described above. A sensitivity of the limiting transient to the RCS vessel average temperature was also performni.
The most limiting,single active failure assumed for a sm881 break LOCA is that of an emergency power train failure which results in the loss of one complete train of ECCS components. In additiion, a Loss-of-Offsite Power (LOOP) is assumed to occur coincident with reacto~ trip. 1%is means that credit
'ei may be taken for at most two high hei safety injection NISI) puhipk an'd ohe low he%, or residual. heat removal (RHR), pump., However, in the analysis of the small break LOC'Apresentedhere, only the minimum delivered ECCS flow from a single high head SI pump with degraded .flow was assumed.
The small break LOCA analysis performed for the Turkey Point Units 3 and 4 uprating program utilizes the NRC-approved NOTRE P Evaluation Model (R'efeiences 2 and 3), with appropriate to model pumped SI and accumulator injection. in 'the'broken loop as well as an 'odifications improved condensation model (COSI) for the pumped SI into the broken and intact loops (References 6 and 7).
The small break LOCA analysis performed for the Turkey Plaint up@ting program assumes SI is delivered to both the intact and broken loops at the RCS.backpressure.
Prior to break initiation, the plant is assumed to be in a fi)11 IjewI:r (I109%) equilibrium condition, i.e.,
the heat generated in'he core iis being removed via the secondary system. Other initial plant conditions assumed in the analysis are given in Table 3.3.2-1. Subsequent to the break opening, a period of reactor coolant system'blowdown ensues in which 1he heat from Qssion product decay, the mh1808wMh3b.wpf:1b/091195 3-210
hot reactor internals, and the reactor vessel continues to be transferred to the RCS fluid. The heat transfer between the RCS and the secondary system may be in either direction and is a function of the relative temperatures of the primary and secondary. In the case of continuous heat addition to the secondary during a period of quasi-equilibrium, an increase in the secondary system pressure results in steam relief via the steam generator safety valves, which were modeled with 3 percent accumulation and 3 percent tolerance.
Should a small break LOCA occur, depressurization of the RCS causes fluid to flow into the loops from the pressurizer resulting in a pressure and level decrease in the pressurizer. The reactor trip signal subsequently occurs when the pressurizer low-pressure reactor trip setpoint, conservatively modeled as 1805 psia, is reached. LOOP is assumed to occur coincident with reactor trip. A safety injection signal is generated when the pressurizer low-pressure safety injection setpoint, conservatively modeled as 1615 psia, is reached. Safety injection is delayed 35 seconds after the occurrence of the low pressure condition. This delay accounts for signal initiation, diesel generator start up and emergency power bus loading consistent with the assumed loss of offsite power coincident with reactor trip, as well as the time involved in aligning the valves and bringing the HHSI pump up to full speed.
These countermeasures limit the consequences of the accident in,two ways:
- 1. Reactor trip and borated water injection supplement void formation in causing a rapid reduction of nuclear power to a residual level corresponding to the delayed fission and fission product decay. No credit is taken in the LOCA analysis for the boron content of the injection water.
(However, an average RCS/sump mixed boron concentration is calculated to ensure that the post-LOCA core remains subcritical -,refer to Section 3.3.5). In addition, credit is taken in the small break LOCA analysis for the insertion of Rod Cluster Control Assemblies (RCCAs) subsequent to the reactor, trip signal, while assuming the most reactive RCCA is stuck in the full out position.
A rod drop time of 3 seconds was assumed while also considering an additional 2 seconds for the signal processing delay time. Therefore, a total delay time of 5 seconds from the time of reactor trip signal to full rod insertion was used in the small break LOCA analysis.
- 2. Injection of borated water ensures sufficient flooding of the core to prevent excessive cladding temperatures.
During the earlier part of the small break transient. (prior to the assumed loss-of-offsite power coincident with reactor trip), the loss of flow through the break is not sufficient enough to overcome the positive core flow maintained by the reactor coolant pumps. During this period, upward flow through the core is maintained. However, following the reactor coolant pump trip (due to a LOOP) and subsequent pump coastdown, a partial period of core uncovery occurs. Ultimately, the small break transient analysis is terminated when the ECCS flow provided to the RCS exceeds the break flow rate.
The core heat removal mechanisms associated with the small break transient include not only the break itself and the injected ECCS water, but also that heat transferred from the RCS to the steam generator secondary side. Main Feedwater (MFW) is assumed to be isolated coincident with the safety injection mAI808wkh3b.wpf:Ib/091195 3-211
signal, and the MFW pumps coast down to 0% flow in IO Second<. A continuous supply of makeup water is also provided to the secondary using the surd(tery feedwater (Aper) sy."tern..nn AHW actuation signal occurs coincident with the safety injection sighal, resulting in the assumed delivery of full AFW system flow 120 seconds following the signal, The heat transferred to the secondary side of the steam generator aids in the reduction of the RCS.pressure.
Should the RCS depresstuize to approximately 600 psig, as in the case of the limiting 3-inch break and the 4-inch break, the cold leg a<xumulators begin to~ inject ~borjated water.into the reactor coolant loops. In the case of the 2-inch break however, the. vessel mixture level is renvered without the aid of accumulator injection.
Evaluations Upon completion of the smalll break LOCA aajalysis, an evaluation was performed for automatic containment spray actuation during small break LiOCA. This e(vah)ation accounts for the fact tha't Turkey Point Units 3 and 4 may be subject to SI .interruptioh fear up to 2 minutes while switching over to cold leg recirculation. 'The, results of this evaluation are discussed in Sectiion 3.3.2.5.
392.4 Acceptance Criteria for Analyses / Evaluations The Acceptance Criteria for the LOCA are described in 10 CFR 50.46 (Reference 1) as follows:
- 1. The calculated msocimum fuel element cladding temperature shall not exceed 2200'F,
- 2. The calculated total oxidation of the cladding shall nowhere exceed 0.17 times the total cladding thickness before oxidation,
- 3. The calculated total amount of hydrogen generated frortt the chemical reaction of the cladding with water or steam shalll not exceed 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding cylinders surrouncling the fuel, excluding the cladding, surrounding the plenum volume, were to react,
- 4. Calculated changes in core geometry shaljj be such that the core remains amenable to cooiling,
- 5. After any calculated successful initial toperation of the FCCS, 'the calculated, core temperature shall be maintained at an ac(aptably low value and decay heat shall be removed for the extehded period of time required by the long-lived iradioactivity remaining:in the core.
Criteria 1 through 3 are explicitly covered by the small brealk LOCA anal ysis at uprated conditio&
m 61808 w~b.wpf:1b/091195 3-212
For criterion 4, the appropriate core geometry was modeled in the analysis. The results based on this geometry satisfy the PCT criterion of 10 CFR 50.46 and consequently, demonstrate the core remains amenable to cooling.
For criterion 5, Long-Term Core Cooling (LTCC) considerations are not directly applicable to the small break LOCA transient, but are assessed in Section 3.3.5 as part of the evaluation of ECCS performance.
The criteria were established to provide a significant margin in emergency core cooling system (ECCS) performance following a LOCA.
3.32$ Results In order to determine the conditions that produced the most limiting small break LOCA case (as determined by the highest calculated peak cladding temperature), a total of four cases were examined.
These cases included the investigation of variables including break size and RCS temperature to ensure that the most severe postulated small break LOCA event was analyzed. The following discussions provide'insight into the analyzed conditions.
First, a break spectrum based on high RCS T,, was performed, as this was expected to yield more limiting PCT results than low RCS T,,. 'Ihe limiting break for the Turkey Point Units was found to be a 3-inch diameter cold leg break. The results of Reference 8 demonstrate that the cold leg break location is limiting with respect to postulated cold leg, hot leg and pump suction leg break locations.
The PCT attained during the transient was 1688'F (refer to Table 3.3.2-2). Inherent in the limiting small break analysis are several input assumptions (see Section 3.3.2.2 and Table 3.3.2-1), while Table 3.3.2-3 provides the key transient event times.
A summary of the transient response for the limiting high T,, 3-inch break case is shown in Figures 3.3.2P through 3.3.2-12. These figures present the response of the following parameters:
RCS Pressure Transient, Core Mixture Level, Peak Cladding Temperature, Top Core Node Vapor Temperature, Safety Injection Mass Flow Rate for the Intact and Broken Loops, Cold Leg Break Mass Flow Rate, Hot Spot Rod Surface Heat Transfer Coefficient, and Hot Spot Fluid Temperature.
Upon initiation of the limiting 3-inch break, there is a slow depressurization of the RCS (see Figure 3.3.2-4). During the initial period of the small break transient, the effect of the break flow rate is not sufficient to overcome the flow rate maintained by the reactor coolant pumps as they coast mh1808w1ch3b.wpf:thf091195 3'-213
down. As such, normal upward flow is mtuntained tjhrough the, core and core heat. is adequately removed. Following reactor 1rip, the remo val of the heat generated as a result of fission products decay is accomplished via a two-phase mixture level covering the core. From the core mixture level and cladding temperahire transient plots for the 3-inch brealc calculations given in Figures 3.3.2-5 and 3.3.2-6, respectively, it is seen that the peak cladding temperature occurs near the time when'he core is most deeply uncovered and the top of the core is~ being ~cooled by steam. This time is characterized by the hi,ghest vapor superheating above the ituxture level (refer to Figure 3.3.2-7).
A comparison of the fiow provided by the safety .injection system to the intact and broken loops to the total cold leg break mass flow rate at the end of the transient (as given in Figures 3.3;2-8, 3.3.2-9 and 3.3.2-10, respectively), shows that at the time the transient was terminated, the total safety injection flow rate that was delivered to the intact and broken loops exceeds the mass flow rate out the break.'n addition, the inner vessel core mixture level has.recovered the top of the core (FJigure 3.3.2-5).~
Figures 3.3.2-11 and 3.,3.2-12 provide additional information os thk hot rod surface heat transfer coefficient at the hot spot and fluid temperature at the h0t spot, respectively.
There is no longer a concern of exceeding the 10 CFR 50.46 ci'iteria as described in Section 3.3.2.4 since:
- 1. The RCS pressure is gradually decaying, and
- 2. 'Ihe net mass inventory is increasing.
As the RCS inventory continues to graduallly increase,, the core ~mixture level wi1ll continue to ~increase and the fuel cladding temperatures will continue to decline. 111e 3~inc'h high T,, small break LOCA.
transient is terminated.
Additional Break Cases Studies documented in Reference 8 have deteamined that the limiting small-break transIient. occurs for breaks of less than 10 inches. in cliameter. To ensure that th'e 3-'inch diameter break was the most limiting, calculations were also performed with break equivalent diameters of 2 inches and 4 inches.
'Ihe results of each of these cases are given in Tables 3.3.2-2 and 3.3.2-3. Plots of the follow'ing'arameters are given in Figures 3.3.i!-13 through 3.3.2-15 for the 2-inch break case and Figures 3.3.2-16 through 3.3.2-18 for the 4-inch break.
- 1. RCS Pressure Tra<asient,
- 2. Core Mxture Level, and
- 3. Peak Cladding Temperature.
mA1808w4%3b.wpf:1bt091195 3-214
The PCTs for the 2-inch and 4-inch breaks were 1656'F and 1583'F, respectively (see Table 3.3.2-2).
The PCTs for each of these cases was calculated to be less than that for the 3-inch break case based on high T,, conditions.
Limitin Tem rature Conditions Reduced operating temperature typically results in a PCT benefit for the small break LOCA.
However, due to competing effects and the complex nature of small break LOCA transients, there have been some instances where more limiting results have been observed for the reduced operating temperature case. For this reason, a small break LOCA transient based on a lower bound RCS vessel average temperature was performed.
'Ihe temperature window analyzed was based on a nominal vessel average'temperature of 574.2'F, with ~ 3'F for an operating window and ~ 8.5'F to bound uncertainties. The break spectrum was performed at the high vessel average temperature, as this case was expected to yield limiting results.
Then, a sensitivity analysis for the low vessel average temperature was performed, based on the limiting 3-inch break case from the break spectrum analyses previously described.
Plots of the following parameters are given in Figures 3.3.2-19 through 3.3.2-21 for the 3-inch break case at low T,conditions:
- 2. Core Mxture.Level, and
- 3. Peak Cladding Temperature.
The PCT for the 3-inch break case based on low vessel average temperature was 1619'F (see Table 3.2-2). Therefore, the PCT for this case was calculated to be less than that for the 3-inch break case with high vessel average temperature conditions.
Evaluations The evaluation for containment spray actuation in small break LOCA resulted in no change to the predicted small break LOCA PCT for the various cases analyzed.
3.32.6 Conclusions A break spectrum supporting the high nominal vessel average temperature was performed. Peak cladding temperatures of 1656'F, 1688'F, and 1583'F were calculated for the 2-inch, 3-inch, and 4-inch cold leg breaks, respectively, thus identifying the 3-inch equivalent diameter break as limiting.
A sensitivity to low nominal vessel average temperature was performed. 'Ihe calculated peak cladding temperature was 1619'F for the Low Tavg case. Therefore, the 3-inch equivalent diameter cold leg break, high nominal vessel average temperature, is the limiting case.
mA1808wMh3b.wpf:1bf091195 3-215
The analyses presented in this section show that the high head safety injection subsystems of the Emergency Core Cooling System, together with the heat reinolal Wmphbility of the steam generator, provide sufficient core heat removajl capability to mount;un the calculated peak cladding temperatturels below the required liniit of 10 CFR 50.,46 which is defined in Section 3.3.2.4.
Hence, adequate protection is afforded by the emergency core cooling system in the event. of a small break Loss-of-Coolant Accident.
322.7 References
- 1. "Acceptance Criteria for Emergency Core Cooling System's for Light Water Cooled Nucleart Power Reactors," 10 CFR 50.46 and Appendix K df lent) CFR 50, Federal Regster, Volume 39, Number 3, Januajp 1974, a!> amended in Federal Register, Volume 53, September 1988.
- 2. Meyer, P.E., "NOTRUIVP - A Nodal Transient SmItll 8reItk &d General Network Code,"WCAP-10079-A, (proprietary) and WCAP-Ii0080-b P-A. (rIon-proprietary), August 1985.
- 3. Lee, N. et al., "Westiinghouse Small Break ECCS Evaltiati'on Model Using the NOTRUMP Code,"
WCAP-10054-P-A (proprietzy) and WCAP-10081-NP-A (non-proprietary), August 1985.
- 4. "Generic Evaluation of Feedwater Transients and Small Break Loss-of-Coolant Accidents in Westinghouse - Designed Operating Plant," NUREG-0611, January 1980. '.
Bordelon, F. M. et al., "LOCTA-P/ Program: Loss-of-Coolant Tmisient Analysis", WC'-8301 (proprietary) and WCAP-8305 (non-proprietzy), Juhe '.1974.
Thompson, C. M, et al., "Addendum to the Westinghouse Small Break LOCA Evaluation Model Using the NOTRUMP Code: Safety Injection ijato the Broken Loop and the COSI Condensation Model", WCAP-10054-P, Addendum '2 (proprietary) and %CAP-10081-NP (non-proprietaryI),
August 1994.
- 7. Shimeck, D. J., "COSI SVStearn Condensation Experiment Analysis", WCAP-11767-P-A (proprietary), and WCAP-11372-NP-A (non-proprietary), Mari;h 1988.
- 8. Rupprecht, S. D. et al, "Westinghouse Small Break LOCA ECCS Ev'aluation Model Generic Study with the NOTRUMP Code", WCAP-11145-P-A (prOpriletary), 'October 1986.
mhl 808wMb3b.wpf: I bf091195 3-216
Table 3.32-1 Input. Parameters Used in.'the Small Break LOCA Analysis Parameter ~Hi h Tav (LOw Tavg)
Reactor core rated thermal power', (MWt)
Peak linear power"(kw/ft) 14.9 Total peaking factor (F< ) at 2.50 peak'ower See Figure 3.3.2-1 1'.70 shape'hu'uel'ccumulator 15x15 DRFA water volume,. nominal (fr'/acc.) 892 Accumulator tank volume, nominal (fP/acc.) 1200'00 Accumulator gas pressure, minimum (psig)
Pumped safety. injection flow See Figure 3.3;2-2 Steam generator tube plugging level Design Flow/loop,,(gpm)
(lb/sec)'300
(%)'hermal 20 85,000 Vessel- average temperature w/ uncertainties, ('F) 585.7 (562.7)
Reactor coolant pressure w/ uncertainties, (psia) 2320 Min. aux. feedwater flowrate/loop, 9.26 Two percent is added to this power to account for calorimetric error. iReactor coolant pump heat is not modeled in the SBLOCA analyses.
This represents a-power shape corresponding to a.one-line segment peaking factor envelope, K(z),
based on F< = 2.50.
DRFA fuel type modeled in the small break LOCA analysis.
Maximum plugging level in any one or all steam generators.
Flowrates per steam generator.
mh1808w1cb3b.wpf:1bf091195 3-217'
Table 392-2 Small Break LOCA Analysis Fuel Cladding Results Brealc Spectrum, (High T,,)
2-inch 3-inch 4-inch Peak Cladding Temperature ('F) 1656 1688 1583 Peak Cladding Temperautrre Location (ft)"'eak
'1375 11.75 11.50 Cladding Temperahjrre Time (sec) '2627 1188 668 Local Zr/H,O ]Reaction, 1Vlax (%) 2.0188 1.5535 06679 Local Zr/H,O lReaction Locseon (ft)* 11,75 11.5P 11.2 l Total Zr/H,O Reaction (%%uo) < 3..0 <10 < 1.0 Hot Rod Burst Time (sec) No Burst No Burst No Burst Hot Rod Burst Location (ft) N/A N/A N/A Results for the limiting 3-inch break size
~Hi ~h T~av ~ Low T~av ~
Peak Cladding Temperanrre ('F) 16tt8 1619 Peak Cladding Temperanrre Location (ft)":
'11 Q5 11.50 Peak Cladding Temperattrre Time (sec) 1188 1229 Local Zr/H,O Reaction, Max (%%uo) '.5535 1.1034 Local Zr/H20 Reaction Location (ft)* I1LI50 11.50 Total Zr/H,O Reaction (90) i< liP < 1.0 Hot Rod Burst Time (sec) No Burst No Burst Hot Rod Burst Location (ft)" N/A N/A
- From bottom of active fuel mh1808wMBb.wpf:1 bt091195 3-218
Table 3.3Z-3 Small Break LOCA Analysis Time Sequence of Events Break Spectrum, (High T,,)
2-inch 3-inch 4-inch Break Occurs (sec) 0.0 0.0 0.0 Reactor Trip Signal (sec) 40.6 17.0 10A Safety Injection Signal (sec) 58.9 30.4 21.4 Top Of Core Uncovered (sec) 1402 482 278'25 Accumulator Injection Begins (sec) N/A 1040 Peak Clad Temperature Occurs (sec) 2627 1188 668 Top Of Core Covered (sec) 4554 2363 965'esults for the limiting 3-inch break size
~Hi h Tav ~Lovv Tav Break Occurs (sec) 0.0 0.0 Reactor Trip Signal (sec) 17.0 14.4 Safety Injection Signal (sec) 30.4 21.8 Top Of Core Uncovered (sec) 482 526 Accumulator Injection-Begins (sec) 1040 1086 Peak Clad Temperature Occurs (sec) 1188 1229 Top Of Core Covered (sec) 2363 2343
'Momentary core uncovery occurred at 213 seconds during prelude to loop seal clearing. The beginning of the subsequent extended core uncovery at 278 seconds is the, time listed.
m:ii1808w443b.wpf:Ib/091195 3-219
K(Z) URVE 2 ~ 5
~ 5 0
0 6 s 10 C(3RE EI.EVAT(ON f t]
Figure. 3.3.2-1: Sxnall Break Bo1: Riod'Power Shape
, mA1808w'eh3b.wpf:Ib/091195 '3-220
400 FLOW TO INT CT LO P FRO HH I 'PUM
~
I 300 200 CO I
100 0-I F LOW- TO BR KEN L OP FR M 1 H SI PU P CA 200 40 0 600 800 $ 000'200 $ 400 PRESSURE [PSIG]
Figure 33.2-2::Small Break Pumped Safety Injection Flow Rate - 1 HHSI Pump e
mAI808w443b.wpf: Ib/091195 3-221
N L 0 0 T WRE BESSG)RE C
JFIOlf. RHZTIORE I%UK, T'
.U J]6) ]FOER ROD PolER KFNHY M
< ',ME,< COCLE XZ-(SVZKKI Figure 3.3.2-3Code Interface Descriiption for the Small jSreak'LOCA'odel'AI 808wMQb.wpf:1bl091195 3=22'2
2500 2000 n $ 500 I
co $ 000 L
500 0
0 1000 2000 3000 4000 Time (e}
Figure 39.2-4: RCS Depressurization Transient, Liiniting,3-Inch Break, High T,,
mh1808wMQb.wpf:Ibf091195 3-223
35,
.'0
)~ 25 TOP OF OOR
~ 20
,15, 0 0000 2000 3000 Tiime (s)
Figure 3.3.2-5: Core Mixture I.evel, 3-Inch Break, Hing Y,<,
mA1808wMb3b.wpf:1bf091195 3-224
3800 3600
~ f400 1200 I
4 ~ 1000 800 600 400 0 $ 000 2000 3000 4000 Time (e)
Figure 3.3;2-6: Peak Cladding Temperature - Hot Rod, 3-Inch Break, High T,,
I m:u808wMh3b.wpf:Ibf091195 .3-225
1400 1200 1000 CO 600 I,
600 400
-0 1000 2000 3000 4000 T iime (.;)
Figure 3.3.2-7: Top Core Node Vapor Temperature, 3-Inch;Br', Highi T,,,
mh1808w4%3b.wpf:1hf091195 3-226
50 40 E
30 10 1000 2000 3000 4000 Time (s)
Figure 3.3.2-8: ECCS Pumped Safety Injection - Intact. Loop, 3-Inch Break, High T.,
mA1808whch3b.wpf:1b/091195 3-227
25 20 E
15 CV 5
1 0i00 2000 3000 4000 Time (s)
Figure 39.2-9: EC~CS Pumped Safety Injection - Broken Loop> 3-Inch Break, High T,,
mh1808wkh3b.wpf:1bf09119$ 3i-228
1600 1400
~E 1200 1000 o 800 600 co 400 C3 200 0
1000 2000 3000 4000 Time (e)
Figure 3.3.2-10: Cold Leg Break Mass Flow, 3-Inch Break, High T,,
m A1808wMBb.wpf:1b/091195 3-229
5 10 LI I
10 CQ 3
10 2
10 C7 0
1'0 0 1000 2000 Zi 000 4000 T iime (. )
Figure 3.3.2-11: Hot Raid Surface Heat TraiIsfer Coefficient - Hot Spot, 3-IndI High T, 'reak, mAISOSwM3b.wpf: IM8119 :3-230
3800 1600
~Lx 1400
~ 1200 L
~ 3000 800 600 400 0 1000 2000 3000 4000 Time (s)
Figure 3.3.2-12: Fluid Temperature - Hot Spot, 3-Inch Break, High T, m%1 808w'eh3b.wpf:1b/091195 3-231
2500 2000 1500 L
L 1000 500 0 1000 2000 3000 4000 5000 Time (s)
Figure 3.3.2-13: RCS Deprmsurization Tramient, 2-Inch Break, High ']P, mal 808wM3b.wpf:1b/09119.'i ';3-232
30
~ 25 tD L
TOP OF C RE OC
~ 20 15 0 1000 2000 3000 4000 5000 Time (s)
'Figure 3.3.2-'14: Core Mixture Level, 2-Inch Break, High, T,,
mAI808wkb3b.wpf:Ib/091195. 3-233
1800 1600
~ 1400 cp 1200
~ 1000 600 600 400 0 1000 2000 3000 4000 5000 Tiime (:)
Figure 32.2-15: Peak Claddling Tempezett1re - EIot Rod, 2-Ind1 Break, )Higp T,,
mh1808w'4%3b.wpf: Ibf091195 3-234'
2500
'2000
~ 1500
' L co 1000
'I CL, 500 1000 2000 3000 Time (e)
Figure 3.3.2-16: RCS Depressurization Transient, 4-Inch Break,, High T.,
mh1808whcb3b.wpf:1b/091195 3-235
30 25 TOP OF CORI=
20 OC 0
15 10 0 'I 000 2000 3000 Time (s)
Figure 32.2-17: Core Mxture Level4-.Inch Break, High T.,
mh1808wkb3b.wpf:1b/091195 3-23i5
1600
'1400
~ 1200
~ 1000
'e L 800 600 400 200 1.000 2000 3000 T ime (s).
Figure 3.3.2-18: 'Peak Cladding Temperature - Hot Rod, 4-Inch iBreak, High T, mA1808wkh3b.wpf:1h/091195 3-237
2500 2000
~ 1500 l
co $ 000 Q
500.
0 0 t000 2000 '3000 alod Time (e)
Figure 3.3.2-19: RCS Depress11rizatiion Transiex1t, 3-Rachi Break, X.ow 'I',
I' mh1808wM3b.wpf:1W091195 ',3-2:38
~ 20 15 0 $ 000 2000 3000 4000 Time (s)
Figure 3.3.2-20: Core Mxture Level, 3-Inch Break, Low T,,
mh1808wkh3b.wpf:1b/091195 3-239
1800 5600
~Lt 1400 cp 1200 L
~ 3000 800 600 400 0 OOOO 2000 3000 4000-Time (s)
Figure 32.2-21: Peak Cladding Temperature --Hot Rod3-Inc%a Br'eak,, Li>w T
, mA1808w443b.wpf:1bt091195 3-240
3.39 LOCA Hydraulic Forces 393.1 Introduction The purpose of a LOCA hydraulic forces analysis is to generate the hydraulic forcing functions and hydraulic loads that occur on Reactor Coolant System (RCS) components as a result of a postulated loss-of-coolant accident (LOCA). In general, LOCA hydraulic forces increase with an increase in RCS coolant density and, consequently, LOCA hydraulic forces increase with lower RCS temperatures. The lower RCS temperatures associated with the plant uprate requires that RCS components be evaluated relative to the higher forces associated with the reduced RCS temperatures.
The hydraulic forcing functions and loads that occur as a result of a postulated LOCA are calculated assuming a limiting break location and break area. The limiting break location and area varies with the RCS component under consideration but historically the limiting postulated breaks are a limited displacement reactor pressure vessel (RPV) inlet/outlet nozzle break or a double-ended guillotine (DEG) reactor coolant pump (RCP)/steam generator (SG),inlet/outlet nozzle break. The NRC's recent revision to GDC-4 allows main coolant piping breaks to be "excluded from the design basis when analyses reviewed and approved by the Commission demonstrate that the, probability of fluid system piping rupture is extremely low under conditions consistent with the design basis for the piping". This
'e exemption is generally referred to as '"leak-before-break" licensing. For Turkey Point, the applicability of a leak-'before-break design basis was approved in (Reference 1) and was subsequently incorporated into the Turkey Point UFSAR in Revision 7 (July 1989). In addition, the NRC recently approved the base case LBB methodology for 2208 MWt (Reference 3). Previous UFSAR Turkey Point LOCA forces analyses did not take credit for the leak-before-break licensing basis. For the plant uprate, leak-before-break credit is used to evaluate the increased LOCA hydraulic forces.
Leak-before-break licensing allows RCS components to be evaluated for LOCA.integrity considering the next most limiting auxiliary line breaks. For Turkey Point, the next most limiting auxiliary line breaks are the pressurizer surge line break (98.35 in') on the hot leg and the accumulator line break (60.19 in~)-on the cold leg. Postulated residual heat removal (RHR) auxiliary line breaks are bounded by the accumulator line break.
3.392 Input Parameters and Analysis Assumptions The LOCA hydraulic forces analysis incorporates initial RCS condition uncertainties due to process measurement accuracy, instrumentation error, analog-to-digital signal processing, and environmental effects on transmitters. For LOCA hydraulic forces, a higher initial pressure is conservative so the uncertainty in pressurizer pressure is added to the nominal RCS pressure; since lower RCS temperatures are conservative, the maximum temperature uncertainty is subtracted from the RCS temperatures corresponding to the plant uprating conditions.
mh1808wkh3c.wpf:IM81195 3-241
Steam generator and loop hydraulic forces are evaluated on the basis of established LOCA forces sensitivities to break siize/location and RCS thermal/hydraulic conditions. The intent of the evaluations is to demonstrate that the increase in LOCA SG/loop hydraulic forces due to changes in RCS temperatures and pressure ca11 be offset by the, less seveie a&ulmulator line and pressurizer surge line breaks postulated under leak-before-break licensing. Note that the analyses of record assumed dbuble-ended guillotine breaks which can be ignored in f'avor of these limiting auxiliary line bireaks.
vessel/internals forces are analyzed (as opposed to evaluated) using the NRC approved 'ressure MULTIFLEX1.0 (Reference 2) computer code since the analysis'of record already considered branch line breaks (as allowed under leaik-before-bireak licensing). Consequently, no break are@ocation margin is available to offset the .increase in vessel/internals .hydraulic forces due to the plant 11prating, therefore LOCA forces were calculated to show acceptable results.
3999 LOCA Force Analysis Acceptance iCriteria and Re nits 3999.1 Reactor Vessel and Vessel Internals Vessel and vessel internals LOCA hydraulic forcing functions Were generated using two postttlated auxiliary line breaks. An accumulator line break was analyzediusing a flexible beam core barrel MULTIFLEXmodel (for fluid-structure interaction) and a pressurizer surge line break was analyzed using the more conservati ve rigid core barrel model. Using these auxiliary line breaks and thie new RCS conditions, the vessel/internals LOCA hydraulic forces were computed and the, results (hortzontzl and vertical LOCA hydraulic forices) were used fair the structturQ aitalysis'.
The results of this analysis wiere compared with the previout'attal~jsis of record) LOCA hydrhuli'c forces analysis which supported the implementation of the Debhs Resistant Fuel Assembly (DRFA) at Turkey Point.. 'Ihe pipe break consiidered in the prior analysis was an accumulator line break; the pressurizer branch line break was not considered. Comparing peak horizontal forces on the core reactor vessel, and thermal slueld, it.was apparent. that the differences between the analysis of 'arrel, record and the present analysiis were minimal (typically less than 5%) up to li00 msec for the accumulator line break. Mter 100 msec, the peak horizontal forces were somewhat greater (typically 10-20%) for the present analysis although the peak forces fair both analyses were decaying with time.
While LOCA horizontal forces at the uprated conditions were expected to increase throughout that;
,transient according to established sensitIivities, the results were judged to be acceptable in liigh't of. th0 coupling of the structural and hydraulic systems and relatively small break area (accumulator branch line versus DEG). With regards to the vertical. forces on reactor in'ternals, the change in forceis Was and consistent with the revised plant operating-conditions, namely, colder fluid 'easonable temperatures, lower thermal design flow, and iugher initial RCS pressure (due to greater uncertainty in pressure). 'ressurizer mhl808wMh3c.wpf:1hV09 1 195 3-242
3399.2 RCS Loop Piping and Steam Generators Hydraulic forcing functions on the RCS loop piping and steam generators were evaluated using established LOCA forces sensitivities to changes in RCS temperatures and reduced break area associated with leak-before-break licensing; LOCA loop and steam generator forces were last analyzed assuming postulated DEG pipe breaks. As a result of the plant uprating, RCS temperatures were reduced in comparison to the analyses of record; resulting in an increase in loop and steam generator forces. However, the increase in LOCA loop/SG forces due to lower RCS temperatures was offset by less severe accumulator and pressurizer surge line breaks postulated under leak-before-break licensing.
Therefore, it was concluded that the leak-before-break credit offsets the increase in loop/SG forces due to lower temperatures and that the analyses of record forcing functions remain bounding for these components.
399.4 Conclusion The LOCA hydraulic forces analysis for Turkey Point in support of the plant uprating incorporated a 8'F reduction in T,which bounds the uprating low-temperature conditions shown in Table 2.1-1.
The forces analysis of the reactor vesseVinternais was based on the MULTIFLEX(Reference 2) computer code and associated post-processors. The postulated break locations included two limiting branch line breaks, i.e, the accumulator and pressurizer surge lines, as allowed under leak-before-break licensing. The MULTIFLEXanalysis assumed bounding,uprated conditions and incorporated plant initial condition uncertainties. 'Ihe results of the analysis, namely, horizontal and vertical LOCA hydraulic forces, were stored on computer files for access by the cognizant structural analysts within Westinghouse.
For the RCS loop piping and steam generators, evaluations were performed using established sensitivities to show that the existing- forces (double ended guillotine breaks as described in the UFSAR) remain bounding due.to the reduction in. effective break area as allowed under leak-before-break licensing.
3.33$ References
- 1. NRC Letter, from G. E. Edison (NRC) to W. F. Conway (FPL), "Turkey Point Units.3 and 4-Generic Letter 84-04, Asymmetric LOCA Loads", dated November 28, 1988.
- 2. Takeuchi, K., et. al., "MULTIFLEX,A FORTRAN-IV Computer Program for Analyzing Thermal-Hydraulic-Structure System Dynamics", WCAP-8708-PA-V1 (Proprietary),
WCAP-8709-A (Non-Proprietary), September, 1977.
mA1808wM3c.wpf:1M81195 3-243
- 3. NRC Letter from R. P. Croteau. (NRC) to J. H. Goldberg (FPL), "Turkey Point Units 3 and 4 to Utilize Leak Before Break Methodology for Reactor Coolant System Piping)" dated -'pproval June 23, 1995.
3.3.4 Hot Leg Switchover Post-LOCA Hot Leg Switchover (HIAO) time is calculated for inclusiion:in emergency operating procedures to ensure there is limited boron precipitation 'in the reactor vessel following boiling in the core after a cold leg break LOCA. This calcu'lation is dependent upon power level and the various boron concentrations of the RCS and ECCS.
The HLSO calculation is performed to show the acceptance criteria of 10 CFR 50A6 continue to be met for the increase in core power from 2200 MWt to 2300 MWt. SpeciGcally, a new HISO time is established at uprated conditions to show that boron concentrations will not build up to a poirit sttch that boron precipitation occurs.. Excessive boron precipitation may result in a change .in core geometry which is not amenable to coolling or reduced heat ~transfer capability such that heat can not be removed for the extended period of time required by the long-lived radioactivity remairung in the core.
Currently, a HLSO time of 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> is calculated for the Turkey Point Units based on a core lpoWer Of 2200 MWt. Although the boron concentrations of the RCS and EPICS are not changing as a result of the uprating, the increase in the core power to 2300 MWt necessitates a recalculation of the HLSO time and hot leg recirculation minimum required flow. 'I1te increate in core power will reduce the HLSO time from the current value.
The new HLSO time based on an uprated core power 2300.MWt is 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Since the HLSO tiime has been reduced, a revised hot leg recirculation minimum required flow was calculated. Based on plant specific criteria established by Westinghouse, sufficient flow must be delivered to the core during the hot leg recirculation phase such that 1.67 times core boilloff is available at the revised HL$0 timk.
The revised hot leg recirculation mirumum flow requirement is 33 ibm/sec. 'fhis hot leg recirkulktioii minimum flow has been shown to be available. I lna~lly, a revised hot leg / cold leg recirculation'ycling time has been calculated based on uprated conditions. The new requirements for cycliing hot leg injection and cold leg injection post-I OCA is 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after initially switching over 'etween to hot leg recirculation and every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after that.
In conclusion, a new HLSO timemiininium flow requirement for hot leg recirculation and cycling time have been established for the uprating project. It has been shown that, for the uprated conditions, the core geometry will remain amenable to cooling and decay heat~ can be removed for the. extended period of time required by the long-lived radioactivity relmaining i6 the core.
m:u 808'.wpf: ib/091195 3-244
3.3S Post-LOCA Long Term Core Cooling The Westinghouse licensing position for satisfying the requirements of 10 CFR 50A6 Paragraph (b)
Item (5), "Long-Term Cooling", is documented in Reference 1. The Westinghouse position is that the core will remain subcritical post-LOCA by borated water from the various ECCS water sources residing. in the RCS and containment sump. Since credit for control rods insertion is not taken for.
Large Break LOCA, the borated ECCS water provided by the accumulators and RWST must have a sufficiently high boron concentration that, when mixed with other sources of borated and non-borated water, the core will remain subcritical assuming all control rods out.
Although uprated power is not part of this calculation, the Tavg range will have an affect on the fluid masses used in the calculation. During post-LOCA long term cooling, the safety injection flow is drawn from the containment sump following switchover from the RWST. The calculations performed by Westinghouse to determine the containment sump boron concentration include the water mass of the RCS. Since the Tavg range will lower the RCS operating temperature, which will increase the density of the fluid, there is a potential for the post-LOCA sump boron concentration to decrease.
However, the effect of this density change on RCS water mass is relatively small, and within the accuracy of the calculation. In addition, the RWST water mass, which is more important in the calculation, is unaffected by this Tavg range. Therefore, the Tavg range has a negligible effect on the post-LOCA sump boron concentration calculation.
In. conclusion, the uprated conditions including Tavg range have been considered and it is concluded that the core will remain subcritical post-LOCA and that decay heat can be removed for the extended period of time required by the long-lived radioactivity remaining. 'Ihe revised post-LOCA long term core cooling boron limit curve is used to qualify the fuel on a cycle-by-cycle basis during the fuel reload process.
3.3$ .1 Reference 1
1..Bordelon, F. M., et al., "Westinghouse ECCS Evaluation Model - Summary," WCAP-8339 (Non-Proprietary), July 1974.
mh1808wkh3c.wpf:1M81195 3-245
3.4 STEAM GENERATOR 'IlJBE RUlH'URE 3.4.1 Identification of Causes and Accident Description
'Ihe complete severance of a single steam generator tube isi assumed to occur. Due to the pressure differential between the primary and secondary systemsradioactive reactor coolant is discharged from the primary into the secondary system. A portion of this radioactivity is released to the outside atmosphere through either the main condenser, the atmdspheritt duimp valves (ADV) or safety reiief valves (SRV). In addition, iodine activity is contained in the secdndary coolant prior to the accident and some of this activity is released to atmosphere as a resttlt bf steaming of the SGs following the accident. This section describes the assumptions and analyses'performed to detertnine the amount of radioactivity released and the offsite doses resulting from this release.
The purpose for performing SGTR event analysis is to establish the offsite doses resulting fr6m the transfer of radioactive reactor coolant to the secondary iide of the ruptured st~ generator (SG) and subsequent release of radioa(cavity to the atmosphere. Acceptance criteria for offsite doses are, expressed as maximum ajllowed whole-body and thyroid doses at the exclusion, area boundary and low population zone. The primaty ther1nah%ydraulic parameterS which affect the calculation of offsite doses for an SGTR include the amount of reactor coolant ttznsferred to the secondary side of the ruptured steam generator and the amount of steam releaSed &otn the tuptured stean1 genetMor to the atmosphere.
'Ihe event analyzed is the, double-ended rupture of a single steam, generator tube as documented in UFSAR, Rev. 12 (Section 14.2A). It is assumed that the primaryito-secondary break flow following an SGTR results in depressmrization of. the. reactor coolant System'(RCS),, and that reactor trip and safety injection (SI) are automatically initiated on low pressurizer pressure. Loss of offsite power (LOOP) is assumed to occur at reactor trip resulting in the release of steam to the atmosphere via the steam generator atmospheric dump val ves ancl/or safety val'ves. Following SI actuation, it is 'assumed that the RCS pressure stabilizes at the value where the SI and break flow rates are equal. The equilibrium primary-to-secondary break flow .is assumed to persist until 30 minutes, after the .initiation of the SGTR, at which time it is assumed that the opeiators have completed the. actions necessary to terminate the break flow and the steam. release from the~ rult1tured steam generator.
After 30 minutes, it is assumed in the UFSAR analysis that steam is 1'eleased only from the intact steam generators in order to dissipate the core decay heItt alnd to sobs'equ'ently cool the plant down to the residual heat removal (KHR) System operating conditions. During post-SGTR cooldown the pressure in the affected steam generator is assumed to b'e dhcrdase'd by the bacldill method (FD 3.1) which is the preferred approach since it minirnizce the radioactivity released to the atmosphere. Use of alternate post-SGTR cooldown procedures ES 3.2 (steam generator blowdown) or FD 3.3 (atmospheric steam dump) would result in an increase in the offsite doses, h'owner, the increase is expected to remain within the 10 CFR 100 acce,ptance criteria. For Ttu.key Point Units 3 and 4, it is assumed that plant cooldown to RHR operating conclitions:is accomplished within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after initiation of the mh1808w1ch3c.wpf:1bf091195 3-246
SGTR and that steam releases are terminated at this time. A primary and secondary side mass and energy balance is used to calculate the steam release and feedwater flow for the intact steam generators from 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and from 2 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
3.42 Input Parameters and Assumptions A steam generator tube rupture (SGTR) thermal/hydraulic analysis for offsite activity release has been performed. The SGTR analysis incorporates a ~ 3'F Tavg window about the current licensed Tavg of 574.2'F as part of the plant uprating effort. Plant secondary side conditions (e.g., steam pressure, flow, temperature) are based on (1) 0% steam generator tube plugging (SGTP) to reflect expected conditions at the uprated power level with the steam generators in their current condition (< 1%
SGTP) and (2) 20% SGTP to reflect lower steam pressure and temperature at the maximum tube plugging condition. The SGTR analysis incorporates a total T,,reduction of 8'F, which bounds the uprating conditions for low T,, provided in Table 2.1-1..
The offsite doses following a steam generator tube rupture (SGTR) reflect:the uprated power level of 2346 MWt and both pre-accident iodine spike and accident initiated iodine spikes (Reference 1). The assumptions used in the SGTR dose analysis are summarized in Table 3A-2.
3.42.1 High Head Safety Injection (HHSI) and Charging Flow Rates At Turkey Point, the charging (positive displacement) pumps automatically trip upon generation of an "SI" signal. However, plant Emergency Operating Procedures (EOP) instruct the operator to restart the positive displacement pumps (PDP) to establish charging flow. Consideration of charging pumps in operation concurrent with HHSI pumps increases total injection flow delivery to the RCS. A greater injection flow rate results in a greater RCS equilibrium pressure and, consequently, higher break flow.
'Ihus, it is conservative to use the combined (HHSI + PDP) maximum injection flow rates in the SGTR analysis. For Turkey Point, a maximum charging pump flow capacity of 100 gpm is assumed which is added to.the maximum (all four pumps operating) HHSI flow rate at each RCS pressure point.
3.422 RHR Cut-in Time Twenty-four hours is conservatively assumed for the RHR cut-in time based on the RCS heat load and RHR heat removal capacity. This affects the duration of long term steam releases from the intact steam generators to the atmosphere following termination of the break flow. The effect of RHR cut-in time on long term doses, however, is not significant since the radiation emitted from the intact steam generators is small relative to that released by the ruptured steam generator.
mh1808wkh3c.wpf:1b/091195 3-247
3.423 Miscellaneous Parameiters The following parameters are: assumed in the analysis:
~ Low pressurizer pressure SI actuation setpoint = 1745 psih
~ Lowest SG safety valve, reseat pressure == 902 psia includes 15% MSSV blowdown and 3%
tolerance.
3.49 Description of Analyses Multiple cases were anal)md, consistent with all of the parameter cases presented .in Section'2.0 of this report.
These cases were individually analyzedI in order to detejtmine the steam releases for the offsid dbse evaluation between 0 and 30 muiutes (break flow termination)1 A.single calculation is performed to calculate long term steam releases fiom the intact steam generators for the tiime intervals 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 2 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (RHR cut-.in time).
3.4.4 Acceptance Criteria The offsite dose limits for a SGTR with a pre-accident iodine spike are the guideline values of 10 CFR 100 (Reference 1). These guideline values are 300 rem thyroid and. 25 rem y-body. For a SGTR with an accident irutiated iodiine spike the acceptance criteria are. a "small fraction of" the'0 CFR 100 guideline values, or 30 rem thyroid and 2.5 rem y-body.
3.4$ Results The tube rupture break flow, atmospheric steam releases, and f'eedwater flows for the offsite dose analysis are summarized in Table 3A-1. Note, that the steam release from the ruptured stmm generator due to failure of the hydraulic line connecting the radiation~ malnitbr tb th'e main steam line is included in Table 3.4-1. les additional steam release is discussed lke11 in thiS section. Also note that maximum steam release and break flow between 0 and 30 min'ute< (time of break flow termination) are based on two different SGTR catses: 1) high Tavg, 0%'SGTP,'nd 2) low Tavg case, 20% SGTP (which bounds the uprating condlitions)For a SGTR event, the amount of radioactivity released to the atmosphere is directly proportional to the amount of steam:teleased through the ruptured steaiu generator safety valves. Consequently, the worst radiological consequences result from the SGTR else with the greatest amou,nt of steam released. Likewise, a. greater bleak flow ~esults in greater radiological contamination of the secondary side which fin titrn results in a greater amount of activity released along with the steam. Maximum break flow and stean release, therefore, represent boundihg values which are conservative for an offsite dose evaluation.
mhl808wkh3c.wpf:1b/091895 3-248
The SGTR thermal/hydraulic results for the plant uprating can be compared to the Turkey Point UFSAR (Section 14.2.4) results. The UFSAR (Reference 1) indicates that 79,718 ibm of reactor coolant is discharged into the steam generator and 48,534 lbm of steam are released to atmosphere during the 30-minute period to isolate the affected steam generator. In this analysis, 102,700 Ibm (28.8% increase) of reactor coolant are discharged into the steam generator and 55,000 (13.3%
increase) ibm of steam are released to atmosphere.
The 28.8% increase in primary-to-secondary break flow can be attributed to (1) a slightly higher RCS equilibrium pressure (1374.9 vs. 1337 psia) and (2) a significantly lower steam generator pressure (902 vs. 1100,psia) following reactor trip. Both factors contribute to a larger primary-to-secondary pressure drop and, hence, larger break flow rate for the plant uprate. Note that the higher RCS equilibrium pressure is due to consideration of the positive displacement charging pump in operation concurrent with the four HHSI pumps; the lower steam generator pressure following reactor trip is due to an increase in the assumed MSSV blowdown to 15% and increase in MSSV tolerance to 3%.
The 13.3% increase in steam released to atmosphere during the 30-minute period to isolate'the ruptured steam generator is due to the following factors: (1) 4.5% increase in plant power, (2) greater RCS metal/fluid stored energy due to higher initial Tavg (577.2'F vs. 574.2'F), (3) lower MSSV setpoint as discussed above, and (4) greater primary-to-secondary break flow (102,700 ibm vs.
79,718 ibm).
The SGTR analysis also considered additional atmospheric steam releases from the ruptured steam generator due to failure of the radiation monitor (RAD-6426) line and minor leakages on the secondary steam and/or feed side of the steam generator.
The calculated thyroid and y-body doses (rem) at the exclusion boundary and low population zone outer boundary are as follows:
EB (0-2 Hr) LPZ (0-24 Hr)
Thyroid: Accident Initiated Spike 6.8 E-2 1.0 E-2 Thyroid: Pre-Accident Spike 4.1 E-1 4.5 E-2 y-Body 2.0 E-2 2.0 E-3 3.4.6 Conclusion The SGTR thermal/hydraulic analysis for offsite activity release has been completed in support of the uprating. Based on a primary and secondary side mass and energy balance, the break flow and atmospheric steam releases from the ruptured and intact steam generators were calculated for 30 minutes. After 30 minutes, it was assumed that steam is released only from the intact steam generators in order to dissipate the core decay heat and to subsequently cool the plant down to the RHR Systems operating conditions. For Turkey Point Units 3 and 4, it was assumed that plant mM 808wkb3c.wpf:1b/091295 3-249
cooldown to RHR operatIing conditions can be accomplished within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after initiation of the SGTR and that steam relies are terminated at this time. A primary and secondary side mass and energy balance was used to calculate the 'steam release and feedwater flow for the intact steam generators from 0 to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and from 2 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. In addition, minor leakage due to failure Of radiation monitor (RAD-6426) liine between 30 minutes (time of break flow tertnination) and'.5 ho11rs'time at which operator isolates leakage) was added to the overall steam releases tci the atmosphere.'he increase in radioactivity released to the atmosphere as-a result of this leakage was insignificant in comparison with the total.
'Ihe SGTR thermal/hydraulic results for this anal ysis wdre Jmrd~ to the Turkey Point UFSAR, Rev. 12 results. As a result of the plant upraling and associated conditions, primary-to-secondary break flow and steam releases were increased.,
The offsite thyroid and y-body doses for the SGTR me wiC1in the accept:u1ce criteria in Section 3.4.4.
3.4.7 Reference
- 1. Turkey Point Units 3 and 4 UFSAR,:Revision 12.
'A1808w443c.wpf:1M81195 3-250
Table 3.4-1 SGTR Thermal/Hydraulic Results for Radiological Analysis Time ibm Tube Rupture Break Flow 0 30 minutes 102,700 Steam Release from Ruptured SG 0 30 minutes 55,000 Steam Release from Ruptured SG 0.5 8.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> 2160 Steam Release Rom Intact SGs 0 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 308,500 Steam Release from Intact SGs 2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 1,731,200 Feedwater Flow to Intact SGs 0 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 280,100 Feedwater Flow to-Intact SGs 2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 1,769,600 Initial Ruptured SG Water Mass (at time zero) 83,800 Final Ruptured SG Water Mass (at > 30 minutes) 96,700
'his steam release is due to failure of the hydraulic line connecting radiation monitor RAD-6426 to the main steam line. A, leak rate of 270 ibm/hr is assumed.'h1808wkh3c.wpf:tb/091195 3-251
Table 3A-2 Asst!unptions for SGTR Dose Analysis Power . 2346 MWt Reactor Coolant Noble Gas Activity 1.0% Fuel Defect Level Prior to accident Reactor Coolant Iodine Activjity Prior to Accident Pre-Accident Spike 60 pCi/gm of DE I-131 Accident Initiated Spike... 1.0 pCi/gpm of DE I-131 Reactor Coolant Iodine A(cavity Increase 500 times equilibrium release Due to Accident Initiated,'Spike rate fi'om fuel for h1iti~d 1.,6 h!ours after SGTR Secondary Coolant Activity .......,.... '...'. '.. '.10 i.(Ci/gm of DE I-131 Prior to Accident SG Tube Leak Rate for Intact SGs During Ac(ident ......... 500 gpd per SG Break Flow to Ruptured SG ........,................... 102,700 lb (0-30 min)
SG Iodine Partition Factor 0.01 Duration of Activity Release from Secondary System . ...... 24 hr Offsite Power Lost Steam Release from SGs to Enviromnent Ruptured SG 55000 lb (0-30 min) 2,160'lb (0.5 - 8.5 hr)o)
Intact SGs ~ l ~ ~ '08+00 lb (0-2:hr) 1,7'31,'200! lb (2-24 lE)
Due to failure. of hydraulic line connecting radiatioh monitor RAD-6426 to the main steamline.!
A leak rate of 270 lb/hr is assumed.
mal 808w(ch3c.wpf:1bl091195 3-252
3.5 CONTAINMENTINTEGRITY ANALYSES 3.5.1 Main Steam Line Break (MSLB) Mass and Energy (MAE) Releases 3.5.1.1 Identification of Causes and Accident Description Steamline ruptures occurring inside a reactor containment structure may result in significant releases of high-energy fluid to the containment environment, possibly resulting in high containment temperatures and pressures. The quantitative nature of the releases following a steamline rupture is dependent upon the many possible configurations of. the plant steam system and containment designs as well as the plant operating conditions and the size of the rupture. '111ese variations make a reasonable determination of the single absolute worst case for both containment pressure and temperature evaluations following a steamline break difficult. The analysis considers a variety of postulated pipe breaks encompassing wide variations in plant operation, safety system performance, and break size in determining the containment response to a secondary system pipe rupture.
In addition to the inside containment analyses performed for containment integrity, an analysis was performed for an outside containment steamline break to determine radiological consequences for the uprated conditions.
3$ .1Z Input Parameters and Assumptions The postulated break area can have competing effects on blowdown results. Larger break areas will be more likely to result in large amounts of water being entrained in the blowdown. However, larger breaks also result in earlier generation of protective trip signals following the break and a reduction of both the power production by the plant and the amount of high-energy fluid available to be released to the containment.
To determine the effects of plant power level and break area on the mass and energy releases from a ruptured steamline, spectrums of both variables have been evaluated. At plant power levels of 102%,
70%, 30% and 0% of nominal full-load power, four break sizes have been defined. These break areas are defined as the following.
- l. A full double-ended rupture (DER) downstream of the flow restrictor in one steamline. Note that a DER is defined as a rupture in which the steam pipe is completely severed and the ends of the break displace from each other.
- 2. A small break at the steam generator nozzle having an area just larger than that at which water entrainment occurs.
- 3. A small break at the steam generator nozzle having an area just smaller than that at which water entrainment occurs.
mfu808wkh3c.wpf:1b/091195 3-253
- 4. A small split rupture that will neither generate a steamline isolation signal from the Westinghouse Engineered Safety Featxxres nor result in water entrainjrnent in the. break effluent.
The cases examined in this study were chosen based on the: resadts of'he analyses presented in 1 for Turkey Point Units 3 and 4. The most-lim'itin'g chse with respect to peak containment 'eference pressure was analyzed'. at the uprated power condition. Initial containment conditions for this lin'utixxg case were assumed to be +3.i0 psig andi 130'F. l.'his cue was a 1.4 ft'based on the steam nIozzlle cross-sectionied area) DER at hot-zero-pow!:r (HZP) conditions. Tlus DER ste~linIe 'low-limiter break was modeled assuxxung isolatiion is acccimplished by the main steam isolation valve in iI:ach intact steamline. The important plant conditions and features that were assumed are discussed in the following paragraphs.
Initial Power Level Steamline breaks can Itxe postulated to occur with the plant in alny operating condition ranyng frdm to full power.,Since stern generator mass decreases with increasing power level, breaks hot'hutdown occurring at lower power leviels will generally result in a greater total mass release to the contairunent.
However, because of incrtused stored energy. in the primary side of the plant, increased heat transfer in the steam generators, and additional energy generation in the fuel, the energy release to the containment from breaks lxostulated to occur during "at-IIxower" op'eration may be greater than for breaks occurring with the plant in a hot-shutdown conditionj. Addhtioxxally, steam pressure and tlxe dynamic conditions in the steam generators change with increasing power and have a significant'nfluence on both the ate of blowdown and the amount'of Noistm'e entrained in the fluid leaving, thb break.
Because of the opposing effeicts (mass ver! us energy relbasb) of'hanging power level on steamline break releases, no single Ixower level can be siingled out'as tx w'orst case initial condition for break event. Therefore, sieveral different power levels spanxxing from full- to zero-power a'teamline conditions have been investigated for Turkey Point Units 3 andI 4 as discussed in Reference 1. For this power uprating analy!sis, only the power level corresponding to the steamline break mass-and-energy releases resulting in the limiting containment prHsure response is included.
In general, the plant initial ccinditiorxs are assumed to be at the noxtxinal value corresponding tb the initial power. Table 3,.5.1-1 identifiiw the values assumed for RCS pressure, RCS vessel average temperature, pressurizer water volume,,steam generator water level, and fi:edwater enthalpy corresponding to the limitiing steamline break case analyzed Sin le-Failure Assum tion To avoid unnecessary coxxservatism, boundiing multiple failure assumptions were not made in the analysis. Only one single falters was considered:in the anslysia. The Main Steam Isolation Walkie Assembly in each stemnline consists of the mssn.'team isolation valve (Msiv) and the main steabt m:stX808wXoh3c.wXIf:Xb/091 195 3-254
check valve (MSCV). The MSIV closes upon an isolation signal to terminate steam flow from the associated steam generator. The MSCV is designed to prevent reverse steam flow in the steamline, thus. preventing blowdown from more than one steam generator for any break inside containment.
However, if the MSCV in the faulted loop is assumed to fail, the intact steam generators would blow down through the break until the MSIVs in the intact loops close. This could result in significant additional mass and energy release to containment. The assumption that both the MSIV and the MSCV in the faulted loop fail exceeds the-current UFSAR analysis assumptions. The intent of this assumption is to show that the protection logic which provides a signal to close the MSIVs, and the associated delay time, is adequate to limit the amount of steam mass and energy discharged into containment such that the containment pressure limit is not exceeded. To do this, no credit is taken for the proper functioning of the MSCV in preventing reverse steam flow from the intact steam generators.
Main Feedwater S stem Main feedwater flow was conservatively modeled by assuming an initial increase in feedwater flow (until fully isolated) in response to increases in steam flow following initiation of the steamline break.
This maximizes the total mass addition prior to feedwater isolation. The steamline break case of Reference 1 which resulted in the limiting containment pressure response occurred from a hot-zero-power condition. During actual plant operation, the main feedwater valves. are not in service at power levels up to approximately 15-20% of full power; rather, the 4-inch feedwater bypass valves are used to provide flow to the steam generators. The flows through the 4-inch feedwater bypass valves as a function of steam generator pressure was generated for both the faulted and the intact loops. The feedwater isolation response time was governed by the response time of the feedwater bypass valves,and was assumed to be a total. of 13 seconds following the safety injection signal.
Following feedwater isolation, as-the steam generator pressure decreases, some of the fluid in the feedwater lines downstream of the isolation valve may flash to steam if the feedwater temperature exceeds the saturation pressure. This unisolable feedwater line volume is an additional source of high-energy fluid that was assumed to be discharged out of the break. The unisolable volume in the feedwater lines are maximized for the faulted loop and minimized for the intact loop. The energy in the unisolable volume is maximized by assuming recirculated feedwater from the condenser rather than "cold" water from the demineralized water storage tank. The following piping volumes available for steam flashing were calculated Rom plant drawings and assumed in the analysis.
Volume from SG nozzle to FCV (faulted loop) - 238 from SG nozzle to FCV (intact loops) - 75 ft'/loop ft'olume Auxili Feedwater S stem Generally, within the first minute following a steamline break, the auxiliary feedwater system will be initiated on any one of several protection system signals. Addition of auxiliary feedwater to the steam mal 808w'4%3c.wpf:tb/091 195 3-255
generators will increase the secondary mass available for release to containment. as well as increase the heat transferred to the-secondary. fluid; The. auxiliary.feedwater flow control valves are set to supply a fixed flow to each steam generator, regardless of the baekpi'ess'ure'in the steam generator. The maximum AFW flowrate ihas been determined to be 254 gpm/FCV (1 FCV per AFW txain, 2 AFW trains per SG; therefore, the total. AFW flowrate is 508 gpiri/SG) for the first 120 seconds, decreasinIg to 140 gpm/FCV (totall AFW flowrate is 280 gprri/SG) for the, remainder of the event. A higher AFW flowrate to the faulted loop steam generator is conservative for the steamline break event; consequently, 254 gprr/FCV for 120 seconds decreasing to 140 gpm/FCV was assumed for the faulted loop steam generator AFW flowrateConversely,, a lower AH@ fl6wrate's conservative for Iite intact steam generators; thus, a const mt 140 gpm/FCV was assumed for each intact loop for the entitle 'oop transient.
Steam Generator Fluid Mass Maximum initial steam generator masses in the faulted loop steam generator were used in both, of the analyzed cases. The use of high initial steam generator masses maximizes the steain generator inventory available for release to containment. The initial masses were calculated as the mas0 corresponding to the programmed level +6% narrow range span. Minimum <<nifial steam gendratdr in the intact loops ste un generators were used in'oth Of the analyzed cases. The use'f 'asses reduced initial steam generator masses min'imizes the availability of the heat sink afforded by thd steam generators on the intact loops. The initial masses were calculated as the mass correspoInditig to the programmed level -6% narrow range span. All steam genei%or fluid masses are calculated corresponding to 0% tube plugging which is conservative with respect to the RCS cooldown through the faulted loop steam generator resulting from the steanQine bi'eak. The water mass defined by portion of the steam generator slowdown recovery system is accounted for as part of an the'nisolable overall mass uncertainty applied to the steam generator ihitihl c'onditions. Tt'us mass uncertaiitty.'is to both the faulted and intact steam generators and is in addition to the programmed 6% 'pplied narrow range span level uncei~nty previously mentioneid:
Steam Generator Reverse jHeat Transfer Once the steamline isolation is complete, those, steam geiierhtoA in the intact steam loops becbmk sources of energy which can be transferred to the steam generator with the broken line. This
'energy'ransfer occurs via the primary coolant. As the primary plant cools, the temperature of the, coolant flowing in the steam generator tubes drops below the temperature of the secondary fluid in thi: in'tact'.
steam generators resultiing in energy bei:ng returned to the primary coolan( This energy is the,n available to be transferred to the, steam generator with the broken steainline. The effects of reverse steam generator heat transfer are included in the results.
mh1808wM3c.wpf:1b/091195 3-256
Break Flow Model Piping discharge resistances were not included in the calculation of the releases resulting from the f
steamline ruptures [Moody Curve for an (0 / D) = 0 was used].
Core Deca Heat Core decay heat generation assumed is based on. the 1979 ANS Decay Heat+ 2'odel (Reference 2).
Steamline Volume Blowdown
'Ihe contribution to the mass and energy releases from the secondary plant steam piping was included in the mass and energy release calculations. 'Ihe flowrate was determined ~using the:Moody correlation, the pipe. cross-sectional area, and the initial.steam pressure. For the limiting steamline DER case analyzed for the power uprating, the unisolable steamline mass is included in the mass exiting the break from the time of,steamline isolation until the:unisolable mass is completely released to. containment.
Main Steamline Isolation The postulated single failure for these two cases-is the failure to close the MSCV in the faulted loop.
In this instance, MSIV closure in the intact loops is required.to terminate the blowdown. A delay time of 7 seconds was assumed (2-second signal'processing-plus 5-second valve closure) with full steam flow assumed through the valve during the valve stroke. 'Ihe assumption of full steam flow from the intact steam generators. for this time conservatively accounts for the effects. of the unisolable steamline volume which would be released following closure of the MSIVs.
Reactor Coolant S stem Metal Heat Ca acit As the primary, side, of the plant cools, the temperature of the reactor coolant drops below the temperature of the reactor coolant piping, the reactor vessel, and the reactor coolant pumps. As this occurs, the'heat stored in the metal is available to be transferred to the steam generator with the broken line. Stored metal heat does not have a major impact on the calculated mass and energy releases. The effects of this RCS metal heat are included in the results using conservative thick metal masses and heat transfer coefficients.
Rod Control The rod. control system was assumed to be in manual operation for the steamline break analyses.
mA1808wkh3c.wpf:ibf091195 3-'257
Protection S stem Actuations The protection systems available to mitigate the effects of a MSLB accident inside containment include reactor trip, safety injection, steamline. isolation, feedwhter isolation, emergency fan coolers, and containment spray. I'he first protection system signal actuated was Ehgh Cont unment Prlesstire (2-of-3 channels) which iiiitiated safety injection; the safety injection signal produced a reactor trip signal. Feedwater system and steam generator blowdown recovery system isolation also occurred as a result of the safety injection signal. Finally, steainline isolation occurred via, a High Steam Flow in ~
2-of-3 steamlines (1-of-2 chaInnels per steamline) coincident with a Low 'T-avg SI signal in 2~of-3 loops.
Safe In ection S stem Minimum safety injection system (SIS) flowrates.corresponding to the: failure of'one SIS traiii (2-of-4 pumps) were assumed in Gus analysis. A ininimum SI flow is coriservative since the reduced boron addition maximizes a return to power resulting from the RCS cool'down. 'Ilie higher power generation increases heat transfer to the secondary side, maximizing steam flow out of the break. The delay time to achieve full SI flow was assumedI to be 23 seconds fdr this linalysi>>.
Core Reactivit Coefficients Conservative core reactivity coefficient<> corresponding tb end-df-clycle conditions, including EIZP stuck-rod moderator density coefficiients, were used to maximize the react1vity feedback effects resulting Rom the steamline break. Use of maximum reactivity feedback results in higher power generation if the reactor returIns critical, thus maxiimizing heat transfer to the secondary sicle of the steam generators.
3$ .18 Description of Analysis The break flows and enthaipies of the steam release throhghI thiI; stI:amiine break is analyzed With'he LOFTP~ (Reference 3) computer code. Blowdown mass and energy releases determined using LOFTRAN include the effects of core power generation,~ main and'uxiliary feedwater additidns, engineered safeguards,system:s, reactor cooIiant system thck metal heat storage, and reverse steam generator heat transfer.
The 'Ibrkey Point NSSS is analyzed using LOFIRAN to determine the transiient steam mass hnd energy releases inside containment foliowirig a, steamline beak event. The tables of mass and energy releases are used as input conditions to the analysis of the containment response as discussed in Section 3.5.4.
'Ihe single most-limiting case with respect to peak contaiinment pressure, based on the results in Reference 1 was analyzed:, a 1.4 ft'ER at hot-zero-power (HZP) conditions.
IA1808wkh3c.wpf:1bf092595 3-258
The DER steamline break event was modeled taking credit only for MSIV closure on the intact loops for steamline isolation.
3S.1.4 Acceptance Criteria The main steamline break is classified as an ANS Condition IV event, an infrequent fault. Additional clarification of the ANS classification of this event is presented in Section 3.2.16 of this report, which discusses the core response to a steamline break event. The acceptance criteria associated with the steamline break event resulting in a mass and energy release inside containment is based on providing sufficient conservatism in the analysis to assure that the containment design margin is maintained.
The specific criteria applicable to this analysis are related to the assumptions regarding power level, stored energy, the break flow model including entrainment, main and auxiliary feedwater flow, steamline and feedwater isolation, blowdown recovery system isolation, and single-failure such that the containment peak pressure is maximized. These analysis assumptions have been included in this steamline break mass.and energy release analysis as discussed in Reference 1 and Section 3.5.1.2 of this report. The tables of mass and energy release for the limiting steamline break case noted in the previous section are used as input to a containment response calculation to confirm the design pressure limit of the Turkey Point containment structure.
3$ .1$ Results Using Reference 1 as a basis, including parameter changes associated with the power uprating, the mass and energy release rates were developed to determine the containment pressure response for the limiting steamline break case noted in Section 3.5.1.3. The mass and energy releases from the 1A ft'ER at HZP conditions resulted in the highest containment pressure. The steam mass and energy releases discussed in this section provide the basis for the containment response described in Section 3.5.4 of this report. Table 3.5.4-6 provides the sequence of events for the limiting steamline break inside containment.
3.5.1.6 Conclusions
'Ihe mass and energy releases from the steamline break case resulting in the limiting containment pressure response identified in Reference 1 has been analyzed at the uprated power conditions. The assumptions delineated in Section 3.5.1.2 have been included in the steamline break analysis such that the applicable acceptance criteria are met. The steam mass and energy releases discussed in this section provide the basis for the containment response described in Section 3.5.4 of this report.
mh1808wkh3c.wpf:tb/091195 3-259
3S.1.7 References
- 1. Gresham, J. A., Heberle, G. H.; Wills, M. Ei. and Scbbeil, Jl. H"Analysis of'Containment Response FollowIing a Main Steam Line Break for Turkey Point Units 3 and 4," WCAP-12262 (non-Proprietary)August 1989
- 2. ANSVANS-5.1-1979, American National Standard for Deca)i Heat Power in Light'Water
-Reactors," August 1979
- 3. Burnett, T. W. T., et al."LOFIRAN Code Description," WCAP-7907-P-A, (Propnet~) and WCAP-7907-A (non-Proprietary)," April 1984 mal 808w~3c.wpf:1M82595
Table 3.5.1-1 Nominal Plant Parameters and Initial Condition Assumptions *
(MSLB M&E Releases)
NOMINALCONDITIONS NSSS Power,.MWt 2311.4 Core Power, MWt 2300 Reactor Coolant Pump Heat, MWt 11.4 Reactor Coolant Flow (total), gpm 255,000 Pressurizer Pressure, psia 2250 Core Bypass, % 6.0 Reactor Coolant Temperatures, 'F Core Outlet 61'1.3 Vessel Outlet 607.8 Core Average 580.5 Vessel Average 577.2 Vessel/Core Inlet 546.6 Steam Generator Steam Temperature, 'F 522.8 Steam Pressure, psia 832 Steam Flow (total), 10~ ibm/hr 10.17 Feedwater Temperature, 'F 443 Zero-Load Temperature, 'F 547 INITIALCONDITIONS POWER LEVEL (%)
PARAMETER'02 RCS Average Temperature ('F) 583.2 547.0 RCS Flowrate (gpm) 255,000 255,000 RCS Pressure (psia) 2250 2250 Pressurizer Water Volume (ft ) 688.6 321.9 Feedwater Enthalpy (Btu/ibm) 424.9 70.68 SG Water Level, faulted/intact (% span) 66/54 56/44 Noted values correspond to plant conditions defined by 0% steam generator tube plugging and the high end of the RCS T-avg window.
m:u808wMh3c.wpf:1V091195 3-261
3.5Z Steamline Bre k Radiological Consequences 3.52.1 Introduction of Causes and Accident Description The complete severance of a main steamline outside containment is assumed to occur. The Melted Steam Generator (SG) willi rapidly depressurize and rele~ase~ radioiOdines initially contained in the secondary coolant and primate coolant activity, transferred via SG tube leak', directly to the outside atmosphere. A portion of'he iodine activity initially contai.ned in the intact SGs and noble gas activity due to tube leakage is released to atmosphere through either the atmospheric dump valves (ADV) or the safety relief valves (SRV). This section describes the assumptions and analysbs ~
performed to determine the amount of radioactivity relemed and the offsite doses resulting fnbm thi4 release.
3.522 Input Parameters and Assumptions The analysis of the steam line break (SLB) reiiologiiwl consequences uses the analytical methods and assumptions outlined in the Standard Review Plan (Reference 1). These along with plant specific assumptions are summarized in Table 3.5.2-1.
3823 Description of Analyses The radiological consequences of a SLB are analyzed with both the pre-accident and acciden), initiated iodine spike models. For the pre-accident. iodine spike it is assumed that a reactor transient has
~
occurred prior to the SGTR and has raised the RCS iodine concentration to 60 pCi/gm of dose equivalent (DE) I-131. For the accident initiated iodine spike the reactor trip associated with break (SLB) creates an iodine spike in the RCS which increases the iodine release rate from the'teamline the fuel to the RCS to a value 500 times greater than th6 rele~ ate corresponding to the m~urd equilibrium RCS Technic'd Spec'ification concentration of 10 pCi/gm of DE I-131. The duration of the accident initiated iodine s~pike is 1.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
382.4 Acceptance Criteria The offsite dose limits for a SLB with a pre-accident iodine spike, are the guideline values of 10 CFR 100. 'Ihese guideline values are 300 rem. thyroid add 25 tjem'y-body. For a SLB with an accident initiated iodine spike the acceptance criteria are a "small fraciion of'he 10 CFR 100 guideline values, or 30 rem thyroid and 2.5 rem y-body.
<gal mA1808wMh3c.wpf:1M81895 3-262
3.528 Results The calculated thyroid and 7-body doses (rem) at the exclusion:boundary and low population zone outer boundary are as. follows:
EB (0-2 Hr) LPZ'(0-24 Hr)
Thyroid: Accident Initiated Spike 4.2 E-1 1.1 E-1 Thyroid: Pre-Accident Spike 5.2 E-1 1.1 E-1 y-Body 1.9 E-4 4.6 E-5 382.6 Conclusions The offsite thyroid and y-body doses due to the SLB are within the acceptance criteria in Section 3.5.2.4..
3S2.7 References
- 1. NUREG-0800, Standard Review Plan 15.1.5, Appendix, A, "Radiological Consequences of Main Steam Line. Failures Outside of a Containment," Rev. 2, Iuly 1981.
mh1808wkh3c.wpf:1bf091 195 3-263
Table 3.52-1 Assumptiions Used for SLB Dose Analysi~>
Power .. .. 2346 hPVt Reactor Coolant Noble Gas Activity 1.0% Fuel Defect Level Prior to Accident Reactor Coolant Iodine Activity-Prior to Accident Pre-Accident Spike 60 pCi/gm of DE 1-131 Accident Initiated Spike ..... 1.0 pCi/gm of DE 1-131 Reactor Coolant Iodine Activity ~....... 500 times equilibrium Increase Due to Accident Initiated release rate from fuel for Spike initial 1.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> af1er SLB Secondary Coolant Activity '...'... 0.10 pCi/gm of DE I-131 Prior to Accident SG Tube Leak Rate During Accident ..... 500 gpd per SG Iodine Partition Factor.;
Faulted SG ....... 1.0 (SG assumed to steam dry)
Intact SGs .......... 0.01 Duration of Activity Release from'Secondary System Offsite Power Lost Steam Release from SGs Faulted SG . 84,128 lb (0-2 hr)
Intact SGs . 269,700 lb (0-2 hr) 369,300 lb (2-8 hr) 984,700 Ib (8-24 hr) mA1808wMh3c.wpf:1b/091195 3-264
3.52.1 Introduction The purpose of this analysis was to calculate the long-term Loss-of-Coolant Accident (LOCA) mass and energy releases. for the hypothetical double-ended pump. suction (DEPS) rupture and double-ended hot leg (DEHL) rupture break cases with the uprated conditions for the Turkey Point Units 3 and 4 Thermal Uprating Program.
The uncontrolled release of pressurized high temperature reactor coolant, termed a LOCA, will result in release of steam and water into the containment. This, in turn, will result in an increase in the containment pressure and temperature. The mass and energy release rates, described in this section form the basis of further computations to evaluate the structural integrity of the containment following a postulated accident (see Section 3.5.4).
3.592 Input Parameters and 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 the RCS initial conditions, core decay heat, safety injection fiow, and primary and secondary metal mass and steam generator heat release modeling. Specific'ssumptions concerning each of these items are discussed below. Tables 3.5.3-1 and 3.5.3-2 present key data assumed in the analysis.
For the long-term mass and energy release calculations, operating temperatures to bound the highest average coolant temperature range were used as bounding analysis conditions. The modeled core power was 2346 MWt, adjusted for calorimetric error (+2 percent of power). 'Ihe 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 to account for instrument error and deadband is reflected in the initial RCS temperatures. The initial reactor coolant system (RCS) pressure in this analysis is based on a nominal value of 2250 psia plus an allowance 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. 'Ihe 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, 2250 psia plus uncertainty was selected for the initial pressure as the limiting case for the long-term mass and energy release calculations.
mA1808wM3c.wpf:1bj'091195 3-265
The selection of the fuel design features for the Iong-term mass and energy release calculation is based~
on the need to conservatively miocinuze the core stored energy. The margin in core stored energy was chosen to be+15 percent. Thus, the analysis very consdrvativdly accounts for the stored energy in, the core.
Margin in RCS volume of 3% (which is composed o: f 1.6% allowance, for thermal expansion and L4%
for uncertainty) is modeled.
Regarding safety injection flow, the mass and energy release calculation considered configurations/
to conservatively bound respective alignments. A spectrum of cases including: 'ailures (a) a Diesel Failure (1 HHSI, 1 LHSI, & 1 CSS Pump);
(b) a Containment Spray Pump Failure (2 HHSI, 2 LHSI, 8c 1'SS Pump); and (c) a No Failure Case (2 HHSI, 2 LHSI, Sc 2 CSS Pumps).
The following assumptions were employed to emue 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% full-power conditions)
- 2. An allowance in temperature for instrument error and dead band (+7.4'I )
- 3. Margin in RCS volume of 3% (which is composed of 1.6% allowance for thermal expanlsiok, &d.
1.4% for uncertainty)
- 4. 102% of core rated power, 2346 MWt
- 5. Allowance for calorimettic error (+2 percent of power)
- 6. Conservative coefficient of heat. transfer (ii.e., steam generator~primary/secondary heat transfer and reactor coolant system metall. heat transfer)
- 7. Allowance in core stored. energy for effect of fuel densiificatioh
- 8. A margin in core, stored energy (+15 percent included t6 akcoitnt for manufacturing tolerances)
- 9. An allowance for RC,S initial pressure uncertunty (+70 psi)
- 10. A maximum cont;unment backpressure equal to design pressure
- 11. Allowance for RCS flow uncertainty (-3.5%)
mA1808wMQc.wpf:1b/091195 3-266
- 12. Steam generator tube plugging leveling (0% uniform)
Maximizes reactor coolant volume and fluid release Maximizes heat transfer area across the SG tubes Reduces coolant loop resistance, which reduces the hp upstream of the break and increases break flow Thus, based on the previously discussed conditions and assumptions, a bounding analysis of Turkey Point Units 3 and 4 is made for the release of mass and energy from the RCS in the event of a LOCA at 2346 MWt.
3.599 Description of Analyses The evaluation model used for the long-term LOCA mass and energy release calculations was the March 1979 model described. in Reference 1. 'IMs evaluation model has been reviewed and approved generically by the NRC. It has also been utilized and approved on the plant-specific dockets for other Westinghouse PWRs such as Catawba Units 1 and 2, Beaver Valley Unit 2, McGuire Units 1 and 2, Millstone Unit 3, Sequoyah Units 1 and 2, Watts Bar Units 1 and 2, Surry Units 1 and 2, and Indian Point Unit 2.
This report section presents the long-term LOCA mass and energy releases that were generated in support of the Turkey Point Units 3 and 4 thermal uprating program. These mass and energy releases are then subsequently used'in the containment integrity analysis presented in Section 3.5.4.
3.599.1 LOCA M&E 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.
- 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.
mhl808w'ch3c.wpf:Ibf091195 3-'267
- 3. Reflood - begins when the water from the lower. plenum enters the core and ends when the core is completely quenched. iIi
- 4. Post-reflood (Fro1h) - describes the period following the refloOd transient. For the pump suction break, a two-phase nugae exits the core,, passes through the hot. legs, and is superheated in the steam generators. AIIter the broken loop steam, generator coo1ls, the break flow becomes twd-phase.
3$ 33.2 Computer Codes
'Ihe Reference 1 mass and energy release evaluation model is tA1mpriSed of xnass and energy release versions of the following codes: SAT/A VI, WI~I.OOD, and FROTH. These codes were'&d tb calculate the long-terin LOCA mass and energy releases for Turkey Point Umts 3 and 4.
SATAN calculates blowdown, the erst portion of the thermal-hydraulic tmnsient following break initiation, including pa>sure, enthalpy, density, mass 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 tra11sient where the core reflooding phase occurs after the primary coolant, system has depressurize'd (blo~Vdo'wn) due to the loss of water through l
the break and when water supplied by the Emergency Core Cooling refill the reactor vessel and provides cooling to the: core. The most-important feature is the, stcam/water mixing mode]I (see ill Section 3.5.3.5.2).
FROTH models the post-reflood portion of'he transilient. The FROTH code is used for the st&arri generator heat addition cajlculation 5 om the broken and intact loop steam generators.
3.5333 Break Size and Location Generic studies have been performed with respect. to the'ffect 'of postulated break size on the L()CA mass and energy releases. The double ended guillotine break has been found to be limiting dtte to larger mass flow rates during the blowdown phase of thb tr&iknt. During the reflood and froth
'lat phases, the break size has little effect on the releases.
'Duce distinct locations in the reactor coolant system loop can be postulated for pipe rupture for M&E release purposes:
- 1. Hot leg (between vessel and. steam generator)
- 2. Cold leg (between pump and vessel)
- 3. Pump suction (between steam generator and pump) m:u808wMh3c.wpf:Ib/091195 3-268
The break locations analyzed for this program are the double-ended pump suction (DEPS) rupture (10.48 ft'), and the double-ended (DEHL) rupture (9.19 ft'). Break mass and energy releases have been calculated for the blowdown, reflood, and'post-reflood phases of the LOCA for the DEPS cases.
For the DEHL case, the releases were calculated only for the blowdown. The following information provides a discussion on each break location.
The DEHL 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 and vents directly to containment. As a result, the reflood mass and energy releases are reduced signiflcantly 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). Therefore, only the mass and energy releases for the hot leg break blowdown phase are calculated and presented in this section of the report.
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, which 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 greatly reduced and the energy release rate into the containment is reduced. Therefore, the cold leg break is not included in the scope of this uprating.
The pump suction break combines the effects of the relatively high core flooding rate, as in the hot leg break, and the addition of the stored energy in the steam generators. As a result, the pump suction break yields the highest energy flow rates during the post-blowdown period by including all of the available energy of the Reactor Coolant System in calculating the releases to containment.
3$ 93A Application of Single-Failure Criterion An analysis of the effects of the single-failure criterion 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 DEHL break.
Three cases have been analyzed for the effects of a single failure. The first case postulated the single failure is the loss of an emergency diesel generator. This results in the loss of one train of safeguards equipment. The second case is the assumed failure of a containment spray pump. As compared to the mh1808wkb3c.wpf:tb/091195 3-269
first case, the SI flow would be greater and the time of RWST depletion would be earlier. For the third case, no failure is postulated to occur that would impact the amount of ECCS flow. The analysis
'f the cases described provides conflidence that the effect of crddiwe single failures is bounded.
369.4 Acceptance C'riteria for Analyses A large break loss-of-coolant accident is classified as an ANS Condition IV event, an infrequent fault.
The relevant requirements are, as follows.
~ 10 CFR 50, Appendi:x A.
~ 10 CFR 50, Appendi;x K., paragraph I.A In order, to meet these requirements, the, following must be addressed.'.
Sources of Energy
- 2. Break Size and Location
- 3. Calculation of Each Phase of the Accident 3.598 M&E Release Data 3$ 9$ .1 Blowdown Mass and Energy Release Data A version of the SAT/dl-VI code is used for computing the blcIwdown transient. The code utilizes the control volume (element) approach with the capability fdr n'iodt:ling a large variety of thermal flttid configurations. The fluid properties are considered uniform and thermodynamic equilibrium is 'ystem assumed in each element. A point kinetics model is used with weighted feedback effects. The niajdr feedback effects include moderator density, moderator temperanire, and Doppler broadening. A flow calculation for subcooled (modlified Zaloudek), two-phase (Moody), or, superheated break 'ritical flow is incorporated into the analysis. The methodology for the use of this model is described in Reference 1.
Table 3.5.3-3 presents the calculated mass and ene,rgy release for the blowdown phase of the DEHL For the hot leg break mass and energy release tables,l br6ak~path 1 refers to the mass and 'reak.
energy exiting from the reactor vessel side of tihe break; break path 2 refers to the mass and etierII,y from the steam generator side of'he, break 'xiting Table 3.5.3-6 presents the calculated mass 8aid energy relbasI:s ftor the blowdown phase of the DEPS break. For the pump suction bre iks, break path 1 in the mIaSs 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.
mh1808wM3< wpf:1b/091895 3-270
3.53S.2 Reflood Mass and Energy Release Data The WREFLOOD code is used for computing the reflood transient. 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, 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 1 mass and energy release evaluation model, in recent analyses, e.g., D.C. Cook docket (Reference 2). Even though the Reference 1 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 (Reference 1).
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 (Reference 3), 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.
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 1. For all of these tests, the data clearly indicates 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.
mh1808wM3c.wpf:tb/091195 3-271
Additionally, the following justification is also noted,. The post-blowclown limiting break for the containment integrity peak pressure analysis is the pump suction double-ended rupture break. For this i break, there are two flowpaths available in the RCS by which mass and energy may be reileased.to containment. One is tltrough the outlet of the steam generator, the other via reverse flow thrOugh the reactor coolant pump. Steam which is not condettsed by EPICS injection in the intact RCS loops passes around the downcomer and Qtrough the broken loop cold leg and pump is vented into 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 crit for in this analysis. L1118 assumption is justifl1ed based upon the postulated break location, andI the actual physical presence Of the ECCS injection nozzle. A description of the test and test results is containedI in References 1 and 3.
Tables 3.5.3-7 presents the calculated mass anted energy rielease for the reflood phase of the f
double-ended rupti1re wit~h a single limiting tilure of a diesel generator. Tlus failure case was pump'uction the most-limiting for the LOCA containment iintegrity atjialysis (see SectiOn 3.5.4) for tlhe post-blowdown phase. Other failure scenarios were analyzed, but since the diesel failure is the most-limiting it will be presentedl. The other scenarios thhat were considered were a spray pump failure case and a no safeguards fhilcire case.
The transients of the principa1l parameter during refiood are given in Table 3.5.3-8 for the DEPS diesel-failure case.
3S9SB Post-Refioocl Morass and Energy Relea!se Datfa The FROTH code (Reference 4) is tiised for computing the post.-ref lood trans'ient. 'I>e FROTH code calculates the heat release rates resullting from a two-pha'se inixturt! leVel present in the steam getteraitor tubes. 'Ihe mass and energy release> that ciccur during this phase are typiicaily superheated due to the depressurization and ecluiliibration of the, broken loop and intact loop stean generators. During tMs phase of the transient, the RCS has tguiilibrated with the containment pre!>sure, but the steam generators contain a secondary inventory at an enthalpy that is much higher than the primary side.
'Iherefore, there is a significaint 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 Quid exits the core, flows through the hot legs and becomes superheated as:it passtts thro11gh the steam generator. Once the broken loop cools, the break flow becomes two phase. The methodology for the use of this model i:s described in Reference 1. The mass and energy release aerates de chicul~A by FROTH until the time of containment depressurization. After contairiment depressurization (14.7 psia), the mass and eniergIy release available to contauunent is generated direc:tiy from core boiloff/decay heat.
Table 3.5.3-9 presents the two-phase post-reflood (FROTH) mass and energy release data for the DEPS diesel-failure case.
mh1808wkh3c.wpf: Ib/091195 3-272
3S9S.4 Decay Heat Model On November 2, 1978, the Nuclear Power Plant Standards Committee (NUPPSCO) of the American Nuclear Society approved ANS Standard 5.1 (Reference 5) for the determination of decay heat. This
.standard was used. in the mass and energy release model.
Significant assumptions in the generation of the decay heat curve. for use in design basis containment integrity LOCA analyses include:
- 1. Decay heat sources considered are fission product decay and heavy element decay of U-239 and Np-239.
- 2. Decay heat power Rom 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 11, of Reference 5 up to 10,000 seconds, and Table 10, of Reference 5 beyond 10,000 seconds.
- 5. The fuel has been assumed to.be at full power for 10'econds.
- 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.
Based upon NRC staff review, Safety Evaluation Report (SER) of the March 1979 evaluation-model, use of the ANS Standard-5.1, November 1979 decay heat model was approved for the calculation of mass and energy releases to the containment following a loss-of-coolant accident.
3.539.5 '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 mh1808wMh3c.wpf:1bf091195 3-273
containment pressure. Then the second stage rate is used until the, final depressurization, when the secondary reaches the reference temperature of Teat at 14.7 psia, er 212'F. The heat remount of the broken loop and intact loop steam generators, are calculated se)Ately.
II~
During the FROTH calculations, steam generator heat removal rates are calculated using the secondary side temperature, primary side temperature and a secondary side heat trarisfer coefficient determined using a modified McAdam's correlation. Steam generator kne/gy ts removed during the FROTH transient until the secondary side ternperatiire reaches saturation temperature at the contaimneht design pressure. The constant heat remtoval rate used during the first heat removal, stage iss based on the, final heat removal rate calculate by FROTH. The SG energyI akailIiblk to be released during the first sta'ge is determined by calculating the difference in secondary energy availlable at the containment~ 'nterval design pressure and that at the gower) user specified intkrmledilate equilibration pressure, assutninlg saturated conditions. '.IMs energy is then divided by the firIt s/ageI en'ergy removal rate, resulting in an intermediate equilibratiion time. At this time, the rate of energy release drops substantially to
'the'econd stage rate. The second stage, rale ica deterinined as the fraction of the difference in secondary'nergy available between the intermediate equilibration and final depressurization at 212'F, and the time difference Rom the tiime of the int:rmediate equilibration to the user specified time of the final depressurization at 212'F. With current methodology, all o: f the secondaiy energy remaining hft6r thle intermediate equilibration is conservatively assumed to be rihleased by imposing a mandatory cooldown and subsequent depres<surization down to atmospheric pressure at 3600 seconds, i.e., 14.7 psia and 212'F.
3.538.6 Sources of MAE The sources of mass considered in the I.OCA mass and energy reli.ase analysis are given in Table 3.5.3-10. These soi.irces are the reactor coolant system, accumulators, and pumped safety injection.
The energy inventories consideretd in the LtOCA mass and energy release analysis are gjven in Table 3.5.3-11. 'Ihe energy sources include:
Reactor Coolant System Water Accumulator Water Pumped Injection Water Decay Heat Core Stored Energy Reactor Coolant System Metal - Primary Metal (includi':s SG tubes)
Steam Generator Metal (includes transition cones she'll, MppI:r, and other internals)
Steam Generator Secondary Energy (includes fluid mass and steam mass)
Secondary Transfer of Energy (feedwa1er into and steam out of the steam generator secondaiy) mhl808wkh3c.wpf: Ib/091195 3'74
Energy Reference Points Available Energy: 212'F; 14.7 psia Total Energy Content: 32'F; 14.7 psia 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 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)
In the mass and energy release data presented, no Zirc-water, reaction heat was considered because the clad temperature is assumed not to rise high enough for the rate of the Zirc-water reaction heat to be of any significance.
369.6 Conclusions The consideration of the various energy sources in the long-term mass and energy release analysis provides assurance that all available sources. of energy have been included in this analysis. Thus, the acceptance criteria presented in Section 3.5.3.4 have been satisfied. Any other conclusions cannot be drawn from the generation of mass and energy releases directly since the releases are inputs to the containment integrity analyses. The containment response must be performed. See Section 3.5.4 for the. LOCA containment integrity conclusions.
In contrast to the revised long-term LOCA M&E analyses for the thermal uprate program, the original design basis short-term LOCA mass and energy releases resulting from double-ended ruptures of the primary loop piping. for the subcompartment analyses will remain bounding. This is due to the application of the Leak-Before-Break (LBB) Technology to the;short-term LOCA M&E releases (Reference 6). Under LBB, the most-limiting break would be a double-ended rupture of one of the largest RCS loop branch lines (i.e., pressurizer surge line, accumulator/SI line, or'RHR suction line).
389.7 References
- 1. "Westinghouse LOCA Mass and Energy Release Model for Containment Design - March 1979 Version", WCAP-10325-P-A, May 1983 (Proprietary), WCAP-10326-A (Non-proprietary)
7106),, for D.C. Cook Nuclear Plant Unit 1", June 9, 1989 m:u808wMh3c.wpf:1bf091195 3-275
- 3. EPRI 294-2, "Mxing of Enaergency Core Cooling %'ater with Steam;.1/3-Scale Test and Summary," (WCAP-8423), Final I(eport June 1975
- 4. "Westinghouse M(ass and Energy Relmse Data For Containment Design", WCAP-8264-P-A[
Rev. 1, August 1975 (Proprietary) WCAP-8312-A (N()n-I'.iropirietary)
'5. ANSVANS-5.1 1979, "American 1'lational Standard'for Deca)i Heat Power in Light Water Reactors", August 1979
- 6. Letter, G. E. Edison (NRC) to W. F. Conway (&PL), "NRC Generic Letter 84-04, Asymimeuic Loads for Turkey Point Units 3 and 4", dated Novlmbhr 28, $ 988.
mh1808w4%3c.wpf: Ib/091395 3-276
Table 3;59-1 System Parameters'nitial, Conditions PARAMETERS VALUE Core Thermal Power (MWt) 2346 Reactor Coolant System Total Fiowrate (ibm/sec) .. . 25,813.75 Vessel Outlet Temperature (V) 615.2 Core Inlet Temperature (F) . ....... 554.0 Vessel Average Temperature ('F) ........ 584.6 Initial Steam Generator Steam Pressure (psia) . .... 832 Steam Generator Design . Model 44F Steam Generator Tube Plugging (%) ..0 Initial Steam Generator'Secondary Side Mass (ibm) 103;501.2 Assumed Maximum Containment Backpressure (psia) ........ 69.7 Accumulator Water Volume (ft') 920 N, Cover Gas Pressure (psia)
Temperature (V) ............. 130 Safety Injection Delay (sec) ........ 35.0
'analysis value includes an additional +7.4'F allowance for instrument error and deadband) m:u 808w'eh3c.wpf:1b/091195 3-277
Table 369'-2 Safely Injection Flow Diesel F;ulure (Single. Trsiin)
INJECTION MODE (REFLOOD P'HASE)
RCS Pressure Total Flovi Q~~mQ 0 3581.0 20 3318.0 40 3028.0 60 2705.0 80 232,4.0 100 177'2.0 120 .562.0 140 557.0'51.0 160
'180- 546.0 200 540.0 300 511.0 INJECTION MODE (POST-'REFLOOD PHASE)
RES PressuiIe Total Flow sji ~~prni~
40 584.0 COLD LE(s RECIRCULATION MODE RCS Pressure Tot ii Flow
~si~ ~m~
0 2455.0 mA1808whh3c.wpf: Ib/091195 3-278
Table 3.5.3-3 Double-Ended Hot Leg Break Blowdown Mass and Energy Releases TIME BREAK PATH NO.1 FLOW* BREAK PATH NO.2 FLOW**
THOUSAND THOUSAND SECONDS LBM SEC LBM/SEC
.0000 .0 .0 .0 .0
.0502 52052.2 33058.2 27440.1 17291.7
.100 43931.8 27888.9 26452.2 16683.2
.150 35897.9 22981.1 24471.6 15407.5
.200 33326.1 21354.7 22866.7 14346.6
.251 33160.2 21218.4 21435.1 13371.4
.350 32570.3 20826.9 19771.1 12155.6
.451 31951.0 20439.4 18862.1 11414.2
.651 31684.6 20310.2 17657.4 10398 '
.801 30915.5 19905.6 17137.6 9933.6 1.00 30269.1 19678.5 16589.6 9456.4 1.10 29886.8 19540.7 16459.6 9316.9 1.30 28980.0 19164.3 16433.3 9188.6 1.50 27877.9 18666.2 16584.7 9178.9 1.70 26631.5 18065.9 16804.4 9225.9 2.00 24669.1 17049.7 17091.4 9307.7 2.50 21669.7 15305.2 17288.0 9354.7 3.00 19519.6 13836.8 17132.,6 9254.5 3.50 18277.5 12801.6 16707.8 9031.4 4.00 18070.1 12415.4 16017.6 8682.6 4.50 18724.0 12411.8 14976.4 8157.9 F 00 19164.9 12391.8 13787.'8 7561.6 5.50 19629.4 12455.8 12448.7 6872.4 6.00 15408.3 10487.2 11153.4 6194.5 6.50 15291.3 10332 ' 10052.0 5613.3 7.00 14964.2 10046.5 9145.5 5132.4 7.50 14560.5 9662.1 8373.0 4722.1 8.00 8.50 9.00 14559.9 14274.3 13796.2 9506.0 9216.9 8844.6 7684.'5 7061.7 6486.8 4031 '.
4358.0 3733.1 9.50 13107.5 8386.8 5951.6 3459.7 10 ' 12278.3 7880.0 5457.8 3212.0 10.5 11394.0 7366.6 5005.0 2989.3 11.5 9639.3 6403 ' 4216.3 2611.3 12.0 8625.7 5886.7 3817.1 2422.7 13.0 6475.6 4922.5 2860.2 2002.0 13.5 5475.6 4495.4 2455.6 1809.2 14.0 4478.2 4080.0 2185.7 1656.7 14.5 3403.7 3450.0 2013.2 1544.0 15 ' 2756.9 2981.2 1881.0 1447.5 15.5 2343.8 2615.5 1717.5 1367. 6 mal 808wM3c.wpf:1bf091 195 3-279
Table 3.!i.3-3 (cont.)
Double-Ended Hot, Leg Break Blowdown Mass and Energy',Releases TIME BREAK PATH NO.1 FLOW'* BREAK PATH NO.2 FLOW*'*
THOUSAND THOUSAND SECONDS J LBM~SEC+ ~BTU~SEC L ~LBM~SECQ QBTU/SE4+,
16.5 17i05. 4 2030. 6 1409.9 1224., 6
- 17. 0 1456.8 1771.1 1284.2 1163.,4
- 17. 5 1076.7 1329.4 924.0 1092.,3 18.0 9!93. 6 1238. ip 602.9 743.,5 19.. 0 530.3 670. 7 2,'80. 3 348.,7 19.5 402.8 514.4 1.85. 2 ~231.,7 20 ..0 298.7 382,. 6 .0 .,0 20.5 141.1 182.2 .0 .,0 21.5 .0 : ip .'0 .0 Mass 'and Energy e>citing from the reactor vessel side of the break
- Mass and Energy exiti;ng from the SjG side of the break mh1808wkh3c.wpf:1b/091195 3;280
'Table 3.59M Double-Ended Hot Leg Mass Balance Time (Seconds) 21.50 21.50 Mass (Thousand ibm)
In RCS and ACC 579.16 579.16 579.16 Added Mass Pumped Injection .00 .00 Total Added'**
Total Available *** 579.16 579.16 579.16 Distribution Reactor Coolant 403.94 50.05 93.69 Accumulator 175.22 138.53 94.90 Total Contents 579.16 188.58 188.58 Effluent Break Flow 390.56 390.56 ECCS Spill Total Effluent 390.56 390.56
- Total'Accountable *** 579.16 579.15 579.15
'e mA1808wMQc.wpf: 1bf091195 3-281
Table 3.5.3-5 Double-Ended Hot Iag Energy B:alance Time (Seconds) .,00 21.50 21.50 Energy (Million BTUI)
Initial Energy In RCS, ACC, S/G 623.,75 623.75 623.75'00 Added Energy Pumped Injection Decay Heat 4.75 4.75 Heat from ~
6.15 -6.15 Se:condaty Total Added .,00 ~
1AO -1.40
- Total Available '"** 623.75 62!2.35 622,.35 Distribution Reactor Coolant 237.49 13.09 17.43 Accumulator 17.43 13.78 9A4 Core Stored 23.36 11.01 Primajry iMetal 118.73 1].1.46 Secondary Met tl 58.66 57,22 Steam Generator 168.07 162.68 162.68 (S/G)
Total Contents 623.75 369.25 '369.25 Effluent Break flow 253.09 253.09 ECCS Spill .00 Total Effluent 253.09 '.253.09
- Total Accountable *** 623.75 622.33 622,.33 mA1808wM3c.wpf:1%81195 3-282
Tab1e 3.5.3-6 Double-Ended Pump Suction Break Blowdown Mass and Energy Releases TIME BREAK PATH N0.1 FLOW* BREAK PATH N0.2 FLOW*"
THOUSAND THOUSAND SECONDS LBM/SEC ~BTU SEC LBM SEC ~BTU SEC
.0000 .0 .0 .0 .0
~ 0501 40934.2 22404. 7 28380.4 15458. 8
.100 40700.7 22324.0 21635.0 11808 '
.201 41067.2 22685.4 23122.8 12635.5
.301 41492.3 23129.7 24162.3 13211.5
.400 41955.2 23638.6 24282.2 13283.4
.500 42113.5 23999.6 23792.6 13020.9
.601 41711.5 24037.8 23164.5 12682.8
.701 40664.3 23672.0 22675.9 12421.6
.900 38327.9 22702.5 22172.8 121S6.4 1 '0 1.30 36612.3 34733.0 22054.7 21285.3 21699.8 21198.8 11902.2 11629.2 1.40 33920.5 20944.9 20986.1 11512.9 1.80 31411.9 20017.1 20217.2 11089 '
2.00 29608.8 19271.9 19522.5 10705.4 2.50 20674.6 14138.4 17630.2 9660.9 3.00 15463.2 10687.9 15998 ' 8765.6 3.50 12005.3 8469.4 14856.0 8144 F 9 4.00 10540.3 7553.9 13742.1 7539.0 4.50 9597.1 6963.7 13632.1 7489.7 5.00 9075.7 6638.5 13489.2 7411.9 5.50 8756.9 6481.3 13343.6 7336.9 6.00 8375.5 6316.8 13102.9 7207.7 6.50 8050.8 6145.7 12836.6 7061.0 7.00 7616.5 6460.3 12539.9 6895.5 7.50 6973.8 5903.2 12126.7 6665.1 8.00 7093.6 5690.8 11756.4 6459.0 8.50 7105.0 5535.3 11390.8 6254.7 9.00 6896.8 5428 ' 11005 ' 6041.0 9
10.0
'0 6453.3 6068.8 5244.3 4998.9 10589.0 10162.7 5811.2 5576.7 11.0 5543.0 4523.6 9373.6 5144.5 12.0 4984.3 3991.5 8572.2 4706.4 13.0 4505.5 3481.2 7592.7 4159.8 13 .'5 4308.2 3286.2 7254.1 3868.3 14.0 4130.7 3143.7 7069.4 3634.3 15.5 3483.-0 2879.5 6172.5 2960.7 mh1808wM3c.wpf:1b/091195 3-283
Table 3.5.3-6 (cozen.. )
Double-Ended Pump Suction Break Blowdown Mass cind Energy Releases TIME BREAK E?ATH FLOW* BREAK PATH NO.2 FLOW**
THOUSAND THOUS MID SECONDS LB~M/SEC BTUQSEC LBM/SEC BT~U'SEC 16.0 3244 1 F 2847.0 5802.9 2742 3 16.5 2955.0 2840.7 5382.6 2521~1, 17.0 2435.4 2707.5 4617.4 2081.5 17.5 1964. / 2397.6 3983.0 1687.8 18.0 18.5 1319./
.0'O.11'640.
1!>98,. > 1975.9 2
3410.5 3020.0 1362.5 1145. 1 19.0 1093.7 1365. 0 2709.2 982'.7 19.5 870.4 1089.5 2797.1'050.1 954.2 20.0 856.5 977.2 20.5 660.8 2420 .,2 754: 5
~
21.5 233.1 294.0 724.0 215.2 22.0 100.8 1,27. 6 .0 .0 22.5 . 0. .0 .0 Mass and Energy -exi.ting from the S/C< side of the break
- Mass and Energy exi.ting from the pump side of the break mA1808wIch3c.wpf:Ibr091195 3-284
Tab1e 3.5.3-7 Double-Ended Pump Suction Break with Diesel Failure Reflood Mass and Energy Releases TIME BREAK PATH NO.1 FLOW BREAK PATH NO.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC ~BTU SEC LBM SEC ~BTU SEC 22.5 .0 .0 .0 .0 24.0 .2 .2 .0 .0 24.3 5.4 6.4 .0 .0 24.6 20.8 24.5 .0 .0 25.4 47.0 55.5 .0 .0 26.6 72.6 85.7 .0 .0 27.6 89.8 106.0 .0 .0 30.6 129.0 152.4 .0 .0 31.6 139.7 165.0 .0 .0 32.6 151.0 178.4 1160.4 214.9 33 ' 153.9 181.8 1858.3 347.7 34.6 153.5 181.3 1869.6 352.6 35.6 153.8 181.8 2212.4 381.9 37.6 152.4 180.1 2136.5 372.8 39.6 151.1 178.5 2062.6 363.8 41.6 149.9 177.1 1991.4 354.9 42.6 149.3 176.4 1956.9 350.6 44.6 148.2 175.0 1890.0 342.2 46.6 147.1 173.8 1825.9 334.1 48.6 146.1 172.6 1764.4 326.2 50.6 145.1 171.4 1705.2 318.5 52.6 144.2 170.3 1648.4 311.1 53.6 143.7 169.8 1620.7 307.5 55.. 6 142.9 168.8 1566.9 300.4
- 57. 6 142.0 167.8 1515.0 293.5 59.6 141.3 166.9 1464.7 286.7 61.6 140.5 166.0 1416.1 280.1 65.6 139.0 164.2 1323.1 267.3 69.,6 137.6 162.6 1235.2 255.0 73.6 136. 3 161.0 1151.8 243.0 77.6 135.0 159.5 1072.2 231.3 78.6 134.2 158.6 781.4 187.6 80.6 135.1 159.6 754.0 184.4 81.7 135.5 160.1 739.3 182.7 85.6 136.6 161.4 689.2 176.9 89.6 137. 2 162.1 640.6 171.3 91.6 136.0 160.7 247.5 150.2 93.6 134.0 158.3 245.2 147. 4 101.6 126.4 149.3 236.2 136 ~ 9 102.1 125.9 148.7 235.7 136. 2 mal 808wM3c.wpf:1bl091195 3-285
Tab1e 3.5.3-.7 (cont.)
Double-Ended Pumjp Suction Break wit4 Diesel Failure Reflood Mass and Energy Release.<<
TIME BREAK PATH NO.:L FLOW BIREAK PATH N0.2 FLOW THOUSAND.I~IJ THOUSAND SECONDS LBMjSEC 'SEC LBM~SEC BTU~SEC 109.6 119.6 141.3 2:28. 2 127. 5 115.6 115.2 :L36. 1 2:23. 0 121.3 123.6 110.0 :L29. 9 2,16 9
~ 114.1 125.6 108.9 :L28. 6 2:15. 5 112.5 133.6 104.7 :L23 .'6 2:10. 5 106.'5 141.6 101.2 :L19; 5 206.3 101.5 163.6 94.6 :L11. 7 198.2 92 .'0 189.6 91.0 LO I 193.5 86.5 201.6 90.4 :L06. 7 192.5 85.2 210.8 90.5 :L06. 8 1'94. 6 85.7 m:u 808wM3c.wpf: Ib/091195 3-286
OO TABLE 3.5.3-8 DOUBLE-ENDED PUMP SUCTION BREAK WITH DIESEL FAILURE PRINCIPLE PARAMETERS DURING REFLOOD TIME FLOODING CARRYOVER CORE DOWNCOMER FLOW INJECTION TEMP RATE FRACTION HEIGHT HEIGHT FRACTION TOTAL ACCUMULATORSPILL ENTHALPY SECONDS DEGREE F IN/SEC FT FT (POUNDS MASS PER SECOND) BTU/LDM 22.5 156.0 .000 .000 .00 .333 .0 .0 .0 .00 155.5 16.138 .000 .52 .73 2895.7 2895.7 .0 99.50 155.2 8.217 1.08 .73 2857.6 2857.6 .0 99.50 155.4 2.602 .035 1.31 .197 2827.9 2827.9 .0 99.50 155.6 3.115 .073 1.29 1.82 .303 2806.0 2S06.0 99.50 156.3 2.309 .285 1.50 3.98 .396 2713.2 2713.2 99.50 26.6 156.8 2.227 380 1.61 5.51 .409 2656.7 2656.7 .0 99.50 30.7 159.7 2.497 588 12.64 .427 2412.1 2412.1 .0 99.50 32.6 161.4 2.650 .629 2.16 15.36 .432 2306.1 2306.1 .0 99.50 35.6 164.1 2.545 .659 2.39 15.57 .437 2547.8 2163.7 .0 95.51 37.2 165.5 2.494 .668 2.51 15.57 .437 2476.8 2092.7 .0 95.40 45.0 172.8 2.351 .690 3.01 15.57 .435 2174.7 1790.5 94.82 53.5 181.0 2.264 .699 3.50 15.57 .433 1905.0 1520.7 .0 94.16 62.5 189.8 2.197 15.57 .432 1663.7 1279.4 .0 93.38 72.6 199.6 2.136 .708 4.54 15.57 .431 1429.2 1044.8 .0 92.38 78.6 205.4 2.100 .709 4.85 15.57 .430 1023.3 638.8 .0 89.55 80.6 207A 2.101 .710 4.95 15.57 .432 996.4 612.0 .0 89.29 81.7 2085 2.101 .711 15.57 .433 981.9 597.6 .0 89.14 89.6 215.8 .714 5.40 15.57 .438 883.1 499.1 .0 87.99 91.6 2I75 2.079 .714 5.50 15.43 .437 384.2 .0 .0 73.03
TABLE 3.5.3-8 (cont.)
DOUBLE-ENDED PUMP SUCTION BREAK WITH DIESEL FAILURE PRINCIPLE PARAMETERS DURING REFLOOD TIME FLOODING CARRYOVER CORE DOWNCOMER INJECTION TEMP RATE FRACTION HEIGHT Fl'LOW HEIGHT FRACTION TOTAL ACCUMULATORSPILL ENTHALPY SECONDS DEGREE F IN/SEC FT (POUNDS MASS PER SECOND) BTU/LBM 93.6 219.2 2.050 .714 5.60 15.27 .436 384.2 .0 .0 73.03 102.1 225.9 1.934 .714 14.66 .435 384.3 .0 .0 73.03 113.6 233.8 1.801 .713 6.52 14.08 .433 384.3 .0 .0 73.03 125.3 240.7 1.691 .713 13.73 .431 384.4 .0 .0 73.03 139.6 247.9 1.587 .713 7.56 13.56 .430 384.4 Pr .0 73.03 151A 253.1 1.522 .714 13.58 .429 384.4 .0 .0 73.03 165.6 258.6 1.466 .715 8.50 13.74 .428 384.4 .0 .0 73.03 180.2 263.6 1.427 .718 9.00 14.03 .428 384.5 .0 .0 73.03 195.6 268.4 1.400 .721 9.51 14.41 .428 384.5 .0 .0 73.03 210.8 2725 1.388 10.00 14.83 .429 384.5 .0 .0 73.03
~ a ~ g
~
Table 3.5.3-9 Double-Ended Pump Suction Break with Diesel Failure Post-Reflood Mass and Energy Releases TIME BREAK PATH NO.1 FLOW BREAK PATH N0.2 FLOW THOUSAND THOUSAND SECONDS LBM/SEC BTU/SEC ~LBM SEC BTU/SEC 210.9 100.7 127. 5 283. 9 95.7 225.9 99.9 126. 5 284. 7 95.4 230.9 100.6 127.4 283. 9 95.0 260.9 98.9 125. 3 285.6 94.4 265.9 99.6 126. 2 284.9 94.0 290.9 98.2 124.4 286.3 93.5 295,. 9 98.9 125.3 285.6 93.2 325.9 97.2 123.2 287.3 92.5 330.9 97. 9 124.0 286.6 92.2 355.9 96.5 122.2 288.0 91.7 360. 9 97. 1 123.0 287. 4 91.3 385. 9 95.7 121.2 288.8 90.8 390.9 96.3 122.0 288.2 90.4 420.9 95.0 120.3 289.6 91.9 425.9 95.7 121.2 288.8 91 '
455.9 94.5 119.6 290.1 90.7 460.9 95.2 120.5 289.4 90.3 490.9 93.9 118 ' 290.6 89.4 495.9 94.6 119.8 289.9 89.0 525.9 93.3 118.2 291.2 88.2 530.9 94.0 119.0 290.6 87.8 555.9 92.9 117.6 291.7 89.1 560.9 93.5 118.4 291.0 88.7 585.9 92.3 117.0 292.2 87.9 590.9 93. 0 117.7 291.6 87.5 615.9 91.9 116.4 292.6 86.7 645.9 92.3 116.9 292.2 87.2 670.9 91.2 115.5 293.3 86.3 695.9 91.7 116.1 292.9 86 '
715.9 90.7 114.9 293.8 86.0 740.9 91.0 115.3 293.5 86.5 810.9 89.5 113.3 295.1 84.5 825.9 90.0 114.0 294.5 85.1 850.9 89.2 112.9 295.3 83 '
865.9 89.5 113.4 295.0 84.2 915.9 88.4 112.0 296.1 83.8 925.9 88.8 112.5 295.7 82.9 1055.9 87.1 110.3 297.5 81.8 1060.9 51.0 64.6 333.6 92.2 1172.8 51.0 64.6 333.6 92.2 1172.9 59.5 72.7 325.0 89.0
'e mh1808wM3c.wpf:1b/091 195 3-289
Ta',ble .'3. 5. 3-9 (cont. )
Doub:Le-Ended Pump Suction Break with Diesel Failure Post-Ref lood Mass and Energ p Releases TIME BREAK PATH NO.1 FLOW BRCAK PATH NO.2 FLOW THOUSAND THOUSAI'K)
SECONDS LBM~S]'C B'I~U SEC ICBM~SEC B'i~iJ ~ SEC 1289.1 59.5 74.2 325.0 88,. 8 1289.2 57.5 66.2 327. 29,.3 1680.0 54.0 62.2 0'30.5
- 30,. 0 1680.1 54.0 62;2 26.5 7,.8 3600.0 45.2 52. 0 35;4 9,.4 3600'.1 32.0 36.8 48'. 6 3,.6 3780.0 31.3 36.0 52.4 3,.8 3780.1 34.3 39.5 49l. 4 8..3 10000.,0 23.2 26.7 60.5 :LO., 1 64800.0 14.1 16.2 69~. 6 :L1., 6;.
64800.1 15.5 17.8 68.2 :L1., 5-100000.0 13. 6 15.7 70.. 1 :L1., 8 1000000.0 5. 8. 6.7 77'. 9 :L3., 1 m%1 808wM3c.wpf:1b/091195 :3-290
TABLE 3.53-10 DOUBLE-ENDED PUMP SUCTION BREAK WITH DIESEL FAILURE MASS BALANCE TIME SECONDS .00 22.50 22.50 210.83 1172.93 1289.05 3600.00 MASS (THOUSAND LBM)
IN RCS AND ACC 579.16 579.16 579.16 579.16 579. 16 579. 16 579.16 ADDED MASS PUMPED .00 .00 .00 67.57 437.50 482.15 1370.77 INJECTION TOTAL ADDED .00 .00 .00 67.57 437.50 482.15 1370.77
- ~ TOTAL AVAILABLE*~* 579.16 579. 16 579.16 646.73 1016.66 1061.31 1949.93 DISTRIBUTION REACTOR 403.94 26.46 70.06 111.82 111.82 111.82 111.82 COOLANT ACCUMULATOR 175.22 145.27 101.66 .00 .00 .00 .00 TOTAL CONTENTS 579.16 171.73 171.73 111.82 111.82 111.82 111.82 BREAK FLOW .00 407.43 407.43 534.90 904.83 949.48 1838.10 ECCS SPILL .00 .00 .00 .00 .00 .00 TOTAL EFFLUENT .00 407.43 407.43 534.90 904.83 949.48 1838.10
- TOTAL ACCOUNTABLE *~* 579. 16 579.15 579.15 646.72 1016.65 1061.30 1949.92
00 o
00 TABLE 3.5.3-11 DOUBLE-ENDED PUMP SUCTION BREAK WITH DIESEL FAILURE ENERGY BALANCE TIME SECONDS .00 22.50 22.50 210.83 1172.93 1289.05 3600.00 ENERGY (MILLIONBTU)
TMTTIAI.PMPRGY INDIe C AII" J\veet ~ Jvvt eJC VJ/7 11 41A J J l )A eT1 VJJt JJ
<1A 11 VCet, CC cnA nn VIPt,CC cnl VCet,CC nn CnA ne1 VCJT,CC GEN ADDED ENERGY Pl JMPED nn nn nn A 02 21 OC J Je/J 2C 11 J l Tnn lVVe Tn lV INJECTION DECAY HEAT .00 4e60 19e55 72 63 78 A9 ~ VV zn I<II V HP. AT FROM AA 5 17 C Tet J I 212 J CJ 2 nn J CC n nn DeCC SECONDARY TOTAL ADDED e00 -e57 -57 1n1
~ VJ VH 2C 11A A7 JJvve JTeCC eTTT J VJeCV TOTAT. AVAIIARI P +++ /'M 77 f')2 VJee fA W 4'l2 VCJ C<W VtJ Jt eCA2 CA etnC @et I CJ.J I noJ ID't nn e Je CV 889.5v e ~1 T1TCTDTTTT T/JV JAITJTJTTTATet llVT1 ntt l stetT Vn, MAL'lv An non Jn CD 1.47 I Ie48 Ie14 29.50 29.50 29.50 29.50 COOLANT 1 TT AT TT h 'FAD IvvnlvteJJ n JdJ I J via lt tJ 1'T A2 l't TA AC tJ ~ Tn TVe TC nn VV ~ VV .00 nnnn Je~ntetJ VnT i) TVKGTJ 23.83 14. 14 14.14 4.U3 3.87 3.82 2.68 PRiMARY MET'AL 118.73 112.88 112.88 97.99 58.99 56.38 40.49 SECONDARY 58.66 58.24 58.24 54.45 32.97 31.04 22.54 METAL STEAM 168.07 166.30 166.30 153.12 89.28 84.17 61.01 nnzn.n VCTVT TVT. TVK l ~nn TOTAL CON i I N i S 624.22 373.15 373.15 339.08 214.61 204.90 156.21 BREAK FLOW 250.03 250.03 303.87 510.38 514.54 721.54 ECCS SPILL .00 00 00 00 .00 00 TOTAL EFFLUENT .00 250.03 250.03 303.87 510.38 514.54 721.54
- 0~ TOTAL ACCOUNTABLE *~~ 624.22 623.18 623. 18 642e95 724 98 719 e44 877 75
3S.4 Containment Response 3.5.4.1 Identification of Causes and Accident Description The Turkey Point containment system is designed such that for all high-energy line break sizes, up to and including the double-ended severance of a reactor coolant pipe or secondary system pipe, the containment peak pressure should remain below the design pressure with adequate margin. This section details the containment response subsequent to a hypothetical main steamline break (MSLB)
(Section 3.5.1) or a loss-of-coolant accident (LOCA) (Section 3.5.3).
The containment response analysis demonstrates the acceptability of the containment safeguards systems to mitigate the consequences of a high-energy line break inside containment. The impact of MSLB or LOCA mass and energy releases on the containment pressure is, addressed to assure that the containment pressure remains below its design pressure at the uprated 2300 MWt core power conditions.
In addition to the containment peak pressure and temperature response, the thermal performance of the CCW System is also analyzed for a postulated RCS primary or secondary side rupture.
t 3.5.42 Input Parameters and Assumptions An analysis of containment response to the rupture of the RCS or main steamline must start with knowledge of the initial conditions in the containment. The pressure, temperature, and humidity of the containment atmosphere prior to the postulated accident are specified in the analysis.
Also, values for the initial temperature of the component cooling water (CCW) and temperature of the intake cooling water (ICW) and refueling water storage, tank (RWST) solution are assumed, along with the initial water inventory of the RWST. All of 'these values are chosen conservatively for maximizing containment pressure, as shown in Table 3.5.4-1.
The following are the major assumptions made in the analysis.
(a) The mass and energy released to the containment are described in Sections 3.5.1 for MSLB and 3;5.3 for LOCA.
(b) Homogeneous mixing is assumed. The steam-air mixture and the water phases each have uniform properties. More specifically, thermal equilibrium between the air and the steam is assumed. However, this does not imply thermal equilibrium between the steam-air mixture and the water phase.
(c) Air is taken as an ideal gas, while compressed water and steam tables are employed for water and steam thermodynamic properties.
mh1808w1ch3c.wpf:1b/091195 3-293
(d) For the steamiine break analysis,and the blowdown pbrtibn of the I.OCA analysis, tlhe discharge flow separate:s into steam and water phases at the breakpoint. The sauirated water phase is at the total containment pressure, while the steam phase is at the partial pressure of the steam in the containment. For the post-blowdowii portion of the LOCA analysis, steam and water releases are Iinput separately.
3.5.42.1 Passive Heat Removal The significant heat removal source during the early portion of the transient is the containment structural heat sinks. Provision i:s made in the containment pre~>sure transient analysis for heat transfer through, and heat storage iin, both interior and exterior walls. For each node, a cxinservation of energy equation, expressed in finite-cllifference form, accounts for transient conduction into and out of the node and temperature rise of the nocle. Table 3.5.4-2 is the 'summitry Of the containment structural heat sinks used in the analysis. The thermal properties of each heat sink material are shown in Table 3.5.4-3.
The heat transfer coeffjicient to the containment structure's calculated based primarily on the work of Tagami (Reference 1). From this work, it was deternuned that the value of tlhe heat, transfer coefficient increases parabolically to a peak value. The value then decreases exponentially to a stagnant heat transfer coefficient whIich is a, function of steam-to-air-weight ratio.,
Tagami presents a plot of the maximum vajlue of heat transfer coefficient, h, as a, function of "coolant energy transfer speed," defineid as follows:
total coolant ener~ tmnsferre<d into containment (containment volume) (ti~me interval to peak pressure)
From this, the maximum h of steel is calcu1lateid:
ll = 75 (3.5.4-1) t V where:
h = rnaximtun value of h (BI~r ft'-'F).
time, from start-of-accident to end-Of-blotdohvn for LOCA. and steam Rie isolation for secondary breaks (sec).
c;ontainment free volume: (ft').
c',oolant energy discharge (Btu).
m:u808w~< wpf:iw091195 3-294
The parabolic increase to the. peak value is given, by:
..5 (3.5.4-2)
P where:
h, = heat transfer coefficient for steel (Btu/hr-ft-'F).
,time from start-of-accident (sec).
For concrete, the heat transfer coefficient is taken as 40 percent of the value calculated for steel.
The exponential decrease of the heat transfer coefficient is given by:
h, =h, +(h h,)e """ t>t (3.5A-3) where h = 2 + 50X, 0 < X< 1.4.
h, = h for stagnant conditions (Btu/hr-ft'-'F).
X = steam-to-air weight ratio in containment.
For a large break, the engineered safety features are quickly-brought into operation. Because of the brief period, of time required to depressurize the reactor coolant system or the main steam system, the containment safeguards are not a major. influence on the blowdown peak pressure; however, they reduce the containment pressure-after the blowdown and maintain a low long-term pressure. Also, although the containment structure is not a very effective heat sink during the initial reactor coolant system blowdown, it still contributes significantly as a form of heat removal throughout the rest of the transient.
3S.42.2 Active Heat Removal During. the injection phase of post-accident operation, the emergency core cooling systems deliver water from the refueling water storage tank and accumulators into the reactor vessel. Since, this water enters the vessel at refueling water storage tank and accumulators ambient temperatures, which is. less than the temperature of the water in the vessel, it, can absorb:heat from. the core. until saturation temperature is. reached. During the recirculation phase of operation, water is taken from the mA1808w1ch3c.wpf:ib/091195 3-295
containment sump and cooled in the residual heat removal heat exchanger. The cooled water is then pumped back to the reactor vessel to absorb more decay h~ 'llie heat is removed from the residttal exchanger by the CCW System. The RHR System an'd CCW System performance parameters are 'eat explained in Section 5.5:.l.
Another containment heat removal system is the containment spray. Containment spray is used for rapid pressure reduction and for containment iodjine removal. During the injection phase of operation, the containment spray pumps also ciraw water from the RWS7 anld spray it into the containment through nozzles mounted high above the operating deck. As the spray droplets fall, they absorb heat the containment atmosphere. Since the water con1es from the RWST, the entire heat chpakity of 'rom the spray from the RWST temperaeure to the temperatui.e of tive containment atmosphere is available for energy absorption. During the recircu]ation phase of post-accident operation, water can be drawn from the residual heat. removal heat exchanger outlet and sprayed into the containment ati11oSphere via the containment spray system. The spray flow rate modeled is shown in Table 3.5.4-4.
When a spray droplet enters the hot, saturated, steam-air cdntainment environment fo11lowing~ a IOss>of-~
coolant accident, the vapor pressure. of the water at its surface is much less than the partial pressure of the steam in the atmosphere. Hence, there, will be diffusion of steam to the drop surface andI condensation on the drop'let. Thus mass flow will carry'energy to'the droplet. Simultaneously, the difference between the atmosphere and 1he droplet will cause the droplet temperature alid 'emperature vapor pressure to rise. Tlbe vapor pressure of the droplet will eventually become equal to th0 palrtia1 pressure of the steam, and the condensation will rwase. The temperature of the droplet will esse~ntially ~
equal the temperature of the steam-air mixtur'e.
The equations describIing the temperature rise of a falling droplet are as follows.
d (Mu) =mh +q (3.5.44) dt d
(M) =m (3.5.4-5) dt where q = h,A * (T, T),
m = k,A *(P,,:P).
The coefficients of heat timsfer (Qi and mass transfer (k,) Iare calkulhted from the Nusselt number f'or heat transfer, Nu and the Nussejit number .for mass trankferl Nu'.
Both Nu and Nu'ay be calculatedI from the equations of franz aIad Marsha]1 (Reference 2).
mal 808wM3c.wpf:1b/091195 3-25i6
'Nu = 2 + 0.6 Nu' 2+ 0.6
~Re ~~'~
~e'Sc
'3.5A-6) (3.5.4-7)
Thus, Equations.3.5.4-4 and'3.5A-5 can be integrated numerically to find the internal energy and mass of the droplet. as a function of time as it falls through the atmosphere. Analysis shows that the temperature of the (mass) mean droplet:produced by the spray nozzles rises to a value within 99 percent of the bulk containment ambient temperature in less than 2 seconds.
Droplets, of this size will reach equilibrium temperature with the steam-airlcontainment atmosphere after falling through less than half the available spray fall height.
Detailed calculations of the heatup of spray droplets in post-accident containment atmospheres by Parsly (Reference 3) show that droplets of all sizes encountered in the containment spray reach equilibrium in a fraction of their residence time in a typical pressurized water reactor containment.
These results confirm the assumption that the containment spray will be 100 percent effective in removing heat from the atmosphere. Nomenclature used in this section is as follows.
Nomenclature A = area h, = coefficient of heat transfer k, = coefficient of mass transfer h, = steam enthalpy M = droplet mass m = diffusion rate Nu = Nusselt number for heat transfer Nu' Nusselt number for mass transfer P, = steam partial pressure P= droplet vapor pressure Pr = Prandtl number q = heat. flow rate Re = Reynolds number Sc = Schmidt number T = droplet temperature T, = steam temperature t = time u = internal energy The emergency containment coolers (ECCs) are a final means of heat removal. The ECCs consist of the fan and the banks of cooling coils. The fans draw the dense post-accident atmosphere through mfu808w1ch3c.wpf:ib/092595 3-297
banks of finned cooling coils and niix the cooled stear6hir miXtuh: with the rest of the containment atmosphere. The coils are kept at a low temperature by a rmnstant flow of component cooling eater (CCW). Since this system does not use water from the RWST, the mode of operation remains the both before and after the spray system and emergent. cfire Coolie system change to the 'ame mode. However, CCW is also abased to cool the RHR heat cxclianger(s) during 'ecirculation recirculation. This. will adversely affect EICC performance dud to increaSed CCW temperatures and lower CCW flowrates to the ECCs. See Tablle 3.5A-5 for ECC heat removal capability for the design basis containment integrity analyses. The ECC heat remov'al rateS uSed for the CCW thermal performance analyses are explained in Section 5.5.2.
With these assumptions, the heat removal capability, of the passive and active containment heat removal systems are sufficient to absorb the energy releases and still keep the maximum calculated below the design pressure for the LOCA and MSI..B Cantonment integrity transients. The 'ressure assumptions made for the, CCW thermal performance analyses are more than adequate to demonstrate the heat removal capability of the CCW System.
3.5.49 Description of A,nalysis Calculation of containment pressure, and tkmperanue, as well as the CCW System response is accomplished by use of the computer code: COCO (Reft.recce 4). For analytical rigor and convenience, the cont unment air-steam-wate'r mixture is separated into a'water phase and a stezln-air phase. Sufncient relationships to describe the. transient are provided by the equations of conservation of mass and energy as applied to each system, together 'with the appropriate boundary conditions.
3.5A9.1 MSLB Containment Intiegriity The MSLB mass and ienergy releases that were performed for the 1.4 ft 'DER at Hot Taro Power (HZP) as discussed in Section 35.1 were used to analyze the containinent response. The failure of a MSCV was the limiting singlIe failure f'r MSLB containment integrity. Since the failure was postulated to occur in the secondary stcam system safe/ etIIuipmeht, all of the containment heat removal equipment was assumed to be operatiional. This case was analyzed to the time of dryout. The sequence of events for this case is shoe/n iri Table 3.5A-6.
st&am'enerator 3.5.49.2 LOCA Containment Intiegriity A series of cases was performed for the LOCA clout unment integrity. Section 3.5.3 documented th6 M&E releases for the most-limiting single failure of a diesel generator. for a DEPS break and'h6 releases from the blowdown of a DEHI break. Each of'hese cases was performed at an initial pressure of +0.3 psig and +3.0 psig. These two pressures represent the nominal 'asstimi!d 'ontainment maximum operating pressures in the ciont'unment. 'nd mA1808w'>>ch3c.wi>>f:ih/091195 3-298-
Two additional DEPS cases with a diesel failure were performed. These cases were performed with only 1 ECC actuating from the auto-start signal, a second ECC manually actuated at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after accident initiation, and continuous operation of the recirculation sprays upon actuation during the cold leg recirculation switchover sequence. This differs from the other DEPS cases such that each of those cases assumed that the recirculation sprays would be terminated no later than 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> after accident initiation.
'Ilie COCO calculations for all of the base DEPS cases were performed for 1 million seconds (approximately 11.6 days) and the additional cases were performed for greater than 31 days. The DEHL cases were terminated soon after the end of the blowdown. The sequence of events for each of these cases is shown in Tables 3.5.4-7 through 3.5.4-9.
3S.439 CCW Thermal Performance A series of cases were performed that maximized the heat input to the CCW System and/or minimized the heat removed from the CCW System. This is a different approach than the containment integrity cases which minimize the heat input to the CCW System in order to maximize the containment pressure and temperature conditions. The intent of this portion of the analysis was to determine the impact of the thermal uprating on the inlet and outlet temperatures from the following components:
~ CCW Heat Exchangers (CCW as well as ICW)
~ ECCs (Emergency Containment Coolers)
~ RHR Heat Exchangers (RHR as well as CCW)
As part of this analysis, the CCW, ICW and RHR flowrates and heat exchanger overall heat transfer coefficients based on fouling were modified throughout the series of runs to maximize the temperatures at the entrance or exit of a particular component. The ECC heat removal rates were also modified based on higher than ECC design CCW flowrates which maximized the heat input to the CCW System. For a description of the CCW, ICW and RHR input assumptions, see Section 5.5.2.
The series of CCW thermal performance cases was based on the same failure scenarios for the MSLB and LOCA mass and energy releases from Sections 3.5.1 and 3.5.3. The mass and:energy releases for the MSLB cases were based on the MSCV failure. Mass and energy releases from the diesel failure, the spray pump failure and the "no failure" were used for the LOCA cases. As previously noted, the "no-failure" LOCA releases were based upon all of the ECCS pumps operating. Therefore, these releases could be used for cases that modeled a failure of an ICW pump (an ICW pump failure has no impact on the calculation of M&E releases).
The COCO models for the containment heat sinks and the containment spray system remained the same as for the containment integrity analyses. The performance of the ECCs was maximized with modified conservative assumptions (see Section 5.5.2) so that the ECCs would transfer a maximum amount of energy into the CCW System.
mh1808wkh3c.wpf:ib/091195 3-299
Since the mass and energy releases are calculatecl to maximize that: containment pressure and temperature conditions for the design basis containment integrity analyses, these same releases provide a conservative steam temlperature profile for use with th'e modified ECC performance. This combination of energy in1put to 1he contairunent and energy removal via the ECCs provided a maximum of energy timber into the CCW System.
The amount of energy transferred out of the CCW System hvasl minimized by conservative aSsumpti'onS for the amount of CCW heat exchanger fouling and the ICW System flow rates (see Section ~5.5i2). ~
The temperature of most interest was the peak CCW tempetntttre at the outlet of the CCW heat exchanger (referred to as CCW sup1ply tempeintmre). Although, the entrance and exit ronditions of the other CCW System and MiR System component.l, and the ECCs were also determined. For cases with 2 ECCs operating, the CCW supply temperature peaked within 10 minutes after switchovei'o leg recirculation. All cases resulted in CCW supply temperatures that were within ar~ptable 'old Section 5.5.2 of tliis report rmntains the overall tundlusiont of this analysis for all components 'imits.
considered.
3$ .4.4 Acceptance Criteria The containment response: for design-basis containment integrity is based on an ANS Condition IV event, an infrequent fault. The acceptance criteria for tlie con&nrtient response are:
the peale calculated contlunment press1ue,should not exceed the containment ddaigti pressure of 55 psi,g; the calculated pressure at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> should be 50% of the peak calculated value. ('Ihi:s is related to the criteria for doses at 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.)
3.5.4$ Results The results of the transient analysis of the containment at an initial pressure of +0.3 psig for the LOCA cases are shown in Figures 3.5.4-1 through 3.5A-6. Figures 3.5.4-1 and 3.5A-2 show. the response to the DEPS case with 2 ECCs assumed to be operatuag initially. J>e containment tes+nSe to the DEHL blowdown is presented in Figures 35.4-3 ~d'3.5'.44. The results of the long term DEPS transient with only 1 ECC operating initially and a secoiid E.CC manually actuated at 24 hoM are presented in Figures 3.5.4-5 and Figure, 3.5.4-6. The containment pressure tiansient for the 1.4 ft~
DER MSLB at 0% power with a MSCV faulure is showii in Figurd 3.5A-7. All of these uses show that the containment pressure will remain below design pressure of 55 psig. In addition, ail of the cases performed at the matxinium inlitial containment prese of +3.0 psig were also below the design pressure. After the peak pressure is attained the operation 6f the )afeguards system reduced the pressure. For the LOCA, at 24 houri following the alA:ident, the containment pressure 'ontainment mh1808wkh3c.wpf:1b/091195 3-300
has been reduced to a value well below 50 percent of the peak calculated value. 'Ihe containment integrity results are shown in Table 3.5.4-10 for LOCA and the MSLB ruptures.
The CCW thermal analysis considered several failure scenarios. Cases that modeled a single failure of a diesel generator, a containment spray pump, and an ICW pump were considered. In addition, several non-diesel scenarios were performed where all 3 ECCs would be actuated and/or RHR pumps were assumed to be in a runout condition. In this configuration, the CCW supply temperature was predicted to exceed the acceptable system temperatures. This prompted the need to limit the number of ECCs that would auto-start to two and the flow from the RHR pumps in the "piggy-back" mode. The results of these modifications are acceptable. When the same logic is used to limit the number of ECCs that auto-start.to-two.for-the-MSLB transients, then the COCO-predicted CCWS temperatures show that large break LOCAs are more limiting than MSLB transients.
3.5.4.6 Conclusions The containment integrity analyses have been performed for the thermal uprate program at Turkey Point Units 3 and 4. The analyses included both long-term MSLB and LOCA transients. As described in the results Section 3.5.4.5, all cases resulted in a peak containment pressure that was less than 55 psig. In addition, all long-term cases were well below 50% of the peak value within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Based on these results, all applicable acceptance criteria from Section 3.5.4.4 have been met and Turkey Point Units 3 and 4 are safe to operate at 2300 MWt (core).
The CCW thermal performance analyses have also been performed for the thermal uprate program.
This analysis also considered the LOCA and MSLB transients. As described in Section 3.5.4.5 and Section 5.5.2, all cases resulted in entrance and exit temperatures that were less than the design values.
Based on these results for the CCW System analysis, all applicable criteria for the components have been met and Turkey Point Units 3 and 4 are safe to operate at 2300 MWt (core).
3S.4.7 References
- 1. Takashi Tagami, "Interim Report on Safety Assessments and Facilities Establishment Project in Japan for Period Ending June 1965", No. 1
- 2. Ranz, E. W. and Marshall, W. R. Jr., "Evaporation for Drops", Chemical Engineering Progress, 48, pp. 141-146, March 1952
- 3. Parsly, L. F., "Spray Tests at the Nuclear Safety Pilot Plant", Nuclear Safety Program Annual Progress Report for Period Ending December 31, 1970, ORNL-4647, 1971, p. 82
- 4. "Containment Pressure Analysis Code (COCO)", WCAP-8327 (Proprietary), WCAP-8326 (Non-Proprietary), June 1974 mhl808wkh3c.wpf:1b/091195 3-301
Table 3'-1 Cont:uninent Analysis Paralrneters ICW temperature ('F)[Containment Integrity] 100 ICW temperature ('F)[CCW 'Ihermal Performance] 95 Refueling water temperatrue ('F) 105 RWST minimum water deliverable volume (gal) 2.399 x 10 Initial containment temperzhare ('F) 130 Initial containment pressure (psia) 1,5.0 Initial relative humidity (%%uo) 20 Net free volume (ft') 1.55 x 10 Eme~ren~c Containment Cooleirs Total 3 Analysis maximum 2 Analysis minimum 1 Setpoint (psig) 6.0 Delay time (sec)
Without Offsite Power so.o ilk With Offsite Power 35 Con1ainment Spra'~Pu~mss Total 2 Analysis maximum 2 Analysis minimum 1 Setpoint (psig) 25.0 Delay time (sec)
Without Offsite Power 60.0 With Offsite Power 45.0 mA1808wMQc.wpHb/092595 3-302
Table '3.5.4-2 Containment Heat, Sink Data Wall Heat Transfer
~Deacri rica' ~Area fir" Material Thickness ft 360.9 Paint 0.000833 Carbon Steel '0.617473 2725.6 Paint 0.000833 Carbon Steel 0.232245 6368.1 Paint 0.000833 Carbon Steel 0.109355 5426.0 Paint 0.000833 Carbon Steel 0.066368 17366.0 Paint 0.000833 Carbon Steel 0.038986 137461.3 Paint 0.000833 Carbon Steel 0.021498 84988.4 Paint 0.000833 Carbon Steel 0.011212 105344.0 Paint 0.000833 Carbon Steel 0.005121 89906.9 Paint 0.000833 Carbon Steel 0.001918 10 1378.0 Stainless Steel 0.08398 2335.8 Stainless Steel 0.043972 12 2684.9 Stainless Steel 0.015155 13 27329.0 Stainless 'Steel 0.002537 14 1207.0 Stainless Steel 0.0091 15 2150.0 Aluminum 0.020833 mA1808wkh3c.wpf:1b/091 195 3-303
Table 3.5.4-2 (cont.)
Containment Heat Sink Xlata Wall Heat Transfer
~Descri tion Are a~ft~ Material Thiclgi~es Q}
16 106200.1 Aluminum 0.000603 17 50132.0 )Paint 0.00325 Concrete 1.5 18 67246,.0 jPaint 0.600833 Carbon Steel Liner 6.020833 Concrete 1.5 19 775.0 Stainless Steel Liner 0.01 Concrete 1.5 20 5825.0 Stainless Steel Liner 0.005417 Concrete
'.5 mh1808wM3c.wpf: I M81195 3-304
Table 3;5.4-3 Thermal, Properties: of Containment. Heat Sinks Thermal Volumetric Conductivity Heat Capacity Material
~Btu/6'-'aint 0.138 11.105 Carbon Steel 28.88 54.66 Stainless Steel 14.48 57.37 Aluminum 91.25 38.59 Concrete 1.048 26.27 mh1808wkh3c.wpf: It/09 1195 3-305
Table 3.5.4-4
(".ontainment',Spray Pump Flow Containment 1 Pump 2 Pumps Pr'essure si +i~m} ~~m}
0.0 1548.0 3009.0 10.0 1509.0 2947.0 20:0 1469.0 28'70.0 30.0 1429.0 2789.0 40.0 1386.0 2704.0 50.0 1340.0 2611.0 mal 808wM3c.wpf:1b/091195 3-306
Table 3.5.4-S Emergency Containment Cooler Performance Containment Integrity Analyses (Btu/sec/ECC)
(Based on 2000 gpm CCW Flow/ECC and 25,000 CFM Steam-Air Flour)
Containment Temperature ('F)
CCW Temp. 120. 140. 160. 180. 200. 220. 240. 260. 280.
('F)
- 95. 319.7 898. 1726. 2852. 4504. 6652. 9599. 13505. 18320.
110. 222.4 806. 1635. 2780. 6550. 9485. 13294. 18164.
120. 0.0 589. 1421. 2585. 4181. 6311. 9168. 12921. 17900.
130. 0.0 325. 1162. 2302. 3917. 6030. 8860. 12577. 17253.
135. 0.0 170. 1012. 2171. 3767. 5871. 8704. 12368. 17036.
140. 0.0 0.0 848. 2016. 3603. 5702. 8518. 12196. 16797.
145. 0.0 0.0 664. 1840. 3422. 5516. 8251. 11865. 16541.
150. 0.0 0.0 464. 1649. 3230. 5310. 7954. 11618. 16082.
170 0.0 0.0 0.0 636.4 2188.4 4227.2 6762. 10291. 14652.
210 0.0 0.0 0.0 0.0 0.0 1022.3 3373.6 6597.6 10588.
mh1 808wkh3c.wpf:1b/091195 3-307
'I['able 3'-6 1..4 ft'HSLB Hot Zero Power with MSiCV Ftulure SIequence of Events Time sec Event Des~cri ')tion 0.0 Mlain Steamline Break: Occurs 1.4 Hi-1 Containment Pressure Setpoint Reached:
3.4 Rod Motion Occurs (HI-1 actuates SI whiich actuates Reactor Trip) 9.9 High Steam Flow Coincident with Iww T,~ SI Siignal'(539"F) 14.4 Safety Injection Iniitiated (actuated on HI-1)
FeMwater Isola1ion (actuated on HI-I) 14.5 HI-2 Containment Pressure Setpoint Reached 16.9 Steantiine Isolation Occurs viia a. High St+un.Flow Coincident with Low T,,
Sl Signa'I 36.1 Emergency Containment Cooler! (2) Actuate 76.1 Cont8unnaent Sprays (2 trains) Actuate 238;3 Peak Containment Pressure (48.1 psig) and Temperature (269A'F) Ottcurt 606.0 Mass and Energy Releases Terni~nate (SG Dryout) mh1808w4%3c.wpf:1b/091195
Table 3.5.4-7 Double-Ended'Pump Suction Break Sequence I +02 psig with Diesel Failure of Events Time sec Event Descri tion 0.0 Break Occurs, Reactor Trip and Loss of Offsite Power are assumed 0.8 Containment HI-1 Pressure Setpoint Reached 4.0 Low Pressurizer Pressure SI,Setpoint = 1745;0 psia Reached 5.0 Containment HI-2 Pressure. Setpoint Reached 12.7 Broken Loop Accumulator Begins Injecting Water 13.0 Intact Loop Accumulator Begins Injecting Water 19.7 Peak Pressure and Temperature Occur 22.5 End of Blowdown Phase 50.8 Emergency Containment Coolers (2) Actuate Containment Spray. Suction from RWST Begins (I train) 77.8 Broken. Loop Accumulator Water Injection Ends 89.9 Intact Loop Accumulator Water Injection Ends 210.8 End of Reflood for MIN SI Case 1680.0 RWST Low Level Reached - Recirc;Sequence Begins 3780.0 RWST Low-Low Level Reached - Cold Leg Recirc Begins Containment Spray (RWST) Ends 3780.1 Containment Spray (SUMP) Begins 64,800. Switchover to Hot Leg Recirculation Begins Containment Spray (SUMP) Ends 1.0E+06 Transient Modeling Terminated mA1808wMh3c.wpf:1bf092595 3-309
Tabl.e 3.5.4-8, Double-Ended Pump Suction Break 4 +09 psig with Diesel Failure (Only 1 ECC)
SEQUENCE OF EVENTS Time sec Event Desc~ci tion 0.0 Break Occurs, Reactor Triip and Loss o: f Offsite Power are assu,med 0.8 ContaIinment HI-1 Pressure Setpoint Reached 4.0 Low Pressurizer Pressure SI SetIeint = 1745.0 psia Reached 5.0 Containment Hi-2'Pre!>sure Setpoint Reached 12.7 Broken Loop Accumullator Begins Injecting Water 13.0 Intact Loop Accumulator Begins Injecting Water 19.7 Blowdown Peak Pressure and Temperature Occur 22.5 End of Blowdown iPhase 50.8 'Emergency Contaiament Coolers (1) Actuate 65.0 Containment Spray Suction from RWST Begins,(1 train) 77.8 Broken Loop Accumulator Water Injection Ends 89.9 Intact Loop Accumulator Water fnjeiction Einds 210.8 End of Reflood for MIN SI Case 1059.5 Overall Peak Pressure and Temgratitre O&ur 1680.0 RWST Law Level Reached - Rekirc'Sguehce Begins 3780.0 RWST Low-Low Level Reached - Cold Legi R'ecirc Begins Contaiinment Spray (RWST) EnCk 3780.1- Contai'nment Spray (SUMP) Begins 86,400. ECC Manually Actuated
'econd 1.0E+06 Modeling Terminated 'ransient m:u 80$ w~c.wpf:1 V092595 3'310
Table 3S.4-9 Double-Ended Hot Leg Break Sequence of Events Time sec Event Descri tion 0.0 Break Occurs, Reactor Trip and Loss of Offsite Power are assumed 3.3 Low Pressurizer Pressure SI Setpoint = 1745.0 psia reached 10.9 Broken Loop Accumulator Begins Injecting Water Intact Loop Accumulator Begins. Injecting Water 18.7 Peak'Pressure and Temperature Occur 21.5 End'of Blowdown Phase 50.0 Transient Modeling Terminated mh1808wM3c.wpf:1bf09259$ 3-311
Table 3.5.4-10 containment Integrity Results L,OC',A (Loss of Offsite Power Assumed)
FAILURE PIET PE/QC, TME.OF PEAK TIME OF P SCENARIO (psiig) PRESS PEAK TEMP (oF) PEAK S (psig) PRFSS TEMP psi )
(sec) (sec)
DEPS w/Diesel, 0.'3 45.8 27i0.8 19;7 2ECCs &
Recirc Spray Off 19.7'059.5 8 18 hrs DEPS w/Diesel, -0.'3 46.2 271.1 1059 'i ECC I 1 ECC, 2nd 24 hrs
& Cont'd Recirc Spray DEHL 0.:3 48.1 18.7 273.9 18.7 IVISLB (Offsite Power Airaiiabie)
FAILURE PINIT (psig) PEAIC PRES S TME OF PEAK Tl:MP TIME GF SCENARIO (psig) P'EAK (OF) 'PEAK PRESS TEMP (sec) (W) 1.4 ft DER HZP 3.0 48.1 238.:3- 269A 2.'383'M 808'.wpf:1bf091195 3-312
50 L
0>
L CL.
20 E
0 o
10 o
C3 2 8 4 5 8 7 10 10 10 10 10 10 10 10 10 10 Time (s)
Figure 3$ A-I: DEPS: Diesel Failure Case with 1 CSS and 2 ECCs at PINIT = 09 psig Containment Pressure m:u808wkh3c.wpf: I W091195 3-313
280 260 L
240 E, 220 E 200 180 160 0
0 140 120 MJJll LIILII IJJKU 2
10 10 10 10 10 18 'IO 10 1'0:16 Time (s)
Figure 3$ .4-2: DEPS: Diesel Failure Case with 1CSS and 2ECC at '.PIMT = 09 psig Containment Steam Temperature mh1808wMQc.wpf:1bl09119.'i 3-314
50 co 40
~ 30 L
O 20 E
0 CI 10 o
0 2 -1 2 10 10 10 10 10 Time (s)
Figure 3$ A-3: DEHL: Case mth PINIT = 03 psig Containment Pressure mal 808wM3c.wpf:1M81195 3-315
280 260 240 E 220 I
E 200 180 160 140 C)
CD 120 LLMLLL
-2 2 10 10 "IO 'l0 110 rime (s)
Figure 3.5AM: DEHI.: Case *it4 PINIT = 09 psig Cnntadnment Temjperatuire mhl808wMh3c.wpf:lb/120195 3-316
50 10 10 10 10 10 10 10 10 10 10 Time (s)
Figure 3S.4-5: DEPS: Diesel Failure with 1 CSS and 1 ECC at PINIT = 09 psig Containment Pressure mh1808w'4%3c.wpf:1b/091195 3-317
280 260 I'40 L
~ 220 1
200 E
m 180 160 E 140 C7 120 O
100 10 2
10
~LLUl 110
~lllll Lll 10'0
~ 10
~ 'IO
~lllll 10 LLl
.10
~JJl 10 Time (s)
Figure 3$ .4-6: ]DE)PS: D;iesel Failure witlh 1'CSS and I ECC at PINIT = 03 pslg Containment Steam Temperature mh1808wkh3c.wpf:1M8119$ 3-318
50 L
L 20 4
ID 10 o
0 1 2 10 10 10 10 10 Time (s) e Figure 3$ A-7: 1.4 ft'ZP Steamline Break, MSCV Failure, 2 ECCs and CSSs Containment Pressure mh1808wM3c.wpf:1bl091195. 3-319
3.6 ADDITIONALDESIGN BASIS AND PROGRAMMA'I'IC EVAI.UATIONS 3.6.1 Equipment Quidification Events if'he revised containment accident analysis temiperature ahd 11iressur& are within the existing EQ profiles, except for the long term temperature at 31 daysThe EQ profile is based on the containment temperature returning to 120'F @ter 31 days following a LOCA. inie uprate Containment Integrity Analysis (Refer to Section 3.5') results in an increase of 2.4~F at 31 days. This is within the iiorrnal range for containment temperature (104"F - 130'F). Therefore, the'ccident duration of 31 days is still acceptable and uprate will not. have an adverse impact on the EQ program.
3.62 Hydrogen Generatiion Rates An analysis of contaimnent post-LOCA hydrogen generation rates was performed for the ~key Point uprating program. The hydrogen generation. analysis wak balsed on an uprated total core thermal power of 2346 MWt (102%%uo of 2300 MVt core power). 'Ihe westinghouse anal ysis demonstrates that with no recombiner in,service, the hydrogen concentration in containment wi1ll not exceed four volume percent for 17 days folllowing a LOCA. Placing a hydrogen recombiner in service prior to the 18th day following a LOCA will maintain containment hydrogen levels belOw the lower flammability limiit of four percent.
3.69 Plant Programs Evaluations of the following generic issues/'programs wer'e perfOrmi:d to determine the impact of thermal power uprate to a core power of 2300 MWt.
Appendix R Station Blackout Erosion/Corrosion Check Valve Program NRC Generic Letter 89-10 "Safety-Related Motor-Operated Valve Testing and Surveillance" NRC Generic Letter 89-13 "Service 'Water System Problems Affecting Safety-Related Equipment" NRC Generic Letter 88-20 "Individual Plant Examination ATWS (IPE)"'he evaluation of plant compliance with Appendix R consists of deterinining the impact of uprate on the equipment and systems required to provide the safe shutdown fiinctions. In addition, the existing Appendix R analysis is reviewed to identify any issues that Wottld be impacted by plant uprat0.
Changes in system/component design and operating condktions are i'eviewdA to determine if there is adverse impact on post-fire safe shutdown.
mA1808wM3c.wpf:1b/091895 3-320
The evaluation of the Erosion/Corrosion (E/C) and the Check Valve programs consists of determining the revised program parameters as a result of the uprate. The revised parameters are identified and addressed in the applicable BOP Engineering Report sections and these sections are reviewed to determine the impacts on the programs are adequately addressed.
The evaluation of Generic Letters 89-10 and 89-13 consists of identifying:the applicable system/components and the design basis parameters used in the program inspections. The impact of the uprating on the design basis parameters are reviewed to determine if the parameters used in the inspections are changed.
'Ilie evaluation of the Equipment Qualification (EQ) consists of reviewing the revised containment accident analysis temperature and pressure profiles against the EQ program pressure/temperature profiles to determine that the existing EQ profiles are bounding. Where the EQ profiles are not bounded the impact of the conditions outside the bounding conditions are reviewed to demonstrate the new condition will not impact equipment qualification based on the existing EQ profiles. Radiological EQ review is addressed in Section 3.6.1.
The Uprating Program does not have an adverse impact on the Turkey Point Units 3 and 4 generic issues and programs as discussed'in the followings paragraphs.
The evaluations of the systems impacted by the uprate did not identify changes to design or operating condition that will adversely impact the ability to provide post-fire safe shutdown in accordance with Appendix R. The most noticeable change was in the inventory of the Condensate Storage Tank (CST) and Demineralized Water Storage Tank (DWST) minimum required volumes. The required volumes were increased resulting in an increased minimum Technical Specification volume. 'Ilie revised minimum volume will provide additional available inventory to satisfy the design basis requirement for post-fire safe shutdown and does not adversely impact post-fire safe shutdown.
Station Blackout (SBO):
The evaluations of the systems impacted, by the uprate did not identify changes to design or operating conditions that will adversely impact the ability to provide safe shutdown for SBO; The most noticeable change was in the inventory of the Condensate Storage Tank (CST) minimum required volume. The required volume-was increased resulting in an increased minimum Technical Specification volume. The revised minimum volume ensures the CST design basis has sufficient inventory to maintain the plant at,hot standby for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> followed by a four-hour cooldown to RHR cut-in. This provides adequate inventory available for safe shutdown during an SBO event.
mh1808wMh3c.wpf:th/091895 3-321
Erosion/Corrosion (E/C):
The impact of increased operating velocities in the secondary system susceptible.to E/C are e'valttateid as part of the system/comiponent evaluations. The increase ~in IielOcity-wfilhave an impact on the E/C rates, however the impact is not expect.d to incre:ase th6 rates beyond design limits and the e'xisfing program will continue to ensue the effects of wall thinning are monitored and evaluated.
Check Valve Program:
The evaluations of the systems impacted by the uprate did not identify changes to design or operating conditions that will ad ver!'ely impact the Check Valve program~. The 'velocities will increase .in the secondary plant system but will not have an adverse impact on the operation of the check valves in these systems.
Generic Letter (GL) 89-10: "Safety-Related Motor-Operated Valve Testing and Surveillance" The impact of, increased operating parameters on the design balls tilifferential pressures used in the GL 89-10 Program were evaluate:d. The design basis differential pressures were conservatively based on pump shutoff head, reliief and saf'ety valve setpoints (plus accumulation), and interlock setpoints which are not changed as a result of the: uprate. Therefore, the uprate does not impact the Generic Letter 89-10 Program.
Generic Letter 89-13: "Service Water System Problems Affecting Safety-Rellated Equipment" The impact of revised heat exchanger parameters used in', the CCW thermal analysis were evaluated for their impact on Generic Letter 89-13. The CCW analysis assumed higher tube foul:ing factors in order to reduce the frequency of maintenance of the CCW heat exchangers. The revised fouling and associated CCW and I( W fiow rates are to be included in the (generic Letter 89-13 program for monitoring the system and heat exchanger performann:.
Generic Letter 88-20: "Individual Plant Examination (IPE)"
A review of plant updating was performed for iits impact on the Individual Plant Examination (IPE) performed for Turkey Point in response to Generic Letter 88-20. The impact of uprating, changes to plant procedures that would be requiredand plant. modiTication< associated with uprating were considered. Because the uprating is limitedi to 4.5% and hS, ve'ry tninimal impact on plant.
configuration, no change to core damage frequency (CDF) Was calttulated.,
Anticipated Transients 'Without Scram - ATWS The Final ATWS Rule, 10 CFR 'i0.62, as appliicable to Westinghouse designed PWRs, requires t6e installation of a system diverse from the reactor protection system that helps mitigate the adverse',
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consequences of an ATWS event by initiating a.turbine trip and actuating the auxiliary feedwater system. To comply with this rule, AMSAC (ATWS Mitigation ~Sstem Actuation Circuitry) systems have been installed;and are operational in, both Turkey Point Units 3 and 4. Supporting the basis of the Final ATWS Rule are ATWS analyses performed by Westinghouse (Reference 1).,In these analyses, a 3-Loop PWR with an NSSS power of 2785 MWt was considered. This power'level is significantly higher and bounds the proposed Turkey Point uprated power condition of 2308 MWt.
Hence, the proposed 'Dirkey Point uprated power condition remains within the bounds of the basis of the ATWS analysis.
Reference
- 1. Letter, from T. M. Anderson (Westinghouse) to Dr. S. H. Hanauer (NRC), "ATWS Submittal,"
NS-'TMA-2182, December 30, 1979, .
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3.7 CONCLUSION
S OF AiCCIDENT "ANALYSES All of the UFSAR Chapter 14 accident analyses applicable to Turkey Point Units 3 and 4 were re-analyzed or evaluated to support plant operation at the uprated conditions. All accept:utce criteria continue to be met.
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3.8
SUMMARY
OF UFSAR ASSESSMENT Paragraph (e) of 10 CFR 50.71 provides the requirement to periodically update the contents of the UFSAR originally:submitted as part of, application for the operating license. This is to maintain information in the FSAR as the latest material developed. 'Ihe information in the update is to include the effects. of changes made to the facility or procedures as described in the. FSAR. In compliance with this regulation, revised sections of the Turkey Point UFSAR have been generated as appropriate which reflect the analyses and evaluations that take into account operation at'the uprated conditions.
These revisions will be incorporated into, the Turkey Point Units 3 and 4 UFSAR on a schedule consistent with the FSAR update program already established.
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CHAPTER 4 NSSS AND TURBINE GENERATOR (TG)
COMPONENTS REVIEW
~ i a~
4.0 NSSS AND TURBINE GENERATOR (TG) COMPONENTS. REVIEW
4.1 INTRODUCTION
The following information addresses the evaluation of the. NSSS and TG components to support operation of Turkey Point Units 3 and 4 at the uprated power, within the bounds of the parameters defined in Table 2;1-1. 'Ihe components evaluated for, the uprating are as follows:
Reactor Vessel Reactor Internals Reactor Coolant Pumps Control Rod Drive Mechanisms Reactor Coolant Piping and Supports Pressurizer Steam Generators Fuel Auxiliary Systems Components Turbine Generator Components The primary components of the NSSS were designed and fabricated to the then applicable codes (B31.1 or ASME III, as listed in Table 4.1-9 of the Turkey Point 3 and 4 UFSAR, Rev. 12). Like most PWR plants. as originally licensed, Turkey Point's NSSS and TG components and systems were igenerally designed for the capacity to operate at the "stretch" rating of 2308 MWt NSSS. However, to support this program, it was'necessary to perform specific evaluations or analyses (e.g., stress analyses) at the uprated conditions in order to clearly utilize the existing plant margin for the.uprated power and associated parameters.
'Ihe analyses and evaluations performed for the NSSS and TG components to support the uprating considered the original codes and standards, where those were applied. The ASME Boiler and Pressure Vessel Code, which was the design code for the majority of the RCS components, provides criteria and requirements for the evaluation of stress levels. in pressure boundary components for design, normal operating, and accident conditions. The margin of safety provided by use of the design pressure as a basis for pressure limits is provided by the inherent safety factors in the criteria and requirements of the ASME Code.
The nature of the analyses and evaluations performed for the NSSS and TG components is found in detail in the sections below. However, in general, the efforts focused on structural evaluation, based on revised design performance capability parameters (from Section 2.0 of this report) and on revised'SSS design transients.
In addition, Appendix A to 10 CFR 50, "Fracture Prevention of Reactor Coolant Pressure Boundary (RCPB)",'equires'in part that the RCPB be designed with sufficient margin to ensure that, when m&1808w~.wpf:1M81195
stressed under operating, maintenance, testing, and.accident conditions, (1) the boundary behaves in a.
non-brittle manner, and (2) the probability..of rapidly propagating fracture is mininuzed. PWRs evaluate reactor vessel einbrittlement in accordance with thee criteria in RG 1.99 Revision 2, and 10 CFR 50.61, the Pressurized Thermal Shock (i'TS) rule. The PTS rule requires that the PTS submittal be updated whenever there are changes in core loadings, surveillance measurements, or other-.
information that indicates.a sigruficant,change in projected values. A re-evaluation of the susceptibility of the reactor vessel to PTS was performed, due to the'effects on neutron fluences and transient loadings. 'Ihese effects result partly from the revised vessel avera'ge temperature Ange, bi'it primarily from the higher power le vel assumed in the e valuations. The results of this evaluation are presented in Section 4.3.
4.2 NSSS DESIGN TRhiNSIERIS
'Ihe NSSS design trar5ients were reviewed and revised 'as necessary to incorporate the uprating parameters, as reflected in Table 2.1-1. These were provided to the component designers for their use
'n structural evaluatio.ns and/or analyses to support the nprating. The component analysts used the most limiting NSSS design aran<'ient(s) for each component.
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4.3 REACTOR VESSEL 49.1 Reactor Vessel Integrity 4.3.1.1 Introduction Reactor vessel integrity is impacted by any changes in plant parameters that affect neutron fluence levels or pressure/temperature transients. The changes in neutron fluence resulting from the proposed Turkey Point Units 3 and 4 Uprating Program have been evaluated to determine the impact on reactor vessel integrity. This assessment included. a review of the current integrated material surveillance capsule withdrawal schedule, applicability of the plant heatup and cooldown pressure-temperature limit curves currently contained in the Technical Specifications, and a revision to the RT~ values used in the submittal to the NRC for meeting the requirements of 10 CFR 50.61, known as the Pressurized Thermal Shock (PTS) Rule. The most critical area, in terms of reactor vessel integrity, is the beltline region of the reactor vessel.
49.12 Input Parameters and Assumptions Material data-was obtained for the Turkey Point reactor vessels from FPL's latest PTS submittal.
Fluence projections on the vessel were calculated for the uprated power level for input to the reactor vessel: integrity calculations. These fluence values were used to calculate the end-of-life transition temperature shift (EOL deDr) for development of the integrated surveillance capsule withdrawal schedule, adjusted reference temperature (ART) values for determining the applicability of the heatup and cooldown curves, and RTprs values.
49.19 Descriptions of Analyses/Evaluations The reactor vessel integrity evaluation for the Turkey Point uprating included the following.objectives:
- 1. Review the integrated reactor vessel surveillance capsule schedule to determine if changes are required as a result of changes in vessel fluence due to the uprating.
- 2. Calculate adjusted reference temperature (ART) values, following the methods of Regulatory Guide 1.99, Revision 2, for all beltline material based upon fluence values projected for the uprated condition to determine the applicability of the heatup and cooldown curves presently contained in the Turkey Point Technical Specifications.
- 3. Calculate RT~ values per the PTS Rule for all beltline material in the Turkey Point reactor vessels based upon fluence values projected for the uprated condition at the time of uprating and EOL.
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42.1.4 Acceptance Criteria fair Analyses/Evaluations With respect to the analysis iobjectives stated in 4.3.1.3I the following are the criteria for each area
- 1. Surveillance Capsule Removal Schedule,, The profpos0A ihtegrattd Surveillance capsule removal schedule developed for Turkey Point following the, uprating shall meet the intent of ASTM E185-82.
- 2. Applicability of Heatup and Cooldown Pressure-Temperature Limit Curves: The applicabiliity i date to which the heatup and cooldown curves presently confined iin the Turkey Point Technical Specifications shall be determined.
- 3. Pressurized Thermal Shock (FIS): The uprated R7~ valties for all beltline materials shall not exceed the screerung criteria o.f the PTS Rulie.
49.1$ Results An evaluation of the impact of uprating on reactor vessel integrity was performed for the neutron fluence changes and other relevant system paimneters associMd with the uprating.
A review of the applicability of the cuixent Teclmcal Specificatioin heatup and cooldown curivesi wais completed and ART values vvere calculated for ail beltline:material using the material properties~and uprated fluence projectioM. It was deterimned that the Turkey Point Unit 3 heatup and cooldown curves will be applicable to 19.0 EFPY after the upratiiIg ik iriiplemented. Me applicability date of the 'Dykey Point Unit 4 curves will be 19.7 EFPY after the uprating is implemented.
Calculations were performed for the, upirating using the latest prob:dures specified by the NRC i6 thb PTS Rule. All RT~ values remain below the NRC screening criteria values using the projecIted fluence values through 28.9 EFPY for Turkey Point Unit 3. For Turkey Point Unit 4, all RT~ vahies remain below the NRC screening criteria using the projected fluence values through 28.7 EFPY.
These values represent end of operating license for Turkey Point Units 3 and 4.
42.1.6 Conclusions It is concluded that the upratiing program for, Turkey Point Units 3 anid 4 will not have significaiIt impact on the reactor vessel iintegrity.
49.1.7 References
- 1. 10 CFR 50.61, "Fracture TougluMss Requirements .for Protection Against Pressurized Thermal Shock Events", May 15, 1991.
~
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- 2. ASTM E185-82, Annual Book of ASTM Standards, Section 12, Volume 12.02, "Standard Practice for Conducting Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels, E706 gF)"
- 3. 10,CFR 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements",
January 1, 1990 Edition.
- 4. Regulatory Guide 1.99, Revision 2, May 1988, "Radiation Embrittlement of Reactor Vessel Materials" mh1808wMA.wpf:1M81195
492 Structural Evaluation 492.1 Introduction Evaluations were performed for the various regions of the Turkey Point Units 3 and 4 reactor vessels to determine the stress and fatigue usage effects of NSSS operation at the revis'ed operating ctonditiOns of the uprating progrum throughout the cuirent plant operating licenses.
Descriptio
'922 Input Parameter and of EvaluatIon PeRoWed The evaluations assessed the effects of the revised design transiients and operating parameters on the most limiting locations with regard to ranges of stress intensity and fatigue usage factors in each'f as identified in the reactor vessel stress report and addend ~ The evaluations consider a worst
'the'egions case set of operating parameters and design truisients Rom among the: high temperature upraQng conditions, the low temperature uprating condiItions and the original design basis.
In addition, reactor vessel operation from plant startup until implementation of the uprating and any future operation in accordance with the ori,ginal design basis is 'stilt fu11y 'covered by the stress and fatigue analyses in the reactor vessel stress report., Where appropriate, revised maximum ranges Of stress intensity and maximum usage factors were calcula'ted for'he uprating program. In other cases the original design basis stress analysis remains conservative so that no new calculations were necessary, and the madmum ranges of stress intensity and fatigue usage factors reported in the stress report and the addenda continue to govern.
In addition to the revised operating par;uneters and design transients for the iiprating progtmn, a new set of LOCA loads at the reactor vesseVreactoIr internals int(:rfaces was identified. The revised interface loads were'valuated by comparing them with the correspon'ding Faulted Condition reactor vesseVreactor internals interface loadings which were ju0tifi6d for Iipplication to the Turkey Point Units 3 and 4 reactor vessels.
4929 Acceptance Criteria and Results of Evaluatioiis The uprating does not affect the mmimum ranges of stress intensity reported in the Turkey Point Units 3 and 4 reactor vessel stress repoit. 'The, evaluations Nho1It that for all of the limiting locations, the existing design stress analyses remain conservative when the revised operating parameters and design transients are incorporated. The maximum cumulative fatigue usage factors at all of the limiting locations increase somewhaj'except those in the CRDM housing,, vessel shell, core suppOrt vent nozzle and bottom mounted instillment tubes which remain unchanged. However, 'ads, that occur are generally minimal, and all of the cumulative fatigue usage factors reclaimthe'ncreases under the 1.0 limit with signiQcant marin.
Il 4-6
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The evaluation of the Turkey Point Units 3 and 4 reactor vessels show they are. acceptable for plant operation, in accordance with the uprating program. Therefore, the reactor vessel uprating evaluation, in conjunction with the reactor vessel stress report, addresses reactor operation within the expanded operating temperature ranges as indicated above. Such operation is shown to be acceptable in accordance with the 1965 Edition of Section III of the ASME Boiler and Pressure Code with Addenda through the Summer 1966 for the remainder of, the plant licenses.
4.32.4 Conclusions
,Based on the analysis results discussed in, the preceding section; the reactor'vessel uprating evaluation demonstrates that the uprating does not affect any of the maximum ranges of, stress intensity reported in the reactor vessel stress reports for Turkey Point Units 3 and 4. In addition, the maximum cumulative fatigue usage factors are affected minimally by the revised uprating conditions and continue to remain significantly below the acceptance criterion of 1.00.
4228 References
- 1. Westinghouse Equipment Specification G-676244, Rev. 0 and Addendum Equipment Specification, "Three L'oop - 155-1/2'Inch,I.D. Reactor Vessel," dated 1/28/66.
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4.4 REACTOR INTERNALS Since the operating conditiozs for the Turkey Point Umts 3 and 4 Uprating Program differ &om thel original design operatiing conditions, the reactor pressure vessetl system and the reactor internal components were thoroughly addressed in order to assujre compatibility and structural integrity of the components. In addition, thermal/hydraulic analyses aze requized to verify that existing core bypass flow limits are not exceeded and to de velop pressure drops and upper head temperatures for input to Appendix K (ECCS), non-LOCA accident analyses, and NSSS performance evaluations. The subject areas most likely to be affected by changes in system ojperating condiitions are:
- 1) Reactor internals system thermal/hydraulic performance,
- 2) Rod control cluster assembly (RCCA) scram performance, and
- 3) Reactor internals system stiwctura3I response and integzity.'lite effects on the pressure vesseVreactor lnternajls system at Turkey Point Units 3 and 4 due to the Uprating Program are addressed below 4.4.1 Thermal/Hydraulic System Evaluations 4.4.1.1 System Pressure Losses An evaluation has been performed which determined the pressure distzibutions and flow characte,ristics within the reactor vessel, reactor internals, and reactor core for'he uprating prograin conditions as specified in References 1 and 2. The total coolant pressure drops across the reactor internals increased by 8%. This data was utiilized in the structural evaluation of the reactor internal components and as input into several analyses (i.,e. I.OCA).
4.4.12 Bypass Flow Analysis Bypass flow is the tot;Q amount of reactor coolant flow bypassing the core region and is not effective in the core heat triuisfer process. Analyses were performed to estimate core 'onsidered bypass flow values to either esire that the design bypass flow limit for the plant will not be exceeded or to determine a revised design core bypass flow. The present turkey Point design core brass flow is 6.0% of the total reactor vessel flow. 'Ilie increase in design core bypass flow from 4.5% to 'imit 6.0% is due primarily to the thimble plug elinunation which was implemented in 1988. The total core bypass flow values were determined to be 5.19% and 5.54% for Turkey Point Units 3 and Therefore, the design core bypass flow value of 6.0% of the total vessel flow can be 4,'espectively.
maintained for the uprating.
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4.4.19 Hydraulic Lift Forces An evaluation was performed to determine hydraulic lift forces on the various reactor internals components to ensure that the reactor internals assembly would remain seated and stable for all conditions. The results of the calculations show that, with the uprated RCS conditions, there is a sufficient net clamping force between the reactor vessel head flange and upper internals flange and the reactor vessel shell flange and the core barrel flange of the internals to ensure that the Turkey Point reactor internals assembly will remain seated and stable.
4.42 RCCA Scram Performance Evaluation The rod drop time-to-dashpot entry (from gripper release of the drive rod) must be determined to be less than 2.4 seconds so that existing accident analyses remain valid. Evaluations were performed that determined that the RCCA drop time for the uprated conditions are bounded by the current limit of 2.4 seconds. In addition, the. current normalized RCCA position versus time curve also remains bounding.
4.49 Flow Induced Vibration/Structural Integrity The primary cause of lower internals'xcitations is the flow turbulence generated by the expansion and turning of the flow at the transition from the inlet nozzle to the barrel-vessel annulus and the wall turbulence generated in the downcomer. Evaluations were performed which determined that there is a negligible impact on the core barrel response due to the RCS changes due to the uprating program.
The significant flow-induced forces on the upper internals are due to random turbulences generated by the cross flows which converge on the outlet nozzles. Evaluations were performed which determined that there is approximately 1.9% increase in the flow-induced vibration loads on the guide tubes and support columns due to the RCS changes due to the uprating program. Previous flow induced vibration analysis on the guide tube and the upper support column show that there exist sufficient margins to accommodate this increase in the flow induced vibration loads.
Stresses and fatigue usage factors for the limiting internal components of the upper and lower internals were evaluated for the changes in RCS conditions due to the uprating program and are within acceptable limits.
In summary, the reactor internals components at Turkey Point Units 3 and 4 remain in compliance with the current design requirements for operation at the uprated power conditions.
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4.5 REACTOR COOLANT PUMPS 4$ .1 Introduction
'Ihe Turkey Point Units 3 and 4 have Model 93 reactor coolant pumps (RCPs)'hich were built prior to ASME Code Stamping requirements. The uprating parameters were evaluated for their effect on the RCP structural integrity and the RCP motor performance.
4.52 Reactor Coolant Pump Evaluation For the uprating program, the RCPs were evaluated for any temperatiire increases or pressure increases that exceeded the original Eciuipment Specification (E-Spec.). The "50% step load decrease"'ransient found to increase the, &'bove, 2250 psia from the E-,Spec. value of 120 psi to 128.7 ps/ '(max).
'as The resultant pressure is Iless than the design pressure and so the /ncrease is considered insignificant.
The "Loss Of Flow" tram ient for the uprated condition produces a temperature and a pressure increase as compared to the original E-Spec. These changes are considered minor and less than original design values and other evaluated transients.
The "Feedwater Cycling" transient was not listed in the, 'original E-Spec. No pressure increase for the RCPs is postulated anted only a small temperature increase is postulated. The temperatiire cycling does not meet the ASME defiation for a, significant temperature difference fluctuation. 'Ilius, the Feedwater Cycling transient has no effect on the fatigue integrity of the RCP.
~I 4$ 9 RCP Motor Evaluation The motor is required to drive the pump contiinuously under hot loop conditions without exceeding a specified stator winding temperature rise that is consistent with Nhtiojaal Electrical Manufacturers Association (NEMA) class Ei requirements. Motor testing has st)wn that the actual temperature rise at rated hot loop load (6000 HP) is well within the. specIifichtidn. 'Ihereforeadequate margin exists for continuous operation with any load less than 6000 HP. Fot thb uprated conditions the worst case hot loop load is 5635 HP which is therefore acceptable.'Ihe motor is required to drive the pump for up to 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> (continuous) under cold loop conditions without exceeding a specified stator win&ag temperature rise that is consistent with NEMA Class F requirements. Motor testing has shown that the actual temperature rise at the rated cold loop load (7500 HP) is well witlun the spe,cificatiIon for the RCP. Therefore, adeqiiate margin exists fOr continuous operation with any load less than 7500 HP. Foi'. the uprated conditions, the worse case cold loop load is 7155 HP w'hich is therefore accept'ible.
'Ihe motor must be capable of accelerating its worse case lOad'without damage when 80% rated voltage at the rated frequency is applied. 'Ihe limiting component for this g~ of starting duty is the m:u808wMA.wpfu M81195 4-10
rotor cage winding. 'For, the uprated conditions, the calculated temperature rise for the critical motor components show that the allowable temperature limits are not exceeded.
Performance of the thrust bearings in the motor could be adversely affected by excessive or inadequate loading. The axial down thrust is increased for the uprated condition which results in a 1.2% reduction in bearing loading. This change has been reviewed and determined to be insignificant.
4S.4 Conclusions The uprating parameters are acceptable to the Model 93 RCPs including the spare with respect to structural integrity and motor performance.
4$ $ References
- 1. Westinghouse Equipment Specification 676335, Rev. 1, "Florida Power and Light - Controlled Leakage Pump," WPAD, 10-9-67.
- 2. WAED Equipment Specification E-565604, Rev. C.
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4.6 CONTROL ROD DRIVE MECHANISMS 4.6.1 Introduction This section addresses the acceptability of the, Model L1068 Control Rod Drive Mechanismsl (CRDMs), both full length and part length, for the uprating parameters. The part length (P/L) CRDMs are not used in the operaiion of the plant, however the P/L housings are primary pressure boundary components and so were evaluated with lrespect to the uprated,'conditions.
4.62 Input Parameters and Description of Evaluations Performed
'Ihe CRDMs were evaluated using the uprating design performance capability parameters. The i applicable ASME Section III. Code stress anal'yses were reviewed for the full length (F/L) and part (P/L) CRDMs. The higher temperatures of the uprating, are stiill bounded by the stress analysis. 'ength The original equipment stress report evaluates the pmt length CRDMs for the general loadings provided by Westinghouse. In the report, it is stated that the thrust bearing retainer assembly, located in the lower portion of the CRDM adapter, is designed to act as a thermal barrier between the reactor vessel and the CRDM proper. j%erefore, the uprating tranSients Will not affect the part-length mechanism at elevations above the thrust bearing retainer assembly.
The geometry of the P/L CRDM lower joint is nearly ident'ical'o 'the geometry of the F/L CRDM lower joint. The canopy length on the jF/L CRX)M latch~housing however, is much shorter than the canopy on the P/L CRX)M rapter. Hence, the F/L CKDM canopy will 'be more rigid than the I'/L CRDM canopy. Since a major portion of thermal induced, stress in the canopy is caused 'by expansion between the two connecting components the thermal induced stresses in the
'ifferential canopy will be smaller for the P/L CKDM lower joint. Therefore it may be concluded that the stress analysis of the full-length CRDM lower joint may also be used as a basis to justify the part-length CRDM lower joint.
The transients for the 'Du.key Point Uprating were compared to the Turkey Point Equipment Specification values of Reference 1. 'Ihe Uprating Transients are bounded by the original transients except for a) the large step load decrease which now has a higher maximum pressure of 2379 psia, and b) feedwater cycli,ng.
4.69 Acceptance Criteria and Results of Evaluatio&
For the two cases not bounded by the origina analysis, the fatigue waiver criteria of the ASME Code, NB-3222-4(d) will be usni. From the Code I'&-3222%(d) fatigue waiver, a, significant pressure fluctuation is one which exceeds a pressure difference df 1282 psi. A signiflcant temperature difference fluctuation is a, change of 51.6'.F.
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The changes in these two transients are not significant changes; the pressure change is only 23 psi for the new large step load decrease and the feedwater cycling has a temperature swing of only 32'F.
4.6.4 Conclusions The transient pressure/temperature changes associated with the uprating conditions do not qualify as significant fluctuations to.be included in a code fatigue waiver and hence any fatigue usage increase is insignificant.
Thus, it is concluded that, the Turkey Point Uprating/SGTP transients are acceptable for the F/L and P/L CRDM's.
4.6S Reference
- 1. CRDM Equipment Specification 676426, Rev. 1, WAPD, 11-3-67, and Interim Change No. 1, dated 12-10-76.
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4.7 REACTOR COOLANT PIPINGI AND SIjlPPORTS 4.7.1 Introduction Evaluations were performed on the potential impact the upiI'ati6g grog~ could have on the following components: Reactor Coolant Loop (RCL) piping, primary equipment nozzles, primary equil')ment Reactor Vessel jHead Vent System (RVHVS) pipihg,'and the Pressurizer surge line. 'upports, 4.72 Input Assumptions The evaluation utilized the same analyses and me:thods hand criteria used in the existing de:sign basis for A@key Point continue to be used.
The uprated parameters that define the varIious teiInperatime conditions associated with the potentIial full power operating conditions of the plant we,re definedI in Section 2. All of thee thermal expansion, seismic, and LOCA analy,ses performedl on the piping systetns are performed at fulll power conditions.
The system thermal design transIients are used only i'he pressurizer surge line thermal stratification analysis (in which a formal fatigue analysi,s is performed). The primary loop piping was designe,d and analyzed to the ASA B3L1 Power Piping Code which did not recure a formal fatigue analysis.
'Ihe loop LOCA analysis considers forces associated witIh defiiled postulated breaks and reactor vessel dynamic LOCA displacements arzociated withe defined postulated break cases. The design basis for the Turkey Point RCL piping LOCA analysis has changed as the result of the licensing of loop Ieak-Before-Break (LBB) methodology, which eliminates the'corksid'eration of dynamic effect due to large break LOCA. Postulated guilIlotine breaks in the primary loop piping have been replaced with postulated guillotine breaks at the loop branch connections for the largest class 1 auxiliary linIes (pressurizer surge line on the hot leg and accumulator line on the cold leg).
Because the seismic response spectra have bee:n upgraded since th5 existing design basis loop anhlydis (NRC Bulletin 79-07 vintage evaluation) therefore, new sei<mid adaly'ses were run incorporating the more recent spectra.
Two earlier programs were used as sources of information auid models for this uprating work. The reactor coolant loop mode1l used in tlhe structm@ analysis fo'r uprating was taken from the work performed to respond to the NRC Bulletin "79-07. The primary equipment support sfiffnesses ~use'd ih the analysis were upgmled from the original values to those used in the A-2 program which the asymmetric LOCA loadls on operating pllants. 'nvestigated mh1808wM4.wpf:i b/091195 4-14I.
4.79 Description of Evaluations Computer structural analyses were performed on the RCL piping- system model for the loading conditions of deadweight, thermal, and,seismic. The thermal expansion analysis was run to give the range of loadings associated with the temperature conditions defined.
The seismic analysis was run to include the newer seismic response spectra provided by FPL. The model used for the thermal analysis was also used to run the deadweight analysis to have a consistent set of results. The seismic model merely modified the supports on the. deadweight. model to account for lateral loadings. All three analysis types used the primary equipment support stiffnesses updated for the A-2 asymmetric LOCA loads evaluation.
The deadweight, thermal gow temperature and high temperature cases), and seismic analysis results for this RCL model were used as input to the specific evaluations for the loop piping, the primary equipment nozzles, the primary equipment supports, and the loop LBB.
As discussed above, a LOCA loop analysis was not necessary because the increase in margins after implementing loop LBB was more than enough to balance off any potential increases in LOCA loadings associated with the uprated conditions. Any existing design basis LOCA loadings continue to envelope the proposed uprated condition LOCA loadings.
The evaluation for the primary equipment nozzles involved a comparison of the newly generated loads for the deadweight, thermal, and seismic loading conditions with the allowable nozzle loadings for that equipment.
The primary equipment supports were not a Westinghouse design and the design basis calculations were not available. The analysis/evaluation for the supports consisted of comparing the loads on the various support components to the capacities for those same components. The basis for many of these support calculations goes back to the A-2 asymmetric LOCA loads evaluation.
The RVHVS piping was evaluated by comparing the new temperatures and pressures associated with the uprating program with those used in the existing head vent analysis. These new temperatures and pressures associated with uprating are enveloped by the parameters used in the piping analysis.
The evaluation performed on the pressurizer surge line stratification analysis included a review of the fatigue analysis and the stratification loadings that were transmitted to the pressurizer nozzle from the surge line piping. The changes and the percent increases for the uprated thermal design transients were tabulated and the impact on the fatigue usage factor was calculated. The new uprated conditions were reviewed to determine ifthe old envelope loads on the nozzle changed significantly.
Temperature differences between the hot leg and pressurizer were used to calculate stratified moments in the surge line piping.
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4.7.4 Acceptance Criteria and Results The acceptance criteria for the loop ~piping stress evaluation is dontttined in the 831.,1 Power Piping Code. The applicable load combinations of deadweight, pressuie, seisinic and thermal loads were checked against the appropriate allowable for the ]loop piping material. The pipe stress conditionS were met.
'Ihe primary equipment nozzle loads were compared to the equipmi:nt specification allowables for the specific loading conditions analyzed. All of the niozzle loads met the allowables.
The primary equipment support loads were compared to the various support capacities. All support components assessed met the allowables.
Since the parameters of interest (temperatures and pressures) in the RVHVS piping, analysis enveloped ~
the uprating parameters, there was no impact on tins piping analysis due tio the uprating program.'he results of the evaluation for the pressmizer surge line stratiQcation showed that the uprating conditions changed the fatigue usage factor at the location of highest usage factor from 0.942 to 0.944.
The allowable usage factor is 1.0 and the change calculated was not significant. The calculated change in loadings on the pressurizer nozzle due tio stratification for the uprated conditions was less than 4%. The change i,n nozzle loadings was considered insignificant because the original loadings on the pressurizer nozzle were conservative envelopes that lumped ~various transients under a small number of bounding thermal uses.
4.7$ Conclusions The parameters associated with the uprating program for Turkey Point have been evaluated for impact on the RCL piping, the primajy equipment nozzle!>, the primary equipment supports, the RVHVS piping, and the pressurizer surge line. The evaluation in(licates that all components met appropriate.
allowables. The evaluation for the stated components concluded that the plant uprating program had no adverse effect on the ability of these components to operate until the scheduled end of plant operation.
4.7.6 Reference
- 1. Turkey Point Units 3 and 4, "Approva1l of Leak-Before-Break i(LBB) Methodology for Reactor Coolant System Piping", June 2'3, 1995.
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4.8 PRESSURIZER 4.8.1 Introduction The functions of the pressurizer are to absorb any expansion or contraction of the primary reactor coolant due to changes in temperature and pressure and to keep the reactor coolant system (RCS) at the desired pressure.
The components in the lower end of the pressurizer (surge nozzle, lower head/heater well and support skirt) are affected by pressure and surges through the surge nozzle. The components in the upper end of the pressurizer (spray nozzle, safety and relief nozzle, upper head/upper shell, manway and instrument nozzle) are affected by pressure, sprays through the spray nozzle, and steam temperature differences.
The pressurizer temperature is kept at the water saturation temperature (T-sat) corresponding to the desired pressure. The limiting operating conditions of the pressurizer occur when the RCS pressure is high and the RCS hot leg (T-hot) and cold leg (T-cold) temperatures are low. This maximizes the bT experienced by the pressurizer because of the comparison to T-sat. Due to fiow in and out of the pressurizer during various transients, the surge nozzle alternately sees water at the pressurizer temperature (T-sat) and the RCS hot leg (T-hot). Ifthe RCS pressure is high, with a correspondingly high T-sat, and T-hot is low, then the surge nozzle will experience the maximum thermal stress.
Likewise the spray nozzle and upper shell temperatures alternate between steam at T-sat and spray, which for many transients is at T-cold. Thus, ifRCS pressure is high, with a correspondingly high T-sat and T-cold is low, then the spray nozzle and upper shell will experience the maximum thermal stresses.
4.82 Input of Assumptions and Description of Evaluation For the uprating, the transient conditions differ fiom the conditions to which the Turkey Point Units 3 and 4 pressurizers were originally designed and analyzed. To conservatively maximize thermal stresses the lowest Thand the lowest T conditions were evaluated, regardless of which parameter set they came from.
The analysis was performed by modifying the original Turkey Point Units 3 and 4 pressurizer stress report, which was performed to the requirements of the ASME Boiler and'Pressure Vessel Code, Section III, 1965 Edition, Summer of 1965 Addendum. Analytical models of various sections of the pressurizer were subjected to pressure loads, external loads (such as piping loads), and thermal transients.
The maximum pressure and maximum external loads on the pressurizer are not affected by the thermal uprating conditions. Thus, the primary stresses calculated for the original analysis are still valid. The mal 808wM4.wpf:1M81195 4-17
conditions that affect maximum primary plus secondary stresses do not change as a, result of the uprating, excejpt for the surge nozzle. For all'thee cbmponbnts, the fatigue analysis is 'affected. 'hermal
'he original Turkey Point Units 3 and 4 pressurizer analysis was previously modified to account for normal transients and the surge nozzle analysis was previously updated for the thermal stratification pipe loads in response to Generic Letter 88-11 (Reference 3). 'The analysis update for the uprating considered all the previously reported changes to the original analysis.
4.83 Acceptance Criteriia and Results The evaluation showed that the pressurizer components will continue to meet the ASME Code stres<'nd fatigue requirements for the uprated conditions. The new total fatigue usage factor for each was determined to be less than 1.0 per the ASME Code. 'omponent 4.8.4 Conclusions The results of the pressurizer analysis show that the Turkey Point Plant Units 3 and 4 pressurizer components meet the stress/fatigue analysis requirements ofi the ASME Code, Section III for Ithe plant operation in accordanc with the upiMng program.
4.8$ References
- 1. Equipment Specification 676359, Revision 1, "Reactor Coolant System, Florida Power and
~I Light Turkey Point Urut No. 3, 1300 cu. fit. Pressurizer,l'estinghouse Electric Corporation,,
Atomic Power Division, Pietsburgh, Pennsylvania, March 1969.
- 2. Equipment Specification 676458, Revision 3,, "Reactor Coolant System, Florida Power and Light Turkey Point Urut No. 4, Pressurizer," Westinghouse Electric Corporation, Nuclear Energy Systems, PitL<>burgh, Pennsylvania January 1975.
NRC Generic Letter 88-11, "Pressurizer Surge Line'tratification" dated 12/20/88.
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4.9 STEAM GENERATORS 4.9.1 Thermal/Hydraulic Evaluation 4.9.1.1 Introduction The thermal hydraulic evaluation of the steam generators at uprated conditions has been assessed and determined to be acceptable.
4.9.12 Input Parameters and Assumptions Applicable design parameters for operation at uprated conditions were used for the thermal/hydraulic
~
evaluation. 'Ihe operating steam generator water level was assumed to be at 60% of narrow range span. The as-built steam generator configuration was used for calculation of thermal/hydraulic operating characteristics.
The design fouling factor was originally assumed conservatively high to provide a margin factor for steam pressure performance. In the absence of significant field performance experience, a large value was used to assure that design steam pressure was met. As in the case of Turkey Point, this value was often carried over to the replacement units. Increasing field experience showed that the large values of design fouling factor were very conservative. The uprated value defines a more realistic design operating point, permits. lower design operating temperatures and still provides adequate margin so that the generator is assured of meeting the design steam pressure.
4.9.13 Evaluations Performed The steam generator thermal/hydraulic evaluation of the Turkey Point Units 3 and 4 steam generators included several facets. Operating characteristics of the steam generators at all the uprated conditions were calculated. Attention was focused on secondary side parameters. Parameter values calculated for uprated conditions are compared to the values at the current design conditions. Where appropriate, the parameter values are compared to other existing field experience. In addition, the question of voiding below the water level and its effect on level setpoint is addressed.
4.9.1.4 Thermal/Hydraulic Operating Characteristics Several secondary side operating characteristics were used to assess the acceptability of steam generator operation at uprated conditions.
The circulation ratio (CR) is a measure of liquid flow in'the bundle in relation to the steam flow. It is primarily a function of power. The CR decreases for the uprated condition. Since the steam flow increases with power, the bundle liquid flow decreases at the same condition. The bundle liquid flow mh1808wMA.wpf:1M81195 4-19
minimizes the accumulation of contaminants on the tubesheet and in the bundle. 'I'he uprating has no material effect on this function.
The total bundle flow rate remains essentially unchanged with uprating. The incre ise in steam flovi and concurrent increase in void fraction result in an increased potit.ntial for vibration in the U-bend region. 'Ihis circumstance, however, does not contribute to any significant decrease in long term bundle integrity for the Model 44F steam generators The hydrodynamic stability of a steam generator is characterizing by the damping factor. For'pt'ate'd conditions, damping factors are seen to remain negafive at about the same level as current de'sign. All
'he uprated conditions, therefore, continue to be hydrodynamically stable.,
The reduced steam pressure brings about a,n increased void fraction in the tube bundle. This, causes a small reduction in stmim generator mass that is not considered 'sigi'uficant.
The maximum calculated heat flux at upnted conditions is well within nucleate boiling limits and is lower than values for steam generators currently operating in the field.
The increase in average heat flux will cause some increased potential for corrosIion and long &rid fouling though it is not the dominant factor. Operating temperatures and plant chemistry coupled with plant materials are more, significant facltors. Openting history to date, more than changes which will result from uprating, is the best indication of whether the 'turkey Point umts are susceptible t'ai significant corrosion or performance loss due to fouling.
'Ihe maximum increase, 3 psi., in, total secondly side pressure drop for the steam generator is very small in relation to the, total feed system pressure drop. This should have no significant effect on thb feed system operation.
In summary, the thermal/hydraulic operating characteristics of the Turkey Point Units 3 and 4 steam generators are within acceptable ranges. for all anticipated uprated i'.onditibns.
4.9.1$ Acceptance Criteria and Results The thermal/hydraulic characteri<tics of the. stcam, generators were evaluated with respect to plant safety as to the operational stability and secondary side measurements that are used for trip fiinctions.
Steam generator stability involves the behavior of'he unit iti response to perturbations to the tiperatihg parameters. The measurement of secondary side ]level is performed by the narrow range taps.
4.9.1.6 Conclusions The thermal/hydraulic operating characteristics are within acceptab'Je ranges for all anticipated'p'rating This evaluation has shovin that the steam generator Iuprhted thermal/hydraulic conditions 'onditions.
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are within an acceptable range and are similar to the current conditions. The current high level setpoint of the secondary side will perform as intended.
4.92 Structural Evaluation 4.90.1 Introduction A structural evaluation of the steam "generators was performed at the uprated conditions. The structural, integrity of the steam generators at the increased thermal rating has been assessed and determined to be acceptable.
4.922 Input Parameters and Assumptions The parameters for steam generator structural evaluation covered six uprated condition cases. Cases were analyzed for a steam generator without tube plugging, and for 20% tube plugging. Variations in the primary and secondary temperatures under high and low temperature uprating conditions at full normal power operations are within a1% of the reference conditions. Variations in the secondary side pressure are about+6% and those for the primary-to-secondary pressure differential are within about
~3%. The multiplying factors to be used for adjusting pressure induced stresses under steady-state conditions to obtain stresses for the uprating conditions are: 1.01 for primary side pressure; 1.06 for secondary side pressure; 1.03 for primary to secondary pressure differential.
4.9Z9 Evaluation Criteria
'Ihe design transient applicable for the uprated conditions are in general more severe than the previous ones. Comparison with the original transients indicates that the primary side temperature variations are somewhat greater for the uprated cases. Thermal gradients across the thickness of steam generator components do not change drastically. Secondary side transients basically remain unchanged. Primary to secondary. pressure differential changes were evaluated and the stress range multiplied by the appropriate factor for the transients affected.
The critical steam generator components evaluated structurally were the tubesheet, tubesheet junctions, tube to tubesheet weld, tubes, secondary shell, minor shell penetrations and the feedwater nozzle. The divider plate is not a critical pressure boundary component, but it was also. evaluated for a higher pressure drop across the plate at a plugging level of 20%.
4.92.4 Conclusions Results of analysis performed above for the Turkey Point Units 3 and 4 Model 44F steam generator components show that structural integrity of the components would be maintained for operation at the uprated power level with a maximum plugging level of 20% in the steam generator.
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4.10 FUEL hei 4.10.1 Fuel Assembly Structural Evaluation 4.10.1.1 Introduction E
The current fuel design in place at Turkey .Poi,nt Units 3 and 4, which is 15x15 Debris Resistant Fuel Assembly (DRFA), was evalu,ated at the uprated power conditions to ensure that it still meets the applicable design criteria. The fuel assembly design was evaluated to show that it was struchiralliy adequate to support the increseed power level.
4.10.10 Description of Evaluations/Acceptance Criteria The maximum spacer grid loads and assembly deflections for LOCA conditions were determined for the uprated power. The grid lioacls and assembly deflections were compared to those from the, orIiginal Turkey Point analysis of the DRFA. The maximum grid loM obthindd,from seismic and-LOCA loading analyses were also combi,necl using the square robt gaum of the'quares (SRSS) method.
The design lift forces for the uprating were compared to the generic 15x15 Optimized Fuel Amernbly (OFA) design in order to verify tlhe fuel assembly holddown spring capability under the uprating conditions.
4.10.19 Results The results indicate that both spear grid load and assemlbly deflection are. lower than those from the original analysis of the DRFA in the Turkey Points units. Thus, the most recent LOCA analyses results remain applicablie for the DRFA in both Tcu'key Point units.'esults of the seismic and LOCA. peak grid loads and tht combined grid load, show the load is significantly less than the grid strength. Based on these results, the, 15x15 DRFA designs are structurally acceptable ]for both 'Dykey Point units.
It was also determined that the design lift forces for Turkey Point 3'and 4 under uprated conditions are bounded by the generic 15x15 OFA design. The fuel assemlbly holddown spring capab'ility is 'theIfefcIre verified.
4.10.1.4 Conclusions The Turkey Point 3 and 4 .Debris Resistant Fuel Assembly design was deterfmned to be, strucuiral~ly ~
acceptable for the uprated conditionsThe fuel assembly holddown springs were also found tcI bei acceptable.
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I 4.10.2 Fuel Rod Design Analysis 4.10.2.1 Introduction A fuel rod design analysis was performed to determine the impacts of the uprating on fuel rod design.
This. section summarizes the fuel rod design analyses performed to determine if the design criteria impacted:by the uprating are met.
4.10.22 Evaluations and Results Fuel rod evaluations were performed to determine. the impact of the uprated core power on fuel performance. Evaluations of the fuel rod design criteria impacted by the uprating, including rod internal pressure, cladding stress and strain, cladding fatigue and cladding corrosion were performed at the uprated conditions. These fuel rod design evaluations, performed with the NRC-approved models, have shown that fuel rod design criteria can be satisfied at the uprated core conditions.
4.10.29 .Conclusions It has been demonstrated that the fuel rod design criteria will be satisfied at the uprated core conditions. Furthermore fuel performance evaluations are completed for each fuel region and cycle to demonstrate that all fuel.rod design criteria. will be satisfied under the planned operating conditions as part of the reload safety evaluation process performed. during each reload cycle.
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4.11 NSSS AUXILIARYSYS'EM COMPONIENTS 4.11.1 Introduction The NSSS auxiliary equipment of Turkey Point Units 3 and 4, such as valves, pumps, tanks and heat exchangers, have been evaluated for the uprated conditions.
4.11.2 Input Parameters and Assumptions and Description of Evaluations!Performed The impact of the uprating on the maximum system operating temperatures and pressures were evaluated. The increased dewy heat and post-aa:ident conditiOns 'were considered. The maximum temperature of the component cooling water supplied to auXiliary equipment was also evaluat'ed.'n evaluation of the maximum operating. temperatures and pressures was performed on the following equipment:
~ Residual heat removal system j,'RHRS), component cooling water system (CCWS), containntent spray system (CSS), ancl Spent Fuel Pool. (SFP) vallves
~ CSS, CCWS, SFP, SFP skimmer, charging, RHRS, and HHSI pumps
~ RHRS, CCWS, nonregenerative, sample, excess letdown, seal water, and SFP heat exchangers
~ Boron injection and CCWS surge tanlcs.
~ Waste gas.compressors
~ Radiation Monitors R-17A i&, B (Component Cooling Water).
The impact of changes to thermal transients was'evaluate 6n the following equipment;,
RHRS, CCWS, CSS and SFP valves CSS, CCWS, SFP, SFP skimmer, charging (PD), RHRS, and HHSI pumps RHRS, CCWS, and,SFP heat exchangers Boron injection and (:CWS surge tmLs.
The impact of increased cooling water temperatures was evaluated for the following, equipmetit:
~ RHRS, CSS, HHSI, iutd charging pumps.
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I 4.'119 Acceptance Criteria The evaluation of the NSSS Auxiliary equipment for the uprated condition depends on the comparison of the following values to the original design conditions:
~ Maximum operating temperatures and pressures,
~ Revised thermal transients
~ Increased cooling water temperatures.
If the uprated parameters were bounded by the original design values, then the auxiliary equipment remain qualified for the uprating program. If the revised parameters were not bounded, then the affected equipment needed to be requaliQed.
4.11.4 Results All maximum operating temperatures and pressures are bounded by the existing systems design bases.
Therefore, the auxiliary equipment is qualified for the maximum operating temperatures,and pressures resulting from the Uprating Program. Also, the auxiliary equipment thermal transients resulting from the uprating parameters are. bounded by the original design parameters. Therefore, the auxiliary equipment remains qualified for thermal transients for the Uprating Program. The evaluations performed demonstrate that the Turkey Point RHRS,, CSS, HHSI, and PD Charging pumps will operate as designed for the CCW conditions at the uprated parameters.
4.11$ Conclusions The NSSS Auxiliary equipment. at Turkey Point Units 3 and 4 have been evaluated for the uprated conditions. Upon considerations of peak system temperatures and pressures, thermal transients and increased:, CCW temperatures, it was determined that the evaluated equipment will function as intended for the uprated conditions.
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4.12 TURBINE GENERATOR (TG) COMPONENTS The critical components of the high and low pressure turbines iwere evaluated to establish that structural integrity ancl functional adequacy cain be maintained at the 2308 MWt. (NSSS) upraIted conditions. This review included the stationajy parts of the high pressure and low pressure cylinders, blade rings, nozzle blocks, high pressure bladiing, low ptessttre'bla'ding, piping, Moisture Separator-Reheater's (MSR), extraction piping, and valves. In addition, the rotating blading and rotors of both the high and low pressure, turbines were evaluated. The, turbine auxiliary interface was also eyaluattxi, including the main steam inlet.
The basis for this evaluation was a review of the expected design conditions at the uprated power level. These conditions were comparecl to the applicable design criteria to determine the acceptability
'f operation at the higher power level. A revIiew was performed for both the thermodynatnic operation of the equipment and the mechaii1ic8il function In cases where design margin was minimal, plant operating data was also considered to evaluate, whether the icomponent could be approved for~uprating. ~
A review of all the turbine components and turbine auxiliaries meet the design criteria for the 2308 MWt uprating. )Based on the evaluation it can be concluded that operation at the uprated power level for the TG components is acceptable.
4.13 CONCLUSIONS NSSS components were re-evaluated and resu]Its compared to the aIllowable stress fatigue limits defined by the ASME Code 1Mitions to which the components were originally designed and evaluate The revised conditions and transIient loadings resulted in'tresses and fatigue usage factors below'he Code allowable limits. The conservative assumptions of the original stress report remain bounding for revised conditions .reflected in T'able 2.l-land therefore the original conclusions remain
'he unchanged. 'herefOre,,, it has been determined that the NSSS components will not be adversely affected by the uprating for an NSSS power level of up to 2308 MWt.
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CHAPTER 5 NSSS AND TURBINE GENERATOR (TG)
SYSTEMS REVIEW
5.0 NSSS AND TURBINE GENERATOR (TG) SYSTEMS REVIEW
5.1 INTRODUCTION
The impact of the uprating and associated conditions (as described in Table 2.1-1) was evaluated for the NSSS Fluid Systems, Control=Systems, Reactor Protection Systems, NSSS/BOP Interface Systems, and Turbine Generator Systems. The purpose. of these evaluations was to confirm that the NSSS and TG systems continue;to perform their design functions acceptably at the uprated conditions.
5.2 NSSS'FLUID SYSTEMS 52.1 Reactor Coolant System 52.1.1 Introduction The Reactor Coolant System (RCS) consists of three heat transfer loops connected'in parallel to the reactor vessel. Each loop contains a reactor coolant pump (RCP),, which circulates the water through the loops and reactor vessel, and a steam generator (SG), where heat is transferred to the main steam system (MSS). In addition, the RCS contains a pressurizer which controls the RCS pressure through electrical heaters, water sprays, power operated relief valves (PORVs) and!spring loaded safety valves.
'Ihe steam discharged from the PORVs and safety valves flows through interconnecting piping to the pressurizer, relief tank (PRT).
The key RCS functions are as follows:
To'transfer heat generated in the reactor core to the MSS via the SGs,
~ To transfer decay and sensible heat to the Residual Heat Removal System (RHRS) when the core is subcritical and RCS temperatures are approximately'350'F and lower,
~ 'Ihe RCS fluid acts as a moderator of neutrons,
~ The RCS fluid is a solvent and carrier of'boric acid which is used as a neutron. poison,
~ The RCS is a barrier against fission product release,
~ The.RCS,provides means for pressure control via use of pressurizer heaters, spray flow, PORV's and safety valves.
'Ihe calculated uprated RCS design operating conditions include increases in core power, and the allowable operating range for average RCS temperature (Tavg). The potential impact of the uprated conditions on the previous RCS functions are described'below:
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~ The core power increase will affect the total amount of heat transferred to the MSS.
~ During the second phase, of plant coo3Idown, the REERS will be required to remove larger antounts 'f decay heat from the RCS as the, reactor core is operating at a higher power level. However, at plant shutdown conditions, the RCS condIitions are'not'affected. '
The thermal uprating project c:ut change the transient respOnse of the RCS during normal and postulated design basis events. The acceptability of the RCS with respect to control and~
protection functions has been demonstrated in tltis report.
With higher core power levels, the decay heat levels that must be cooled by the Spent Fnel Pool Cooling System (SFPCS) are increased. Section 5.5.5 addresses the SEVCS capabilities and associated changes to operating ternperatL1res at uprated conditions.
~ With higher core power levels, the amount of boric acid required to achieve desired shutdown margins can increaseSection,5.2.2 of this report addresses boration capabilities at uprated ~
conditions.
~ 'ith higher core power and increased SG tube plugging, RCS available volume and RCS loop ~
flows can decrease, which can reduce pressurizer spray flow capability since loop velocity h'ead is for driving head. In additiona ange of steady state full powe~ RCS operating temperatmjes 'sed is established. Ti;us range, in 01m, can cause changes in nomiinal pressurizer level which can change the steam release, potential to the PRi'.
52.1D Input Parameters and Assumptions The evaluation of the RCS at the, uprated condition required thdd the following changes be considered:
~ Higher SG tube plugging levels reduces the avaiiab1le RCS liquid volume. To provide design input to the calculation of revised RCS source terms, a minimum RCS liquid mass at fulll power operating conditions was calculated.
~ Higher SG tube plugging may reduce available loop fldwsFor RCS loops used for pres'suriizer'pray flow, lower RCS flows redu(xs the available driving head for spray. To sufyort RCS response and plant safety analysis, a range of pressurizer spray flow under full,spray 'ransient operation was calculated
~ The range of RCS operating temperatures provided .in Section'2.0 of this report were used as a to evaluate E(CS design temperatures. 'asis mh1808w&6.wpf:1M81195 5-2
~ Operation at a lower RCS Tavg condition increases the available pressurizer-steam space volume that may have to be condensed in the PRT under limiting RCS transient conditions (e.g., loss of load event).
~ In the cases where a setpoint may be potentially affected, the FPL I&C Matrix Instrument List was reviewed to verify it's adequacy relative to the current process control setpoint value.
5.2.19 Description of Analyses/Evaluations Performed To determine the RCS minimum hot full power liquid mass, the allowable SG tube plugging was considered as well as the limiting masses of other components and other calculation parameters were used to provide a conservative RCS mass condition. To determine pressurizer spray flow capability, a detaBed flow calculation was performed which define the expected minimum, nominal and maximum pressurizer spray flow as a function of assumed RCS loop flow. Expected variations in component hydraulic data were considered to provide a range of expected flows.
Assessing system operation at the higher range of RCS Tavg condition, the maximum expected RCS Thot temperature was compared to RCS design temperatures. In the assessment of system operation at the lower RCS Tavg condition, the available steam space volume in the pressurizer was compared to that assumed in the PRT design basis calculation to assess available margin.
5.2.1.4 Acceptance Criteria for Analyses/Evaluations In the calculation of a revised minimum RCS hot full power liquid mass, no specific criteria had to be met. The calculation biased inputs to establish a conservative (minimum) value.
In the assessment of system operation at the range of RCS Tavg conditions, the maximum expected RCS Thot temperature must be less than or equal to the applicable RCS design temperature to ensure pressure boundary integrity.
The acceptance of the PRT relief capability is not based on a safety function but on a desirable criterion of precluding contamination of containment following a maximum expected pressurizer discharge.
5.2.1$ Results Pressurizer spray flow capability was calculated considering a range of component hydraulic conditions at the revised RCS Thermal Design Flow (TDF) of 85,000 gpm per loop. The minimum calculated total spray flow continues to meet the acceptance criteria.
mh1808wMhS.wpf:1M81195 5-3
With respect to maximum expected RCS H[ot kg (Tlhot) teinpdranue, the, uprated condition temperature is well within the RCS loop design temperafxue of 650'F. Note,, the pressurizer and the surge line has a higher design temperance of 680'F.
With 'respect to the PRT, ihe revised range of RCS Tavg has the potential to change the nominal full load pressurizer steam volume at uprated ernditioM. In getieral, tlie reference nominal presstirizdr level is coordinated with RCS Tavg such that an increase in Tavg raises the nominal pressurizer reference level condition. With respect to the.PRT discharge analysis, a lower RCS Tavg condition is potentially more limiting since pressurizer level is lower'(st5am volume is higher).
Although the revised nomjinal steam volume at uprated power can be somewhat greater than the PRT original sizing basis value the inherent availability of. 19 petceitt steam volume conservatism kn'he sizing. calculation would more, than compensate for the ass/ble ning increase.
5.2.1.6 Conclusions The acceptability of the revised RCS operating conditions at uprated power has been evaluated. The overall conclusion is that the RCS c m continue to perform its design basis functioM without any anticipated plant changes.
m:u808w&6.wpf:1M81195
5.22 Chemical and Volume Control System 5.22.1 Introduction The Chemical and Volume Control System (CVCS) is designed as an interface to the Reactor Coolant System (RCS). Its primary design function is to maintain the required water inventory, soluble boron concentration and water chemistry of the RCS. Other CVCS functions include filling and draining the RCS, reducing the quantity of fission and corrosion product impurities in the RCS, and supplying seal injection flow to the reactor coolant pumps (RCPs). In addition the CVCS meets the requirement in 10 CFR 50 Appendix A which states that there be two independent means of reactivity control, one of which is not the control rods. CVCS reactivity control is performed with the injection of boric acid solution, which is a neutron absorber, into the RCS.
During normal plant operation, the CVCS provides the charging and letdown to the RCS. Charging. is generally performed with one of three positive displacement pumps. In addition to providing charging flow and pressurizer auxiliary spray, the charging pumps also provide seal',injection flow to the RCPs.
5.222 Input Parameters and Assumptions Provided below is a list of key input parameters used on the assessment performed on this system:
~ Of the specified changes in RCS operating conditions addressed by this project, the most significant change due to uprating is the increase in the reactor core power level. In general, the higher reactor core power level may require the CVCS to borate the RCS to a higher concentration at a faster rate. The adequacy of the boron concentrations of the BAST and RWST will need to be assessed.
~ Since the CVCS interfaces with the RCS, specifically the RCS cold and intermediate legs, a change in RCS design temperature may also have an impact on the CVCS functions.
5223 Description of Analyses/Evaluations Performed The present CVCS boration capability was evaluated at the uprated conditions. Specifically, the minimum amounts of boric acid (boric acid concentrations) in the BAST and RWST,presently required in the Turkey Point Units 3 and 4 Technical Specification were reviewed to assure they are sufficient in meeting the Turkey Point Units 3 and 4 Technical Specification (See Section 5.2.2.4).
In the assessment of system operation at the higher range of RCS Tavg condition, the maximum expected RCS temperature was compared to the CVCS design temperatures. Specifically, the RCS cold leg and intermediate leg temperatures at the uprated conditions were evaluated since letdown occurs at the Loop B cold leg and alternate letdown occurs at, the Loop A intermediate leg.
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5.22.4 Acceptance Criteria. for Analyses/E valuations The following CVCS boration requireinents are specified iif. thd Turkey Point Units 3 and 4 Tecluucal Specifications:
~ The amount of boric acid in the BAST and RWST, individually, is sufficient to borate the RCS to cold shutdown (Mode 5) conditions from Mode 1 thirough 4. This includes the amount of boric acid needed to achieve the required shutdowif mlitt irl Mode 5.
~ In Modes 5 and 6, the amount of boric acid in the BAST and RWST, individually, is sufficient'o account for. the effects of RCS shrinkage and the moderator temperature coefficient.
~ The CVCS boration i~ is sufficient to keep up with the ice at which Xenon burns out after tlute peak.
Besides these requirements from the Turkey. Point Technical Specifications, the CVCS perfo~&ce 6t the uprated conditions were compared with the design basisPresently, with one charging pump and either boric acid transfer pump in operation, enough boric,aCid cart be injected into the RCS (during ~a ~
feed and bleed process) to take the reactor to hot shutdown wit1hin forty minutes. In an additional forty minutes, enough 1boriic acid is injected into the RCS to'ompensate for Xenon decay.
In addition to the CVCS boration requirements, the change in RCS operating conditions need to be assessed. The maximum expected RCS co1ld leg tempeNturt nfust be less than or equal to the applicable CVCS design temperature.
5.22$ Results The maximum expected RCS cold leg temperature at uprated condiitions i:s well wMun the CVCS mechanical design temperature of 650'E'. The CVCS operating'eSign temperatLire is limited by the capability of the regenerative heat exchanger. The maxirnurh cbld leg (and intermetHate leg) at the uprated conditiions is also below this temperature. 'Iheiefore, the RCS effluents at.
'emperature the uprate conditions are withiin tlhe design conditions of 'the'VCS. The 'acceptance criteria of Section 5.2.2.4 are satisfied'.
522.6 Conclusions The evaluation of the CVCS at the uprated conditiions ha's h!en performed. The CVCS can continue to perform its design basis functions at the uprated condition of the plant.
I:u 808wMhs.wpf: ib/091195 5-6
5.23 Safety Injection System/Containment Spray System 5.29.1 Introduction The Safety Injection System (SIS) and the Containment Spray System (CSS) are Engineered Safeguards,Systems. They mitigate the effects of postulated design basis events by providing core and containment cooling.
The passive portion of the SIS consists of the three accumulator vessels which are connected to each of the RCS cold leg pipes.
The active portion of the SIS is comprised of a high pressure and a low pressure injection subsystem.
Both subsystems utilize centrifugal pumps which are normally in a stand-by mode and automatically start following generation of a Safety Injection (SI) signal.
The CSS also employs centrifugal pumps which are normally in a stand-by mode and automatically start following generation of a High-High containment pressure condition. These pumps are initially aligned to take suction from the RWST and deliver borated spray water in the upper portion of the containment volume.
As the design basis event proceeds, the RWST water inventory decreases as water is transferred to the RCS and/or containment building. Upon depletion of a majority of the RWST inventory on the affected unit, the operating SIS and CSS pumps are required to be realigned to support the cold leg recirculation mode of operation.
At approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from event initiation, the SIS subsystem is realigned a second time to support the hot leg injection mode of operation. Mis time has been reduced from the current 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> due to increases in core decay heat associated with the uprate.
5.292 Input Parameters and Assumptions In general, the specified changes in RCS operating conditions addressed by the uprating have no direct effect on the overall performance capability of the SIS and/or CSS. These systems will continue to deliver a selected range of calculated flow performance as determined by interfacing system/structure operating conditions (RCS pressure, containment pressure, etc.). The acceptability of a given range of SIS and CSS performance is inherently justified by acceptable plant safety analyses results. For this project, numerous plant safety analyses were reanalyzed or evaluated.
For the High Head Safety Injection (HHSI) subsystem, a reduced minimum pump performance curve was used. The primary effect of this change on subsystem performance is a reduction in both "Cut-In" pressure and minimum flow delivery capability. Since the minimum allowable pump head decreased, mhl808w&6.wpf:ibw91195 5-7
revised flows were recalculated. The T'echnical Specification surveillance requested for the Sii.pumps (T.S. 3/4.5.2, 4.5.2c) is being revised in accordance with reduction of pump head by 100 feet.
5299 Description of Analyses/Evaluations As noted previously, the overall perfornaance of the.SISand.CSS.are independent of. the..RCS, operating conditions being evaluated as part of this project. The RCS operating conditions defined for this project do not affect system flow p:rformance. As such, existing flow capabilifies were generally used except as noted for the HHSI subsystem.
For the HHSI subsystem, revised minimum injection mode flows were sp:cifically recalculated to consider a further degraded pump performance culrve.
5.23.4 Acceptance Criteria for Analyses/Evaluation The general acceptability of system performance are documented in the individual plant safe+ analyses that utilize such inputs 523$ Results The performance of the SIS and CSS is independent of, the thermal uprating,analysis. The acceptability of the systems at uprated condlitions is justified by.aa'.eptable safety analysis results.,
5.29.6 Conclusions As stated previously, the general acceptabiKity iof the existing and newly calculabA SIS and CSS operating parameters defined .for this project are documented in thd various discussions of individual plant safety analyses-results as summarized in,'Section 3.0 of this repoit.
mal 808w~.wpf:1M81195 '-8
5.2.4 Residual Heat Removal System 5.2.4.1 Introduction The Residual Heat Removal System (RHRS) is a dual function system. During normal power operation, the system is in a stand-by mode to support its Engineered Safeguards function (i.e., safety injection). During the second phase of plant cooldown and the plant shutdown mode of. operation, the RHRS is used to remove Reactor Coolant System (RCS) sensible and decay heat. This section discusses the RHRS normal functions (i.e., heat removal). 'Ihe Engineered Safeguards functions of the RHRS are discussed in Sections 5.2.3 (SIS) and 5.5.2 (CCWS).
The maximum heat removal demand on the RHRS generally occurs during the plant cooldown mode of operation when RCS sensible heat (e.g., metal mass), core decay heat and'heat input from a Reactor Coolant Pump (RCP) must all be removed to support RCS temperature cooldown. In addition, operating restrictions are imposed on the maximum allowable CCWS temperature during cooldown which.,can also restrict RHRS heat removal capability.
The overall RHRS heat removal capability can vary significantly depending on system equipment availability, cooling support system equipment availability, cooling support system flows, RHRS and CCWS heat exchanger thermal performance (e.g., fouling level) and ICW System inlet temperature.
The Turkey Point system design basis considered only the normal cooldown condition-with all RHRS and associated cooling system equipment available. Once plant cooldown is achieved, only one train of RHRS equipment and associated cooling system support equipment is generally used to maintain RCS temperature.
52.42 Input Parameters and Assumptions Of the changes in RCS operating conditions due to the uprating, only the increase in reactor core power level has a significant effect on RHRS thermal performance capability. Specifically, higher core power levels will increase RCS decay heat loads, which must be removed during plant cooldown and shutdown conditions. From a hydraulic (flow) perspective, the revised RCS operating conditions have no direct impact on the flow delivery capability of the RHRS. Likewise, existing instrumentation and controls are. independent of uprated conditions and do not need to be evaluated.
For this project, RHRS thermal performance were calculated for the following cooldown scenarios:
~ The ability of the RHRS to accept the RCS heat removal function during the second phase of plant cooldown (i.e., RHRS Cut-In).
~ The ability of the RHRS to cool down the RCS with all equipment operating to a cold shutdown condition (200'F) and a refueling condition (140'F). Note: RHRS operation with all equipment mh1808wkhS.wpf:1M81195 5-9
available (including supiport systems) is refeirred to as a "normal" plant cooldown within'he context of this section.
~I
~ The ability of the RHRS to cool down the R.CS under a 1/mitling Appendix R postulated fire incident.
~ The ability of the RHRS to cool down the R.CS unifier limiting equipment availability to a cold shutdown condition (200'F).
A set of thermal analysis operati.ng conditions which wduld bound both current andi expected thermal uprate plant conditions was developed.
5.2.49 Description of Analyst/Evaluations The thermal (cooldown) performance of the RHRS was levaluated for the scenarios of RHR irutiation, normal cooldown, Appendlix R cooldown and abnormal cooldown. The evaluation of these scenarios considered normal equipment alignment and various cashew of selected components unavailable!. These assumed operation of RHRS, CCWS,, ICW and RCS equipment in different 'ases conQguratidns.'ormally one RCP is in operation during EQ6(S coo1ldoWn to promote miixing within the RCS lolops Several cases were analyzed assuming no RCPs in operatiori.
5.2.4.4 Acceptance Criteria for Analyses/Evaluation During a typical plant cooldown event, the RCS is cooled Rom its~ "no-load" condition to the RHRS cut-in condition of 350'F by. providing secondary side water to the steam generators. For abnorntal conditions where the Condensate Storage T'ank (CST) will prov'ide'the water, the RHRS must'be of accepting the RCS heat removal prior to depletion o: f the CST inveritory. 'apable The normal cooldown scenario assurues all cooling trains are available. The original RHRS equine!nt criteria was selectedl to acl;ueve a refueling condition in a'ertain time based on economic 'izing considerations. As such there is no a speciGc des.'ign basis acceptance criterion f'r the normal cooldown. However, the standard Technical Specificatidns typi'cally speciify a 36-hour time dimtion for achieving cold shutdown under certain conditions.
For an Appendix R event, the plant is required to be in cold shutddwn within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of the event initiation considering the poss,ibility of a. concurrent loss-'of-*ffsite. gwer condition. Credii; can be taken for operator action. The AipPendix R cooldown, asSumles Only a single active train of coblirig equipment is available.
m:u 808w&6;wpf:I M81195 5-10
5.2.4$ Results Under various scenarios of different equipment either available or not, the RHRS was found capable of accepting the RCS heat removal function within the required time frame.
For normal cooldown under the most restrictive operating parameters and with all cooling equipment available, the RHRS is able to cool the RCS to Cold Shutdown conditions within the standard Technical Specification cooldown time of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
For an Appendix R cooldown,under the most restrictive operating parameters with one train of active cooling equipment available and loss of offsite power, it was determined that the RCS could be cooled down within the criteria.
5.2.4.6 Conclusions The evaluation of the RHRS at the uprated conditions has been performed: and it is concluded that the RHRS can perform its design basis functions.
m:u &0&wM6.wpf:1b/091195 5-11
5.2$ NSSS Sampling System 5.2$ .1 Introduction The NSSS Sampling System is designed to permit remote sampling of fluids from the jReactot Coolant System (RCS) by means of permanently installed lines. The system can obtain samples from the pressurizer liquid and steam space, the jRCS A and B hot legs, the three accumulators, the residual heat removal loop, the letdown lines at the Met and outlet of the demineralizers, the Volume Control Tank (VCT) gas space and the three steam generators (secondary side). ~
The sampling system integrity and performance is directly linked t6 the systems to which it is connected. Of the systems where samples are taken from, the RCS yields the highest pressure arid temperature challenge to the sampling system. Therefore, the sampling system has been designed to bound the RCS maximum temperature and press'.
At the uprated conditions, the changes in the RCS'operating conditions may affect the performance of the sampling system. The satnplia, espaia)ly those taken directly .from the RCS, are impacted by the changes in the RCS winch include increases in core power and the allowable operating range for average RCS temperature gavg)The calculated RCS design operating conditions are based On the conditions. 'prated 5.282 Input Parameters and Assumptions The range of RCS operating conditions are the basis for determining limiting conditions on the sampling system. The limiting conditions are compared to the original system design parametlersl 5.289 Description of'nalysestEvaluations Performed In the assessment of system operation, the maximum sample ternperaoae based on the maximum expected RCS temperature are: compared to the, sampling system mechanical design temperature.
'2$
.4 Acceptance Criteria for AnalysestEvaltLations In the assessment of systetn operation, the maximum ex+ctdA Sample temperature and pressure must.
be less than or equal to the applicable sample system medhalnichl dj:sign temperature. This enlsurda the integrity of the system.
52$ $ Results Of the changes due to 1he thermal power upratiing, the increase in range of RCS temperatures has the most direct impact on the, sampling system. At the maximum uprated Thot temperature, samples taken from the RCS hot leg are welli within the sampling system mechani'cal design temperature.
mhl808wM6.wpf:M81195 5-12
However, with respect to.samples taken from the RCS, the pressurizer liquid and steam samples yield the most limiting conditions on the sampling system. The samples taken from the pressurizer are at a higher temperature since they. are initially at saturated conditions. For the thermal power uprating the RCS operating pressure is not affected; therefore, the. maximum expected temperature of the samples taken-from the Pressurizer is also not affected (i.e., the saturation temperature at the RCS, pressure is unchanged).. The performance of the sample system piping and sample heat exchangers remain acceptable for the thermal power uprating.
5.2$ .6 Conclusions The sampling system can continue to perform its design basis functions without any anticipated plant changes.
5-13
5.2.6 Head Vent/Pressurizer Vent 5.2.6.1 Introduction
'Ihe Reactor Coolant System (RCS) is provided with tw'o primary vent paths for post-accident hydrogen venting and to sup1port plant operations. One vent is provided near the top of the preslsurizer and is tied-in to the common piping which connects the pressurizer head to the two power operated'elief valves. 'lite second vent is tied-in to a connection near the top of the Reactor Vessel (RV) hmd.
For both vent paths, 0uo power operatcxf isolation valve's ar'e provided in pat@lel to ensure that a given path can be opened. These vents 8',so utiliize common discharge piping that allows flow to be directed to either the Pressurizer Relief Tank (PRT) or directly to conMinrnent (if desired). The two discharge paths are each provided with a power operated isolation valve to ensure positive illation.
In general, the RCS vents are used to support normal plant operations (e,g., RCS draining and filling) and post-accident conditions (e.g., vent non-condensible gases that can interfere with core cooling).
The safety related functions of the vent lines are 1) to ahaidtairi RCS pressure boundary integrity when i the system is not in uM:, 2) to support venting operation'hen required during post-accident dunditions and 3) to be capable of being isolated following venting operations.
The primary changes due to uprating include Iincreases in core power, SG tube plugging level and the allowable operating range for average RCS temperature (Tavg). 'Ihe potential impact on the RCS vent systems are described below:
~ With changes in iRCS operating conditions, the operating temperature of vented fluid cM either increase or decrease.
With increased SG tube plugging, RCS available volume re~decrease.
52.62 Input Parameters and .Assumptions In evaluating the uprated condition, a 20% SG tube plugging level was consiidered because it reduced the available RCS volume,. The range of RCS operafing teNperattues at the uprated condition was used to evaluate the adequacy of the vent system design'emperature. Only the portion of vent piping that comprises the RCS pressure boundary is requRed to be evaluated to ensure pressure boundary integrity.
5.2.69 Description of Analyses/Evaluations In general, an evaluation process was used to assess the overall acceptability of the vent systems at the Uprate revised operating conditions. To assess the impact of increased S/G tube plugging, 'hermal the RCS volume basis used in sizing the vent, systems Was devibwdd. To assess the impact of. revise,d mh1808w&6.wpf:1M81195 5-14
RCS operating temperatures, the maximum expected RCS Thot temperature was compared.to system design temperatures.
5.2.6.4 Acceptance Criteria In the assessment of system vent sizing, the actual RCS volume should. be less than or equal to.the volume criteria to ensure that venting durations remain bounding. In the assessment of system operation at the higher range of RCS Tavg condition, the maximum expected RCS Thot temperature must be less than or equal to the applicable system design'temperature to.ensure pressure boundary integrity.
5.2.6$ Results Me RV head vent flow rate capability is'based on venting 1/2 of the RCS volume within a one-hour duration. Since the net effect of any'S/G tube plugging is a reduction in.RCS total volume, the existing system venting flow rate capacity is unaffected.
With respect to revised.RCS operating, temperatures, the uprated Thot temperature is increased but is lower than the design condition of the head, vent and pressurizer vent piping that comprises the RCS pressure boundary. Since the revised Thot temperature is well within these design conditions, pressure boundary integrity is ensured.
5.2.6.6 Conclusions Based on the evaluation outlined in this section, the pressurizer and RV head vent systems are not impacted by the changes in RCS operating. conditions associated with the Thermal Uprate project. As such, these systems can-continue to perform their design basis functions without requiring any plant changes.
mh1808w~.wpf:1M81195 5-15
52 CONTROL SYSTElMS Control systems were evaluated .in order to verify that adequatl: margin t6 reactor protectiOn SystemS setpoints exists at the uprated conditions for the followittg desiIgn basis transients:
50% load rejection from full power 50% load rejection from 50% power 10% step load decrease 5% per minute urut loadie~unloading Results of these analyses indicate that adequate margjn exists and that the plant is adequately stable at the uprated conditions. As such, no changes to control systems setpoints are recommended.
mA1808wM6.wpf:1M81195
5.4 REACTOR PROTECTION SYSTEM/ENGINEERED SAFETY FEATURES ACTUATION SYSTEM SETPOINTS The Technical Specification Reactor Protection System/Engineered Safety Features Actuation System setpoints, and the Core Operating Limits Report have been reviewed for plant operation at a core power level up to 2300 MWt for the RCS- flow limit. As part of the review, Technical Specification changes were necessary to meet NRC approved Westinghouse setpoint and RTDP methodologies (References 1, 2, 3, and 4).
Tables 5.4-1 and 5.4.2 list both the current and proposed values for each function and parameter impacted. Incorporating these Technical Specification changes will ensure that the Turkey Point Units 3 & 4 will operate in a manner consistent with the UFSAR assumptions.
References:
- 1. WCAP-12632, "RTD Bypass Elimination Licensing Report for Turkey Point Units 3 & 4,"
June .1990.
- 2. WCAP-12745, Revision,1, "Westinghouse Setpoint Methodology for Protection Systems Turkey Point Units 3 &, 4," December 1995.
3.'CAP-13719, Revision 1, "Westinghouse Revised Thermal Design Procedure Instrument Uncertainty Methodology Florida Power & Light Company Turkey'Point Units 3 & 4,"
January 1995.
- 4. WCAP-13719, Revision 2, "Westinghouse Revised Thermal Design Procedure Instrument Uncertainty Methodology Florida Power & Light Company Turkey Point Units 3 & 4,"
June 1995.
mal 808w1ch5.wpf:1b/1 13095 5-17
Tab1le 5.4-1 Summary Of The, Reactor Protection System Setpoint Changes TURKEY POINT TECHNICAL SPECIFICATION TABLE 22-1 REACTOR TRIP SYST: EM INSTRUMENTATION CURRENT A]MD PROPOSED'RIP SETPOINTS Overtemperature b,T Reactor Trip Functional Trip Setpoint 'llowable Value Unit 5 Current Value"'l Proposed Value Current Value'> Proposed Value K, 1.25 1.24 i0.73 0 84 0.016 0..01/ N/A N/A K3 0.0011 0.00'10 N/A N/A
<~74.2,'F <577 ')'F N/A N/A
-b,l Gain 1.5 0.0 N/A N/A
+b,i Gain 2.19 N/A N/A f(b.i) Penalty -46, -50,,
Dead-band to to N/A
+2 +2 Overpower /) T Reactor Trip Functional Trip Selpoi'nt Allowable Value Unit 6 Current Value", Proposed Value Current Value" Proposed Vaj!ue 1.10 N/C 0.96 0.002:32 0.,00]I6 N/A N/A
<&74.2'F <&77.2'F N/A N/A
'he information provided in lAis column represents the parameters provided to the NRC via FiPL i Letter I 95-131, Implementati'on of the Revised Thermal Design Procedure and Steam Generator Water Level Low-Low Setpoint.
N/A - Not Applicable N/C - No Change mhl808wMh5.wpf: Ib/1 10995 5-18
Table 5.4-1 (Continued)
'Summary Of The Reactor Protection System Setpoint Changes TURKEY POINT TECHNICAL SPECIFICATION TABLE 2.2-1 REACTOR TRIP SYSTEM'INSTRUMENTATION CURRENT AND PROPOSED TRIP SETPOINTS Reactor Coolant Flow-Low Functional Trip Setpoint Allowable Value Unit 10 Current Value'roposed Value Current Value'roposed Value Footnote 90% TDF
" 90% TDF "'8.8% N/C Steam Generator Water Level Low-Low Functional Units Trip Setpoint Allowable Value 11 and 12 Current Value Proposed Value Current Value" Proposed Value Setpoint >10.0 N/C 28.9 28.15 "The information provided in this column represents the parameters provided to the NRC via FPL Letter L-95-131, Implementation of the Revised Thermal Design Procedure and Steam Generator Water Level Low-Low Setpoint.
N/A - Not Applicable N/C - No Change Thermal Design Flow = 89,500 gpm
- ~* Thermal Design Flow = 85,000 gpm mh1808wkh5.wpf: tb/110995 5-19
Tablle 5.4-2 Summary Of The Engineered Safety Features Actuation System Setpoint Changes TURlWY POINT TECHNICAL SF'LCIFICATIONS TABLE 3.3-3 ENGINEERED'AFETY FEATURES ACTUATIOlV SYS2 EM INS2'RUMENTATION 2'RIP SETPOINTS CURRENT AND PROPOSED TRIP SETPOINTS Steam Generator Water Level Low - Low Functional Unit Allowable Value 6.b Value'roposed Value Current Valu6/'/ Pro posed- Value, ,Current Setpoint 210.0% iN/C ~:8.9% >8.15%
mA1808wkh5.wpf:1b/101695 5-20
Table SA-2 (Continued)
Summary Of The Engineered Safety Features Actuation System Setpoint Changes TUREEY POILVT TECHNICAL SPECIFICATIONS TABLE3.3-3 (Continued)
E1VGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMElVTATION TRIP SETPOINTS CURRENT AND PROPOSED TRIP SETPOINTS High Steam Line Flow Functional Units Trip Setpoint Allowable Value 1.f and 4.d Current Value" Proposed Value Current Value" Proposed Value Setpoint <40% <42.6%'44%
5 A function defined as follows: A dP corresponding to 40% Steam Flow at 0% load increasing linearly from 20% load to a value corresponding to 120% Steam How at full load.
< A.function defined as follows: A dZ corresponding to 40% Steam Flow at 0% load increasing linearly Rom 20% load to a value corresponding to 114% Steam Flow at full load.
< A function defined as follows: A LQ'orresponding to 42.6% Steam How at 0% load increasing linearly from 20% load to a value corresponding to 122.6% Steam How at full load.
¹¹ < A function defined as follows: A W corresponding to 44% Steam Flow at 0% load increasing linearly tiom 20% load to a value corresponding to ltd.5% Steam Flow at full load.
"The information provided in this column represents the parameters provided to the NRC via FPL I
Letter 95-l31, 'Implementation of the Revised Thermal Design Procedure and Steam Generator Water Level Low-Low Setpoint.
N/A - Not Applicable N/C - No Change m:u808trr&6.wpf:1M81895 5-21
5S NSSS/BALANCE-OF-PLAÃiT (BOP) INTERFACE SYStI'EMS 5$ .1 Auxiliary Feedwater System/Condensate Storage Tank 5$ .1.1 Introduction The Auxiliary Feedwater (AZW) System is evaluated to exIsure tihat the current AFW flows and startiag times are acceptable to support design basis plant transients at plant uprate condlitions. In addition, the Condensate, Storage Tanllcs (CSTs) are evaluated to ensure that their capacity is adequate to supply the AFW System at plant uprate conditions.
The AFW System is a Safety Related system, and )is shared between Uaits 3 and 4. The AFW System supplies feedwater to the steam generators (SGs) duri11g transients when normal feedwater sources are not available.
'Ihe following are the design basis transients that establish the minimum/maximum d~ System requirements:
SBLOCA in combinati,on with a LOOP (both units),
LOOP to both units, LOMF (single unit), and MSLB.
The most limiting plant traasieats requiring minimum AFW flout are a LOOP event or a SBLOCA concurrent with a LOOP. 'Ihe worst case transient for a single unit requiring minimum AFW flow is a LOMF. Maximum AF'W flow to any one of the SGs is'determined usiag the maximum fliow assumed for a MSLB event.
In addition to flow requirements, the ARV System is Ileqttired to begin delivering water to The SGs within: a set delivery time at a pressure equal to or greater than the set pressure of the lowest set SG safety valve, plus 3% acicumulation pressure.
A minimum CST volume for the 8~/ S'stem is requlired for accident mitigation and subsequent cooldown of the plant to the: RIM System initiation conditions.
5$ .12 Description of Analyses/Evaluatiotii Performed The evaluation consisted of compariag the AFW Systetn minimuim/maximum flow inputs uSed in the uprate core response and mass and energy relea.'e analyses of the LOMF, LOOP, SBLOCA (with LOOP), and MSLB eveaits to the calculated expect+i flo4s tO de'termini'. whether uprate affi'.cd th0 AFW System's capability in supplying feedviater to thk SGs.
mh1808w&d.wpf:Ib/091195 5-22
In addition, existing CST and AFW System component design parameters and Technical Specification requirements were reviewed to determine if the existing CST volume and AFW pressure and delivery are adequate at the uprate condition.
The evaluation identified that the flows utilized in the core response analyses for the LOMF, LOOP, and SBLOCA with LOOP events are. less than or equal to the minimum flows calculated. It was also found-that the flow utilized in the mass and energy analysis. for a MSLB event is equal to the calculated, maximum flow.
It was also determined that the AFW System components have sufficient margin to provide the required flow and pressure, and that the stroke time of the motor operated AFW steam supply isolation valves provided adequate time in delivering AFW flow to the SGs.
The CST minimum usable, volume which is required to support the. design basis that the plant be maintained at hot standby for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> followed by a four-hour cooldown to RHR cut-in temperature (350'F) was also determined for the uprated power. This minimum usable volume is 199,100 gallons.
5$ .19 Conclusions t The existing AFW System and CST are capable of providing the required AFW flow and volume needed to support the design basis transients at plant thermal uprate conditions.
mA1808wMhs.wpf:tb/091195 5-23
5.52 Component Cooling N'ater System 5.52.1 Introduction The Component Cooling Water System (CCWS) iis an intermediate closed-loop cooling~system between NSSS equipment which potentially process radioactive fluids, and the plant ultimate heat sink.
The primary CCWS functiIon is heat removal which is accomplIIshed by the continuous recirculation of, flow within two main cooling headers. The CCWS is required to operate for all normal and abnormal operating conditions., Ultimate, heat sink cooling flow is provided by the Intake Cooling Water 'lant (ICW) System which cielivers flow to the tube side of th'e CCWS heat. exchangers.
In addition to traditional system cooling requirements, thte TIurkI:y Point Units 3 and 4 CCWS'lso provides cooling to the containment building atmosphere. Separate sets of containment coolers (air-to-design) are used to perform this function for normal plant operations and post-accident operating 'ater
~
conditions. The post-accident function is provided by Emergency Containment Cooler., (ECCs), of, which three are provided. As part of uprate, d',esign changes will be made to assure no more than 2 ECCs will automatically start in response to an accident.
CCWS heat removal capability will change depending on various operational factors. In general) system heat removal capability becomes more restrictive with the following operating contHtion changes:
Higher CCWS cooling heat loads Higher CCWS heat exchanger tube plugging i Higher CCWS heat exchanger fouling Lower ICW flow to the CCWS heat exchanger Higher ICW temperature to the CCWS heat exchanger The evaluation of the CCWS .for the 'Ihrkey Point uprated condition considered the opt,:rational modes of Power Operation (including st utup), Residual Heat Removal (KHR) cooldown (including and refueling) and Post-Accident (injection and recirculation).
cold'hutdown 5622 Input Parameters and Assumptions In general, the thermal performance of the CCWS (in cohjtutctiOn 4vith the ICW System) was evaluated or analyzed under "worst-case" operating conditions to ensure conservative operating performance. Of the. changes in RCS operating conditions due to uprating, only the increase in reactor core power level has a signiflcant effect on CCWS thermal performance capability. Specifically, higher core power levels will .'increase RCS and Spent Fuel Pool (SFP) decay heat loads which must be removed during all operating conflgurations.
mh180Sw~.wpf:IM81195 5-24
Provided'below are the critical CCWS heat removal functions that were reviewed as part of this project:
~ Accommodate expected Power Operation configuration heat loads while maintaining supply temperature to within the existing maximum normal limit.
~ Support the RHR System relative to its RCS decay heat removal function. This capability is discussed in the RHR System section of this licensing report (See Section 5.2.4).
~ Maintain operating temperatures during post-accident configurations within NSSS equipment cooling requirements. Peak system operating temperatures. occur during post-accident operations due to elevated containment conditions and unrestricted heat rejection into the CCWS.
~ The adequacy of the CCWS piping network at projected operating temperatures.
In general, input parameters were chosen to yield conservative analysis results based on allowable variations. For example, containment integrity analyses inputs were established based on minimum heat transfer conditions. System thermal analyses, however, maximized heat input into the CCWS in order to establish maximum operating temperatures.
5.523 Description of Analyses/Evaluation For the Power Operation and RHR Cooldown configurations, thermal performance calculations were performed at steady-state plant operating conditions using standard water-to-water heat exchanger heat transfer equations and generalized heat transfer methodology. During postulated design basis events, the CCWS major heat loads (ECCs and the RHR heat exchangers) are variable in nature and vary significantly with containment operating conditions. Therefore Containment Integrity analysis methodology was used to conservatively calculate limiting CCWS and ICW System post-accident operating conditions. Input parameters to these analyses were modified to maximize CCWS and ICW Systems'perating temperatures.
As part of this project, maximum expected CCWS operating temperatures were conservatively defined/calculated for use in the evaluation of system piping stress analyses. For this work, maximum expected CCWS inlet temperatures and minimum expected component fiows were generally used to calculate worst-case component outlet temperatures.
5.52.4 Acceptance Criteria For the Power Operation configuration, the capability to maintain the CCWS supply temperature at or below the maximum allowable temperature. Credit can be taken for operator actions to reduce variable CCWS heat loads, if required.
mh]808wM6.wpf:1M81195 5-25
For CCWS performance capability during post-ac'cident operatiion, the following are the most critical CCWS operating temperatures:
CCWS Heat Exchanger Shell,'Side Inlet (return) Tit.mperature CCWS Heat Exchanger Shell,'Side Outlet (supply) Te&perahire ECC CCWS Outlet Temperature RHR Heat Exchanger CCWS Outlet 'Temperature For the CCWS heat exchanger retuin temperature, verification that the CCWS outlet temperaturei remains at or below the point where two phase flow cait occur'and within CCWS pump Net Positive Suction Head (NPSH) lirrutations is require. This ensures that single phase (i.e., liquJid) flow conditions continue to occur and. that the CCWS pump would confinue to operate.
For CCWS supply temperature, verific'ition that it remains witlun analyzed limits is needed tO eiisur'e that equipment cooled by the system remaiins operable.
For the ECC and RHR heat exchangers, verification that the CCWS outlet temperature remains at or below the point where two phase flow can occur. With single phalse (i.e., liquid) fiow conditions, continuous heat removal would occur.
With respect to CCWS piping structural integnty, a set of maxiimum CCWS operating tempeitatures ~
were defined for use in CCWS piping stress reanalyses. Thtis criterion ensures ovei@1 systeml piPinP availability/operability under worst-use operating conditions.
5$ 2$ Results 5$ 2$ .1 Power Operation For Power Operation it was found that the maximum CCWS supply temperature could be maiintained at or below its maximiim '.limit with only two CCWS heat exchangers in service. Operator actioits may be necessary to restrict system heat loads dtuing limiting ICW'ystem operating conditions (elevated ICW inlet teiuperattire, elevated tube fouling, etc.). An etxample of such an operator action is the reduction of non-essential heat loads 5$ 2$ 2 Post Accident
'Ihe Large Break LOCA and the MSLB inside containment accidents result in the highest heat input condition to the CCWS. The CCWS thermal nsponse duririg both the inj,ectiion and recirculation'odes was considered. Calculations showed that when all three ECCs are allowed to operateCCWS operating temperatures can be above its maxiinum allowable limits dmng injection and/or recirculation. When only one or two ECC's are assumed to statt, CCWS acceptance criteria atre met.
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The piping stress analyses results showed that CCWS operating temperatures are within maximum allowable values.
5.52.6 .Conclusions Based on the CCWS thermal analyses and associated component evaluations performed at uprated condition, it is concluded that the CCWS is capable of performing its intended cooling function: For post accident conditions, this is based on allowing no more than two ECCs to automatically start on an "SI",signal.
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5.59 Normal Containment Cooling System 5.53.1 Introduction
'Ihe Normal Containment Cooling System (NCCS) is not safety related and has no impact on the plant licensing basis.
During normal plant operation, the NCCS removes the heat loSt from all equipment and pipihg in containment, and maintains containment bulk ambient tAmgratur6 at or below a normal ambient temperature of 120'F. The NCCS also provides sufficient air mixing and circulation throughout all containment areas to permit maintenance and/or refueling operations after reactor shutdown. ~
The NCCS is comprised of, the Normal Cont'unment Coolers (NCCS) and the Contro'.i Rod Drive Mechanism (CRDM) Coolers. The NCCS consists of four cooling units and associated ductwork. The CRDM, consisting of two cooling u,nits and associated ductwoik, Supplements the NCCS, and cd be to remove heat from the reactor vessel head during natural circulation cooldown. 'sed The required cooling coil cleanli.ness is maint uned by regular cleaning, inspection and prevehtiW maintenance practices
,5.532. Description nf-Analyses/Evaluation Performed The-NCCS evaluation consisted of comparing the, totA heat. load in containment due to uprate with the total heat removal load provided by the. NCCS and CRDM cooling urllts during normal operon and assuring that the NCCS can maintain the contairunent operating temperature at or below 120~F. Thb expected increase in the containment total heat load was calculated to be less than the heat rdm&val capacity provided by the number of cooling units currently operating at Units 3 and 4. Due to the current margin in heat load removal capabiility, and the ini6im9 expected increase in total heat load with uprate, operating temperatures inside contaimnent are expected to increase no more than 2'F above current levels.
Regardless of the number of cooling units currently used in~ plant operation, normal operating temperatures in contaimnent have not reached the 120'F litnit. Representative operating temperatures recorded in containment for May through July 1993 range approximately between 101'F and 117'F for Unit 3 and 100'F and 117'F for Unit 4. 'Ihese temperature ranges are reasonably conservative as they include full-power operationin summer montl e.
In addition, in the unlikely event. that contlunment operating temperate were to exceed 120'F, but 125'F, the Technical Specifications allow operation to continue for a cumulative 336 hou'rs per 'ot at a temperature not to exceed 125'F. 'ear
~
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5.599 Conclusions The increase in containment total heat load and operating-temperature due to uprate will not impact the capability of the NCCS to maintain containment operating temperature below the design basis of 120'F. The design capacity for NCCS and CRDM cooling units exceeds the heat load expected at uprated conditions.
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5S.4 Emergency Contaiinment Cooling ancl Filtering Systems 5.5.4.1 Introduction The safety-related Emergency Containment Cooling and Fil'tering Systems (FCCFS) is used in conjunction with the Containment Spray System (CSS) to provide adequate 1heat removal capabi)ity ~in ~
containment following a Imss of Coolant Acc1ident (LOCA) or Main Steam Line B~eak (MSLB). In addition, the ECCFS is used to provide adequate air reciirculatidn capability in containment following a LOCA to reduce the iodine concenhetion and prevent hydrogen cOncentration buildup. Tlhe ECCFS is comprised of two systems; the Cooling System and the Filtering System.
The ECCFS is comprised of three Emergency Containment Coolers (FCCs) only one of which is required to remove heat fi om containment atmosphere t(i keep 'the'containment temperature and from exceeding design Ilimi.ts. In addition, the cooling system provides air recirculation for
'ressure hydrogen dispersion following a LOCA., to impede hydrogen accumulations from reaching flammable or explosive concentratioris in the contammzenI'. The Cooling System's minimum heat removal capability is modeled in the Containment Intetpity analysis as a function of temperature and the performance of each ECC is used as an input in determining the LOCA long-tenn pressure and temperature transient effects. The Cooling System's maximum heat removal capability is modeled in the Component Cooling Water System (CCWS) pest-accident thermal analysis to limit CCW temperatures.
'Ihe ECCFS is also comprised of three Emergency Conthirutient Filters (ECFs), any two of which must operate following a LOCA with failed fuel to remove freya iodine from the containment's atmosphere.
Each ECF contains a spray system, which:is used to remove decay heat from the charcoal filters in the event of a loss of forced air flow through the charcoal filter. The Filtering System's iodine reduction capability is modeled in the Environmental Consequences of a Loss-of-Coolant Accident analysiC (e.g., offsite dose analysis).
5$ .42 Description of Analyses/Evaluation Performed
'Ihe ECCFS evaluation consisted of determining ifuprate affects the ability of the FCCFS components based on the Containment Integrity Analysis, the Hydrogen Concentration Analyses, and the Offsite Dose Analysis results. In adclition, the effect of a, 3% increase in CSS flow temperature due to uprate
'n the heat removal capability of the'ECF,spray system was determined using existing limiting CSS flow parameters.
Uprate was determined. not to affect the design of the ECCs or the equipment associated with them as the Containment Integrity, Offsite Doseand Hydrogen ConCentration Analyses yield acceptable results ~
that do not impact the existing design of the ECCFS components.
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The uprate ECC CCW inlet and.outlet temperatures are bounded by the existing design temperatures.
As such, changes in CCW flow parameters due to uprate will not affect the ECC equipment design.
The Hydrogen Generation Analysis for the Turkey Point Units 3 and 4 uprating is discussed in
,Section 3.6.2.
The Offsite Dose analysis for the plant thermal uprate is based upon the existing 'ECF fiow rates and filter efficiencies. Therefore,, there is no impact on the ECF's iodine reduction capability at the uprated power level.
In utilizing the existing CSS inlet flow conditions at uprate, the CSS flow.~T was determined not to increase. However, the maximum inlet and outlet temperature will increase by approximately 5'F.
Based upon a maximum inlet flow temperature of 205'F, the charcoal filters were found to be maintained at less than, the design basis limit of 250'F.
In addition, the time the ECF spray systems are required for post-accident:conditions were found to not be impacted by plant uprate because the.,pre-uprate analysis is based upon a core power of 2300 MWt (plus 2%).
5S.49 Conclusions The plant~thermal uprate to a core power of 2300 MWt (plus 2%) will'not impact the capability of the ECCFS to provide both adequate. heat removal capability following an MHA, and adequate air recirculation to reduce the iodine concentration and provide. hydrogen concentration control following a LOCA.
This conclusion is supported by the uprate Containment Integrity, Hydrogen Concentration, and Offsite Dose analyses which utilize existing,ECCFS component data, as documented above, and,yield results within existing design limits.
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5.5$ Spent Fuel Pool Cooling System 5.5$ .1 Introduction The Spent Fuel Pool (SFP) Cooling System removes decay~ heat from the spent fuel assemblies stored in the SFP during plant operations and refueling. A small portion of the cooling fiow can bel di0eWd through a demineralizer and .filters for pmification of'h6 water. Surface debris in the SFP is removed via two skimmers, a skimper pump, and amociated filters. Each Unit's spent fuel pool cooling looip consists of pumps, heat exchanger,:filters, demineraliizer, piping, aud Msociated valves and instrumentation. The pump draws water from the SE'P, circulates .it tluough the heat exchanger ~vhere it is cooled by the Component. Cooling Water (CCW) System.
The SFP cooling system is designed to maintain iits cooling fuActi6n during and after a, seismic event, and to structurally witlhstamd a design temperature of 212'F,. The SFP is designed to withstand stresses associated with a steady-state gr;Mlient of 150'F.
With the installation of high density spent fuel storage rack!i, the SFP cooling system was reevaluated to determine the effect on the system o: f increasing the spent fuel storage capacity. The high density fuel storage racks increased the pooll capacity from 4 2/3 cores'to 9 cores (Note.", the evaluation assumed 1413 assemblies which is 9 more assemblies than the 'actlial maximum storage capaciity of 1404 assemblies). This expansion of the sipent fuel storage in the pool increised the decay heat load for each pool and the pool peak transient water temperature after refueling to less than 141'F., With a freshly discharged core, p1lus,the heat load from the previously discharged fuel (i.e., 7 1/2 corda),'h6 pool water temperature: is maiintained less than 180'F.
5$ $ 2 Description of Analyses/Evaluation Per'forined The Thermal Uprate will increase the core power level 6'oml 2200 MWt to 2300 MWt. Since'hd decay heat rate of the gent fiiel .is a. function of the core power level, the SFP cooliing heat load will increase. This increase wiill result in higher heat loadls transferred to the CCW system and increased operating temperatures in the spent fuel pool. The thermal power uprate iis not expected to impact the impurity level in the spent fuel pool and the design of th'e piirification loop will not be impact'ed.
The SFP cooling was evaluated at the uprated power level th ddterfnine the iinpact on the SFP heat load and resultant maxiimum bulk: temperattire. The followii>g eases consistent with the UFSAR Appendix 14D and SRji'uidelines were: evaluated:
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Case 1 Normal Refueling 1/2 core offload at 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> after shutdown Case 2 Normal Operation 1/2 core offload at 36 days following shutdown Case 3 Abnormal Operation with SFP Cooling Full core offload at 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> following a forced shutdown. with 1/2 core recently offloaded (36 days after a;normal refueling shutdown)
Case 4 Abnormal Operation without SFP Cooling Full core offload. at 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> following a forced shutdown with 1/2 core recently offloaded (36 days after a normal refueling shutdown)
For this case the makeup rate to replace SFP inventory-due to tboil off should also be determined.
Based on the results of the evaluation, the impact, of the uprated power level is as follows:
Case 1 Normal Refueling The maximum expected SFP heat load and temperature for a 1/2 core offload at 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> after shutdown is 16.6 MBTU/HR and 147'F.
Case 2 Normal Operation The maximum expected SFP heat load and temperature for a 1/2 core offload at 36 days following shutdown is 10 MBTU/HR and 130'F.
Case 3 Abnormal Operation with SFP Cooling The maximum expected SFP heat load and temperature for a full core offload at 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br /> following forced shutdown with 1/2 core recently offioaded (36 days after a normal refueling shutdown) is 35.5 MBTU/HR and 194.5'F. The time to reach the maximum steady state temperature with SFP cooling is 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
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Case 4 Abnormal Operation without SFP Cooling The maximum expected SFP heat load and temperature for a full core offload at 150 hotirs a forceps shutdown with 1/2 core recently offloaded (3(5 days after shutdown) is 'ollowing 35.5 MB EU/HR and 212'FThe time to reRh boilingI wi'th no SFP cooling is 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
The maximum boil off (makeup) rate at 212F is 76.3 GPM.
5$ $ 9 Conclusions The existing SFP coolIing will be adequate for the uprated c'onditions. The maximum expected temperature for,a 1/2 coie normal refueling is 147'F which is below the steady-state gradient design temperature of 150'F. The maximum temperature was c@cI~lated based on conservative decay'eat loads, rapid core offload, madmum cooling water temperature, and a 1/2 core offload. The decay heat load evaluation indicates that the temperature would remain above 140'F for approximately 150 hours0.00174 days <br />0.0417 hours <br />2.480159e-4 weeks <br />5.7075e-5 months <br />.
Also experience from previouis refuelings and data taken during the tJnit 4 1994 outage, demonstrate that the expected temperature for a full core offload in the SFP willi be below that calculated.
For the abnormal case of a full.core offload following a-recent noiinal refueling the maximum temperature calculated is 194.5'F with SFP cooling. The SFP coo'ling loop is designed to reiIaail functional during and followiiag a seismic everIt, and structu~rallIy withstand a design temperattire of 212'F. With a complete loss of SFP cooling, the temperatute will reach boiling (212'l.) in about 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.. The makeup rate to replace water loss due to boiling is approximately 76.3 gpm. Theie ik still sufficient time to provide makeup at ah available makeup rate of 10G gpm to maintain the SFP inventory.
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5.6 TURBINE-GENERATOR SYSTEMS The Turkey Point turbine, generator system designs have been evaluated to determine their operability under uprated conditions. The following provides a summary of each system's acceptability of performance under the proposed uprated conditions.
5.6.1 Component Evaluation 5.6.1.1 Turbine
'The turbine has been evaluated for areas such as increased steam flow and variation in pressure, and generator, heat balance. The turbine meets Westinghouse acceptance for, continuous service at the total NSSS power of 2308 MWt .
5.6.12 Moisture Separator-Reheater (MSR)
It is expected that the current MSR will meet, or exceed, the requirements for the new heat balance for 2308 MWt.
5.6.19 Generator The proposed uprate in turbine input power to the generator is within the limits of the generator's
.capability curve. Westinghouse has reviewed the Unit 4.generator that was rewound'by ABB and since FPL has elected to operate the generator within the original capability curves, no modifications are required and Unit 4 is expected to perform the same as Unit 3.
5.6.1.4 Exciter and Voltage Regulator The evaluation for the exciter and voltage regulator confirm that no modifications are required and that they, can be operated at the uprated conditions.
5.6.1$ Coolers The lube oil coolers, generator seal oil cooler (hydrogen side), exciter air cooler, and hydrogen cooler
-have been evaluated and no modifications are required for operation at the proposed uprated conditions.
5.6.1.6 Miscellaneous Systems
'he turbine control:system, gland seal system, gland'steam leakoff piping, cylinder heating steam system, valve leakoff piping, gland condenser, lubrication oil system, and rotor turning gear have been m:u808w~.wpf:Ib/091195 5-35
reviewed and evaluated and no modifications are requirkd for kckptable operation at the proposed uprated condition.
5.6.1.7 Conclusions In this study of the turbine generator systems for the, up'rating, a review was made of the follOwing areas: the moisture separator-reheater, generator, exciter, voltage .tegdlator, coolers (lube oil,~ generator ~
seal oil, exciter air, and hydrogen), turbine control system, gl&d leal'system, lubrication oil system and the rotor turning gear. The basis f'or this eviduatiott was a review of the expected design conditions at the uprated power level. These conditions were compared to the applicable to determine the acceptability of operation at the higher power level. Previous modification design'riteria records. from both Westinghouse and FPL were checked to ensure that the latest plant conditions. were.
evaluated. In cases where design margin was minimal, plant o~perating data was also considered to determine whether the component could be approved for uprating.
The study results show that all the turbine generator systems and turbine auxiliaries re viewed meet the design criteria for the 2308 MWt upratiing. It is therefore acceptable from a systems viewpoint for the plant to operate at the uprated power level 5.7 Conclusions (NSSS and Turbiine Generator (TG)'ystetns.'Review)
The evaluations discussed above concluded that the design teq<Qrements of the NSSS fluid sgstents, Control and protection system, TG systems and NSSS/BOP interface systems are met for the Uprating and associated primary ternperan~e conditions.
mh1808w&6.wpf:1M81 195 .')-36
CHAPTER 6 BALANCE OF PLANT (BOP)
EVALUATIONS
6.0 BOP EVALUATIONS'.1 INTRODUCTION This section primarily focuses on the information requested in Regulatory Guide 1.70, Chapter 10, that applies to power uprating.
The power conversion systems were designed to utilize the energy available from the nuclear steam supply system. The original system and equipment sizing was based on an NSSS power rating of 2208 MWt and a steam flow of 9.60 x 10'b jhr. Uprating will increase main steam flow to 10.061 x 10'b jhr or approximately a 5% increase.
The system operating and design pressures and temperatures for uprated conditions were developed by preparing new heat balances to reconstitute a baseline and describe uprate conditions.
6.2 BOP SYSTEMS 6.2.1 Main Steam System The Main Steam (MS) System from the steam generators up to and including the Main Steam Isolation Valve (MSIV) assemblies are. safety related. The MSIV assemblies include the Main Steam Check Valves (MSCVs) and Main Steam Bypass Valves (MSBVs).
The Main Steam (MS) system design including the main steam isolation valve assemblies and main steam safety valves (MSSVs) were evaluated to ensure that system and component capabilities bound the main steam conditions at the 2308 MWt uprated power rating. The atmospheric dump valves and the condenser dump valves are discussed in Section 6.2.2.
The main steam design conditions of 1085 psig and 600'F remain unchanged and bound all predicted operating conditions for both the system and components. At 2308 MWt, the predicted main steam flow is 10,061,000 lb/hr, an increase of approximately 5% over the original Westinghouse maximum guaranteed steam flow of 9,600,000 lb/hr . The predicted uprate main steam flows are 0.2 % less than the original maximum calculated conditions. The changes to the predicted operating pressures and temperatures at the uprate power conditions have no negative effect on the system piping or design.
The predicted increase in the main steam operating flow was evaluated for increased erosion/corrosion concerns. Because of the small increase in the piping velocities associated with the uprate, the E/C impact will be small. The plant E/C program will continue to monitor for material degradation.
Four MSSVs are located outside containment on each of the three main steam lines to protect the steam generators and MS piping Rom over-pressure. The safety valves discharge to atmosphere are designed and manufactured:in accordance with ASME Boiler and Pressure Vessel Code, Section III.
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Re-analysis of the Loss of External Load Transient Analysis (UFSAR Section 14.1.10) at thai up'ratty conditions confirmed that the existing MSSV setpoints and capacities were adequate at the uprate power level. Other non-I.OCA events that could potentially iitipabt the design Steam Generator Pressure criterion were also reviewed (e.g, UFSAR Sections 14.11, Loss of Normal Feedwater; UFSAR 14.1.12, Loss of AC Power: UFSAR 14.,1.9, Ltiss of Rm:tor Coolant Flow (IAicked Rotor, Partial Loss of Flow and Complete Loss of Flow)). A Se~int tolerance of ~ 3% was deteritiindA tb be acceptable and all safety margins are met for the uprated power level.,
MSSV discharge pipe backpressure will be higher at th>>: uprabA conditions requiring a modiflcation to the MSSV discharge piping to ensure adequate margin at uprate.
The MSIV assemblies provide safety related isolation capability for the steam generators for Main Steam Line Breaks (MSLBs) and Steam Generator Tube'Rupttires'SGTRs) events. One valve is provided outside containment for each maiit sRam lint from the steam generatorS. Each 'ssembly valve assembly consists of a swing disc held open agairist flow by a pneumatic cylinder and a check valve downstream to stop reverse flow from the other two stea~m generators in the event of a'stehm up-stream of the. isolatiion valve. 'reak The MSIVs are maintluned closed by the Instjvment Air System. On Unit '3, a safety related nitrogen supply subsystem functions as a backup to the Instrumetit Air System'. On Umt 4safety rel'ated air accumulators are provided to perform this backup function. Ne 4alve assemblies were evaluated for the rapid closure conditions associated with a postulated pipe break. Based on a review of the existing design reports, the MSIV and MSCV capa'bilities are acceptable for operation and transients ht tHe uprated power, level.
6.2D Steam Dump System
'Ihe Steam Dump System consists of four condenser duinp valves (CDVs) on a line from the Main Steam (MS) System which dump MS to the main condenser as necessary to accommodate a deader trip with turbine trip and three atmospheric dump valveS (ADVs), tine on each MS line upstrmn of the Main Steam Isolation Valve (MSIV).
For the uprating, the C'DVs are capable of passing the required'26% and 27% of the uprate Ml-load MS flow at low To and high TG operation, respectively. The ADVs provide for plant cooldown when the main condenser. is unavailable. fwo of the three ADVs wi11l be capable of passing 10% of the rated steam flow at no load pressure and each ADV is required to pass 10% of its respective steam generator rated steam flow at 775 psia.
Additionally, the predicted MS pressure, temperatureanted vhlokity at uprate will be below the',
steam'ump system and component design.
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6.29 Condensate and Feedwater System The Condensate and Feedwater System automatically maintains the steam generator water level during steady state and transient operations. The systems do not perform any safety related functions, except for the feedwater isolation valves and those-portions of the feedwater system downstream of the isolation valves to the steam, generators.
All of the system operating conditions are bounded by the existing design conditions. The condensate/feedwater system temperatures will increase slightly at the uprate conditions. The operating pressures will decrease slightly at uprate due to condensate/feedwater pump head characteristics and increased pressure drop at increased fiow rates.
The total Condensate and Feedwater System resistance was evaluated for the higher flow rates at the uprate power level. The steam generator pressure remains approximately the same as experienced with the existing power level. Based on the system pressure drop and feedwater control valve capability at uprated conditions, the existing pumps have sufficient head to overcome the increased total system resistance with two condensate and two feedwater pumps in operation at the uprated condition. This is the same pump alignment used at the existing power level.
The net positive suction head (NPSH) available at the suction of the feedwater and condensate pumps is adequate at the uprated conditions.
The effect of the increased condensate/feedwater flows associated with uprate is not expected to alter the E/C rates appreciably as the velocity increases. The existing Erosion/Corrosion monitoring program will be continued to ensure that this conclusion is correct.
6.2.4 Steam Generator Blowdown System The Steam Generator Blowdown (SGBD) System does not perform a safety-related function, except for steam generator isolation and has no impact on the plant licensing bases. The SGBD System is used in conjunction with the chemical feed system to control the chemical composition of the steam generator feedwater within allowable parameters as specified by generator manufacturer. The system also controls the build-up of solids in the steam generator water. The evaluation consisted of comparing the feedwater system design parameters at uprate and the blowdown flowrates to the existing system and component design parameters.
The SGBD System is sized to provide adequate capacity to maintain steam generator secondary side water chemistry under normal conditions, and to recover chemistry to within allowable limits for expected plant transient conditions. The steam generator design conditions do not change as a result of the uprate and therefore the SGBD System design conditions will also not change. Similarly, the flash tank and the downstream piping design conditions are still bounded by the existing design. Since none of the flow design parameters have changed significantly, the uprate will have no effect on the mh1808wM6.wpf:IM81195 6-3
SGBD System. The potential for erosion/corrosion (E/0) will inNease with the slight increase in blowdown flowrate and velocity due to the uniate. Honest.r, desi'gn E/C limits are not exceeded.
6.2$ Extraction Ste Im System The Extraction Steam (EKI) System contains piping and Salves thatl transport steam extracted from various stages of the main turbine to the shell-side of the Feedwater (FW) heaters.
Extraction steam temperatures and pressures pred!icted at uprate were determined to be bounded by the
'S piping design. Additionally, the performance of the non-return valves serving tlhe Nos. 3, 4, 5, hand 6 FW heaters are not impacted by uprate.
The extraction steam flows at update will be slightly hig1her but are bounded by the Extraction Steam (ES) piping design, and are not expected to exceed erosion/corrosidn rate liiriits.
6.2.6 Circulating Waiter System The. Circulating. Water (CW) System is not safety related and has iio impact on the plant licensiiig basis.
The CW System supplies the unit's two-shell condenser with cooling water. The CW Systent why to ensure its capability to maintain the condenser pressure below maximum turbine 'valuated backpressure limits/turlbine trip setpoint The CW System outlet temperature:is expected to increase less than I'F at uprate, however, the condenser has sufficient margin to maintain turbirie backpressure below the maximum limits/tIIrbine setpoint. The environmental impact on the canal system associated with the CW and ICW 'rip System's heat duty increase is discussed further in Section 7.0.
Turbine Plant Cooling Water System
'.2.7 The Turbine Plant Cooling Water gPCW) System is a closed-loop cooling water system and provides cooling water, during normal operation, to various non-safety related equipment coolers.
The heat absorbed by the 'TPCW System is rejechxl to the Ititake Cooling Water (ICW) Syste&,
which, in turn, rejects the heat to the plant cooling canals. Ihe TPCW System is isolated following a design basis accident.
The TPCW System heat load that is expected to increase because of uprate is that associated with the generator hydrogen coolers. However, the two TPCW hmt exchangers are capable of providing the heat removal and therefore, bound the uprate conditions. 'ncreased mhl808wM6.wpf: Ibl091295
62.8 Intake Cooling Water System The Intake Cooling Water (ICW) System. provides cooling water to the safety-related Component Cooling Water (CCW) and non-safety related Turbine Plant Cooling Water (TPCW) heat exchangers.
The system is designed for removal of normal operating heat loads from the CCW and TPCW systems. In addition, the ICW System is also required to remove the heat'load associated with the CCW System during accident conditions to support both reactor heat removal.and containment heat removal requirements. 'Ihe ICW System also provides lube water to the circulating water pumps located in the Intake Area The ICW System will experience higher heat loads during normal operation, resulting in slightly higher ICW discharge temperatures to the canal system. However, the existing ICW design basis is not exceeded, as is supported by the CCW analysis (See Section 5.5.2).
6.2.9 Instrumentation and Control Valves Instrumentation and'control valves in the following BOP systems were reviewed to determine whether any modifications to the existing design would be required as a result of the uprating:
Main Steam Main Condenser Condenser Air Removal Circulating. Water Condensate Polishing Condensate and -Feedwater Extraction Steam Feedwater Heater, Moisture Separator and Reheater, Vents k Drains Steam Generator Blowdown Auxiliary Feedwater Intake Cooling Water Spent Fuel Pool Cooling Turbine. Plant Cooling Water Instrument Air Primary Water Makeup Auxiliary Steam Containment Purge Heating Ventilation and Air Conditioning Emergency Containment Cooling and Filtering Normal Containment Cooling mh1808wkh6.wpf:1M81195. 6-5
A comparison between existing operating par.uneters, uprate operating parameters and instrutnenf ranges were made to evaluate whetlter the instruments aire suitable for uprate conditions. The existing design conditions were used as the lbasiis of comparison with uprate operating conditions.
Control valves" and plant i,nshrumentation were reviewed to dete'rmine'the'ffects of uprate on their design and current setiMints. Operating flows, pressures and temperatures at uprate were reviewed to determine whether they are enveloped by existing design conditions.
Based on the instrumentation and control valve review it was concluded that the difference between uprate and the current op:ratiing conditiions are negligible and the instrumentation and control va'Ives are acceptable for uprate conditions with only the, condensate storage tank level,-ECC start logic and the turbine first-stage pressure signal comparators requiring setpoint and.calibration changes.
6.2.10 Electrical SysItems The Turkey Point Unit 3 and 4 station electrical systems, which include the 240 kV switchyard and the 4.16 kV, and the 480V S ystems,, are designed to provide a simple arrangement of buses requiring a minimum of switching to restore power to a bus-:in the 6vettt the kormal 'supply to the bus is lost.
It was determined that the, m;un generator .is operating within tlhe generator capability cu'rve with atnple margin to handle the uprated power output.
It was also determined that the electrical distribution sy<ter6 is~able to accommodate the uprate requirements without exceeding equipment ratings.
6.2.11 Heating, Ventiilatiionand Air Conditioning The following Heating, Ventilation, and Ailr Conditioning Systems, were evaluated to ensure that they are capable of supporting the plant-thermal uprate conditions:
Control Room DC Equipment/Invertor .'Rooms Cable Spreading Sc Computer F~uipment Rooms Radwaste Building Fuel Handling Building 480V Load Centers &. 4,.16 kV Switchgear Rooms Building 'uxiliary Unit 4 Emergency Diesel Generator Building Electrical Equipment Room Containment Penetrations m%1 808wM6.wpf: I b/091895 6-6
During normal plant operation, these systems cool, heat, and ventilate plant areas to maintain a suitable environment for plant personnel and equipment, as appropriate. These systems will continue to maintain normal operating temperatures at or below their respective maximum normal operating temperatures. 'Ihis is due to the negligible changes in the environments they serve, and/or the excess margin specified in their original design.
6.2.12 Miscellaneous Systems Evaluations of the following systems were performed to determine the impact of the thermal uprate:
Instrument Air Primary Makeup and Demineralizer Water Auxiliary Steam and Condensate Recovery Post Accident Sampling Containment Purge Feedwater Heaters Condensate Polishing System Heater, Moisture Separator and Reheater Drain System Main Condenser Except for associated containment isolation features, these systems do not perform any, safety related function and'continue to function as intended at the uprated conditions.
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69 BALANCE OF PLANT COMPONENTS 63.1 Accident Shielding - Viital Access
'lite shielding provided by the walls o.f cubicles that house compmei1ts carrying post-accident recirculation fluids serve the dual purpose of linuting the doses received by plant per.'onnel during any planned post-accident vital mission, as well as reducinp thi'. +st-accident ridiation exposure~of Safety components located adj8eent to these cubicle. 'elated
'Ihe equipment qualification and vital access dose estiniates are based on the reactor equilibrium core inventory assuming full power operation, source term guidance relative to pest-accident core releases as provided in TID 14844, and plant speciflc mitigation sy'stern design feahues.
Core uprate impacts the equiilibrium core inventory and'herefore 'the post-accident radiologic!al 0oulce An'additional factor that can impact the equilibrium core inventoty is the expected fuel burnup. 'erm.
The impact of a core uprate from 2200 MWt to 2300 MWt, and the potential use of a. 24 m6nth nominal fuel cycle, on the post-accident rMllologicai source terms, was evaluated, to assess the impact on post accident exposure rates in various plant areas, And to derdo&trate the acceptability of the existing plant shielding.
The existing. post-LOCA source terms whiich are conservatiively based on a core thermal powier 6f 2200 MWt, were compared to the source terms associated with th'e uprated (2300 MWt plus 2%), 2'4 month extended burnup. The comparison included soutce terna A (containment attnosphere, i.e., 100%
noble gases, 25% halogens diluted in contaimnent atmosphere), source term B 1yressurized L'OCA i.e., 100% noble gases, 50% hal,ogens andi 1% remainder diluted in the RCS volume) hnd 'iquid, source term C (depressurized LOCA liquid or sump water, i.e., 50% halogens and 1% rentainder diluted in the sump water volume).
The approach taken was to perform a comparison of'he current design basis source terms and the core uprate source terms and estimate a jpercentage impact due to the change, rather than develop actt1al rate estimates at various locations/times using the new core inventory. For the unshieldI:d Cask,
'ose the impact on post-accident dose rates was estimated by cotnparin'g the total energy release rates as a function of time for Source Term A, B, and C. In ordelc to detnokstrate the acceptability of the existing post-accident shielding requirements, the sour&, te&s we/e weighted by the concrete reduction factors for each energy group, for 1 and 2 feet of cottcrdte (typical shield thickness), thus providing a basis for compariison of the post-I.OCA spedtrdm hardness of source terms A, B, and C (when unattenuated, or attenuated tl1rough 1 ft and 2 ft concrete) with respect to titne, for the'ri'ginal basis versus the uprated source terms. 'esign The evaluation indicated that there is a close match between the source terms based on thi: ull1rat4%
core/24 month fuel cycle,and the current design basis source term. The existing shielcling and post-mal 808w'eh6.wpf: tb/091195 6-8
accident dose rate estimates are adequate for the uprated conditions and any variances from existing calculated values are insignificant.
662 Equipment Qualification - Radiological Equipment Qualification dose estimates are based on the reactor equilibrium core inventory assuming full power operation, source term guidance relative to post-accident core releases as provided in TID 14844, and plant specific mitigation system design features.
Core uprate impacts the equilibrium core inventory and therefore the post accident radiological source term. An additional factor that can impact:the equilibrium core inventory is the expected fuel burnup.
The impact of a core uprate from 2200 MWt to 2300 MWt, and the potential use of a 24 month nominal fuel cycle, on the post accident radiological source terms, was evaluated, to assess the impact on post accident radiation dose estimates in various plant areas, and to demonstrate the acceptability of the existing post accident equipment qualification dose requirements for safety related components.
The existing post-LOCA integrated gamma source terms which are conservatively based on a core thermal power of 2300 MWt, were compared to the integrated gamma source terms associated with the uprated (2300 MWt plus 2%), 24 month extended burnup cycle. The comparison included source term A (containment atmosphere, i.e., 100% noble gases, 25% halogens diluted in containment atmosphere),
source term B (pressurized LOCA liquid, i.e., 100% noble gases, 50% halogens and 1% remainder diluted in the RCS volume) and source term C (depressurized LOCA liquid or sump water, i.e., 5%
halogens and 1% remainder diluted in the sump water volume).
The approach taken was to perform a comparison of the current design basis integrated gamma source terms to the core uprate integrated gamma source terms, and estimate a percentage impact due to the change rather than develop actual integrated gamma dose estimates at various locations/times using the new core inventory.
The current "shielded" gamma design basis source terms are essentially equal in energy spectrum hardness (within 1%) to the corresponding extended burnup source terms. Consequently, the percentage impact on equipment qualification gamma doses is considered to be the same whether the controlling contribution is the result of an unshielded or a shielded source. The impact on post accident integrated gamma doses was therefore estimated by comparing the total unshielded integrated energy releases as a function of time for Source Term A, B, and C, between the design basis core versus the uprated, extended burnup core.
The impact on beta doses was assessed by a dose model consistent with the semi-infinite cloud model outlined in Regulatory Guide 1.4. A region of air with a very small exhaust rate (to prevent quiescence), was modelled. The appropriate &actions of core inventory associated with source terms A, B and C was "PUFFED" into this region and allowed to decay for 721 hours0.00834 days <br />0.2 hours <br />0.00119 weeks <br />2.743405e-4 months <br />. Region volumes and densities were addressed for consistency, but the exact values were not considered mh1808wM6.wpf:1b/091195 6-9
important for this evaluaiion since the results were ratioed to develop. the estimated impact. The calculated beta doses are for comparison purposes only and are not intended to replace the eIxistiing beta dose values that support eqiuipment qualification.
The evaluation indicated that there is a close match between the integrated gamma source terms based on the uprated core/24 month fuel cycle and the design basis source term.
Since the gamma energy spectr<< for all three source terms We essentially equal in hardness (whether shielded or unshielded), throughout the entire accident, the ~gamma equipment qualification doses calculated based on design basis source terms are essentially unaffected by the uprate and use of extended burnup fuel, and is valid for uns'hielded as well as shielded components.
Therefore, it is concludecl that the. existing equipment qiIalificaitioh gamma and beta dose estimates are adequate for the uprated conditions and any variance fi.om existing calculated values are insign'ifiIcant and that the total integrated dose to safety relatecl equipment from an accident remains unchanged from that previously evaluated.,
693 Ratlwaste Systems The liquid and gaseous radwaste activity is influenced by the reactor coolant activity which is a function of the core power level. IMs section discusses the itnpact of the uprate on the existing liquid and gaseous radwaste system for normal operational releases. The accident rele~ are discussed in Sections 3.2.14 and 3.2.15.
Potentially radioactive liqtuid waste from Units 3 ancl 4 chemistry laboratories, containment sumps, floor drains, showers, and miscellaneous sources are collected in waste hold up tanks. The liquid waste is processed through demi,neralizers and the effluent:stored in the waste monitoring taIIks.'aundry waste is normally segregated and sent to monitor tanks. Liquid waste in the momtoring tanks are released after sampling and analysis in, accordance vt ith Teichnical Specification 3/4.11.1. The effluent discharge is monitored by a radioacti ve liquid effluent monitor.
The activity of the steam generator blowdown discharge to the blowdown flash tank is monitored and the releases are sampled and analyzed .in accordance with I~'echnical Specification 3/4.11.
Radioactive and potentially radioactive gases .from Units 3 and 4 (I.'ontainment Buildings, Auxiliary Spent Fuel Poo',i, Radwaste Building, and Laundry area Ne released via the monitored implant 'uilding, i
vent. Radioactive gases from the plant priimafy systems are stored in the gas decay tanks. The 'gas&
held up to reduce the activity levels by radioactive decay prior to release. The gaseous waste are
're released:after sampling and analysis in accordance with Technical Specification 3/4.11.2.
The limits placed on plant radioactive effluent release by 10 CFR 20 andi 10 CE'R 100 have lieeII.
considered in the design and operatIing plans for the plant, with the objective to maintain release mhI808wM6.wpf:IM81195 6-10
concentration at the site boundary below natural background activity and thus only a minute fraction of 10 CFR 20 limits. To achieve these objectives, the facility has been designed and is operated as follows:
- 1. Liquid wastes are collected in tanks and processed by the waste disposal demineralizer. Waste evaporators are also provided if necessary. The waste processes provided can reduce activity well below established limits and represent a design for reducing activity to the lowest practicable value.
- 2. Gaseous wastes are stored in decay tanks for natural decay. Gases will be released through the monitored plant vent, and at the site boundary the annual dose will not exceed the regulatory limits.
The quantity of radioactivity contained in each decay tank is restricted to provide (a) assurance that in the event of an uncontrolled release of the tank's contents, the resulting total body exposure to an individual at the nearest exclusion area boundary will not exceed 0.5 rem, and (b) assurance that the concentration of potentially explosive gas mixtures contained in the Gas Decay Tank System is maintained below the flammability limits of hydrogen and oxygen.
The existing design of the radwaste systems is based on the core power level of 2300 MWt. The uprate does not require changes to the existing design and/or operation of the radwaste systems. There is-expected to be minimal impact on the frequency of and the amount of waste processed, however the radwaste process capability to meet the existing Technical Specification limits is not impacted . No Technical Specification changes are required.
Uprating to a core power level of 2300 MWt does not impact the ability of the radwaste systems to provide adequate processing and maintain the normal operational radioactive releases within regulatory limits.
69.4 Reference
- 1. TID 14844 entitled "Calculation of Distance Factors for Power and Test Reactor Sites",
J. J. DiNuno, et. al. dated March 23, 1962.
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6.4 ADDITIONALBOP RXVIE'WS 6.4.1 High Energy I.ine Break System operating parauneters for uprate were evaluated against the system pressure and/or temperau1re ~
parameters used in the existing iplant base:s to demonstrate the acceptability for High Energy Line Break (HELB) effects. '1'he HELB review was c:onducted to e,valuate the possible effects on thet inPut to EQ analysis (pressure, temperature, and flooding), jet impingenmnt forces on components ~and structures, and pipe rupture restraint reactions as a result of plant thermal uprate to 2308 MVt. Fol the Auxiliary and Standby Steam Generator Feedwater and Steam Generator Blowdown systems, the consequences of the dynamic effects o: f HELB were treated as independent of the system parameters, and dependent on the ana)ysiis of the potential targets.
The resulting conditions obtatined (i.e., pressure, temperature, jet load, etc.), assuming the postulated if failure of the affected piping systems, were acceptable at the uiprate conclition, they were boundecl by those conditions used in the existing design bases. The reSulting Conditions associated with the HELB were considered bounding if the internal pipe operating cottditionS used 1n the previous HELB analysis at the existing 2208 h.tWt rating were bounded by the s'am'graIing modes at the 2308 MWt uprate conditions.
'Ihe uprate review considered the consequences of postulated breaks OutSide and inside containment for the following high energy piping systems:
Main Steam (MS) System, Main Feedwater (FW) System, Auxiliary Feedwater (A1FW) System; consisting of the steam supply to the pump turbine anted the AFW discharge, Standby Steam Generator Feedwater System, Steam Generator Blowdown (SGBD) System, and Chemical and Volume Control Sy: stem (CVCS); cOnsiSting of the letdown and charging lines.
core uprate will not change 1he temperature and pressure enviroruttent used as the basis for pipe bretak analysis. System operatltlig parameters for upj~ are: bouncled by the original (existing) 2208 MWt and no additional analysis was required. 'nalyses 6.42 Piping and Supports The purpose of the piping anted support reviiew is to evaluate piping systems for the effects reSulting thermal uprated conditions in order to demonst1zte design basis compliance. Operation at the 'rom uprated conditions may increase piping stresses caused by slightly higher operating temperatures, pressures and flow rates. Additionally, pipe supports and equipment nozzles may be subjected tO slightly increased loadiings due to the thermal uprate condition.
mh1808wkh6.wpf:Ih991 195 6-12
The specific piping systems evaluated for thermal uprated conditions are as follows:
Safe Related Pi in S stems Auxiliary Feedwater Supply Auxiliary Feedwater Pumps Steam Supply Chemical and Volume Control Component Cooling Water Condensate Storage Tanks and Transfer Pumps Containment Spray and Containment Emergency Filters Feed water Intake Cooling Water Main Steam Pressurizer Safety and Relief Valve Piping Primary Water and Demineralized Water Safety Injection and Residual Heat Removal Spent Fuel Pool Cooling Steam Generator Blowdown Waste Disposal - Liquid Non-Safet Related Pi in S stems Circulating Water Condensate Extraction Steam Feedwater Heater, Moisture Separator and Reheater (Vents, Drains and,Relief Valves)
Turbine Plant Cooling Water The piping and support review concluded that each piping system remains acceptable and continues to satisfy design basis requirements when considering the effects resulting from thermal uprated conditions. 'Ihe evaluations also document that no piping or pipe support modifications are required as a result of the increased power level.
6.43 Structures The effects on structures due to the thermal power uprate of Turkey Point Units 3 and 4, are reflected in changes to the loads transmitted from equipment, systems, and components, and from the normal operating and postulated accident environments. UFSAR Appendices SB and SA describe the design bases of the containment and the other Class I structures, including the loadings used in their design.
'Ihe loadings associated with equipment, systems, and components and the normal and accident environments, which are influenced by thermal uprate, were evaluated in detail.
The loads which are the basis for the design of Class I structures are described in UFSAR Appendix SA and are a subset of those described for the containment. These loads are the dead m:u 808 wM6.wpf:1b/091195 6-13
loads, pipe rupture loads, piping reactions, elthquake load's and wind loads. The pipe rupture loads and the piping reactions as'e affected by the thermal uprate and were evaluated.
The design basis pressure for the containment, 55 psig, is based on a LOCA and was compared'o of the Containment Integrity Analysis (Section 3.5)J The limiting case for the calculated the'esults containment peak LOCA pressure for the thermal uprate conditions is the Double-Ended Hot Leg (DEHL) break resulting in a pressuie of 48.1 psig which is less than 'the'ontainment design'bars
'alue.
Since the uprate calculahxi peak LOCA cont8dnment attnosphere temperature is below that calculated for existing conditions and the durations of the temperature tr8msients are similar it is concluded'hat the design basis containment liner temperature and wall thermal padiients shown in ~AR 5.1-8 are not e,xceeded by core uprate. 'igure The existing analysis of the consequences of the high energy line 'breaks (Section 6.4.1) is not changed by thermal uprate. These consequences include both the magnitude and types of loads (reactionS, jest impingement, and whiip) and the: locations of the breaks. The pipe support reactions resulting from thermal uprate (Section 6.4.2) are acceptable and no sigjnifi~t changes to these loads were identified.
Therefore, the proposed thermal uprate will not adversely affect structures as refiected in changes to the loads transmitted from equipment, system:s, and cornpohenfs, aind from the normal operating and postulated accident pressure and temperature env.iromnents.'h1808wM6.wpf:1M81195 6-14
CHAPTER 7 IRONMENTAL CONSIDERA. TION
II V
7.0 ENVIRONMENTALEVALUATION This section discusses the need for the thermal power uprate and the potential impact the thermal power uprate will have on the environment. The onsite and offsite radiological and non-radiological environmental effects are evaluated.
Turkey Point Units 3 and 4 are currently licensed for a core power level of 2200 MWt and the proposed thermal power uprate will increase the licensed core power level to 2300 MWt which will result in an increase in electrical generation output of approximately 30 MWe per unit. Appendix B of the Turkey Point Units 3 and 4 operating licenses provide for changes in facility design and operation provided such changes do not involve an unreviewed environmental question.. This section discusses the environmental evaluation of the impact of the thermal power uprate and documents that the thermal power uprate neither constitutes an unreviewed environmental question nor will have a significant impact on the quality of the human environment.
Environmental issues associated with the issuance of an operating license for both Turkey Point Units,3 and 4 were originally evaluated in the "Final Environmental Statement (FES) related to the Operation of the Turkey Point Plant" (Reference 1). A further evaluation of impacts was performed in connection with the proposed license amendments which recaptured the construction period for the operating license (Recapture Amendments) (Reference 2). The approval of the Recapture Amendments allows FPL to operate Turkey Point Units 3 and 4 for a full 40 year operating period (an additional 5.25 and 6 years, respectively, beyond the previously approved operating period). The NRC's Environmental Assessment and Finding of No Significant Impact (Reference 3) related to the operating license extension concluded that the proposed action will not have a significant effect on the quality of the human environment.
The environmental review conducted for the proposed thermal power uprate considered the need for the power uprate and the resulting environmental impact associated with it. 'Itus included considering the operating license and NPDES permit limits and the information contained in the FES and the evaluations associated with the Recapture Amendments. This evaluation included determining whether the power uprate would cause the plant to exceed discharge limits and NPDES permit conditions associated with the operation of the plant. In addition, a review of the recent Ttirkey Point Units 3 and 4 Annual Radioactive Effluent Release Reports was undertaken to evaluate whether a small increase in discharge amounts is acceptable. Slight increases in discharge amounts, if any, associated with the proposed thermal power uprate are acceptable, as annual discharges will continue to be, a small percentage of the allowable limits and the FES estimates.
7.1 NEED FOR ACTION
'II1e proposed action would increase the electrical output of each Turkey Point unit by approximately 30 MWe, and thus, would provide additional electric power to service commercial and domestic loads on the Florida Power and Light Company grid. The thermal power uprate is needed to accommodate mh1808wkh7.wpf:tb/091195 7-1
the annual growth rate in the FPL service tenitory while avoidling major capital expenditures for new generating capacity. 'Ihe thermal power uprate program wiill result in direct displacement of higher cost fossil fuel generation wiith lowlier cost nuclear fuel generation.
7.2 OFFSITE RADIATIONEXPOSURE Offsite radiation exposures from norm<8 operation and Accidents ate assessed and documented in'he Turkey Point Units 3 and 4 Updated Final Safety Analysis (VFSAR) with additional information contained in the FES and evaluation associated with the Redaptur& Amendments.
7.2.1 Normal Operation Exposure The offsite radiation exposure from various pathways to the maximally exposed individual member of general public has been evaluated for the proposed uprate.
'he Section V.D. of the Flà projected doses and anticipated'nnual reIiease of radioactive materia Q characterized in Table III-2 and III-3 resulting, from radioactive materials released to the enviromnent from routine operations of the two reactors. Title 10 CFR Part 50,, Appendix I, which provides guidelines for meeting as low as reason, ably achievable (ALARA)doses from the reactors, is incorporated in the 1hrkey Point Units 3 and 4 Technicall SiIN:cifi&tions And Offsite Dose Calculation Manual (ODCM).
The results of operating experience:in effluent, offsite dose calculation results, and the radiological monitoring program demonseate the mini!mal radiollagic~l impact upon the general 'nvironmental public from the operatiion of the two reactors.
The liquid effiuent from the plant are. discharged Iinto a tIloskd keoling canal system.
Gaseous waste from routine operations are collected, cothpr6ss6d, Nd stored in holdup tanks at the plant. The holdup tanks allow for the decay of short half-life radionuclides prior to release througih high efficiency particullate absolute (HEPA) filters to rer6ov6 pkrtiduiate material.
Turkey Point Units 3 and 4 have consistently been operated'well vithi'n the requirements of 10 CFR 50 Appendix I for alll types of releases as documented. in the Turkey PoIint Units 3 and 4 Annual Radioactive Effluent Relmse Reports.
'Ihe Turkey Point Units 3 and 4 Radliological Effluent Techrucal Specifications (RETS) are also in compliance with the goal of maintaining radiation exposure ALARA. The capability of the 'Dykey Point Units 3 and 4 to meet the required Effluent Technical Specifications and maintain mediation exposure ALARA, as analyzed in the FES and evaluations ahsokiat6i with the Recapture Amendments, will not be impacted by the Ciermal power uprate.
m&1 S08w'ch7.wpf:1b$ 91195 '7-2
7.22 Accident Exposure Offsite radiation exposures from postulated accidents are assessed and documented in Section 3.0, consistent with the analysis in the FES and the evaluation associated with the Recapture Amendments.
The offsite doses for the exposure postulated under accident conditions remain within the guidelines of 10 CFR 100.
7.3 ONSITE RADIATIONEXPOSURE AND RADIOACTIVEWASTE PRODUCTION The thermal power uprate is not expected to increase the day-to-day radiation exposures encountered by plant workers since the in-plant radiation levels will not change significantly, with respect to the evaluations in the FES and the evaluations associated with the Recapture Amendments.
FPL has. developed and implemented comprehensive ALARAprograms at its nuclear power plants.
Three types of waste are generated at Turkey Point Plant: gaseous, liquid, and solid. Each of these types of waste is discussed in Section 6;3.3 and below with respect to their impact on waste treatment.
The gaseous radwaste systems are designed to assure that the airborne release of such waste is maintained ALARAduring normal plant operation. The RETS ensure that the equipment required to maintain the:offsite doses ALARA will be operable and will be operated as required to maintain the releases ALARA.
The liquid waste treatment systems at Turkey Point Units 3 and 4 are designed to meet the ALARA goals. These systems are also subject to the RETS for assurance of operability.
Operation of Turkey Point Units 3 and 4 at the uprated power level may result in additional solid Low Level Radioactive Waste (LLRW) that will have to be shipped for disposal. However, the annual volume of LLRW is not expected to increase significantly. Additionally, 'Ibrkey Point's LLRW disposal volume is well below the median value for similar two unit pressurized water reactor (PWR) sites. Over the years, significant improvements have been made in the way that LLRW is handled and disposed. Turkey Point Plant also uses volume minimization techniques and other volume reduction processes to minimize the volume of LLRW for final disposal. These techniques should further minimize any impact power uprate might have. on the generation of additional LLRW.
7.4 NON-RADIOLOGICALEFFECTS The FES (Reference 1) and the evaluations associated with the Recapture Amendments (References 2 and 3) assessed the non- radiological impacts of plant operation as a function of plant design features, relative loss of renewable resources, and relative loss or degradation of available habitat.
Environmental impacts associated with forty year operating licenses were originally evaluated in the FES. The FES and the evaluations associated with the Recapture Amendments concluded that, after weighing the environmental, economic, technical, and other benefits against environmental costs and mh1808wM7.wpf:1M81195 7-3
considering available alternatives, and subject, to certain conditions, from. the standpoint of environmental effects, the issuance of operating Hcense< fob Trmkky Point Units 3 and 4 was'n action. These assessments, and the assumptions on which they were based, remain-valid and'cceptable are not impacted as a result of the thermal power uprate.
Protection of the enviromnent is asmed by compliance wiih penruts issued by federal, state,'nIf local'gencies.
7.5 NATIONALPOLLUTANT DISCHARGE EK IMINATIONSYSTEM I,'NPDES) PE~IT IMPACT The Turkey Point Plant consIists of two fossil fuel uruts (Units 1 and 2) and the two nuclear units (Units 3 and 4). The four uruts obtain their cooling water frortt add discharge to a closed cobling canal system. All water used at the, plant, is recycled within th'e closed canal system exce~pt station make-up which is purchased from the local municipal utility. The thermal loading on the cabal frorh the four units is approximateiy 14 x 10'tu/hr.
The Turkey Point Units 3 and 4 were licensed for an initial licensed power level of 2200 MWt with an ultimate thermal generating capacity identified in the Final Environmental Statement of 2300 MWt.
'Ihere are no discharges to B.iscayne Bay or Card Sound from the plant site and therefore the Turkey Point NPDES permit does not place any operating limits on either flow or temperature.
'Ihe heat duty increase, associated with uprate is mainly associated with the Circulating Water System and will be approximately 440 x 10'.Btm%r. 'Ihis represents a 4A% increase over the present power level but is insignificant when compared to the heat load frbm all four uruts and the incident 'solar heat gain to the canal. 'adiation For normal Circulating Water System operation, which includes the reduction in cu'culating vl ates'lbw caused by the existing condenser tubes plugged, the maximum temperature increase expected as h result of the uprate between inlet and outlet will be appr'oxi'mately'0.7'F 'over existing plant dperhtidn.
Therefore, the thermal power uprate of the Turkey Point Uruts 3 and 4 will have no adverse imphct<
on the environment or result. in exceedi,ng NPDES permit limits.
7.6 ALTERNATIVETO THE PROPOSED ACTION The, principal alternative would be "no action" with respect to t'e requested amendments for the thermal power uprate. No action would not significantl) reduoI: thee enviromnental impact of plaht operations, but would restrict operatIion of the Turkey Point facility to the, currently licensed powder level. No action would prevent the faci,lity from generating the, additional approximately 30 MWe for each Turkey Point unit that is needed for present and future sy<terh loads.
mAI808wMh7.wpf:1b/091195
7.7 ALTERNATIVEUSE OF RESOURCES This action does not involve a significant increase in the use of resources not previously considered in the "Final Environmental Statement Related to the Operation of Turkey Point Plant," dated July 1972 (Reference 1) and the environmental evaluation performed to support the "Issuance of Amendments Re: Recapturing Construction Period in the License Term," dated April 20, 1994 (References 2 and 3).
7.8
SUMMARY
OF ENVIRONMENTALANALYSIS The radiological and non-radiological environmental impacts related to the proposed license amendments associated with the thermal power uprate have been analyzed and evaluated as follows:
~ There will be no significant change in the types or in the amounts of any radiological effluents over those which have already been evaluated and found acceptable in the FES and evaluations associated with the Recapture Amendments. Similarly, there will be no significant increase in individual or cumulative occupational or population exposures.
~ There will be no significant increase in the types or amounts of radioactive wastes over that already evaluated in the FES and evaluations associated with the Recapture Amendments.
~ There will no significant increase in non-radiological impacts over those evaluated in the FES and evaluations associated with the Recapture Amendments.
Based on these analyses, it has been concluded that there are no significant radiological or non-radiological impacts associated with the thermal power uprate. The thermal power uprate will have no significant impact on the quality of human environment and does not involve an unreviewed environmental question as defined in Appendix B, the Environmental Protection Plan, of the operating licenses.
7.9 REFERENCES
- 1. "Final Environmental Statement Related to the Operation of Turkey Point Plant", dated July 1972, United States Atomic Energy Commission.
- 2. Letter, K. N. Harris (FPL) to USNRC, "Proposed License Amendments Operating License Expiration Date", dated February 25, 1992, L-92-31.
- 3. Letter, R. P. Croteau (USNRC) to J. H. Goldberg (FPL), "Environmental Assessment and Finding of No Significant Impact for Recapturing Construction Period in the License Term - Turkey Point Units 3 and 4", dated April 7, 1994.
mA1808wkh7.wpf:tb/091195 7-5
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