Text

Non-proprietary Version of WCAP-14723, Farley Nuclear Plant Units 1 & 2 Power Uprate Project NSSS Licensing Rept
	ML20135C973
Person / Time
Site:	Farley
Issue date:	01/31/1997
From:	; WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:	;
Shared Package
ML20135C833	List: ML20135C831; ML20135C864; ML20135C973; ML20135C981;
References
	WCAP-14723, NUDOCS 9703040367
	Download: ML20135C973 (393)
	v • d • e

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i i l Farley Nuclear Plant . Units 1 and 2 l

O Power Uprate Project 1 NSSS Licensing Report .

4 i 1 l We s tin g hou s e En ergy S y s te m s W-amme t 49 l PDR u 3 p

WESTINGHOUSE NON-PROPRIETARY CLASS 3 i

   '                                               WCAP-14723                               I (G                                                                                        l 1

Farley Nuclear Plant Units 1 and 2 ! Power Uprate Project NSSS Licensing Report i i l January 1997 a j Westinghouse Electric Corporation Energy Systems Business Unit P.O. Box 355 Pittsburgh, PA 15230-0355 C 1997 Westinghouse Electric Corporation All Rights Reserved m:\3254wVrontmtr.wpf.ib-013097

4 t r TABLE OF CONTENTS ; . l 3 EXECUTIVE SUMM ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xv t I 1 1-1

1.0 INTRODUCTION

J

1.1 Purpose and Scope

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 - 1

- 1.2 Methodology and Acceptance Criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1 (

j 1.3 Technical Basis for Significant Hazards Evaluation ...................1-2 Conclu sions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 -2 i , 1.4 2- 1 i I . 2.0 NSSS PARAMETERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2- 1 ! 2.1 PCWG Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . l< 3-1 4 ! 3.0 NSSS DESIGN TRANSIENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 3.1 NSSS Design Transients ....................................... 3-1 1 3.2 Auxiliary Equipment Design Transients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-2 l

i i I i

. 4.0 N SS S S YSTEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4- 1 {, i 4.1 NSSS Fluid Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-1 l 4.2 NSSS/ BOP Fluid Systems Interfaces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-13 j 4.3 NSSS Control Systems ....................................... 4-20 l j 4 1 5.0 NSSS COMPONENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5- 1 4 5.1 Reactor Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5- 1 1 5.2 Reactor Pressure Vessel System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-2 5.3 Fuel Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5- 11 l 5.4 Control Rod Drive Mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-12 5.5 Reactor Coolant Loop Piping & Suppolts . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 13 i 5.6 Reactor Coolant Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-14 i 5.7 Steam Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . 5- 14 i 5.8 Pressurizer . . . . . . . . . . . . ...................................5-17 I NSSS Auxiliary Equipment ................................. 5-18 5.9 . 6-1 6.0 NSSS ACCIDENT ANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 LOCA Transients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . 6.1 i 6-60 6.2 Non-LOCA Transients . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.3 Steam Generator Tube Rupture Transient . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-202 , I 6.4 LOCA Mass and Energy Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-209 6.5 Main Steamline Break Mass and Energy Releases . . . . . . . . . . . . . . . . . . . . . 6-253 i 1 l m:\3254w.non\frontmar wpf1b.013097 i i j

I i TABLE OF CONTENTS (cont.) 6.6 LOCA Hydraulic Forces ...................................... 6-277 O 6.7 Reactor Trip System / Engineered Safety Feature Actuation System Setpoints . . 6-282 7.0 NUCLEAR FUEL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7- 1 7.1 Core Thermal-Hydraulic Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-1 7.2 Fuel Core Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7- 1 1 7.3 Fuel Rod Design and Performance ............................... 7-17 7.4 Heat Generation Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-22 7.5 Neutron Fluence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-25 7.6 Source Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-27 1 1 i O; I 1 1 1 1 1 9 l l l m:\3254wmon\frontmtr wpf.It@l3097 ii i I

4 LIST OF TABLES

l Table 2.1-1 NSSS PCWG Input Parameters for Farley Power Uprate Project . . . . . . . . . . . . 2-4 )

i Table 2.1-2 NSSS PCWG Parameters for Farley Power Uprate Project . . . . . . . . . . . . . . . . . 2-6 i Table 6.1.1-1 Major Plant Parameter Assumptions Used in the BELOCA Analysis for l Farley Units 1 and 2 and Where They Will be Documented . . . . . . . . . . . . . . . 6-6 i Table 6.1.1-2 Best Estimate Large Break LOCA Results . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-7 Table 6.1.2-1 Input Parameters Used in the Small Break LOCA Analysis . . . . . . . . . . . . . . l 6-18 ; Table 6.1.2-2 Small Break LOCA Analysis BOL Fuel Cladding Results Limiting Configuration Determination for 3-inch Break . . . . . . . . . . . . . . . . . 619 Table 6.1.2-3 Small Break LOCA Analysis Fuel Cladding Results Burst / Time in Life Results for ZIRLO Cladding . . . . . . . . . . . . . . . . . . . . . . 6-20 Table 6.1.2-4 Small Break LOCA Analysis Fuel Cladding Results, Break Spectrum . . . . . . . . 6-21 Table 6.1.2-5 Small Break LOCA Analysis Time Sequence of Events . . . . . . . . . . . . . . . . . 6 22 Table 6.1.3-1 ECCS Minimum Required Flow Rates for Farley Uprating to 2775 MWt .... 6-56 Table 6.2.0-1 Non-LOCA Key Accident Analysis Assumptions for FNP Uprate . . . . . . . . . . 6-65 Table 6.2.7-1 Sequence of Events - Loss of Load / Turbine Trip Event . . . . . . . . . . . . . . . . . . 6-87 Table 6.2.81 Time Sequence of Events for Loss of Normal Feedwater Flow . . . . . . . . . . . . . 6-98 Table 6.2.9-1 Time Sequence of Events for Loss of Non-Emergency ac Power . . . . . . . . . . 6-107 Table 6.2.14-1 Sequence of Events - Inadvertent ECCS at Power Event . . . . . . . . . . . . . . . . 6- 129 Table 6.2.17-1 Sequence of Events - Complete Loss of Forced Reactor Coolant Flow Event . . . . . . . . . . . . . . . . ...............................6-145 Table 6.2.19-1 Time Seque :e of Events for the Repture of a Main Steamline . . . . . . . . . . . 6-161 Table 6.2.21-1 Summary of Results for the Locked Rotor Transient . . . . . . . . . . . . . . . . . . . 6-182 Table 6.2.21-2 Sequence of Events - Locked Rotor Transient . . . . . . . . . . . . . . . . . . . . . . . 6- 1 8 2 Table 6.2.22-1 Results of the Rod Cluster Control Assembly Ejection Accident Analysis . . . . 6-197 Table 6.2.22 2 Sequence of Events - RCCA Ejection Accident . . . . . . . . . . . . . . . . . . . . . . 6- 19 8 Table 6.31 SGTR Thermal-Hydraulic Results for Farley . . . . . . . . . . . . . . . . . . . . . . . . 6-207 mms 4..nonumnumwpr.ib-ono97 iii

i LIST OF TABLES (cont) Table 6.3 2 Bounding SGTR Thermal-Hydraulic Results for Farley Radiological Dose Analysis . . . . . . . . . . . . . . . . ..... ....................... 6-208 Table 6.4.1-1 System Parameters, Initial Conditions for Thermal Uprate . . . . . . . . . . . . . . . 6-221 Table 6.4.1-2 Safety injection Flow - Minimum Safeguards . . . . . . . . . . . . . . . . . . . . . . . . 6-222 Table 6.4.1-3 Safety Injection Flow - Maximum Safeguards ....................... 6-223 Table 6.4.1-4 Double-Ended Hot Leg Break, Blowdown Mass and Energy Releases . . . . . . . 6-224 1 Table 6.4.1-5 Double-Ended Hot Leg Break, Mass Balance . . . . . . . . . . . . . . . . . . . . . . . . 6-226 i l Table 6.4.1-6 Double-Ended Hot Leg Break, Energy Balance . . . . . . ............... 6-227 ) Table 6.4.1-7 Double-Ended Pump Suction Break, Blowdown Mass and Energy Releases < (Same for all DEPS Runs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .... 6-228 Table 6.4.1-8 Double-Ended Pump Suction Break - Minimum Safeguards, Reflood Mass and Energy Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-230 Table 6.4.1-9 Double Ended Pump Suction Break - Minimum Safeguards, Principle Parameters During Reflood . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-232 Table 6.4.1-10 Double-Ended Pump Suction Break - Minimum Safeguards, Post-Reflood Mass and Energy Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-234 Table 6.4.1-11 Double-Ended Pump Suction Break, Mass Balance, Minimum Safeguards . . . . 6-236 Table 6.4.1-12 Double-Ended Pump Suction Break, Energy Balance, Minimum Safeguards . . . 6-237 Table 6.4.1-13 Double-Ended Pump Suction Break - Maximum Safeguards, Reflood Mass and Energy Releases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-238 Table 6.4.1-14 Double-Ended Pump Suction Break - Maximum Safeguards, Principle Parameters During Reflood . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-240 Table 6.4.1-15 Double-Ended Pump Suction Break - Maximum Safeguards, Post-Reflood Mass and Energy Releases . . . . ............. . . . . . . . . 6-24 2 l Table 6.4.1-16 Double-Ended Pump Suction Break, Mass Balance, Maximum Safeguards . . . . 6-244 Table 6.4.1-17 Double-Ended Pump Suction Break, Energy Balance, Maximum Safeguards . . 6-245 Table 6.4.1-18 Double-Ended Hot Leg Break, Sequence of Events . . . . . . . . . . . . . . . . . . . 6-24 6 1 m:\32s4w. con \frontmtr.wpf Ib-013097 iv

I l I r LIST OF TABLES (cont.) ( x_ Table 6.4.1-19 Double-Ended Pump Suction Break - Minimum Safeguards. Sequence of Events .........................................6-247 Table 6.4.1-20 Double-Ended Pump Suction Break - Maximum Safeguards. ; Sequence of Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-248 ' Table 6.4.1-21 LOCA Mass and Energy Release Analysis, Core Decay Heat Fraction ... .. 6-249 Table 6.5-1 Nominal Plant Parameters for Thermal Uprate (MSLB M&E Releases) . . . . . . 6-269 Table 6.5-2 Initial Condition Assumptions for Thermal Uprate ......... .......... 6-270 Table 6.5-3 Protection System Actuation Signals and Safety System Setpoints for Thermal Uprate Analysis ................................... 6-271 1 2 Table 6.5 4 1.069 ft MSLB Hot Full Power with Containment Safeguards Failure Sequence of Events (Peak Temperature Case) . . . . . . . . . . . . . . . . . . . . . . . . 6-273 2 Table 6.5-5 0.591 ft Split MSLB at 30% Power with Containment Safeguards Failure l Sequence of Events (Peak Pressure Case) . . . . ...................... 6-274 1 [] V Table 6.5-6 Transient Summary for the Spectrum of Breaks at 102% Power - Outside Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-275 ! Table 6.5-7 Transient Summary for the Spectrum of Breaks at 70% Power - Outside Containment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-276 Table 6.7-1 Summary of the Technical Specification Reactor Trip System Setpoint Changes ........................................... 6-283 Table 6.7-2 Summary of the Technical Specification ESFAS Setpoint Changes . . . . . . . . . 6-287 Table 7.1-1 Thermal-Hydraulic Design Parameters for Farley Units I and 2 . . . . . . . . . . . 7-7 Table 7.1-2 Initial Condition Uncertainties Used in DNBR Analyses . . . . . . . . . . . . . . . . . 7-10 Table 7.2-1 Farley 2785 MWt Uprating Program Key Safety Parameters .............. 7-15 Table 7.3-1 Summary of Parley Uprating Parameters Analyzed in Fuel Rod Design Eval uati on . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . 7-21 Table 7.6-1 Input Parameters for Fission Product inventory Calculation . . . . . . . . . . . . . . . 7-30 Table 7.6-2 Equilibrium Loading Pattem . . . . . . .... .... . ... ........ . 7-30 A Table 7.6-3 Input Parameters for Fission Product inventory Calculation . . 7-31 (b) ... .... .. m:\3254w.non\tmntmtr.wpf 1t4)l3097 y

LIST OF FIGURES Figure 6.1.2-1 Small Break Hot Rod Power Shape . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-23 Figure 6.1.2-2 Small Break Pumped Safety Injection Flow Rate - 1 HHS1 Pump . . . . . . . . 6-24 Figure 6.1.2-3 Code Interface Description for the Small Break LOCA Model . . . . . . . . . . . 6-25 Figure 6.1.2-4 RCS Depressurization Transient, Limiting 3-Inch Break, Low T,,,, Unit 1 ... 6-26 Figure 6.1.2-5 Core Mixture Level,3-Inch Break, Low T,,,, Unit 1 .................. 6 27 Figure 6.1.2-6 Peak Cladding Temperature - Hot Rod, 3-Inch Break Low T,.,, Unit 1 . . . . 6-28 Figure 6.1.2-7 Top Core Node Vapor Temperature, 3-Inch Break, Low T,,,, Unit 1 . . . . . . 6-29 Figure 6.1.2-8 ECCS Pumped Safety injection Inch Break, Low T,,,, Unit 1. . . . . . . . . 6-30 Figure 6.1.2-9 Cold Leg Break Mass Flow, 3 Inch Break, Low T,,,, Unit 1 . . . . . . . . . . . . . 6-31 Figure 6.1.2-10 Hot Rod Surface Heat Transfer Coefficient Hot Spot,3-Inch Break, Lo w T,,,, Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-3 2 Figure 6.1.2-11 Fluid Temperature - Hot Spot,3-Inch Break, Low T,,,, Unit 1 ........ .. 6-33 Figure 6.1.2-12 Intact Loop Accumulator Flow,3-Inch Break, Low T,,,, Unit 1. . . . . . . . . . 6-34 Figure 6.1.2-13 Primary Side and Intact Loop Secondary Side Pressure,3-Inch Break, Lo w T,,,, Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6- 35 Figure 6.1.2-14 Intact Loop Cold Leg Nozzle Liquid Mass Flow Rate,3-Inch Break, Low T,,,, Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-36 Figure 6.1.2-15 Intar. Loop Cold Leg Nozzle Vapor Mass Flow Rate,3-Inch Break, l ow T,,,, Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6- 37 Figure 6.1.2-16 RCS Depressurization Transient,3-Inch Break, High T,,,, Unit 1. . . . . . . . . 6-38 Figure 6.1.2-17 Core Mixture level,3-Inch Break, High T,,,, Unit 1 . . . . . . ... .. .... 6-39 Figure 6.1.2-18 Peak Cladding Temperature - Hot Rod,3-Inch Break, High T,,,, Unit 1. . . . 6-40 Figure 6.1.2-19 RCS Depressurization Transient,3-Inch Break, Low T,,, Unit 2 . . . . . . . . . 6-41 Figure 6.1.2-20 Core Mixture Level,3-Inch Break, Low T,,,, Unit 2 ....... . ... . .. 6-42 Figure 6.1.2-21 Peak Cladding Temperature - Hot Rod,3-Inch Break, Low T,,,, Unit 2 . . . . 6-43 Figure 6.1.2-22 RCS Depressurization Transient,3-Inch Break, High T,,,, Unit 2 . ...... . 6-44 m:\3254 w .non\frontmir.wpf. I b.013097 vi

4 LIST OF FIGURES (cont.) Figure 6.1.2-23 Core Mixture level, 3-Inch Break, High T,,,, Unit 2 . . . . . . . . . . . . . . . . . 6-45 Figure 6.1.2-24 Peak Cladding Temperature - Hot Rod, 3-Inch Break, High T,,,, Unit 2 . . . . 6-46 Figure 6.1.2-25 RCS Depressurization Transient,2-luch Break, Low T,,,, Unit 1 . . . . . . . . . 6-47 Figure 6.1.2-26 Core Mixture Level,2-Inch Break, Low T,,,, Unit 1 .................. 6-48 Figure 6.1.2-27 Peak Cladding Temperature - Hot Rod,2-Inch Break, Low T,,,, Unit i ..... 6-49 Figure 6.1.2 28 RCS Depressurization Transient,4-Inch Break, Low T,,,, Unit 1. . . . . . . . . 6-50 Figure 6.1.2-29 Core Mixture Level,4-Inch Break, Low T,,,, Unit 1 .................. 6-51 Figure 6.1.2-30 Peak Cladding Temperature - Hot Rod,4-Inch Break, Low T,,,, Unit 1 . . . . 6-52 Figure 6.1.2-31 Peak Cladding Temperature - Hot Rod,3-Inch Break, Low T.,,, Unit 1, ZlRLO Cladding, 5500 MWD /MTU . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-53 Figure 6.1.2-32 Peak Cladding Temperature - Hot Rod,3-Inch Break Low T,,,, Urrit 1. Zirc-4 Cladding, 6000 MWD /MTU . . . . . . . . . . . . . . . . . . . . . . . . 6-54 Figure 6.1.4-1 Post-LOCA Suberiticality Boron ................................ 6-58 Figure 6.2.'i-1 Total Loss of External Electrical Load with Pressure Control Nuclear Po'.ver and Pressurimr Pressure versus Time . . . . . . . . . . . . . . . . 6-88 Figure 6.2.7-2 Total Loss of External Electrical Load with Pressure Control DNBR and Steam Temperature versus Time . . . . . . . . . . . . . . . . . . . . . . . 6-89 Figure 6.2.7-3 Total Loss of Extemal Electrical Load with Pressure Control Pressurimr Water Volume and Vessel Average Temperature versus Time . . . 6-90 Figure 6.2.7-4 Total Loss of Extemal Electrical Load without Pressure Control Nuclear Power and Pressurimr Pressure versus Time . . . . . . . . . . . . . . . . . 6-91 Figure 6.2.7-5 Total Loss of Extemal Electrical Load without Pressure Control DNBR and Steam Temperature versus Time . . . . . . . . . . . . . . . . . . . . . . . 6-92 Figuir 6.2.7-6 Total Loss of Extemal Electrical Load without Pressure Control Pressurimr Water Volume and Vessel Average Temperature versus Time . . . 6-93 i Figure 6.2.8-1 Loss of Normal Feedwater, Pressurimr Pressure and Level versus Time . . . . 6-99 ! Figure 6.2.8-2 Loss of Normal Feedwater, Nuclear Power and Core Heat Flux versus Time . 6-100 Figure 6.2.8-3 Loss of Normal Feedwater, RCS Loop Temperatures versus Time . . . . . . . . 6-101 j m:\3254w.non\frontmtr wpf.lb-013097 vii

._4

LIST OF FIGURES (cont.) Figure 6.2.8-4 Loss of Normal Feedwater, Steam Generator Pressure and Mass versus Time . 6-102 Figure 6.2.9-1 Loss of ac Power to the Plant Auxiliaries, Pressurizer Pressure and Level versus Time . . . . . . . . . . . . . . . . ............. . . . . . . . 6- 108 Figure 6.2.9-2 Loss of ac Power to the Plant Auxiliaries, Nuclear Power and Core Heat Flux versus Time ..................................6-109 Figure 6.2.9-3 Loss of ac Power to the Plant Auxiliaries, RCS Loop Temperatures versus Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-110 Figure 6.2.9-4 Loss of ac Power to the Plant Auxiliaries, Steam Generator Pressure and Mass versus Time ............................... 6-111 Figure 6.2.14-1 Inadvenent Operation of ECCS at Power DNBR Case, T,., = 577.2*F, Nuclear Power and Steam Flow versus Time . . . . . . . . . . . . 6-130 Figure 6.2.14-2 Inadvenent Operation of ECCS at Power DNBR Case, T,,, = 577.2*F, Pressurizer Pressure and Water Volume versus Time . . . . . . 6-131 Figure 6.2.14-3 Inadvenent Operation of ECCS at Power DNBR Case, T,,, = 577.2*F, Core Average Temperature versus Time . . . . . . . . . . . . . .6-132 Figure 6.2.14-4 Inadvenent Operation of ECCS at Power Pressurizer Fill Case, T,., = 577.2*F, Nuclear Power and Steam Flow versus Time . . . . . . . . . . . 6- 13 3 Figure 6.2.14-5 Inadvenent Operation of ECCS at Power Pressurizer Fill Case, T,,, = 577.2*F, Pressurizer Pressure and Water Volume versus Time . . . . . . 6-134 Figure 6.2.14-6 Inadvenent Operation of ECCS at Power Pressurizer Fili Case, T ., = 577.2*F, Core Average Temperature versus Time . . . . . . . . . . . . . . . 6-135 Figure 6.2.14-7 Inadvenent Operation of ECCS at Power Pressurizer Fill Case, T,., = 567.2*F, Nuclear Power and Steam Flow versus Time . . . . . ...... 6-136 Figure 6.2.14-8 Inadvenent Operation of ECCS at Power Pressurizer Fill Case, T,,, = 567.2*F, Pressurizer Pressure and Water Volume versus Time . . . . . . 6-137 , 1 Figure 6.2.14-9 Inadvenent Operation of ECCS at Power Pressurizer Fill Case. l T ., = 567.2*F, Core Average Temperature versus Time . . . . . . . . . . . . . . . 6-138 Figure 6.2.17-1 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay), Core Flow versus Time . . . . . . . . . .............. . . . . . 6-146 Figure 6.2.17-2 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay), Nuclear Power versus Time . ................... . . . . . . . 6- 147 l l m:\32s4 w aon\frontmtr.wpf. I b-013097 viii i

LIST OF FIGURES (cont.) Figure 6.2.17-3 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay), Pressurizer Pressure versus Time . . . . . . . . . . . . . . . . . . . . . . . . . 6-148 Figure 6.2.17-4 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay), Average Channel Heat Flux versus Time . . . . . . . . . . . . . . . . . . . . 6-149 Figure 6.2.17-5 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay), Hot Channel Heat Flux versus Time . . . . . . . . . . . . . . . . . . . . . . . 6-150 Figure 6.2.17-6 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay), DNBR versus Time ..................................6-151 Figure 6.2.19-1 Steamline Break Transient With Offsite Power 1.069 ft: Double Ended Rupture, Core Heat Flux and RCS Pressure versus Time . . . . . . . . . . . . . . . 6-162 Figure 6.2.19-2 Steamline Break Transient With Offsite Power 1.069 ft: Double Ended Rupture. Core Average Temperature and RV Inlet Temperature versus Time . 6-163 Figure 6.2.19-3 Steamline Break Transient With Offsite Power 1.069 ft: Double Ended Rupture, Pressurizer Water Volume and Core Flow versus Time . . . . . . . . . 6-164 Figure 6.2.19-4 Steamline Break Transient With Offsite Power 1.069 ft' Double Ended y Rupture, Core Boron and Reactivity versus Time . . . . . . . . . . . . . . . . . . . . 6-165 l 2 Figure 6.2.19-5 Steamline Break Transient With Offsite Power 1.069 ft Double Ended Rupture, Steam Pressure and Steam Flow versus Time . . . . . . . . . . . . . . . . 6-166 Figure 6.2.19-6 Steamline Break Transient With Offsite Power 1.069 ft' Double Ended Rupture, Total Feedwater Flow versus Time . . . . . . . . . . . . . . . . . . . . . . . 6-167 Figure 6.2.19-7 Steamline Break Transient Without Offsite Power 1.069 ft: Double Ended ; i Rupture, Core Heat Flux and RCS Pressure versus Time . . . . . . . . . . . . . . . 6-168 2 i Figure 6.2.19-8 Steamline Break Transient Without Offsite Power 1.069 ft Double Ended Rupture, Core Average Temperature and RV Inlet Temperature versus Time .6-169 Figure 6.2.19-9 Steamline Break Transient Without Offsite Power 1.069 ft: Double Ended Rupture, Pressurizer Water Volume and Core Flow versus Time . . . . . . . . . 6-170 2 Figure 6.2.19-10 Steamline Break Transient Without Offsite Power 1.069 ft Double Ended Rupture, Core Boron and Reactivity versus Time . . . . . . . . . . . . . . . . . . . . 6-171 Figure 6.2.19-11 Steamline Break Transient Without Offsite Power 1.069 ft: Double Ended Rupture, Steam Pressure and Steam Flow versus Time . . . . . . . . . . . . . . . . 6-172 Figure 6.2.19-12 Steamline Break Transient Without Offsite Power 1.069 ft: Double Ended Rupture, Total Feedwater Flow versus Time . . . . . . . . . . . . . . . . . . . . . . . 6-173 mA3254w.non\frontmtr.wpf.1b-013097 ix

LIST OF FIGURES (cont.) O Figure 6.2.21-1 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot), Reactor Coolant System Pressure versus Time . . . . . . . . . . . . . . 6-183 Figure 6.2.21-2 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Total RCS and Faulted Loop Flow versus Time . . . . . . . . . . . . . 6-184 Figure 6.2.21-3 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Nuclear Power versus Time . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-185 Figure 6.2.21-4 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot), Average Channel Heat Flux versus Time . . . . . . . . . . . . . . . . . . 6-186 Figure 6.2.21-5 All Loops Initially Operating, One Lncked Rotor (Peak Pressure / Hot Spot), Hot Channel Heat Flux versus Time . . . . . . . . . . . . . . . . . . . . . 6-187 Figure 6.2.21-6 All Loops Initially Operating One Locked Rotor (Peak Pressure / Hot Spot), Clad Inner Temperature versus Time . . . . . . . . . . . . . . . . . . . . . 6-188 Figure 6.2.22-1 RCCA Ejection, BOL HFP, Nuclear Power versus Time . . . . . . . . . . . . . . . 6-199 Figure 6.2.22-2 RCCA Ejection, BOL HFP, Hot Spot Fuel and Clad Temperatures versus Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6-200 Figure 7.2-1 Moderator Temperature Coefficient Versus Power at Beginning of Life No Xenon Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 16 Figure 7.2-2 Maximum Total Peaking FQ Versus Core Elevation, Normal Operation . . . . 7-17 i l l l i m11254 w .non\frontmtr *pf. l b-013097 x

I i ; 4 LIST OF ACRONYMS l 3- ( AE Auxiliary Equipment AFWS Auxiliary Feedwater System AFW Auxiliary Feed Water ! AIA Analysis Input Assumptions j i ALA J. M. Farley Unit I ! ANS American Nuclear Society l AOA Axial Offset Anomaly j APR J. M. Farley Unit 2 ARO All Rods Out ART Adjusted Reference Temperature j ARV (Steam Generator) Atmospheric Relief Valve ! ASME American Society of Mechanical Engineers AVB Anti-Vibration Bar i BE Best Estimate BELOCA Best Estimate Loss of Coolant Accident l l BOC Beginning of Cycle j BOL Beginning of Life ! BOP Balance of Plant

B&PV Boiler and Pressure Vessel j CCW Component Cooling Water C&FS Condensate and Feedwater System CH/SI Charging / Safety Injection (also referred to as HHSI) j CHF Critical Heat Flux COMS Cold Overpressure Mitigation System i CQD Code Qualification Document CRDM Control Rod Drive Mechanism

$ 'CRSD Core Radiation Source Data CS Control Systems CSAU Code Scaling, Applicability, and Uncertainty CST Condensate Storage Tank DBE Design Basis Earthquake ] DC Downcomer DECLQ Double-Ended Cold Leg Quillotine DEHL . Double-Ended Hot Leg DEPS Double-Ended Pump Suction DER Double Ended Rupture DNB Departure From Nucleate Boiling DNBR Departure From Nucleate Boiling Ratio ! DT Design Transients I ECCS Emergency Core Cooling System l mA3254w.non\fmanc.wpf:IMI3m xj

l i LIST OF ACRONYMS (cont.) EDG Emergency Diesel Generator O EOC End of Cycle EOP Emergency Operating Procedures EOL End of Life ER Engineering Report ERG Emergency Response Guidelines EFPY Effective Full Power Years ESF Engineered Safety Features FA Fuel Assemblies FAC Final Acceptance Criteria FCV Flow Control Valve FF Fouling Factor FIV Flow-Induced Vibrations FIL Full Length FLB Feedwater Line Break FNP Farley Nuclear Plant FS Fluid Systems FSAR Final Safety Analysis Report FWIV Feedwater Isolation Valve GDC General Design Criteria GDT Gas Decay Tanks HFF Hydraulic Forcing Functions HFP Hot Full Power HHSI High Head Safety Injection (also referred to as CH/SI) HL Hot Leg HLSO Hot Leg Switch Over HZP Hot Zero Power IFBA Integral Fuel Bumable Absorbers j IFMs Intermediate Flow Mixing Grids LBB Leak Before Break LBLOCA Large Break Loss of Coolant Accident l LHSI Low-Head Safety Injection (also referred to as RHR/SI) LOCA Loss of Coolant Accident LOF Loss of Flow LOLflT Loss of Loadfrurbine Trip j LONF Loss of Normal Feedwater ) LR Licensing Report l ! LTCC Long Term Core Cooling i ! M&E Mass and Energy ! MFIV Main Feedwater Isolation Valve i m:\3254w.non\frontmtr.wpf:1b-013097 Kii

I 1

LIST OF ACRONYMS (cont.) MOL Middle of Life MSIBV Main Steamline Isolation Bypass Valve MSIV Main Steamline Isolation Valve MSLB Main Steam Line Break MSSV Main Steam Safety Valve MTC Moderator Temperature Coefficient NF Neutron Fluence NPSH Net Positive Suction Head NRC Nuclear Regulatory Commission NSR Normalized Stability Ratio NSSS Nuclear Steam Supply System NUPPSCO Nuclear Power Plant Standard Committee OPAT Overpower Delta Temperature OTAT Overtemperature Delta Temperature P/L Part length ' PCT Peak Clad Temperature PCWG Performance Capability Working Group PGBU Power Generation Business Unit PLS Precautions, Limitations and Setpoints O PMA PMTC Process Measurement Allowance Positive Moderator Temperature Coefficient PORV Power Operated Relief Valve PSARV Pressurizer Safety and Relief Valve FTS Pressurized Dermal Shock PWR Pressurized Water Reactor RAOC Relaxed Axial Offset Control RCCA Rod Cluster Control Assembly RCL Reactor Coolant Loop RCLP&S Reactor Coolant Loop Piping and Supports l RCP Reactor Coolant Pump RCS Reactor Coolant System i RD Radiation Doses RG Regulatory Guide RHR Residual Heat Removal RHR/SI Residual Heat Removal / Safety Injection (also referred to as LHSI) RP Rod Performance RPVS Reactor Pressure Vessel System RSAC Reload Safety Analysis Checklist RSE Reload Safety Evaluation mA3254 w.non\frontmtr.wpf; l b-013097 xiii

i l LIST OF ACRONYMS (cont.) ' RSR Relative Stability Ratio RTDP Revised Thermal Design Procedure RTSR Reload Transition Safety Report RV Reactor Vessel RWST Refueling Water Storage Tank SAL Safety Analysis Limit SBLOCA Small Break Loss of Coolant Accident SCS Southem Company Services SFPCS Spent Fuel Pool Cooling System SG Steam Generator SGTP Steam Generator Tube Plugging SGTR Steam Generator Tube Rupture SI Safety Injection SIS Safety Injection System SLB Steam Line Break SNC Southem Nuclear Company SSE Safe Shutdown Earthquake STDP Standard 'Ihermal Design Procedure SW Service Water TDF Thermal Design Flow TG Turbine Generator T&H Thermal & Hydraulics TMI Three Mile Island V5 VANTAGE 5 VCT Volume Control Tank W Westinghouse WAR Work Authorization Request WOG Westinghouse Owners Group 9 m:\3254 w.non\frontmtr.wpf. l b-013097 xiv

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l ! I i, EXECUTIVE

SUMMARY

ne purpose of the Farley Power Uprate Project is to increase the electrical output (MWe) of Farley l i Nuclear Plant (FNP). ? r In support of the Farley Power Uprate Project, Westinghouse has performed analyses and evaluations for the Unit I and Unit 2 Nuclear Steam Supply Systems (NSSS) to demonstrate that the Farley NSSS l ts in compliance with applicable licensing criteria and requirements at the uprated NSSS thermal l power of 2785 MWt (reactor power of 2775 MWt). De scope of the Westinghouse analyses and j_ ' evaluations included the NSSS performance parameters, design transients, systems, components, f l accidents, and nuclear fuel. Those portions of the Westinghouse scope that are not impacted by power l uprate or were previously analyzed for power uprate conditions were not reanalyzed as part of this project. Furthermore, this report does not include all previously analyzed transients 'which assumed i power uprate conditions submitted as part of other licensing changes and approved by the NRC (e.g., [ VANTAGE 5 fuel and OTAT/OPAT setpoints). f i In addition to the NSSS analyses performed by Westinghouse, other power uprate analyses were performed by Bechtel, Southem Company Services (SCS), and Southern Nuclear Operating Company ; (SNC). To establish consistency among the various analyses, a common analysis input assumptions l list was mutually developed and used. . l This NSSS Licensing Report provides a description of the NSSS analyses and evaluations performed f by Westinghouse for the power uprate project. A description of the analyses and evaluations [ performed for the Balance of Plant (BOP) secondary systems and components and the radiological / ! containment response analyses is provided in the BOP Licensing Report. The focus of these Licensing l Reports is on providing the information required by NRC to approve power uprate for FNP. The results of the Westinghouse NSSS analyses and evaluations satisfy the project purpose and ! demonstrate that applicable licensing criteria and requirements are satisfied for the NSSS performance ! parameters, design transients, systems, components, accidents and nuclear fuel at the power uprate conditions. ;

i i l m:\3254w.non\frontmtr.wpf Ib413097 xy f

1.0 INTRODUCTION

1.1 Purpose and Scope

The purpose of performing the Farley Power Uprate Project NSSS analyses and evaluations is to demonstrate that the Farley NSSS is in compliance with applicable licensing criteria and requirements and can operate acceNably at the increased rated thermal power (power uprate) conditions. This report summarizes the NSSS analyses and evaluations and their results. The Farley Power Uprate Project scope is divided among Southern Nuclear Operating Company (SNC), Southem Company Services (SCS), Bechtel, and Westinghouse. De Westinghouse scope includes the Nuclear Steam Supply System (NSSS) performance parameters, design transients, systems, components, accidents and nuclear fuel. NSSS analyses that have already been performed for power uprate conditions, such as VANTAGE 5 fuel analysis, did not need to be reanalyzed as part of this project. The power uprate analyses and evaluations described in this report were based on the parameters listed in Section 2. { i 1.2 Methodology and Acceptance Criteria The Farley Power Uprate Project has been structured consistent with the methodolog- established in WCAP-10263, "A Review Plan for Uprating the Licensed Power of a PWR Power Plant," dated 1983. Since its submittal to the NRC, the methodology has been used successfully as a basis for power uprate projects on over twenty pressurized water reactor (PWR) units, including Vogtle Units 1 and 2 and Turkey Point Units 3 and 4. The methodology in WCAP-10263 established the ground rules and criteria for power uprate projects, including the broad categories that must be addressed, such as NSSS performance parameters, design transients, systems, components, accidents and nuclear fuel as well as the interfaces between the NSSS and the Balance of Plant (BOP) fluid systems. Inherent in this methodology are key points that promote correctness, consistency, and licensability. The key points include the use of well-defined analysis input assumptions / parameter values, use of currently approved analytical techniques (e.g., methodologies and computer codes) and use of currently applicable licensing criteria and standards. The power uprate analyses and evaluations were performed in accordance with Westinghouse quality assurance requirements defined in the Westinghouse Quality Management System (QMS) procedures, which comply with 10 CFR 50 Appendix B criteria. These analyses and evaluations are in conformance with Westinghouse and industry codes, standards, and regulatory requirements applicable to Farley Units I and 2. Assumptions and acceptance criteria are provided in the appropriate sections of this report. m:\32s4w.non\sec t.wpf:Ib-012997 l-l

l l l 1.3 Technical Basis for Significant liazards Evaluation This report and the BOP report provide the technical basis for the significant hazards evaluation included with the proposed Technical Specifications changes for the Farley Power Uprate Project. 1.4 Conclusions The results of the NSSS analyses and evaluations demonstrate that the Farley NSSS is in compliance with applicable licensing criteria and requirements and can operate acceptably at the power uprate conditions. l l l

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l 9 i m:02s4w.nonWImpf;IM12997 1-2

O

Q 2.0 NUCLEAR STEAM SUPPLY SYSTEM (NSSS) PARAMETERS The power uprate project included NSSS performance analyses to develop bounding NSSS Performance Capability Working Group (PCWG) Parameters. These parameters provide the Reactor , Coolant System (RCS) and secondary system conditions (temperatures, pressures, flow) that are used in the analyses and evaluations of the NSSS, including NSSS design transients, systems, components, accidents, and nuclear fuel. 2.1 PCWG Parameters 2.1.1 Introduction and Background Tne PCWG parameters are established using conservative assumptions in order to provide bounding

conditions to be used in the NSSS analyses. For example, the RCS flow assumed is the Thermal Design Flow (TDF), which is a conservatively low flow that accounts for flow measurement uncertainty and bounds the maximum expected steam generator tube plugging (SGl?) level (i.e.,15%

average /20% peak in one steam generator). The PCWG parameters were determined such that FNP would have operating flexibility; a range of conditions was therefore set based on the vessel average . temperature (T,,,) and the SGTP level. The T,,, range was specified between 567.2'F and 577.2*F, while the SGTP level can vary from 0% to 15% on average, with a maximum of 20% peak SGTP in ] d any one steam generator. The NSSS power level of 2785 MWt, the TDF value of 86,000 gpm/ loop, j J and the SGTP level of 15% average /20% peak are consistent with the PCWG parameters which were l used in the VANTAGE 5 Fuel Upgrade Project. j

2.1.2 Input Parameters and Assumptions l The input parameters and assumptions used in the calculation of the PCWG parameters established for i the uprate project are summarized in Table 2.1-1. The major inputs used in the generation of the PCWG parameters are listed below.

The power level for the uprating was set at 2785 MWt NSSS (2775 MWt core). This is approximately 4.7% higher than the current NSSS power rating of 2662 MWt (2652 MWt core). Note that the original NSSS rating for FNP was 2660 MWt, including 8 MWt net RCS heat input. But, NSSS analyses were recently performed to allow an increase to 2662 MWt by incorporating 10 MWt net RCS heat input, which more closely reflects actual plant performance. The current licensed core power remained unchanged.

       =       The TDF of 86,000 gpm/ loop incorporated sufficient margin to support 15% average SGTP.

This flow was applied for all cases, even those which assumed 0% SGTP, in order to be consistent and for conservatism. m.0254w.non\sec2.wpf;t t412997 2-1

Three values of SGTP were assumed: 0%,15%, and 20%. The current plugging levels at both Farley units are about 7%. Each unit is limited to a 15% average level which provides maximum margin allowance for future tube plugging. The 20% SGTP level allows for up to 20% plugging in any one steam generator, as long as the average of the 3 steam generators is not above 15%.
Design core bypass flow was assumed to be 7.1% with thimble plugs not installed. FNP has the capability of installing thimble plugs at some point in the future. Therefore, all applicable accident analyses address thimble plugs being in or out.
A range of full power normal operating T,,, from 567.2 F to 577.2*F was selected for the analyses. The maximum temperature of 577.2*F maintains the current design T,,, value on which all the present analyses, including the VANTAGE 5 fuel upgrade analyses, are based.

The lower T,,, of 567.2*F allows FNP to operate at reduced primary side temperatures. This 10*F temperature window is sufficient to cover the projected operating temperature range of both Farley units. 2.1.3 Acceptance Criteria for Determination of Parameters The primary acceptance criteria for the determination of the uprate PCWG parameters are (1) The parameters must minimize feasibility issues from an analysis point of view, and, (2) the parameters must provide FNP with adequate flexibility and margin for plant operation. 2.1.4 Discussion of Parameter Cases Table 2.1-2 provides the NSSS PCWG parameter cases which were generated and used as the basis for the uprating project. The original design parameters are also shown for comparison purposes. A description of the 6 uprated cases follows. Cases 1 through 3 represent the uprated conditions at a vessel average tempemture of 577.2*F. The difference between the 3 cases is the assumed SGTP level. Case 1 is based on 0% SGTP (to provide conservatively high secondary side performance conditions), Case 2 assumes 15% SGTP, and Case 3 assumes 20% SGTP. Although the plant is limited to 15% average and 20% peak SGTP in any one ( steam generator, the parameters in Case 3 are based on uniform 20% SGTP as a simplifying assumption for analysis purposes. Note that the primary side temperatures are identical for each of y these cases. Cases 4 through 6 reflect the same input assumptions as Cases 1 through 3 except that a reduced T,,, l j of 567.2*F is used. As such, Cases 4 through 6 yield the lowest possible design cold leg temperature for the analyses, as well as the minimum secondary side steam generator pressure and temperature.

a i m:\3254w.nonwc22pf;lb-012997 2-2

Dese 6 cases of performance capability parameters were used by Westinghouse in their analytical effons. Westinghouse performed the analyses and evaluations based on the parameter set or sets which were most limiting, so that the analyses would suppon operation of the Farley units over the range of conditions specified. i 1 O m:\3254w.non\sec2.wpf:Ib 012997 2-3

TABLE 2.1 1 NSSS PCWG INPUT PARAMETERS FOR FARLEY POWER UPRATE PROJECT Parameter Uprate FUEL TYPE AND FEATURES Type VANTAGE 5 IFMs (Yes/No) Yes Fuel Rod OD (Inches) 0.360 Number of Grids / Material 6 ZIRLO/ Zinc-4, 2 Inconel,3 IFM Clad Material ZIRLO/Zire 4 Peaking Factors Fq 2.5 (VS)** Fw 1.7 (VS)*' Pn i 1.574 (VS)"' NSSS THERMAL POWER NSSS Power (MW:) 2785 Core Power (MWt) 2775 Net Heat Input (MWt) 10 RCS FLOW Thermal Design Flow (gpm/ loop) 86,000 i Flow Measurement Uncertainty (%) 2.1 - 2.4 Total Core Bypass Flow (%) 7.1 Thimble Plugs (In/Out) In/Out RCS TEMPERATURE Vessel Average (*F)"' 567.2 - 577.2 Vessel Outlet ("F)") "' RCS PRESSURE (psia) 2250 STEAM GENERATOR Steam Pressure (psia)"' -"' l Moisture Carryover, Max (%) 0.25 l Steam Generator Tube Plugging Level Max (%) 15 avg /20 peak m:\3254w.non\sec2.wpf.lb 012997 2-4

J J TABLE 2.1 1 (cont.) NSSS PCWG INPUT PARAMETERS FOR FARLEY POWER UPRATE PROJECT j Parameter Uprate BOP SYSTEMS 9 Main Feedwater Temperature ("F) 443.4* i Notes: 1 4 l (1) Only T,,, or Tw is used as an input to the NSSS PCWG parameter analysis. Neither is used as an input if j steam generator outlet steam pressure is used as an input. See Note 2. ( ) (2) Steam generator outlet steam pressure may be used as an input to the NSSS PCWG parameter analysis if i it is specified (e.g., to support turbine generator MWe output) for use in the determination of a vessel T , or vessel T . f j (3) On a best-estimate basis, the actual Tu for power uprate is to be equal to or below the actual Tw at the j current NSSS power level (consistent with the turbine generator performance analysis). The NSSS PCWG j l Parameters for use in the NSSS design and safety analyses may specify higher values for Tw consistent with NSSS PCWG parameter analysis methodology (e.g., use of a conservatively low RCS Thermal J Design Flow). (4) On a best-estimate basis, the power uprate steam generator outlet steam pressure is to be equal to or above ; 787 psia (consistent with the turbine generator performance analysis). The NSSS PCWG Parameters for > j use in the NSSS design and safety analyses may specify lower values for steam generator outlet steam j pressure consistent with NSSS PCWG parameter analysis methodology (e.g., use of a conservatively high l

steam generator fouling factor and maximum SGTP levels).

(5) The feedwater temperature value of 443.4'F is consistent with NSSS PCWG panmeter analysis I methodology for the uprated power level of 2785 MWt. On a best-estimate basis, the feedwater . temperatures for Unit I and Unit 2 are anticipated to be .vithin a couple degrees of this value. l (6) Analyses and/or evaluations will be performed to provide bounding values for LOPAR fuel (and V5 fuel adjacent to LOPAR assemblies) in case LOPAR fuel assemblics are used in the core. These will be 4 addressed as necessary during the reload process by use of approved methodologies. Peaking factors are

not used as input in the calculation of PCWG parameters.

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TABLE 2.12 NSSS PCWG PARAMETERS FOR FARLEY POWER UPRATE PROJECT THERMAL DESIGN PARAMETERS Oririnal CASE 1 CASE 2 CASE 3 NSSS Power, % 100 104.7 104.7 104.7 MWt 2660 2785 2785 2785 10' BTU /hr 9079 9503 9503 9503 Reactor Power, MWs 2652 2775 2775 2775 10' BTU /hr 9051 9469 9469 9469 Thermal Design Flow, I.oop gpm 88,500 86,000 86,000 86,000 Reactor 10' lb/hr 100.7 98.1 98.1 98.1 Reactor Coolant Pressure, psia 2250 2250 2250 2250 Core Bypass, % 4.5 7.1 7.1 7.1 Reactor Coolant Temperature, 'F Core Outlet 613.7 618.1 618.1 618.1 Vessel Outlet 610.9 613.3 613.3 613.3 Core Average 580.3 581.8 581.8 581.8 Vessel Average 577.2 577.2 577.2 577.2 Vessel / Core inlet 543.5 541.1 541.1 541.1 Steam Generator Outlet 543.3 540.8 540.8 540.8 Steam Generator Steam Temperature. 'F 517.2 518.0 512.4 510.0 Steam Pressure, psia 793 798 760 744 Steam Flow,10' lb/hr total i1.61 12.27 12.25 12.25 Feed Temperature. 'F 437.3 443.4 443.4 443.4 Moisture, % max. 0.25 0.25 0.25 0.25 Tube Plugging, % 0 0 15 20 Zero Load Temperature, 'F 547 547 547 547 HYDRAULIC DESIGN PARAMETERS Pump Design Point, Flow (gpm)/flead (ft.) 88.500/264 , Mechanical Design Flow, gpm 101,800 l Minimum Measured Flow, gpm total 274,800 264.200'" 264,200'" 264,200'" l Best Estimate Flow, gpm 95,000 92,000 90,700 FOOTNOTES: (1) MMF based on 2.4'A flow measurement uncertainty; analyses cover range of MMF from 263,400 gpm (2.1%) to 264,200 gpm (2.4%). O m:\3254w.nonisec2nf:tt412997 2-6

 ,- ~

TABLE 2.12 (cont.) l NSSS PCWG PARAMETERS FOR FARLEY POWER UPRATE PROJECT THERMAL DESIGN PARAMETERS Original CASE 4 CASE 5 CASE 6 i NSSS Power, % 100 104.7 104.7 104.7 MWt 2660 2785 2785 2785 l 19 BTU /hr 9079 9503 9503 9503 Reactor Power, MWt 2652 2775 2775 2775 ! 1& BTU /hr 9051 9469 9469 9469 Thermal Design Flow, loop gpm 88,500 86,000 86,000 86.000 99.4 99.4 99.4 l Reactor 11lb/hr 100.7 Reactor Coolant Pressure, psia 2250 2250 2250 2250 ! Core Bypass, % 4.5 7.1 7.1 7,1 l Reactor Coolant Temperature, 'F Core Outlet 613.7 608.8 608.8 608.8 Vessel Outlet 610.9 603.8 603.8 603.8 Core Average 5803 571,7 571.7 571.7 Vessel Average 577.2 567.2 567.2 567.2 Vessel / Core inlet 543.5 530.6 530.6 530.6 Steam Generator Outlet 543.3 5303 5303 5303 l Steam Generator l Steam Temperature. 'F 517.2 507.1 501.5 499.1 Steam Pressure, psia 793 726 690 675 Steam Flow,11 lb/hr total 11.61 12.24 12.22 12.22 : N Feed Temperature 'F Moisture, % max. 4373 0.25 443.4 0.25 443.4 0.25 443.4 0.25 Tube Plugging, % 0 0 15 20 , Zero lead Temperature 'F 547 547 547 547 j HYDRAULIC DESIGN PARAMETERS Pump Design Point Flow (gpm)/ Head (ft.) 88,500/264 Mechanical Design Flow, gpm 101,800 274,800 264,200* 264,200'" 264,200'" Minimum Measured Flow, spm total 95,000 92,000 90,700 Past Estimate Flow, gpm FOOTNOTES: (1) MMF based on 2.4% flow measurement uncertainty; analyses cover range of MMF from 263,400 gpm (2.1%) to 264,200 gpm (2.4%). l l l I f l 4 l l m:\3254w.non\sec2.wpf.Ib.012997 27

                                                          -                   -                                 -                          -l

i 3.0 NSSS DESIGN TRANSIENTS h 4 This chapter discusses the generation of NSSS and auxiliary equipnent design transients for the , uprated power conditions. Current NSSS design transients were analyzed for their continued j applicability at uprated power and the resulting transient curves were provided to all system and i component designers for use in their specific analyses. Section 3.1 describes the evaluation performed. } Auxiliary equipment design transients were also evaluated to determine whether they remain applicab'e j for use in the uprating analysis of all the auxiliary equipment in the NSSS. The results of this l evaluation are presented in Section 3.2. } 3.1 NSSS Design Transients i 1 i- 3.1.1 Introduction and Background i i As part of the original design and analyses of the NSSS components for the Parley Nuclear l Plant (FNP), NSSS design transients (i.e., temperature and pressure transients) were specified for use j in the analyses of the cyclic behavior of the NSSS components. To provide the necessary high degree j of integrity for the NSSS components, the transient parameters selected for component fatigue analyses j were based on conservative estimates of the magnitude and frequency of the temperature and pressure ,j transients resulting from various plant operating conditions. The transients selected for use in component fatigue analyses were representative of operating conditions which would be considered to I occur during plant operations and were considered to be sufficiently severe or frequent to be of possible significance to component cyclic behavior. The selected transients were representative of j plant transients which, when used as a basis for component fatigue analysis, would provide confidence l that the component was appropriate for its application over the operating license period of the plant. For purposes of analysis, the number of transient occurrences were based on an operating license 1 period of 40 years.

i 3.1.2 Input Parameters and Assumptions NSSS design transients are based primarily on the NSSS Performance Capability Working Group (PCWG) parameters as discussed in Chapter 2 of this report. 'Ihe NSSS PCWG parameters upon which the original NSSS design transients were based were compared to the NSSS PCWG parameters for power uprate and shown to be different in critical areas such as RCS hot leg j temperature (Tw) and RCS cold leg temperature (T ). These differences are sufficient to require l reassessment of the original NSSS design transients and to require that revised NSSS design transients be specified for power uprate. 1 l l mA3254w.nonisec3.wpf:lt412997 3-1

1 1 1 3.1.3 Description of Analyses and Evaluations The Farley PCWG parameters for power uprate were compared to the PCWG parameters for plants prototypical to Farley in order to identify NSSS design transients which bound the Farley PCWG parameters (i.e., Tu and Ta) fcr power uprate and which are broader than and could be conservatively used in the Farley NSSS component fatigue analyses and evaluations. This evaluation identified a prototypical plant for which the majority of NSSS design transients were appropriate for Farley. These prototypical NSSS design transients were supplemented with analyses to develop Farley-specific design transients. These revised NSSS design transients were used in the NSSS component fatigue analyses and evaluations presented in Chapter 5 of this report. 3.2 Auxiliary Equipment Design Transients l 3.2.1 Introduction and Background As part of the original design and analyses of the NSSS auxiliary components (i.e., NSSS auxiliary pumps, valves, and heat exchangers) for FNP, auxiliary equipment design transients (i.e., temperature and pressure transients) were specified for use in the analyses of the cyclic behavior of the NSSS , l auxiliary components. To provide the necessary high degree of integrity for the NSSS auxiliary components, the transient parameters selected for component fatigue analyses were based on conservative estimates of the magnitude and frequency of the temperature and pressure transients resulting from various plant operating conditions. The transients selected for use in component fatigue analyses are representative of operating conditions which would be considered to occur during plant operations and are considered to be sufficiently severe or frequent to be of possible significance to component cyclic behavior. The transients were selected to be conservative representations of transients which, when used as a basis for component fatigue analysis, would provide confidence that I the component was appropriate for its application over the operating license period of the plant. For purposes of analysis, the number of transient occurrences were based on an operating license period of 40 years. 3.2.2 Input Parameters and Assumptions l The review of the NSSS auxiliary equipment design transients was based on a comparison between the NSSS PCWG parameters for power uprate as discussed in Chapter 2 of this report and the parameters which make up the curren; auxiliary equipment design transients. O m:\3254w.non\sec3.wpf;1b-012997 3-2

i i 3.2.3 Description of Analyses and Evaluations 4 7 A review of the current auxiliary equipment transients determined that the only transients that could be 4 potentially impacted by the uprating are those temperature transients that are impacted by full load

NSSS operating temperatures, namely Tw and T,.. These transients are currently based on an assumed full load NSSS worst case Tw of 630*F and worst case T,. of 560 F. These NSSS temperatures were originally selected so that the resulting design transients would be conservative for a i wide range of NSSS operating temperatures.

4 3.2.4 Results and Conclusions-f j Since the PCWG parameter ranges for Tw (603.8* - 613.3*F) and T, (530.6* - 541.l*F), are less l limiting than the temperature ranges which established the current auxiliary equipment design I transients, it is concluded that the actual temperature transients (that is, the change in temperature from Tw or T,. dictated by the uprated parameters to a lower auxiliary system related temperature or vice 1 l versa) are less severe than the current design temperature transients, and these design transients remain j applicable at uprated power. O i 1 i ?, a i. I m:\3254w.non\sec3.wpf.lb-012997 3-3

4.0 NSSS SYSTEMS j- 4.1 NSSS Fluid Systems 4.1.1 Reactor Coolant System l The Reactor Coolant System (RCS) consists of three heat transfer loops connected in parallel to the l l 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 / relief valves. The steam discharged from the PORVs and safety / relief valves flows through interconnecting piping to the pressurizer relief tank (PRT). This section identifies the key functions of the RCS and identifies which functions are potentially impacted by the uprate project.

     'Ihe key RCS functions are as follows.

1) The RCS transfers heat generated in the reactor core to the MSS via the SGs.

O. i I

2) When the core is suberitical and RCS temperatures are approximately 350*F and lower, the RCS provides means to transfer decay and sensible heat to the Residual Heat Removal Systein j (RHRS).

3) The RCS fluid acts as a moderator of neutrons by slowing the neutrons to lower thermal energy states and increasing the probability of thermal fission.

4) The RCS fluid is a solvent and carrier of boric acid which is used as a neutron poison.

5) The RCS is the second of three " barriers" against fission product release to the environment.

(The fuel cladding is the first barrier, and the containment building is the third.)

6) The RCS provides means for pressure control via use of pressurizer heaters and spray flow.

The calculated RCS design operating conditions at the uprated power are presented in Chapter 2 of this report. The primary changes in PCWG parameters which impact the RCS functions include the increase in core power, the allowable operating range for average RCS temperature (T,,,), and reduced Thermal Design Flow. O m:\3254w.non\sec4.wpf lt412997 4.]

The potential impact of the uprated conditions on the previous RCS functions are described below. a) The core power increase will affect the total amount of heat transferred to the MSS. Verification that the major components can suppoit this normal heat removal function is addressed in Chapter 5 of this report. b) During the second pha,e of plant cooldown, the RHRS will be required to remove larger amounts of decay heat from the RCS. Section 4.1.4 of this report addresses the RHRS cooldown capability at upreted conditions. c) The increase in thermal power can change the transient response of the RCS to normal and postulated design basis events. The acceptability of the RCS with respect to control and protection functions are addressed in Sections 4.3 and 6.7 of this report. d) With reduced TDF, RCS loop flows can decrease. The reduction in RCS loop flows, in tum, can reduce pressurizer spray flow capability since loop velocity head is used for driving head. In addition, a range of steady state full power RCS operating temperatures is established. This range, in turn, can cause changes in nominal pressurizer level which can change the steam release potential to the PRT. The " systems" impact of these described changes is discussed within this section. i 4.1.1.1 Input Parameters and Assumptions As noted earlier, the general acceptability of the changes to RCS operating conditions is justified by acceptable plant transient and safety analyses results which are discussed in other sections of this report. For the FNP uprate project, various " systems" assessments were performed. Provided below is a listing of key inpct parameters used in the " systems' assessments.

1) To provide design input to the calculation of revised RCS source terms, an RCS liquid mass at full power operating conditions was calculated. RCS masses were calculated for 0% and 15%

SG tube plugging levels. In addition, RCS masses were calculated for T,y values of 567.2 F and 577.2*F.

2) For RCS loops used for pressurizer spray flow, lower RCS flows reduce the available driving head for spray. To support RCS transient response and plant safety analyses, a range of pressurizer spray flow under full spray operation was calculated. For this calculation, the piping layouts for Farley Units 1 and 2 were used along with pressurizer spray valve hydraulic performance.

mA3254w.nonhec4 wpf:lb012997 42

l l r l [ ]d 3) The range of RCS operating temperatures provided in Chapter 2 of this report was used as a basis to evaluate RCS design temperatures. i , 4) Operation at a lower RCS T,,, condition increases the available pressurizer steam space j volume that may have to be condensed in the PRT u'nder limiting RCS transient conditions (e.g., loss of load event). The existing Westinghouse PRT design basis sizing calculation for FNP was used as a basis for this evaluation. I !

5) The NSSS Precautions, Limitations and Setpoint (PLS) document for Farley Units I and 2 was l i used as a basis to identify the potential need for process setpoint changes. In general, this [

I ' document provided the bases for process control setpoints for fluid systems within the scope of Westinghouse. ! 4.1.1.2 Results

Pressurizer spray flow capability was calculated considering a range of RCS process conditions (
corresponding to the T,,, range of 567.2*F - 577.2'F at the revised RCS Best Estimate Flow. This [

d provides an expected range of flow considering hydraulic / calculational uncertainty. The calculations demonstrate that the minimum required spray flow of 600 gpm can be achieved over the entire range ; 7 of anticipated RCS process conditions. ; t i The maximum expected RCS Hot Leg (TJ temperature at uprated conditions is 613.3'F. This l temperature is well within the RCS loop design temperature of 650*F. Note, the pressurizer and the i surge line have a higher design temperature of 680*F. ! l With respect to the PRT, the revised range of RCS T,,, will change the nominal full load pressurizer l ] steam volume at uprated conditions. In general, the reference nominal pressurizer level is coordinated j with RCS T,,, such that an increase in T,,, raises the nominal pressurizer reference level condition. With respect to the PRT discharge analysis, a lower RCS T,,, condition is more limiting than a higher !

RCS T,,, condition, since pressurizer level is lower and steam volume is larger. i l

The Westinghouse setpoint calculation for the Farley PRT considered the maximum pressurizer steam I 2 { discharge equal to 110 percent of a nominal full load pressurizer steam volume of 608 ft . With a

1400 ft' pressurizer vessel, the assumed steam volume comprises approximately 43% of the total i available volume. For Farley, Westinghouse specified the design basis RCS T,., condition at 577.2'F.

l At this value, the Westinghouse PLS document specifies a plant pressurizer nominal reference level condition of 55% of level span. For comparison purposes, this condition would represent a nominal j steam volume of 45% of level span. At the thermal uprate project lower specified RCS T,,, condition (567.2*F), the nominal pressurizer j level would be reduced. Using the design basis level program, the revised reference level at the lower . T,,, condition would be approximately 44% of span. The steam volume would correspond to m:\3254w.non\sec4.wpf.Its012997 43 J l

approximately 56% of span. The discharge of this steam mass to the PRT after an isentropic compression to the safety valve discharge pressure results in a maximum PRT temperature of 204*F, and is acceptable. Therefore, the low alarm setpoint (68%) will not be changed. The current high alarm setpoint (78%) results in a PRT pressure less than one-half of the rupture disc burst pressure. Therefore, the high alarm setpoint is acceptable. A review of the pressure drop between the reactor vessel annulus and the reactor vessel outlet nozzle was also performed to assess whether any changes had to be incorporated in the cold overpressure mitigation analysis. A previous analysis for Farley Units 1&2 determined the pressure drop between the reactor vessel annulus at midloop elevation, and the outlet nozzle, also at midloop elevation. That analysis was performed based on the design conditions applicable at that time, including the current power level. The analysis has been reviewed in light of the uprated power conditions, which include an NSSS power level of 2785 MWt. The conclusion of this review is that the pressure drops calculated and provided in the above mentioned previous analysis remain valid for the power uprate conditions. This conclusion is based on the following:

1) The cold overpressure mitigation calculation is based on 0% power. As such, the uprated power itself has no effect on the result.

2) The pressure drop was also determined at cold conditions (70*F) to maximize the AP. He temperature range included with the uprating program therefore has no impact as well.

3) The RCS flow and associated AP were determined at a steam generator tube plugging level of 2%, which is less than the current level of approximately 7% in both units. His is a conservative assumption used to obtain greater flowrates and greater pressure drops. It is act

) likely that Farley will unplug enough tubes that would yield an equivalent plugging level less than 2%. In addition, the calculated best estimate flow at 0% power and 70*F was increased by 2% to provide some additional margin and to account for any uncertainties. The pressure drop values which were previously calculated for the cold overpressure mitigation analysis remain bounding for the uprating and are as follows.

                                           # RCPs Running     AP (psi) 1              25 2              35 3              60 9

m:\3254w.non\sec4 wpf:1b-012997 4-4

Lastly, the PLS document was reviewed with respect to the thermal uprate operating conditions, and no changes are required for the RCS section of the PLS. The pressurizer spray line and surge line low temperature alarm serpoints were also evaluated. The original design basis value for each is 500 F and was set considering a design basis RCS T, value of 543.5*F. The minimum RCS T,,is defined at 530.6*F at the uprated conditions. Although the absolute margin between T,a and the nominal low alarm setpoint is reduced (43.5*F versus 30.6*F), no operational concems (e.g., nuisance alarm) are expected with the existing setpoint value. 4.1.1.3 Conclusions As previously stated, the acceptability of the revised RCS operating conditions at uprated power is discussed in various sections of this report and the BOP Licensing Report. From a " systems" perspective, operation at the revised RCS conditions was assessed. The overall conclusion from this assessment is that uprating will not affect the ability of the RCS to perform its design basis functions and that no system changes are required. 4.1.2 Chemical and Volume Control System The Chemical and Volume Control System (CVCS) is a key auxiliary support system to the RCS. The CVCS is physically connected to the RCS and is normally in operation. Its primary design function is to maintain RCS water inventory, boron concentration, and water chemistry. Other RCS I support functions include purification and seal injection flow to the RCPs. Key functions of the CVCS are as follows: RCS Pressure Boundary Integrity - Portions of the CVCS which comprise the reactor coolant pressure boundary are designed for expected RCS operating conditions to minimize the probability of pressure boundary failure. Boration - Consistent with the requirements of 10 CFR 50 Appendix A (General Design Criteria), the CVCS provides means for reactivity control independent of control rods. This function is accomplished via delivery of boric acid solution, which is a neutron absorber, into the RCS.

Containment Isolation - Following design basis events, CVCS connections to the RCS which penetrate containment, with the exception of the RCP seal injection line, are automatically isolated during all events that require containment isolation.

i mA3254w.non\sec4.wpf.It>-012997 45

The primary RCS parameter changes due to the thermal uprating include an increase in core power, allowable operatcg range for RCS T,,,, and reduced Thermal Design Flow. The impact of the revised operating conditions on CVCS functions are described below. a) With the revised RCS T,,, range, RCS operating temperatures can vary and potentially affect RCS pressure boundary integrity. The acceptability of revised RCS temperatures on systems performance is discussed within Section 4.1.2.2. The acceptability of revised RCS temperatures with respect to thermal transients on CVCS components is addressed in Section 5.9 of this report. b) With a revised RCS T,,, range, RCS liquid volume can change, which may impact boration requirements. With respect to CVCS boration operations, a smaller RCS liquid volume is conservative. As such, no additional discussion is required. For dilution operations, a smaller RCS liquid volume results in faster dilution. From an analysis standpoint, this is conservative and requires no additional discussion. From a loss of RCS shutdown margin condition, faster dilution is adverse to safety. This issue is addressed in Section 6.2 of this report. c) Containment isolation functions are not impacted by the power uprate conditions. 4.1.2.1 Acceptance Criteria for Analyses / Evaluations In the assessment of CVCS operation at revised RCS operating temperatures, the maximum expected O. RCS Ta must be less than or equal to the applicable CVCS design temperature and less than or equal to the heat exchanger design inlet operating temperature. The former criterion supports the functional operability of the system and its components. The latter criterion supports the heat exchanger design operating conditions. In the assessment of CVCS operation at revised Component Cooling Water System (CCWS) operating temperatures, the maximum expected CCWS " supply" temperature must be less than or equal to existing allowable operating limits. This criterion supports the overall functional operability of the system and the components serviced by the CCWS. In the event a CCWS temperature incr:ase occurs, further component evaluations would be required. The CVCS boration capability must meet or exceed core reload requirements for both emergency boration and ability to satisfy RCS shutdown margins. This is verified as a normal part of the fuel l reload process. O mA3254w.non\sec4*pf;tb-012997 4-6

p Q 4.1.2.2 Results With respect to maximum expected RCS cold leg temperature, the current design basis RCS T,. temperature is 543.5*F. At uprated conditions, the revised design basis T, is 541.l*F. This revised temperature is well within the system design temperature of 650*F (same as the RCS) and within the maximum RCS inlet operating temperature of 547'F considered in the CVCS overall design including the regenerative and excess letdown heat exchangers. The RCS pressure boundary integrity is therefore not affected. Furthermore, since regenerative and excess letdown heat exchangers are within l the design basis temperatures, the letdown and seal water heat exchangers, which are located l downstream, will also operate within acceptable limits. Since T, will be less than or equal to the current design basis of 543.5*F, heat loads on the CCWS remain valid for power uprate. The CVCS portion of the PLS document was reviewed with respect to the thermal uprate operating conditions and no changes are required. Existing system operating parameter bands and associated ! alarm / control setpoints are acceptable. l l 4.1.23 Conclusions l From a " systems" perspective, CVCS operation at the revised RCS temperature conditions were I q reviewed and the results prescated in the previous subsection. The overall conclusion from this k assessment is that the uprating will not require any system changes for the CVCS to perform its design basis functions. 4.13 Safety Injection System ne Safety injection System (SIS) is an Engineered Safeguards System which is used to mitigate the effects of postulated design basis events. The basic functions of this system include providing short and long-term core cooling, and maintaining core shutdown reactivity margin. He SIS is also referred to as the emergency core cooling system (ECCS). At Farley Units I and 2, the SIS is comprised of three subsystems. The passive portion of the system is the three accumulator vessels which are connected to each of the RCS cold leg pipes. Each accumulator contains borated water under pressure (nitrogen cover gas). The borated water automatically injects into the RCS when the pressure within the RCS drops below the operating pressure of each of the accumulators. The active portion of the SIS is comprised of a high pressure and a low pressure injection subsystem. Both subsystems utilize centrifugal pumps which automatically start following generation of a Safety Injection (SI) signal. The High Head Safety Injection (HHSI) system provides emergency core cooling flow as soon as the operating pressure within the RCS drops below the HHSI " Cut-In" pressure (HHSI C pump shut off head adjusted for the effects of pump miniflow and elevation).

  .ms--a -                                           47 l

The Residual Heat Removal System (RHRS) is used as the low pressure subsystem. In this Low Head Safety Injection (LHSI) subsystem, injection flow will occur as soon as the operating pressure within the RCS drops below the RHRS " Cut-In" pressure (RHRS pump head adjusted for elevation). As the design basis event proceeds, the Refueling Water Storage Tank (RWST) borated 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 HHSI and LHSI pumps are required to be realigned, using the sump as a water source, to support the cold leg recirculation mode of operation. Long-term core cooling is provided by the LHSI system heat exchangers. In an immediate response to a design basis event, the SIS is designed to perform its safety functions, assuming a loss of offsite power, and considering a single active failure. An example of a postulated single failure is the failure of an emergency diesel generator to start. This failure would preclude a train of SIS pumps from operating. In the long term (beyond 24 hours), if an active failure has not occurred, a system leak (i.e., passive failure specifically identified in the licensing bases) could occur which may require operator actions to realign the system to support adequate performance. Several attemate flow paths exist so that long term core cooling can be provided should a passive failure occur. 4.1.3.1 Input Parameters and Assumptions In general, the specified changes in RCS operating conditions due to thermal uprating (higher core power, and range in hot full power T,y) have no direct effect on the overall performance capability of the SIS. These systems will continue to deliver a selected range of calculated flow performance (minimum and maximum) as determined by interfacing system / structure operating conditions (RCS pressure, containment pressure, etc.). The acceptability of a given range of SIS performance is justified by acceptable plant safety vialysis l results. For this project, the plant safety analyses were reanalyzed or evaluated. For the HHSI subsystem, a reduced (i.e., further degraded) minimum pump performance curve was used. This change provides future operating flexibility. The primary effect of this change on subsystem performance is a reduction in both " Cut-In" pressure and minimum flow delivery capability. In order to support evaluation of this change in operating conditions, revised minimum HHSI subsystem flow performance was calculated. In addition, the HHSI branch line balancing criteria has been relaxed to allow 20 gpm flow imbalance between branch lines. Currently, the plant uses a flow balance criteria of 198 1 5 gpm for each branch line. A revised criteria of 198 gpm -5 gpm / +15 gpm was implemented in the uprate l analyses. m:\3254w.non\sec4.wpf:Ib-012997 4-8

r For the LHSI subsystem, a new base pump curve and an increased (i.e., funher degraded) degradation allowance for the minimum pump performance curve was used. This change provides future operating flexibility. The primary effect of this change on subsystem performance is a reduction in both

  " Cut-In" pressure and minimum flow delivery capability. In order to suppon evaluation of this change in operating conditions, revised minimum LHSI subsystem flow performance was calculated.

To calculate revised SIS performance, hydraulic models of Parley Unit I and 2 safety injection subsystems were created. These models were based on the latest piping layout drawings for the safety injection subsystems and suppon removal of the Boron Injection Tank (BIT). Resistances for the throttled or orificed paths were based on either test criteria or test results. Paths with throttle valves include the high head safety injection cold and hot leg branch lines, the RCP seal injection lines, and the lines which contain the RHR butterfly valves. The charging pump miniflow line resistances were based on vendor test data for the miniflow orifices. 4.1.3.2 Results Different cases of ECCS flow rates, various RCS pressures and different combinations of ECCS equipment were evaluated. The minimum safeguards ECCS flow rates (LHSI and HHSI) for this repon were calculated assuming a pump head degradation allowance of 10% (of the design head at the o design flow). The calculated ECCS flowrates were provided as input to the various plant safety analyses. All flowrates are applicable to both units. 4.133 Conclusions The acceptability of the existing and newly calculated SIS operating parameters defined for this project , is documented in the various discussions of individual plant safety analysis results as summarized in Chapter 6 of this report. All results show that the performance of the SIS is acceptable to meet all I plant safety analysis acceptance criteria. 4.1.4 Residual Heat Removal System l l 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 core decay heat. The auxiliary 4 feedwater and main steam systems are used for the RCS heat removal during the first phase of plant ! cooldown and may supplement the second phase of plant cooldown. This section discusses the RHRS normal functions (i.e., heat removal). The Engineered Safeguards functions of the RHRS are discussed in Section 4.1.3 (SIS). b) V The maximum heat removal demand on the RHRS 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 m:\32s4w.non\sec4.wpf.Ib-012997 49

Coolant Pump (RCP) must all be removed to suppon RCS temperature cooldown. In addition, operating restrictions are imposed on the maximum allowable CCWS temperature and flow 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, and SW system inlet temperature. In general, RHRS thermal heat removal capability becomes more restricted when operating conditions change as outlined below.

Higher RCS heat loads
Lower RHRS flows
Lower CCWS flow to the RHRS heat exchanger
Lower SW flow to the CCWS heat exchanger i
Higher CCWS auxiliary heat loads
Higher CCWS temperatures
Lower CCW heat exchanger UA )

l l 4.1.4.1 Input Parameters and Assumptions ; i Of the specified changes in RCS operating conditions addressed by this project, only the increase in reactor core power level has a significant effect on RHRS thermal performance capability. I Specifically, higher core power levels will increase RCS decay heat loads, which must be removed during plant cooldown and shutdown conditions. As such, detailed thermal analyses were performed. From a hydraulic (flow) perspective, the revised RCS operating conditions have no direct impact on j the flow delivery capability of the RHRS. As such, no hydraulic evaluations were performed. l Likewise, existing instrumentation and controls are independent of uprated conditions and were not evaluated. RHRS thermal performance was calculated for each of the following three cooldown scenarios.

1) The ability of the RHRS to accept the RCS heat removal function during the second phase of plant cooldown (i.e., RHRS Cut-In). l

2) 'Ihe 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 available (including support system 0 is referred to as a " normal" plant cooldown within the context of this section.

3) The ability of the RHRS to cool down the RCS under limiting equipment availability to a cold shutdown condition (200 F). Note, RHRS operation -vith one subsystem of equipment available (including support systems) is referred to as a " single train" plant cooldown within the context of this section.

m:\32s4w.non\sec4 wpf:1b-012997 4-10

t 0(> For scenario 2), the RHRS major components were originally sized to achieve a targeted (desired) ' overall cool down from system " Cut-In" (which occurs 4 hours after reactor shutdown) to a refueling RCS temperature (140*F) in approximately 16 hours (20 hours total duration). This " normal" cooldown (with all cooling equipment available) was reanalyzed at the higher core power level. ! For scenario 3), the Farley Technical Specifications require that the RHRS cool the RCS from 350*F i at 6 hours after shutdown to 200 F by 36 hours after plant shutdown in the event that one CCWS train is unavailable. Westinghouse worked closely with SCS to establish a set of thermal analysis operating conditions which would bound current thermal uprate plant conditions. Westinghouse performed the thermal analyses, and SCS and Bechtel performed the necessary CCWS and SW System hydraulic analyses which provided inputs (i.e., cooling system flows). Provided below are key inputs used in the various RHRS the:1nal (cooldown) analyses.

RHRS " Cut In" Temperature - 350*F
CCWS Maximum Allowable Temperature - 120*F for normal cooldown

                                                         - 130*F for single train cooldown O

SW System Maximum Inlet Temperature - 95'F during normal operation (97.3*F post-LOCA in the other unit)
RCP Heat input Term to the RCS/RHRS - 17.3 x 10' BTU /hr (when 1 RCP operating)
RCS Heat Capacity - 1.7 E+6 BTU /*F 4.1.4.2 Acceptance Criteria for Analyses / Evaluation When all cooling equipment is available, the RHRS is expected to perform a " normal" cooldown. The '

original RHRS equipment sizing criteria (20 hour cooldown to 140 F) was aibitrarily selected based j on economic considerations. As such, there is not a specific design basis acceptance criterion for the

       " normal" cooldown. In the standard Westinghouse plant Technical Specifications, however, a 36-hour cold shutdown time duration is typically specified for conditions which result in plant equipment        ,

I remaining inoperable past the allowable action time. The 36 hour duration is broken down to a 6 hour period to achieve a Hot Standby condition with an additional 30 hour duration specified to achieve a Cold Shutdown condition. A single train cooldown could occur if some equipment is unavailable. The Farley Tech .ical Specifications require that the RHRS cool the RCS from 350*F at 6 hours after shutdown to 2 36 hours after plant shutdown in the event that one CCWS train is unavailable. m:\3254w.non\sec4.wpf:1b-012997 41]

4.1.4.3 Results and Conclusions The following are the results and conclusions drawn for each of the analyzed scenarios:

RHRS ' Cut-In" It was determined that the RHRS is capable of accepting the RCS heat removal function at uprated conditions. That is, the RHRS can be " Cut-In" (and atmospheric steam release can be terminated) within the 8 hour time period which is assumed in the radiological dose analyses.
" Normal" Cooldown With all cooling equipment trains available, the maximum calculated duration to cool down the RCS from 350*F to 200 F (Cold Shutdown) is less than 6 hours. The 6-hour maximum calculated duration is well within the 30-hour technical specification cooldown time.

With all cooling equipment trains available, the maximum calculated time to cool down the RCS from 200*F to 140 F (Refueling) is less than 27 hours. Any extension of the cooldown time is primarily an economic factor.

*         " Single Train" Cooldown (equipment unavailable)

If plant cooldown is initiated with only one train of equipment available, the RHRS can cool the RCS from 350*F to 200*F within 46 hours with the SW temperature at the maximum allowable operating temperature of 95*F. If the SW temperature ir v7.3'F, one train of equipment can cool the RCS from 350*F to 200 F within 52 hours. The cooldown time can be reduced to within the Technical Specification limit of 30 hours by stopping the operating reactor coolant pump when RCS temperature reaches 220*F. Based on the above discussions, it can be concluded that the operation of the Farley Units 1 and 2 RHRS at thermal uprate RCS operating conditions will not impact its ability to perform intended decay heat removal functions. 4.1.5 Other NSSS Systems Other NSSS systems which were reviewed and found to be acceptable for power uprate were the Boron Recycle System, the Boron Thermal Regeneration System, and the Waste Gas Processing System. O m:\3254w.non\sec4.wpf:lb ol2997 4-12

a i i 4 4.2 NSSS/ BOP Fluid Systems Interfaces i The following Balance-of-Plant (BOP) fluid systems were reviewed to assess compliance with j Westinghouse Nuclear Steam Supply Systems (NSSS)/ BOP interface guidelines: Main Steam System j (MSS), Steam Dump System, Condensate and Feedwater System, Auxiliary Feedwater System and i I Steam Generator Blowdown System. The various interface systems were reviewed with the purpose of j providing interface information which could be used in the more detailed BOP analyses. The results 1 of those analyses are provided in the BOP Licensing Report. l l The uprated condition increases NSSS power to 2785 MWt. At the upper T,,, limit of 577.2*F, the j power increase would result in approximately 5.7% increase in steam /feedwater mass flow rates. l Additionally, the steam generator average tube plugging level of 15% in combination with the lower

limit T,,, of 567.2 F would result in a reduction of full-load steam pressure from 793 psia to 690 psia. '

l The evaluations of the above BOP systems relative to compliance with Westinghouse NSSS/ BOP

interface guidelines were performed to address the NSSS PCWG parameters for power uprate analyses which include ranges for parameters such as T.,, (567.2*F to 577.2*F) and steam generator tube j plugging (0% to 15% average). These ranges on NSSS operating parameters result in ranges on BOP j parameters such as steam generator outlet steam pressure (690 psia to 798 psia). De NSSS/ BOP interface evaluations were performed to address these ranges on NSSS and BOP parameters even v though the Farley units are not expected to operate at the low end of the steam generator outlet pressure range due to turbine volumetric flow limits.

4.2.1 Main Steam System The uprating coupled with the potential reduction in full-load steam pressure to the average minimum ! value of 690 psia impacts main steam line pressure drop. At the a'retage minimum steam generator , pressure of 690 psia, the full-load steam mass flow rate would increase about 5.3 percent; however, l due to the reduced operating pressure and the lower-density steam, the volumetric flow rate would j increase by approximately 22 percent and steam line pressure drop would increase by approximately 28 percent. <

Note that the original NSSS operating parameters for the NSSS power of 2660 MWt resulted in a l I steam line pressure drop of about 43 psi and a pressure of about 750 psia at the turbine inlet valves. Based on the range of NSSS operating parameters for the uprating to 2785 MWt, the lowest steam generator pressure would result in a pressure at the turbine inlet valves of approximately 635 psia. ! ne major components ci the MSS are the Stean: Generator Main Steam Safety Valves (MSSVs), the j Steam Generator Power Operated Atmospheric Relid Valves (ARVs) and the Main Steam Isolation Valves (MSIVs). , i mA32s4w.non\sec4 wpf.1t9012997 4 .13 1 1

4.2.1.1 Steam Generator Main Steam Safety Valves The MSSVs must have sufficient capacity so that main steam pressure does not exceed 110% of the steam generator shell-side design pressure (the maximum pressure allowed by the ASME B&PV Code) for the worst-case loss-of-heat-sink event. Based on this requirement, Westinghouse applies the conservative criterion that the valves should be sized to relieve 105 percent of the maximum calculated steam flow at an accumulation pressure not exceeding 110 percent of the Main Steam System design pressure. Each operating unit at Farley Nuclear Plant has fifteen safety valves with a total capacity 4 12,984,660 lb/hr, which provides about 105.8 percent of the maximum calculated steam flow lo/hr for the uprating. The total capacity was originally based on the capacity of all safety valves at an inlet accumulation pressure of 1182.5 psig, which is 10% above the lowest set safety valve pressure (1075 psig). As stated in the Technical Specifications, operability of the MSSVs limits the secondary system pressure to within 110% (1194 psig) of its design pressure of 1085 psig during the most severe anticipated system operational occurrence. Therefore, based on the range of NSSS PCWG parameters for the uprating, the capacity of the installed MSSVs meets the Westinghouse sizing criterion. 4.2.1.2 Steam Generator Power Operated Atmospheric Relief Valves (ARVs) The primary function of the ARVs is to provide a means for decay heat removal and plant cooldown by discharging steam to the atmosphere when either the condenser, the condenser circulating water pumps, or steam dump to the condenser is not available. Under such circumstances, the ARVs in conjunction with the Auxiliary Feed 9 ater System (AFWS) permit the plant to be cooled down from the pressure setpoint of the lowest-set MSSVs to the point where the Residual Heat Removal System ) (RHRS) can be placed in service. During cooldown, the ARVs are either automatically or manually ! controlled. In automatic, each ARV P&I controller compares steam line pressure to the pressure setpoint, which is manually set by the plant operator. The ARVs also automatically modulate open and exhaust to atmosphere whenever the steam line pressure exceeds a predetermined setpoint to minimize safety valve lifting during steam pressure transients. In the event of a tube rupture event in conjunction with loss of offsite power, the ARVs are used to , cool down the RCS to a temperature that permits equalization of the primary and secondary pressures at a pressure below the lowest-set MSSV. RCS cooldown and depressurization are required to preclude steam generator overfill and to terminate activity release to the atmosphere. The three ARVs are sized to have a capacity equal to about 10 percent of the steam flow used for plant design, at no-load steam pressure. At uprated power, this capacity permits a plant cooldown to RHRS operating conditions in 4 hours (at an assumed cooldown rate of 50*F/hr) assuming 2 hours at hot standby. This sizing is compatible with normal cooldown capability and minimizes the water supply required by the AFWS. This is based on one train of AFW operating and flow going through all three SGs. mA32s4w.non\sec4 wpf.Ib-012997 4 14

l l Based on the range of NSSS operating parameters for the uprated power level, the ARV total capacity is about 14 percent of the required maximum steam flow. Therefore the ARVs are adequate based on the range of NSSS operating conditions proposed for uprating. 4.2.1.3 Main Steam Isolation Valves and Main Steam Isolation Bypass Valves The MSIVs are located outside the containment and downstream of the MSSVs. The valves function to prevent the uncontrolled blowdown of more than one steam generator and to minimize the RCS

cooldown and containment pressure to within acceptable limits following a main steam line break. To , acccmplish this function, the original design requirements specified that the MSIVs must be capable of closure within 5 seconds of receipt of a closure signal against steam break flow conditions in the forward direction. As part of the power uprate project, NSSS control systems and safety analyses ! I were performed to relax this maximum closure time requirement to 7 seconds. Rapid closure of the MSIVs following postulated steam line breaks causes a significant differential pressure across the valve seats and a thrust load on the main steam system piping and piping supports in the area of the MSIVs. The worst cases for differential pressure incicase e.nd thmst loads are controlled by the steam line break area (i.e., mass flow rate and moisture content), throat area of the steam generator flow restrictors, valve seat bore, and no-load operating pressure. Since these variables and no-load operating pressure are not impacted by the uprating, the design loads and associated stresses resulting from rapid closure of MSIVs will not change. Consequently, power uprate has no significant impact on the interface requirements for the MSIVs. The MSIV bypass valves are used to warm up the main steam lines and equalize pressure across the MSIVs prior to opening the MSIVs. The MSIV bypass valves perform their function at no-load and low power conditions where power uprate has no significant impact on main steam conditions (e.g., steam flow and steam pressure). Consequently, power uprate has no significant impact on the interface requirements for the MSIV bypass valves. 4.2.1.4 Main Steam System Conclusions ! i Conclusions of the assessment of the uprated conditions on the Main Steam System are summarized below.

Based on the range of NSSS operating parameters for the uprating, the capaci% of the installed MSSVs meets the Westinghouse sizing criterion.
The installed ARVs are adequately sized for the uprating.
The MSIVs and MSIV bypass valves are not impacted by the uprating.

m:u254wmonssec4.wpfa b-ot2997 4-15 1 j

4.2.2 Steam Dump System The steam dump system creates an artificial steam load by dumping steam from ahead of the turbine valves to the main condenser. The Westinghouse sizing criterion recommends that the steam dump system (valves and pipe) be capable of discharging 40 percent of the rated steam flow at full-load steam pressure to permit the NSSS to withstand an external load reduction of up to 50 percent of plant rated electrical load without a reactor trip. To prevent a trip, this transient requires all NSSS control systems to be in automatic, including the Reactor Control System, which accommodates 10% of the load reduction. A steam dump capacity of 40 percent of rated steam flow at full load steam pressure also prevents MSSV lifting following a reactor trip from full power, assuming a 10% step load reduction is accomplished by the control rod drive system. 4.2.2.1 Steam Dump System Major Components Each FNP unit is provided with eight condenser steam dump valves. The total capacity provides a steam dump capability of about 41.9 percent of the original maximum guaranteed steam flow. For the uprated conditions, an evaluation indicates that the total steam dump capacity is about 38 percent of rated steam flow at the lower end of the T,,, operating range. A total steam dump capacity of about 38 percent of full load steam flow should be adequate since early plant startup testing demonstrated that the recommended capacity of 40 percent of rated flow includes about 15 percent margin. Note at the upper end of the T,,, operating range and a full-load steam generator pressure of 798 psia, steam dump capacity is about 45 percent of rated flow. The NSSS controls systems analysis (Section 4.3) provides an evaluation of the adequacy of the steam dump capacity at the uprated conditions. To provide effective control of flow on large step load reductions or plant trip, the steam dump valves are required to go from full-closed to full-open in 3 seconds at any pressure between 50 psi less than full load pressure and steam generator design pressure. The dump valves are also required to modulate to control flow. Positioning response may be slower with a maximum full stroke time of 20 seconds. These requirements are still applicable for the NSSS operating conditions for uprating. 4.2.2.2 Steam Dump System Conclusion The conclusion of the assessment of the uprated conditions on the Steam Dump System is that for the range of operating conditions for the uprating, steam dump capacity is less than the Westinghouse recommended capacity at the lowest analyzed steam pressure; however, the design load rejection capability has been confirmed by a control systems operability assessment (i.e., margin to trip analysis) and the condenser steam dump system has been shown to be acceptable. m:\3254w.non\sec4.wpf.lb-012997 4-16

O . Q 4.2.3 Condensate and Feedwater System The Condensate and Feedwater System (C&FS) must automatically maintain steam generator water i levels during steady-state and transient operations. The range of NSSS PCWG parameters will result in a required feedwater volumetric flow increase of up to 6.3 percent during full-power operation. The i higher feedwater flow and higher feedwater temperatures will have an impact on system pressure drop, which may increase by as much as 12.3 percent. Also, a comparison of the uprated PCWG parameters with the original PCWG parameters indicates that the SG full-power operating steam pressure may be decreased by as much as 103 psi.

       'Ihe major components of the Condensate and Feedwater System are the Feedwater Isolation Valves, 4

the Feedwater Control Valves and the Condensate and Feedwater System Pumps. t 4 4.2.3.1 Feedwater Isolation Valves /Feedwater Control Valves The feedwater isolation valves (FIVs) are located outside containment and upstream of the feedwater j control valves (FCVs). The valves function in conjunction with the primary isolation signals to the FCVs and backup trip signals to the feedwater pumps to provide redundant isolation of feedwater flow to the steam generators following a steam line break or a malfunction in the steam generator level o control system. Isolation of feedwater flow is required to prevent containment overpressurization and )h excessive reactor coolant system cooldowns. To accomplish this function, the FCVs and the backup FIVs must be capable of closure within 5 seconds and 30 seconds respectively, following receipt of any feedwater isolation signal. The quick-closure requirements imposed on the FCVs and the backup FIVs causes dynamic pressure ! l changes that may be of large magnitude and must be considered in the design of the valves and associated piping. The worst loads occur following a steam break from no load conditions with the conservative assumption that all feedwater pumps are in service providing maximum flow following the break. Since these conservative assumptions are not impacted by the uprating, the design loads and j associated stresses resulting from rapid closure of these valves will not change. l 4.2.3.2 Condensate and Feedwater System Pumps 2 3 The C&FS available head in conjunction with the FCV characteristics must provide sufficient margin ! for feed control to ensure adequate flow to the steam generators during steady-state and transient , operation. A continuous steady feed flow should be maintained at all loads. The hydraulics of the C&FS in conjunction with the allowable range of feedwater pump n d control should permit operation over the entire range of NSSS operating conditions for uprating. However, to

  , / optimize feedwater control and minimize the duty on the feedwater control valves, the feedwater pump j(    speed control program should be adjutted for the specific operating conditions.

m:\3254w.non\sec4.wpf.It412997 4.}7 1

Further evaluation of the C&FS, including the feedwater and condensate pumps, is contained in the BOP Licensing Repon. This evaluation shows acceptable results. 4.233 Condensate and Feedwater System Conclusions The evaluations of the Condensate and Feedwater System at the uprated conditions show that the hydraulics of the C&FS in conjunction with the allowable range of feedwater pump speed control permit operation over the entire range of full power NSSS operating conditions for the uprating. 4.2.4 Auxiliary Feedwater System The Auxiliary Feedwater System (AFWS) supplies feedwater to the secondary side of the steam generators at times when the normal feedwater system is not available, thereby maintaining the heat sink of the steam generators. The system provides feedwater to the SGs during normal unit stanup, hot standby, and cooldown operations and also functions as an Engineered Safeguards System. In the latter function, the AFWS is directly relied upon to prevent core damage and system overpressurization in the event of transients and accidents such as a loss of normal feedwater or a secondary system pipe break. The minimum flow requirements of the AFWS are dictated by accident analysis, and since the uprating impacts these analyses, evaluations of the limiting transients and accidents are performed to confirm that the AFWS performance is acceptable at the uprated conditions. The AFWS pumps are normally aligned to take r,uction from the condensate storage tank (CST). To O fulfill the Engineered Safety Features (ESF) design functions, sufficient feedwater must be available during transient or accident conditions to enable the plant to be placed in a safe shutdown condition. During normal plant operations, the CST should contain a minimum useable inventory of condensate that is sufficient to bring the unit from full load to hot standby conditions in the event of a total loss of offsite power, hold the plant at hot standby for 2 hours, and then cooldown the RCS to hot shutdown (RHRS cut-in temperature 350*F) in 4 hours. As pan of the original plant design process, Westinghouse determined that 142,000 gallons of condensate was required to meet the above design interface criteria. Since this inventory is a function of plant rated power and other NSSS operating parameters, a new analysis was performed as pan of the BOP analyses to determine / confirm the required inventory at uprated conditions. This analysis is described in the BOP Licensing Report. O m \3254w.non\sec4.wpf.It>-012997 4*'

4.2.4.1 Auxiliary Feedwater System Conclusions he Auxiliary Feedwater System was evaluated at uprated conditions and the conclusions are summanzed below. = De minimum flow requirements of the AFWS are dictated by accident analysis and since the uprating impacts these analyses, evaluations of the limiting transients and accidents have been performed to confirm that the AFWS performance is acceptable at the uprated operating conditicas. These analyses are described in Chapter 6.0 of this repon and show acceptable results. A new analysis to determine the required CST inventory at uprated conditions was performed as pan of the BOP analyses and is described in the BOP Licensing Repon. This analysis shows acceptable results. t 4.2.5 Steam Generator Blowdown System ! The Steam Generator Blowdown System is used in conjunction with the Chemical Addition System to , control the chemical composition of the steam generator shell water within the specified limits. The l blowdown system also controls the buildup of solids in the steam generator water. i ne Farley steam generators and the SG blowdown system are designed to handle a maximum ) continuous blowdown rate of 12.5 GPM per steam generator and a maximum intermittent blowdown l rate of 50 GPM per steam generator. The maximum rate can only be handled through the bypass i ponion of the processing system, since the processing equipment is only designed to handle 50 GPM total from all three steam generators. De actual blowdown flows required during unit operation are based on chemistry control and tubesheet sweep requirements to control the buildup of solids. Dese requirements are not significantly impa::ted by uprating. De capability of the SG blowdown system at power uprate conditions has been evaluated as pan of the BOP analyses, is described in the BOP Licensing Repon, and has been shown to be acceptable. 4.2.5.1 Steam Generator Blowdown System Conclusions Conclusions of the evaluation for the Steam Generator Blowdown System are as follows.

The interface requirements are not significantly impacted by uprating.
The capability of the SG Blowdown System at power uprate conditions has been shown to be acceptable as described in the BOP Licensing Repon.

m:\3254w.non\sec4 wpf;1b-012997 4 19 l

4.3 NSSS Control Systems The impact on the NSSS control systems for the Farley power uprate was evaluated. The NSSS control systems functional requirements and logics have not been changed from the current design basis requirements. However, Rod Control (Reactor Control), Steam Dump Control, and Pressurizer Level Control systems require setpoint changes to support the power uprate project. Also, protection system setpoint changes must be accounted for to determine the impact on unit operating margin. This section summarizes the control system Condition I transient analyses performed for uprate and *.he associated evaluation results. To ensure that the revised NSSS control systems setpoints will provide an acceptable plant response at the uprated power conditions, the limiting NSSS control systems design basis Condition I transients (50% load rejection,10% step load change, and 5% per minute ramp) were analyznl. The results showed an acceptable plant response during and following the transients. The results also demonstrated acceptable control system performance. However, the 50% load rejection transient at low T,,, and beginning of life (BOL) conditions showed slight oscillatory plant responses during and following the transient. This is not considered to be a function of power uprate but rather a strong function of core kinetics and the magnitude of the steam dump proportional band. The analysis results of the 50% load rejection at low T,,, and end-of-life (EOL) conditions are acceptable. The steady-state plant response and plant operability margins are also acceptable at low T,,, and BOL conditions. With a slightly higher full load T.,, (570 F), acceptable results were obtained at BOL conditions. Based on this, it is judged that a slight oscillatory plant response following a 50% Joad rejection transient at low T,,, and BOL conditions is receptable. The revised pressurizer level program for full power will accommodate the pressurizer no-load to full load shrink / swell for the plant heatup and cooldown at both high (577.2'F) and low (567.2*F) T,,, at the uprated power conditions.

  'Ibe reactor protection system OTAT and OPAT setpoints and time constants, and Permissive P-9 and P-8 setpoints have been reviewed for the power uprate project. The recently revised OTAT and OPAT setpoints were evaluated to assess the plant operability margins during and following the Condition I transients at the uprated power conditions. "Ihe steady-state and transient margins to OTAT and OPAT were also evaluated. The results demonstrate that adequate operating margins exist for these setpoints I

at steady-state and transient conditions. The evaluation of the permissive P-9 setpoint showed that with all NSSS control systems operational in the automatic mode, the maximum allowable P-9 setpoint is 50% power. That is, a turbine trip from 50% power with a pennissive P-9 setpoint of 50% power will not result in opening of the pressurizer PORVs or a reactor trip. The revised permissive P-8 setpoint is not challenged by the Condition I transients and therefore was not evaluated with respect to plant operability margins during and following Condition I transients. Other reactor trips that could be challenged by Condition I transients at uprated power (i.e., power range high flux high, pressurizer low pressure, pressurizer high level, and SG low-low level) were included in the transient analyses. Evaluation of the analysis results confirmed that plant operating margins are not degraded. f mA3254w.non\sec4 M :lt>-012997 4-20

P i I W margin to certain Engineered Safety Features (ESF) setpoints (e.g., pressurizer low pressure, steam line low pressure, and SG high-high level) may be affected by the low T,,, operation. These ESF i setpoints were also evaluated using the uprate Condition I transient analysis. Results showed adequate l margn to all ESF actuation setpoints considered for this evaluation, except the low steam line pressure l Si actuation setpoint at low T,., conditions. With a full load steam pressure 2 715 psia at low T,,, (567.2*F), however, an adequate margin to low steam line SI setpoint was obtained. This is acceptable ; because it has been determined, as part of the turbine generator performance analyses, that the Farley l units will not be able to operate at full thermal power at steam pressures below approximately j 770 psia. l The sizing of the major NSSS control system components (e.g., steam dump valves, pressurizer spray ; valves and heaters, etc.) potentially affected by the power uprate project was evaluated, and the results showed that the instaJed capacities of these components are adequate for the Farley power uprate. The Westinghouse control system analysis associated with the cold overpressure mitigation analysis was also reviewed for the power uprate project. This review concluded that the results of the analysis l (i.e., equivalent mass input rate for heat input transient) remained valid for the power uprate conditions. ; i l t i i I mv254w.nonw4.wpf.iwi2997 4-21 ; j

h 5.0 NSSS COMPONENTS 5.1 Reactor Vessel A 5.1.1 Structural Evaluation j P Evaluations were performed for the various regions of the Farley Units 1 and 2 reactor vessels to ; determine the stress and fatigue usage effects of NSSS operation at the revised operating conditions of j the Power Uprate Project throughout the cunent plant operating licenses. De evaluations assessed the effects of the revised design transients and operating parameters on the most limiting locations with regant to inges of stress intensity and fatigue usage factors. De . evaluations considered a worst case set of operating parameters and design transients from among the l high temperature power uprate conditions, the low temperature power uprate conditions, and the original design basis. In addition, reactor vessel operation from plant startup until implementation of the power uprate and any future operation in accordance with the original design basis is still fully covered by the stress and fatigue analyses. Where appropriate, revised maximum ranges of stress intensity and maximum usage i factors were calculated for the power uprate project. In other cases the original design basis stress analysis remains conservative so that no new calculations were necessary. In addition to the revised operating parameters and design transients for the power uprate project, a i new set of LOCA loads at the reactor vessel / reactor intemals interfaces was identified. De revised l interface loads were evaluated by co;nparing them with the corresponding Faulted Condition reactor vessel / reactor internals interface loadings which were justified for application to the Farley Units I and 2 reactor vessels. i The evaluation of the Farley Units 1 and 2 reactor vessels show that they are acceptable for plant ! operation in accordance with the power uprate project. Derefore, the reactor vessel power uprate evaluation addresses reactor operation within the expanded operating temperature ranges as indicated above. Such operation is shown to be acceptable in accordance with the 1968 Edition of Section III of the ASME Boiler and Pressure Vessel Code with Addenda through the Summer 1970 for the remainder of the plant licenses. ! The reactor vessel power uprate evaluation demonstrates that power uprate increases the maximum ranges of stress intensity for only the primary outlet and inlet nozzles. The increased maximum ranges of stress intensity for the primary nozzles and nozzles safe ends still remain within the acceptance criterion of 3S,. In addition, the maximum cumulative fatigue usage factors are affected minimally by the revised power uprate conditions and continue to remain below the acceptance criterion of 1.00. m11254w.non\sec5.wpf:1b 013097 5-1

5.1.2 Reactor Vessel Integrity Reactor vessel integrity is impacted by any changes in plant parameters that affect neutron fluence levels or pressure / temperature transients. The most critical area, in terms of reactor vessel integrity, is the beltline region of the reactor vessel. The changes in neutron fluence resulting from the Farley Units 1 and 2 Uprating Program have been evaluated to determine the impact on reactor vessel integrity. This assessment included a review of the current material surveillance capsule withdrawal schedules, applicability of the current heatup and cooldown pressure-temperature limit curves, and a revision to the RTm 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. Plant-specific material infonnation, including related data available from surveillance program results, has been considered in the uprating evaluation. 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 ARTmn) for development of the surveillance capsule withdrawal schedules, adjusted reference temperature (ART) values for determining the applicability of the heatup and cooldown curves, and RTm values. New heatup and cooldown limit curves have been calculated for 36 and 54 EFPY at power uprate conditions. These curves will be provided to the NRC under separate submittal. g it was determined that all of the beltline materials in the Farley Units 1 and 2 reactor vessels have RTm values below the ITS Rule screening criteria at EOL. Also, Farley Units 1 and 2 will be in Categories I and 11 for the Emergency Response Guideline (ERG) pressure-temperature limit categories, respectively. Therefore, it is concluded that the uprating program for Farley Units I and 2 will not have a significant impact on the reactor vessel integrity. 5.2 Reactor Pressure Vessel System The reactor pressure vessel (RPV) system consists of the reactor vessel, reactor intemais, fuel, and control rod drive mechanisms. The reactor intemals function to support and orient the reactor core fuel assemblies and control rod assemblies, absorb control rod assembly dynamic loads, and transmit these and other loads to the reactor vessel. The reactor vessel internal components also function to direct coolant flow through the fuel assemblies, to provide adequate cooling flow to the various internals structures, and to support in-core instrumentation. They are designed to withstand forces due to stmetural deadweight, preload of fuel assemblies, control rod assembly dynamic loads, vibratory loads, earthquake accelerations, and LOCA loads. O l I mA3254w.nonssecs.wpr:ib-oi3097 5-2

I i i l b Evaluation of the uprated conditions requires that the reactor vessel /intemals/ fuel system interface be assessed to show compatibility and that the structural irc.egrity of the reactor vessel /intemals/ fuel l system is not adversely affected. In addition, thermal-hydraulic analyses are required to determine plant specific core bypass flows, pressure drops and upper head temperatures in order to provide input to the LOCA and non-LOCA safety analyses as well as NSSS performance evaluations. Generally, the areas of concern most affected by changes in system operating conditions are: a) Reactor intemals system thermal / hydraulic perfonnance; b) Rod control cluster assembly (RCCA) scram performance; and c) Reactor internals system structural response and integrity. 5.2.1 Thermal / Hydraulic System Evaluations 5.2.1.1 System Pressure Losses ne principal reactor coolant system flow route through the reactor pressure vessel system at the Farley units begins at the three inlet nozzles. At this point, flow tums downward through the reactor vessel core barrel annulus. After passing through this downcomer region, the flow enters the lower reactor vessel dome region. His region is occupied by the internals energy absorber structure, lower O support columns, bottom-mounted instrumentation columns, and supporting tie plates. From this region, flow passes upward through the lower core plate, and into the core region. After passing up through the core, the coolant flows into the upper plenum, turns, and exits the reactor vessel through the three outlet nozzles. Note that the upper plenum region is occupied by support columns and RCCA guide columns. A key area in evaluation of core performance is the determmation of hydraulic behavior of coolant flow within the reactor intemals system, i.e., vessel pressure drops, core bypass flows, RPV fluid temperatures and hydraulic lift forces. The analysis determined the distribution of pressure and flow l within the reactor vessel, intemals, and the reactor core for the uprated conditions. 5.2.1.2 Bypass Flow Analysis l 1 Bypass flow is the total amount of reactor coolant flow bypassing the core region and is not i considered effective in the core heat transfer process. Since variations in the size of some of the j bypass flow paths, such as gaps at the outlet nozzles and the core barrel, occur during manufactunng or change due to different fuel assembly designs or due to changes in the RCS conditicas, plant specific as-built dimensions are used in order to demonstrate that the bypass flow lir.dts are not violated. Therefore, analyses are performed to determine core bypass flow values to either show that the design bypass flow limit for the plant will not be exceeded or to determine a revised design core m:\3254w.non\sec5.wpf:1b-013097 5-3

bypass flow. Note that since the as-built information is different between Farley Unit I and Unit 2, each unit will have a different best estimate core bypass flow value. The present design core bypass flow limit is 7.1% (with thimble plugs removed) of the total reactor vessel flow for each Farley unit. The purpose of this evaluation is to show that the design value of 7.1% can be maintained at the uprated RCS conditions. The principal core bypass flow paths are the: Baffle-Barrel Region; Vessel Head Cooling Spray Nozzles; Core Barrel - Reactor Vessel Outlet Nozzle Gap; Fuel Assembly - Baffle Plate Cavity Gap; and Fuel Assembly Thimble Plugs. Note that regarding the baffle / barrel region, the Farley Unit 2 reactor vessel intemals configuration incorporates downward coolant flow in the region between the core barTel and the baffle plates. For the downflow configuration, only the flow that actually leaks through the baffle joints and into the core before it reaches the bottom of the baffle-barrel region is core bypass flow. The Farley Unit I reactor vessel intemals incorporate a converted upflow configuration. The reactor coolant flow enters the baffle-barrel region at the bottom former elevation and passes through the flow holes at each successively higher former elevation, past the upper core plate, and into the outlet plenum. For the upflow configuration, all the flow which enters the baffle / barrel region is core bypass flow. Fuel assembly hydraulic characteristics, system parameters, such as inlet temperature, reactor coolant pressure and flow were used in conjunction with a computer code to determine the impact of the new uprated conditions on the total core bypass flow. The total core bypass flow values (including uncertainties) were determined to be 5.74% and 5.49% for Units 1 and 2, respectively. 'Iherefore, the design core bypass flow value of 7.1% of the total vessel flow is maintained. 5.2.1.3 Hydraulic Lift Forces The reactor internals hold-down spring is essentially a large diameter belleville type spring of rectangular cross section. The purpose of this spring is to maintain a net clamping force betweco tne reactor vessel head flange and upper intemals flange and the reactor vessel shell flange and the core barrel flange of the intemals. An evaluation was performed to determine hydraulic lift forces on the various reactor intemal 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, the Farley Unit 1 & 2 reactor internals assembly would remain seated and stable. O l m:\3254w.nonisec5.wpf lb413o97 5-4 l l

  - . ~ . _ - . _ . . _ _ - . . _ _ _ _ . . . _._. _ ._. _ ._ _                                          . . . . _ . _ _ _ . _ . . _ _ _ _ . . _ ._.

t f 5.2.1.4 RCCA Scram Performance Evaluation i i ! De RCCAs represent the interface between the fuel assemblies and the other intemals components. , ! An evaluation was performed to determine the potential impact due to power uprating at Farley I Units 1 and 2 on RCCA scram characteristics used in the FS AR for accident analyses. This analysis is based on 17 x 17 VANTAGE 5 fuel assemblies presently umi in the Farley units. I Calculations were performed which indicated that, for even the most severe case, the maximum drop ! time-to-dashpot entry of 2.7 seconds for the Farley Units 1 and 2 remains conservatively applicable for j accident analyses. 9 i 5.2.1.5 Momentum Flux and Fuel Rod Stability l

Baffle jetting is a hydraulically induced instability or vibration of fuel rods caused by a high velocity j jet of water. This jet is created by high pressure water being forced through gaps between the baffle i plates which surround the core. In order to guard against fuel rod failures from flow induced
vibration, the crossflow emanating from baffle joint gaps must be limited to a specific momentum l flux, V2h, that is, the product of the gap width, h, and the square of the baffle joint jet velocity, V 2,

.I lV i In order to assess the impact of the new RCS conditions on the baffle jetting margins of safety at the Farley units, the ratio of the margins of safety between the present configuration and the new uprated configuration has been determined. In c.h evaluation. it was assumed that there were no degraded j bolts in the baffle-barrel region at Farley. De results show that the impact on the margins of safety l for momentum flux due to the new conditions for power uprating do not change significantly from the ! present conditions based on mechanical design flow. ! l 5.2.2 Mechanical System Evaluations ! l ! l l 1

The mechanical response of the Reactor Coolant Sy.; tem (RCS) subjected to auxiliary line breaks of a '

LOCA transient is performed in three steps. First, the RCS is analyzed for the effects of loads I l j induced by normal operation, which includes thermal, pressure, and deadweight effects. From this i analysis, the mechanical forces acting on the RPV which would result from the release of the

equilibrium forces at the break locations are obtained. In the second step, the loop mechanical loads

! and the reactor intemals hydraulic forces are simultaneously applied, and the RPV displacements due i to the LOCA are calculated. Finally, the structural integrity of the reactor coolant loop and component l 4 supports to deal with the LOCA are evaluated by applying the reactor vessel displacements to a

mathematical model of the reactor coolant loop. Dus the effects of vessel displacements upon loop j and reactor vessel and its intemals are evaluated.

i j Since Farley Units 1 and 2 take credit for leak-before-break (LBB) applied to the primary loop, the

LOCA analyses of the reactor pressure vessel system for postulated ruptures of the primary loop I

i _ mA3254w.non\sec5.wpf:lt413097 5-5 I 1

1 l piping are not required. Then the next limiting breaks to be considered are the branch line breaks which consists of (a) accumulator line, (b) pressurizer surge line, and (c) residual heat removal (RHR) line breaks. The pressurizer surge line break was initially included and it bounded the RHR line break. Subsequent to starting the LOCA analysis, NRC approval of LBB was obtained for the pressurizer surge line break. Based on this NRC approval, surge line break did not have to be included in the dynamic analysis. However, for conservatism, the surge line break was evaluated. Of these branch line breaks, the most limiting breaks considered for the dynamic analysis of Farley Units I and 2 reactor pressure vessel system are the accumulator line break (cold leg) and the pressurizer surge line break (hot leg). l 5.2.2.1 Loss-of Coolant Accident (LOCA) Loads The LOCA loads applied to the Farley Units I and 2 reactor pressure vessel system consist of (1) reactor internal hydraulic loads (vertical and horizontal), (2) reactor coolant loop mechanical loads, and (3) pressure loads acting on the baffle plates. All the loads are calculated individually and j combined in a time-history manner. The severity of a postulated break in a reactor vessel is related to two factors: the distance from the reactor vessel to the break location, and the break opening area. The nature of the reactor vessel i decompressio, following a LOCA, as controlled by the intemals structural configuration previously discussed, results in larger reactor internal hydraulic forces for pipe breaks in the cold leg than in the hot leg (for breaks of similar area and distance from the RPV). Pipe breaks farther away from the reactor vessel are less severe because the pressure wave attenuates as it propagates toward the reactor vessel. With the consideration of LBB, the auxiliary line breaks, such as the accumulator line break and ti.e pressurizer surge lire break, are not as severe as the main line breaks (e.g., RPV inlet nozzle or RCP outlet nozzle break). l The pressure loads acting on the baffle plates were calculated from the MULTIFLEX code output for I the two breaks considered. The maximum pressure load on any baffle span (between formers) was calculated to be approximately 40 psi. This is a substantially smaller peak LOCA pressure load than j has previously been calculated (85.5 psi) for the 3-loop baffle-barrel configuration. Therefore, since LOCA-induced baffle-former bolt loads have been found to be acceptable in the previous evaluation, they will be acceptable for the current evaluation as well. 5.2.2.2 Flow Induced Vibrations Flow-induced vibrations (FIV) of pressurized water reactor internals have been studied at Westinghouse for a number of years. The objective of these studies was to show the structural integrity and reliability of reactor internal components. O I mM254w.non\sec52pf.lb-013097 5-6

i Results from the scale model and in-plant tests indicate that the primary cause of lower intemals' excitations 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. The PCWG parameters which could potentially influence the RV response of the reactor intemals !' include the inlet nozzle flow velocities, vessel / core inlet temperatures, and the vessel outlet temperatures. Generally, the inlet nozzle velocity for the RV response during hot functional testing is l calculated at the mechanical design flows which are approximately 15% higher than the thermal design j flows. Since the thermal design flows for the power uprate changes are lower than the original thermal design flow rates and since FNP hot functional tests were performed at flow rates higher than those for the power uprate conditions, the existing test results are conservative and remain applicable. The other parameter which would influence the RV response is the core inlet temperature. For the most limiting case of the power uprate changes, the vessel / core inlet temperature is 530.6*F. The I original vessel / core inlet temperature is 543.5'F. This temperature change implies a change in water density which is considered to have a negligible impact. i Since the changes evaluated in this program did not include any changes to the mechanical l characteristics of the fuel assembly design, there is no change in the fuel related core barrel vibrational j response. For the uprated conditions, it was determined that the flow-induced vibration loads on the guide tubes ! and the upper support columns increase by approximately 1.9%. Previous RV analyses on the guide tubes and the upper support columns show that there exist sufficient margins to accommodate this increase in the RV loads. Consequently, the structural integrity of the Farley reactor internals remains acceptable with regard to flow-induced vibrations. 5.2.3 Structural Evaluation of Reactor Internal Components 5.2.3.1 Introduction In addition to supporting the core, a secondary function of the reactor vessel intemals assembly is to direct coolant flows within the vessel. While directing the primary flow through the core, the intemals assembly also establishes secondary flow paths for cooling the upper regions of the reactor vessel and for cooling the internals structural components. Some of the parameters influencing the mechanical design of the intemals lower assembly are the pressure and temperature differentials across its component parts and the flow rate required to remove the heat generated within the structural components due to radiation (e.g., gamma heating). The configuration of the internals provides for adequate cooling capability. Also, the thermal gradients, resulting from gamma heating and core coolant temperature changes, are maintained below acceptable limits within and between the various structural components. mA3254w.nonWc5.wpf.It413097 5-7

Structural evaluations are required to demonstrate that the structural integrity of the reactor components is not adversely affected directly by the change in RCS conditions and transients and/or by secondary effects of the change on reactor thermal hydraulic or structural performance. The presence of heat generated in reactor internal components, along with the various fluid temperatures, results in thermal gradients within and between components. These thermal gradients result in thermal stresses and thermal growth which must be accounted for in the design and analysis of the various components. Since the Farley reactor internals were designed prior to the introduction of Subsection NG of the i ASME Boiler and Pressure Code Section III, a plant specific stress report on the reactor intemals was I not required. However, the design of the Farley reactor internals was evaluated according to the Westinghouse internal criteria which were similar to the criteria described in Subsection NG of the l I ASME Code,1989 edition,1990 addenda. Moreover, the structural integrity of the Farley reactor intemals design has been shown by analyses performed on both generic and plant specific bases. These analyses were used as the basis for the evaluation of the critical Farley reactor internal j components for the plant uprating and the revised thermal transients. l l 5.2.3.2 Lower Core Plate l Structural evaluations were performed to demonstrate that the structural integrity of the lower core plate is not adversely affected directly by the change in RCS conditions and/or by secondary effects of the change on reactor thermal hydraulic or structural performance. For this lower core plate evaluation the criteria described in Section III. Subsection NG of the ASME Code,1989 edition,1990 addenda, were utilized. The conclusion of these evaluations is that the structura} integrity of the lower core plate is maintainable. The evaluation of the new reactor coolant system conditions, which are due to the power uprating, demonstrated acceptable margins of safety and acceptable fatigue utilization factors for all ligaments under all loading conditions. l 5.2.3.3 Baffle Barrel Region Components The Farley I and 2 lower internals assembly consists of a core barrel into which baffle plates are installed, supported by interconnecting former plates. A lower core support structure is provided at the bottom of the core barrel and neutron panels surround the core barrel. 'Ihe components which comprise the lower internals assembly are precision machined with the baffle and former plates being installed into the core barrel by bolting. The reactor vessel internals configuration for Farley Unit 1 incorporates a converted upficw baffle-barrel region; the configuration for Farley Unit 2 is of a downflow design. The designations "upflow" and "downflow" refer to the flow direction in the baffle-barrel region. In both cases, the flow helps to cool the baffle-barrel region; in the downflow mA32%.nonsec5 wpf:1b-013097 5-8

1 1 i > 1 I i V 1 configuration, however, the pressure difference across the baffle plates at the upper core levels is l j significantly higher than it is in an upflow configuration. l

                                                                                                                                      .i 5.2.33.1 Core Barrel Evaluation l

l ! The thermal stresses in the core barrel shell in the core active region are primarily due to temperature ! l gradients through the thickness of the core barrel shell. Calculations were performed to determine the l l thermal bending and skin stresses in the core banel for the new uprated RCS conditions. Calculations l l were also performed for normal and upset conditions. De maximum and minimum thermal bending ! and skin stresses were then used to determine cyclic stresses; these in tum were used to determine the ) )

allowable number of fatigue cycles based on ASME code allowables. Dese calculations indicated that j j the actual number of fatigue cycles, based on all normal / upset conditions, was well below the ;

j allowable. From these very conseivative results, it can be concluded that the core barrel is structurally J

adequate for the new RCS conditions at the Farley units. I
I I

5.2.33.2 Bame Plate Evaluation i } !

The thermal stresses in the baffle plate are caused primarily by the temperature gradient across the !

I baffle thickness. De temperature difference between baffle and banel produces the donunant loads on ! the baffle-former bolts. Calculations were performed to determine the thermal moments in the baffle l f plates for the new uprated RCS conditions. Calculations were also performed for normal and upset j conditions. The maximum and minimum thermal bendir g and skin stresses were then used to j ! determine cyclic stresses; these in tum were used to determme the allowable number of fatigue cycles, N, based on ASME coc'e allowables. These calculations indicated that the actual number of design l j fatigue cycles, based on all normal / upset conditions, was well below the allowable. From these very ) l conservative results, it can be concluded that the baffle plates are stmeturally adequate for the new ] RCS conditions at the Farley umts. l l i l 5.2.3.3.3 Bame/ Barrel Bolt Evaluation l i l The bolts are evaluated for loads resulting from hydraulic pressure, seismic loads, preload and thermal 1 ! conditions. The temperature difference between baffle and banel produces the dominant loads on the ! baffle-former bolts. The primary stresses are produced by hydraulic pressure and seismic loads I whereas the secondary stresses are produced by the bolt preloading and thermal conditions, ne new RCS conditions do not affect the deadweight or pieload forces. Since these bolts are qualified by test, l 4 the evaluation for the revised loads consisted of comparing the existing operating bolt loads to those j developed with the new RCS conditions. De results indicate that the baffle /former thermal loads and j barrel /former bolt loads with the cunently analyzed conditions envelope those developed with the new RCS conditions. A fatigue analysis using these temperature differences was perfonned using two independent methods for calculating the strain concentration factor (fillet / shank) of the baffle-fonner f bolts. With both of these methods, fatigue usage was calculated to be less than unity when best , .l \ I mA3254w.non\sec5.wpf;Ib 013097 5-9

!                                                                                                                                         i
                                                                                                                                   - -l

estimate strain concentration factors were used. Therefore, it is concluded that the baffle /former and barrel /former bolts are structurally adequate for the new RCS conditions at the Farley Nuclear Plant. 5.23.3.4 Upper Core Plate Evaluations The upper core plate positions the upper ends of the fuel assemblies and the lower ends of the control rod guide tubes, thus serving as the transitioning member for the control rods in entry and retraction from the fuel assemblies. It also controls coolant flow in its exit from the fuel assemblies and serves as a boundary between the core and the exit plenum. The upper core plate is restrained from venical movement by the upper suppon columns which are attached to the upper suppon plate assembly. The lateral movement is restrained by four equally spaced core plate alignment pins. The stresses in the upper core plate are mainly due to hydraulic, seismic, and thermal loads. The total thermal stresses are due to thermal bending moments through the thickness and surface peak stresses. Evaluations were performed to determine the impact of the uprating program on the structural integrity of the upper core plate. As a result of this evaluation, it is concluded that the upper core plate is structurally adequate for the new RCS conditions at the Farley units with regard to the uprating program. 5.2.3.4 Additional Components In addition to the previously described evaluations, a series of assessments were performed on a number of reactor internal components which were not significantly impacted by the power uprating (and the resulting internal heat generation rates) but are affected by the new RCS conditions due to the primary loop design transients. These components are: a) Core barrel plug, b) Lower core suppon plate, c) Lower suppon columns, d) Core barrel outlet nozzle, e) Core barrel flange, f) Lower radial restraints (clevis inserts), g) Upper core plate alignment pin, h) Upper suppon columns, i) Upper suppon plate, j) Guide tubes and suppon pins, and , k) Neutron pads. The results of these assessments verified that the above listed components are stmeturally adequate for the new RCS conditions at the Farley units. m:\3254w.non\sec5.wpf:lt4)l3097 5-10

a 5,2.4 Summary of Conclusions for Reactor Pressure Vessel System Analyses have been performed to assess the effect of the changes due to power uprate. De results of l these analyses follow,

1) De total core bypass flow values (with uncertainties) were determined to be 5.74% and 5.49%

for Units I and 2, respectively. Derefore, the design core bypass flow value of 7.1% of the total vessel flow can be maintained.

2) Hydraulic forces were calculated to assess the structural integrity of the reactor internals, and it

] was determined that the Farley Nuclear Plant reactor internals assembly will remain seated and stable with the new conditions. . 3) An RCCA perfonnance evaluation was completed, and it indicated that the current 2.7 second RCCA drop time to dashpot entry limit (from gripper release of the drive rod) is satisfied at power uprate conditions. E

4) Baffle plate momentum flux margins of safety due to power uprate conditions are relatively i unchanged from present conditions for mechanical design flow, and therefore remain acceptable.

5) Evaluations were completed that indicated the new RCS conditions will not adversely impact the response of reactor internals systems and components due to seismic /LOCA excitations and flow induced vibrations.

i

! 6)      Evaluations of the critical reactor internal components were performed which indicated that the structural integrity of the reactor internals is maintained with the new reactor coolant system conditions due to the power uprate program.

. 5.3 Fuel Assemblies De 17xl7 VANTAGE 5 (VS) IFM fuel assembly design has been analyzed for LOCA and safe shutdown earthquake (SSE) loading conditions. De LOCA analyses were performed considering the use of leak before break criteria. He maximum structural and IFM grid load and the maximum fuel assembly deflection were determined. De analysis results of the combined LOCA and seismic loadings indicate that adequate margin for both fuel rods and thimble tubes exists, so that fragmentation of fuel rods will not occur for the uprated conditions. De reactor can be safely shutdown under faulted condition loading. He 17x17 V5 IFM assembly design is structurally acceptable under the combined seismic and LOCA loadings for the Farley plants. mu254. o.s cs.pt swiwn 5-11

De seismic and LOCA analyses determined the maximum impact forces for the 17x17 V5 sttuctural and IFM grids. These loads were found to be below the allowable grid strengths. Based on the results of the combined SSE and LOCA analyses, the 17xl7 V5 IFM fuel assembly design is structurally acceptable for both Farley units. Core coolable geometry requirements are met. De analyses also showed that LOPAR fuel can be inserted in the core at power uprate conditions and not be limiting with respect to maintaining core cooiable geometry under combined LOCA and SSE loading conditions. It was determined that the flow per assembly in the Farley units is lower than the flow per assembly in other plants. He lift forces derived from the other evaluations bounds the lift forces for the Farley uprating, and the fuel assembly holddown spring capability was verified to be acceptable. Dus, the fuel assembly structural integrity is not affected by the Farley uprating. Other areas for which the power uprate has a negligible effect include fuel rod fretting, oxidation and hydriding of thimbles and grids, fuel rod growth gap, and guide thimble wear. De impact on these areas is negligibic due to the fact that the temperatures are not increasing for the power uprate program. It is concluded that the uprating will not exacerbate any of these potential fuel issues. 5.4 Control Rod Drive Mechanisms The ASME Code structural consideratiou for the pressure boundary components of the Westinghouse Full Length (F/L) L-106A Control Rod Drive Mechanism (CRDMs) and Capped Latch Housing ! Assembly and the Royal Industries Part length (P/L) CRDMs were considered for the Farley Uprating ) Program. Note the P/L CRDMs have the control rods removed, but the pressure boundary components i are still in place. The Farley Units I and 2 F/L CRDMs see the hot leg temperature defined by " Vessel Outlet" on the PCWG Parameters. The maximum temperature listed is 613.3*F for cases 1 through 6 while the ; I pressure remains the same at 2250 psia. De CRDM generic Code reports use 650*F as the operating temperature, so the PCWG cases for the uprating are still bounded by the generic analysis. The new uprating design transients were evaluated. He largest temperature and pmssure changes from either the high tempercure case or the low temperature case were used. Farley 1 and 2 are both designed to the 1970 Addenda of the ASME Section III NB Code, and any Code reconciliation of the Farley units to the generic stress analysis has been previously performed. I he F/L and P/L CRDMs were evaluated with respect to these design transients for loadings and fatigue considerations. A review of the structural and thermal analyses of the P/L and F/L CRDM pressure boundary components determmed that the Code criteria are maintained for the uprating. mms 4. ws.pr uim 5-12 O

5.5 RCL Piping and Supports l The uprating program and its associated parameters were reviewed for impact on the existing design j basis and column tilt analysis for the reactor coolant loop (RCL) piping, primary equipment nozzles, primary equipment supports, pressurizer safety and relief valve (PSARV) piping, and the pressurizer i surge line piping. De temperature changes associated with uprating cause potential load changes in the components to be reconciled. The changes in the thermal design transients are factored into the : fatigue aspects of the piping evaluation. ! I A De analyses, methods and criteria used in the existing design basis for Farley Units I and 2 continue to be used. Three basic sets of input parameters that were used in the evaluation of the RCL piping and supports are the PCWG parameters, the thermal design transients, and LOCA parameters. , De PCWG parameters define the various temperature conditions associated with the potential full , power operating conditions of the plant. All of the thermal expansion, seismic, and LOCA analyses ; performed on the piping systems are done at full power conditions. De thermal design transients are l used in the evaluation of the piping fatigue. De loop LOCA forces associated with defined postulated l breaks and reactor vessel dynamic LOCA displacements associated with defined postulated break cases are used as inputs. Because of the licensing of loop LBB methodology, postulated guillotine breaks in j the primary loop piping have been replaced with postulated guillotine breaks at the loop branch connections for the largest ASME Class I auxiliary Ima (surge line on the hot leg and accumulator I line on the cold leg). l The evaluation for the RCL piping, the primary equipment nozzles, the primary equipment supports, i the PSARV piping, and the pressurizer surge line indicates that all components meet appropriate allowables.

In all cases, except for the RCL crossover leg usage factor, the existing evaluations remain applicable. The crossover leg usage factor experiences a minor increase due to the uprating transients but does not exceed the specified limit for break postulation. The evaluation for the RCL piping and supports concludes that the plant uprating program has no adverse effect on the ability of these components to operate. 5.5.1 RCL Piping and Supports - LBB The original structural design basis of the Farley RCS required consideration of dynamic effects resulting from pipe break and that protective measures for such breaks be incorporated into the design. There were NRC and industry initiatives that resulted in demonstrating the use of LBB criteria could be applied to RCS piping based on fracture toughness technology and material toughness. The Farley units primary loop piping analyses and the application of LBB was documented in WCAP-12825 and approved by NRC letter to APCo dated August 12,1991. i ad3254w.nonwc5 wpf;1b 013097 5-13

i l l An evaluation was performed to determine the impact of uprating conditions and primary loop pump column tilt on the LBB conclusions for the Farley primary loops. It is judged that the LBB margins ! will have negligible change, and the LBB conclusions of WCAP-12825 remain unchanged. 5.6 Reactor Coolant Pumps This section addresses the acceptability of the Farley Units I and 2 Model 93A Reactor Coolant Pumps (RCPs) at the uprating conditions. 5.6.1 Structural The Westinghouse Model 93A RCPs were designed and analyzed to meet the Farley pump specifications and the ASME Code. The review of the uprating transients on RCP generic analysis reports shows that ASME Code is still met for the uprating transients and parameters. In conclusion, the new parameters and transients for the Farley Units 1 and 2 Uprating Program are considered acceptable for the Model 93A RCPs. The pump pressure boundary parts are considered to still satisfy the RCP E-Specs and the ASME Code. 5.6.2 RCP Motor The worst case loads for the RCP motors were calculated for the Farley uprated conditions. Using the revised loads, all of the Farley RCP motors were evaluated in the four areas where parameter changes affect performance. These areas are continuous operation at the revised hot loop rating, continuous operation at revised cold loop rating, starting, and the loads on thrust bearings. Each of these areas were determined to be acceptable at the uprated conditions. 5.7 Steam Generators The Farley Model 51 Steam Generators (SG) were analyzed at the uprated power conditions in the areas of structural acceptability, thermal-hydraulic, U-bend fatigue, tube degradation, and tube plugging and repair. 5.7.1 Steam Generator Structural Evaluation The structural evaluations are based on the results of the previous structural analysis of the series 51 steam generators. The structural evaluation for Farley is also based on the detailed structural analysis performed for a prototypical plant as part of an uprating project. The prototypical plant has Model 51 SGs which were analyzed to PCWG parameter ranges and NSSS design transients that envelope the parameters and design parameters for the Farley power uprate project. The stresses of the original Model 51 SG analysis were scaled by the primary to secondary side pressure difference ratios at the uprate conditions to the original analysis conditions to determine the stresses at the uprate conditions. l m:\3254w.non\sec5.wpf.Ib-013097 5-14

i 1 i

                     . A conservative ratio based on the prototypical plant uprating was used for calculating stresses and l                       fatigue for Farley Udts 1 and 2, since the prototypical plant conditions envelope the Farley conditions.

De results of the evaluation concluded that, with the exception of the secondary manway bolts, the -

i uprated power conditions will not adversely affect the maximum stresses and fatigue usage factors for , the SG components analyzed, and that the ASME Code Section III is satisfied. The secondary l j 4 manway bolts will be replaced prior to the 34th year of service, which is the time at which the fatigue j usage limit would be exceeded, in order to comply with the requirements. d r f 5.7.2 Steam Generator Thermal Hydraulic Evaluation I j Secondary side steam generator performance characteristics, such as circulation ratio, moisture i. carryover, hydrodynamic stability, heat flux and others, are affected by increased thermal power and ; j changes in steam pressure. Steam pressure, in turn, is determined by the power as well as primary .; l temperature and tube plugging level. i ! Applicable design parameters for operation at uprated conditions were used for the thermal-hydraulic l evaluation. Based on the evaluation for uprated power, it is concluded that the thermal-hydraulic i operating characteristics of the steam generators are within acceptable ranges and will not be adversely I affected by the uprated conditions. 1 I 5.7.3 U-bend Fatigue Evaluation l l De potential for vibration of the small radius U-bends due to fluid elastic instability at the power uprate conditions was assessed. De initiation of a circumferential tube crack at the top tube support plate at North Anna I has been attributed to fatigue due to fluid elastic instability. It is therefore I important to know the magnitude of U-bend vibration and associated tube stress for the power uprate ! operating conditions. The results of this evaluation show which tubes in the Farley 1 & 2 steam t generators are more susceptible to fatigue and may require preventive action (i.e., plugging) for long-i term operation at the uprated conditions. i j Results of the evaluation showed that no preventive tube repair is required to support plant operation ! at the best estimate steam generator outlet pressure of 787 psia. Preventive tube repair should not be j } required for operation of Unit I and Unit 2 as long as steam generator outlet pressures remain above j 770 psia and 773 psia, respectively. The existence of a power skew (i.e., asymmetric steam flow from l

the steam generators) could require preventive tube repair above these pressures; however, such repair would not be requised for at least 13.7 years after power uprate is implemented. Following

)

  ;                      implementation of power uprate, the outlet pressure and the steam flow for each steam generator can       ;

be documented on a cycle specific basis for use in any future update of the U-bend fatigue l i i evaluations. i j ms254w.monsi cs.wpr:ib-oi3097 5-15 4

I l 5.7.4 Steam Generator Tube Degradation f 5.7.4.1 ' Introduction + . In order to minimize the potential impact of power uprate on steam generator tube degradation, selection of the optimum point (best estimate steam pressure) at which to design the HP turbine i modifications for power uprate included the objective of maintaining the post-uprate " actual" Tw at the l same value (with a 2 0.5'F allowance to account for measurement variations and uncertainties) as the I pre-uprate " actual" Tw taking into account potential changes to other parameters that affect NSSS

performance. Thus, power uprate should not have a significant impact on Tw which is the most important parameter with respect to steam generator tube degradation. Power uprate does include a slight reduction in steam pressure (and corresponding saturation temperature) that has the potential to l impact steam generator tube degradation. The impact of the reductions in steam pressure and saturation temperature on steara generator outside diameter stress corrosion cracking (ODSCC) and ; primary water stress corrosion cmcking (PWSCC) was reviewed and shown to be acceptable. Since l power uprate will not have a significant impact on Twand since the impact of a slight reduction in steam pressure and saturation temperature on ODSCC and PW' SCC was shown to be acceptable, the impact of power uprate on steam generator tube degradation is acceptable considering the uncertainties associated with estimat:ng tube degradation. The evaluation of ODSCO and PWSCC assumed that the hot leg temperature is unchanged for the uprated conditions, while the steam pressure is reduced, consistent with the best estimate steam generator outlet pressure for full power operation at 2785 MWt. I 5.7.4.2 ODSCC Changes to other primary and secondary side parameters as a result of the uprating are not considered i in the analysis of ODSCC since their impact is minimal. The ODSCC rate is assumed to vary only as a function of the local temperature and the applied pressure difference. Effects of possible changes in environment (caused by a change in the boiling j I temperature elevation) and by changes in the thermal stress are considered to be less important. Based on the review of the uprated power conditions on ODSCC in the Farley SGs, there is no significant impact due to the uprating. 5.7.4.3 PWSCC l PWSCC of Alloy 600 is a mode of intergranular stress corrosion that has been observed in various PWR primary system components. The most commonly affected component, and the one of most i general concern for maintenance and repair, is the SG heat transfer tubing. I mu254w.nonws wpr.ib-oi3097 5-16

PWSCC kinetics are a strong function of stress. The sources of stress that contribute to the total effective stress include the residual stress (from tubing and SG manufacturing operations), the throughwall pressure stress, and the thermal stress (due to throughwall AT). The only stress that is affected by the uprate conditions is the throughwall pressure stress, which increases due to the increase in normal primary-to-secondary side AP from approximately 1435 to 1463 psi. The change in throughwall pressure stress will increase the pressure stress term and will have a j maximum estimated effect of increasing the PWSCC kinetics by approximately 2 to 2.5%. In view of the uncertainties associated with estimating the various contributions to PWSCC, this effect is not significant.

Based on the review of the uprated power conditions on PWSCC in the Farley SGs, there is no significant impact due to the uprating. ] 5.7.5 Steam Generator Tube Plugging and Repair Criteria The impact of power uprate on the steam generator tube plugging and repair criteria as contained in the Technical Specifications was assessed. It was shown that the current Technical Specification w criteria for tubes, welded joint sleeves, mechanical joint sleeves, and tube support plate intersections support full power operation and are applicable for power uprate conditions, consistent with the best estimate steam generator outlet pressure at 2785 MWt. The current Technical Specifications (for Unit 2 only) include criteria for F* that support operation with a steam generator outlet pressure of 793 psia (i.e., normal primary-to-secondary AP of 1457 psi). This does not bound the best estimate stea.n generator outlet pressure of 787 psia for normal full power operation at power uprate conditions. Analysis was performed to revise the Technical Specification criteria for F* to bound the best estimate steam generator outlet pressure at 2785 MWt. 5.8 Pressu.izer-The functions of the pressurizer are to absorb any expansion or contraction of the primary reactor coolant due to changes in temperature and/or pressure and, in conjunction with the pressure control system components, to maintain the RCS at the desired pressure. The first function is accomplished by keeping the pressurizer approximately half full of water and half full of steam at normal conditions, connecting the pressurizer to the RCS at the hot leg of one of the reactor coolant loops and allowing inflow to or outflow from the pressurizer as required. The second function is accomplished by keeping the temperature in the pressurizer at the water saturation temperature (T,.) corresponding to the desired pressure. The temperature of the water and steam in the pressurizer can be raised by m:\3254w.non\secL*ps:1b 013v7, 5-17

operating electric heaters at the bottom of the pressurizer and can be lowered by introducing relatively cool spray water into the steam space at the top of the pressurizer. The componcnts 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, spray flow through the spray nozzle, and steam temperature differences. The limiting operating conditions of the pressurizer occur when the RCS pressure is high and the RCS hot leg (Tw) and cold leg (T, ) teinperatures are low. This maximizes the AT that is experienced by the pressurizer. Due to flow in and out of the pressurizer during various transients, the surge nozzle altemately sees water at the pressurizer temperature (T.) and water from the RCS hot leg at Tw. If the RCS pressure is high (which means, correspondingly, that T. is high) and Tw is low, then the surge nozzle will see maximum thermal gradients; and, thus experience the maximum thermal stress. Likewise, the spray nozzle and upper shell temperatures altemate between steam at T, and spray, which, for many transients, is at T, . Thus, if RCS pressure is high (T. is high) and T, is low, then the spray norzle and upper shell will also experience the maximum thermal gradients and thermal stresses. The results of the pressurizer analysis showed that the Farley Units I and 2 pressurizer components meet the stress / fatigue analysis requirements of the ASME Code, Section III,1968 edition, Winter 1970 addenda, for the plant operation in accordance with the thermal uprating program. 5.9 NSSS Auxiliary Equipment NSSS auxiliary equipment was evaluated for impact by the uprated conditions. The original design parameters, manufacturing / quality assurance requirements, and transients for the auxiliary valves, auxiliary pumps, and heat exchangers are defined in the Equipment Specifications. No tanks were affected by the uprated power project. In addition, pump hydraulic and heat exchanger performance requirements were defined by Data Sheets which were invoked via the equipment purchase orders. Westinghouse perfonned its evaluations based on the original Westinghouse design requirements. Based on the uprated parameters for the NSSS auxiliary equipment, the following conclusions were made:

.         Comparison of the maximum system operating temperatures and pressures at uprated conditions to the original system design conditions shows that all maximum operating temperatures and pressures for systems within Westinghouse scope are bounded by the existing design basis. Since all auxiliary equipment was designed consistent with the system design rn:\32s4w. con \sec5.wpf.It413097                    5-18

_ ~ . - . . - - . . - . _ . . - - . - - . . - . - . ~ . - . - . . - - - - - - - - . . . . . - . - ~ - . F i 7 4 h j requirements, the auxiliary equipment is acceptable for the maximum operating temperatures and pressures resulting from the thennal uprating. Also, the auxiliary equipment thermal transients resulting from the thermal uprating are bounded by the original Farley design parsmeters. Therefore, the auxiliary equipment remains acceptable for the thermal transients resulting from the uprated power. mms 4w.nonws.wpowi3097 5-19

t J 6.0 NSSS ACCIDENT ANALYSES Dis chapter provides the results of the analyses and/or evaluations which were completed for the NSSS accident analyses in suppon of the thermal uprate project. Section 6.0.1 first gives a summary of the instrumentation uncenainty analysis results which were used in the accident analyses. The accident analysis areas covered within this chapter include: best estimate large break LOCA (BELOCA) and small break LOCA (SBLOCA), LOCA-related areas (hot leg switchover, post-LOCA long term core cooling, and rod ejection accident analysis), non-LOCA transients, steam generator tube rupture (SGTR), LOCA and main steamline break mass and energy releases, LOCA hydraulic forces, and protection system setpoints. The NSSS accident analyses and/or evaluations were performed relative to the Revision 13 version of the Final Safety Analysis Repon (FSAR). All references to the FSAR (e.g., FSAR figures) are to this . ; version. The NSSS accident analyses and/or evaluations described in this chapter suppon deletion and removal l of the Boron Injection Tank (BIT). The detailed results and conclusions of each analysis area are presented within each subsection. 6.0.1 Initial Condition Uncertainties This chapter addresses the initial condition uncenainties used in the accident analyses that were , reanalyzed or evaluated for Farley Units 1 and 2 to suppon the uprate project. The uncertainties are ! included in the non-LOCA analyres, large and small break LOCA, LOCA forces (which are provided l as input to component structural analyses), steam generator tube rupture, and main steamline break and j LOCA mass and energy releases (which are provided as input to the containment integrity analyses). Six parameters include initial condition steady-state uncertainties that are explicitly modeled in various , transient and accident analyses.

Pressurizer Pressure (automatic pressurizer pressure control system and narrow range pressure j indications) 1 l
RCS T,,, (automatic reactor control system and T,,, indications) ,

a Reactor Power (daily calorimetric power measurement .,ed to normalize power range i instruments) i

RCS Total Flow (plant computer measurement based on RCS loop flows normalized to ,

calorimetric based RCS flow measurement) i m:\3254w.non\sec6.wpf:IM12997 6-1 l

Steam Generator Water Level (automatic steam generator water level control system and narrow range level indications) Pressurizer Water Level (automatic pressurizer water level control system and hot-calibrated level indications) The uncertainty calculations have been performed for Farley Nuclear Plant Units 1 and 2 with the plant-specific instrumentation and calibration procedures. The following table summarizes the results and the uncertainties that are used in the Farley transient and accident analyses. Uncertainty Allowance Used in Parameter Calculated Uncertainty Safety Analysis Pressurizer Pressure $48.1 psi (random) 250.0 psi (random)

                                       -1.5 psi (bias)

T.,, 13.7'r (random) 26.0*F (includes cold leg

                                       -1.0*F (bias)                      streaming bias of-1.0*F)

Power 21.1% RTP (random) 12.0% RTP (random) RCS Flow 21.9% TDF (random) 12.1% TDF (random)* Steam Generator Water Level 26.8% span (random) 27.0% span (random)

                                       -4.9% span (bias)                  -5.0% span (bias)                ;

1 Pressurizer Water Level 24.1% span (random) 25.0% (random)

                                       +0.6% span (bias)                                                   ,

Detailed results and conclusions are provided in References I and 2. l

Applicable for range of 22.1% to 22.4%.

6.0.2 References j 1. WCAP-12771, Revision 1, " Westinghouse Revised Thermal Design Procedure Instrument Uncertainty Methodology for Farley Nuclear Plant Units 1 & 2 (Uprating to 2785 MWt NSSS Power)," September 1996.

2. WCAP-14715, " Westinghouse Steam Generator & Pressurizer Level Control Instrument Uncertainty Methodology for Farley Nuclear Plant Units 1 & 2 (Uprating to 2785 MWt NSSS Power)," September 1996.

l l I O l m:\3254w.non\sec6.wpf:lt412997 6-2 l t

i , f- 6.1 LOCA Transients - j 6.1.1 Best Estimate Large Break Loss-of Coolant Accider ; 6.1.1.1 Introduction 1 l A Westinghouse LOCA evaluation metho.16bgy for three- and four-loop PWR plants based on the revised 10 CFR 50.46 (References 1, 2, rond 3) and Regulatory Guide 1.157 (Reference 4) is ] documented in WCAP-12945, " Code Qualification Document (CQD) for Best Estimate LOCA

Analysis" (Reference 5) and revised in the Revised Methodology Report (Reference 6). His

) methodology was recently approved by the NRC (Reference 7). i- { his section summarizes the application of the Westinghouse Best-Estimate (BE) LOCA Evaluation Model to Farley Units 1 and 2 for analysis of large break LOCAs, at the uprated power conditions {

(Reference 9). This BE model is used to calculate the Peak Cladding Temperature (PCT), including the calculation of total uncertainties, as the licensing basis for both Farley units.

1

6.1.1.2 Description of Analyses j l

j The Westinghouse Best-Estimate Large Break LOCA (BE LBLOCA) methodology follows the basic ! steps developed in the Code Scaling Applicability and Uncertainty (CSAU) methodology l (Reference 8). It includes a detailed treatment of the uncertainties associated with the computer code models used to analyze the accident scenario, and the uncertainties associated with plant operation. ! The thermal-hydraulic computer code which is used to calculate fluid and thermal conditions in the PWR during a large break LOCA is ,WCOBRAfrRAC (Reference 5). i ! ! The methods used in the application of WCOBRA/ TRAC to the large break LOCA are described in References 5,6, and 7. A detailed assessment of the computer code WCOBRA/ TRAC was made l_ j through comparisons to experimental data. These assessments were used to develop quantitative j estimates of the code's ability to predict key physical phenomena in a PWR large break LOCA. i Modeling of a PWR introduces additional uncertainties which are identified and quantified in the plant i specific analysis (Reference 9). The final step of the best estimate methodology is to combine all the ! uncertainties related to the code and plant parameters, and estimate the PCT at 95 percent probability. , ! Table 6.1.1-1 lists the plant specific parameters used in the Farley Units 1 & 2 plant specific analysis

and the location of the documentation of the values and ranges used for the parameters. Further 1
' description of the transient behavior is provided in the FSAR.

t 6.1.1.3 Acceptance Criteria and Results I l Table 6.1.1-2 presents the 50th and 95th percentile PCT for Farley Units I and 2, maximum cladding 1 oxidation, maximum hydrogen generation, and cooling results. mA3254w.nonhec6 wpf.Itr012997 6-3 4 j

I It must be demonstrated that there is a high probability that the limits set forth by 10 CFR 50.46 will not be exceeded. The demonstration that these limits are met for Farley Units 1 and 2 are as follows:

1) There is a high level of probability that the peak cladding temperature (PCT) shall not exceed 2200*F. The results in Table 6.1.1-2 indicate that this limit has been met.

2) The maximum calculated total oxidation shall no where exceed 0.17 times the total cladding thickness before oxidation. The approved methodology assesses this requirement using a plant specific transient which has a PCT in excess of the estimated 95th percentile PCT. Based on this conservative calculation, a maximum total oxidation of 12 percent is calculated, which meets the regulatory limit.

3) The calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical am.ont that would be generated if all of the metal in the cladding cylinders surrounding the fuel were to react. This requirement was assessed using the approved analysis option described in Section 10-3 of Reference 9. The total amount of hydrogen generated, based on this conservative assessment, is 0.006 times the maximum theoretical amount, which meets the regulatory limit.

4) Calculated changes in core geometry shall be such that the core remains amenable to cooling.

This requirement is met by demonstrating that the PCT does not exceed 2200*F, and the seismic and LOCA forces are not sufficient to distort the fuel assemblies to the extent that the core cannot be cooled. The approved methodology (Reference 7) specifies that effects of LOCA and seismic loads on core geometry do not need to be considered unless grid crush extends to in-board assemblies. Fuel assembly structural analyses performed for power uprate indicate that this condition does not occur. Therefore, this regulatory limit is met.

5) After any calculated successful initial operation of the ECCS, the calculated core temperature shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long lived radioactivity remaining in the core. While

        ,W_ COBRA / TRAC is typically not run past full core quench, all calculations are run well past PCT turnaround and past the point where increasing vessel inventories are calculated. The conditions at the end of the WCOBRAfrRAC calculations indicates that the transition to long term croling is under way even before the entire core is quenched.

6.1.1.4 Conclusions The expected PCT and its uncertainty developed above is valid for a range of plant operating conditions. In contrast to current Appendix K calculations, many parameters in the base case calculation are at nominal vdues. The range of variation of the operating parameters has been accounted for in the estimated PCT uncertainty. The operating ranges for major plant parameter assumptions will be documented in FSAR Chapter 15. If operation is maintained within these ranges, the LOCA analyses developed in this report are valid for the power uprate conditions. m:\3254w.non\sec6.wpf:Ib-013097 6-4

                                                                                                      )1 6.1.1.5 References

1. 10 CFR Part 50, " Acceptance Criteria for Emergency Cooling Systems for Light Water Cooled Nuclear Power Plants," Federal Register 39, (3), December,1973.

2. SECY-83-472, Information Report from W. J. Dircks to the Commissioners, " Emergency Core Cooling System Analysis Methods," November 17,1983,

3. Federal Register, " Emergency Core Cooling Systems: Revisions to Acceptance Criteria," V53, N180, pp. 35996-36005, September 16,1988.

4. USNRC Regulatory Guide 1.157, "Best-Estimate Calculations of Emergency Core Cooling System Performances," May 1989.

5. " Westinghouse Code Qualification Document for Best Estimate Loss of Coolant Accident Analysis," WCAP 12945-P-A (Proprietary), Volumes I V.

6. Letter, N. J. Liparulo M) to R. C. Jones (USNRC), " Revisions to Westinghouse Best-Estimate Methodology," NTD-NRC-95-4575, October 13,1995.

p 7. Letter, R. C. Jones (USNRC) to N. J. Liparulo M), " Acceptance for Referencing of the Topical Report WCAP-12945 (P), Westinghouse Code Qualification Document for Best Estimate Loss-of-Coolant Analysis," June 28,1996.

8. Boyack, B., et al.,1989, " Qualifying Reactor Safety Margins: Application of Code Scaling Applicability and Uncenainty (CSAU) Evaluation Methodology to a Large Break Loss-of-Coolant-Accident," NUREG/CR-5249.

i

9. "Best Estimate Analysis of the Large Break Loss of Coolant Accident for Farley Units 1&2 Power Uprate," WCAP-14746 (Proprietary), January 1997.

10. Letter, D. B. Vassallo (USNRC) to C. Eicheldinger M), " Topical Report Evaluation for the Westinghouse ECCS Evaluation Model: Supplementary Information," May 30,1975.

O m:\3254w.non\sec6 wpf.1t412997 6-5 ,

TABLE 6.1.11 MAJOR PLANT PARAMETER ASSUMPTIONS USED IN TIIE BELOCA ANALYSIS FOR FARLEY UNITS 1 & 2 AND WHERE THEY WILL BE DOCUMENTED Documentation Parameter FSAR Plant Physical Description Plant Initial Operating Conditions FSAR Reactor Power COLR/FSAR Peaking Factors FSAR Axial Power Distribution 1 Fluids Conditions FSAR T,,, FSAR Pressurizer Pressure FSAR Reactor Coolant Flow Accumulator Temperature FSAR FSAR Accumulator Pressure FSAR Accumulator Volume Accident Boundary Conditions FSAR Single Failure Assumptions FSAR Safety injection Flow FSAR Safety injection Temperature Diesel Generator Delay Time FSAR FSAR Containment Pressure I I 1

l 1 l l O! m:\3254w.non\sec6.wpf.ib-012997 6-6

i I I l TABLE 6.1.12 BEST ESTIMATE LARGE BREAK LOCA RESULTS Value Criteria 50th Percentile PCT (*F) <!647 N/A 95th Percentile PCT (*F) <2064 <2200 Maximum Cladding Oxidation (%) 12 <17 Maximum Hydrogen Generation (%) .6 <1 Coolable Geometry Core Remains Coolable Core Remains Coolable Long Term Cooling Core Remains Cool in Long Core Remains Cool in Long Term Term O i O m:\3254w.non\sec6.wpf:Ib-012997 6-7

i 6.1.2 Small Break LOCA 6.1.2.1 Introduction 9 This section contains information regarding the small break Loss-of-Coolant Accident (LOCA) analysis and evaluations performed in support of the uprate project for Farley Units 1 and 2. The purpose of j analyzing the small break LOCA is to demonstrate 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 figures, as well as a more detailed description of the limiting transient. Analyses showed that no design or regulatory limit related to the small break LOCA would be exceeded due to the uprated power and assumed plant parameters. 6.1.2.2 Input Parameters and Assumptions The important plant conditions and features are listed in Table 6.1.2-1. Several additional considerations that are not identified in Table 6.1.2-1 are discussed below. Figure 6.1.2-1 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 . I the core (the axial offset is +13%). 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 shown in Table 6.1.2-1. Figure 6.1.2-2 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. The flow from the LHSI pumps was not modeled in this analysis since the RCS pressure experienced in the transients did not reach the LHSI pressure range for the break spectrum analyzed. 6.1.2.3 Description of Analyses / Evaluations Performed Analytical 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 Emergency Core Cooling System (ECCS) Evaluation Model was developed to determine the RCS mA3254w.non\sec6.wpf.lb-ol2997 6-8

response to design basis small break LOCAs, and to address NRC concerns expressed in J NUREG-0611 (Reference 4). l l The RCS model is nodalized into volumes interconnected by flow paths. The broken loop is modeled

explicitly, while the intact loops are lumped together into a second loop. Transient behavior of the system is determined from the governing conservation equations of mass, energy, and momentum. l The multi-node capability of the program enables explicit, detailed spatial representation of various system components which, among other capabilities, enables a proper calculation of the behavior of the loop seal during a small break LOCA. The reactor core is represented as heated control volumes 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 power history, uncovered core steam flow, and mixture heights as boundary conditions (see Figure 6.1.2-3). Analysis Since the pre-uprate analysis indicated that the 3-inch break was the most limiting condition, and since the limiting break size is not expected to shift due to the analysis assumptions used here, four cases were nm consisting of up-flow /down-flow (Unit 1/ Unit 2) and high/ low T, conditions for the 3-inch break. Using the limiting 3-inch configuration, the 2-inch and 4-inch equivalent diameter cold leg y) breaks were performed using the analytical model described above to confirm that the limiting break I size, in fact, did not shift. The most limiting single active failure assumed for a small break LOCA is that of an emergency power train failure which results in the loss of one complete train of ECCS components, in addition, a Loss-of-Offsite Power (LOOP) is assumed to occur coincident with reactor trip. 'Ihis means that credit may be taken for at most one high head safety injection (SI) pump and one low head, or residual heat removal (RHR), pump. In this analysis, only one HHSI pump is modeled, and the LHSI pump is not needed since the RCS pressure experienced in the transients did not reach the LHSI pressure range for the break spectrum analyzed. The assumption of LOOP as the limiting single failure for small break LOCA is part of the NRC approved methodology and does not change as a result of the uprated conditions. LOOP is limiting due to the fact that one train of SI, one motor driven AFW pump, and power to the RCPs are all lost. Any other single failure would not result in a more limiting scenario since either increased SI flow or AFW flow or continued RCP flow would improve the overall transient results. The small break LOCA analysis performed for the Farley uprate project assumes ECCS flow is delivered to both the intact and broken loops at the RCS backpressure. RCS backpressure has been assumed for the SI delivery since the injection piping is located near the top of the RCS cold leg piping, and the limiting break location is in the bottom of the RCS cold leg piping. The overall PCT d results due to the reduction of SI experienced from shearing off the injection line due to a break in the top of the cold leg would be less limiting than the case where the break is modeled at the bottom of mA3254w.non\sec6 wpf.Ib-012997 6-9

I i I I l l the cold leg with the SI line remaining attached. The elevated break location would allow for vapor to escape from the system sooner such that the accumulator setpoint would be reached earlier due to the l more rapid depressurization. SI to the broken loop is modeled explicitly such that the 150*F PCT l penalty which has been assessed to the pre-uprate analysis no longer applies. Additionally, no credit has been taken for the new Si condensation model (COSI), since the final model implementation was i not approved prior to completion of this analysis. Acceptable results have been obtained without l taking credit for the ne v Si condensation model, so that additional margin was not needed. 1 Prior to break initiation, the plant is assumed to be in a full power (102%) equilibrium condition, i.e., the heat generated in the care is being removed via the secondary system. Other initial plant conditions assumed in the a talysis are given in Table 6.1.2-1. Subsequent to the break opening, a period of reactor coolant system blowdown ensues in which the heat from fission product decay, the hot reactor intemals, and the icactor vessel continues to be transferred to the RCS fluid. The heat transfer between the RCS and che secondary system may be in either direction and is a function of the relative temperatures of the prinwy 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. When a small break LOCA occurs, clepressurization 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 i signal subsequently occurs when the pcessurizer low-pressure reactor trip setpoint, conservatively ) modeled as 1840 psia, is reached. LOCP is assumed to occur coincident with reactor trip. A safety l injection signal is generated when the pressurizer low-pressure safety injection setpoint, conservatively modeled as 1715 psia, is reached. Safety injection is delayed 27 seconds after pressurizer pressure decreases to the low pressure setpoint. This delay accounts for signal initiation, diesel generator start up and emergency power bus loading consis'ent with the assumed loss of offsite power coincident with reactor trip, as well as the time involved in aiigning the valves and bringing the HHSI pump up to full speed. These countermeasures limit the consequences of the accident in two ways. l

1. Reactor trip and borated water injection cupplement void fonnation 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 stiall break LOCA analysis for the boron content of l the injection water.

In addition, credit is taken in the small break LOCA analysis for the insertion of Rod Cluster Control Assemblies (RCCAs) subsequent to th t reactor trip signal, while assuming the most reactive RCCA is stuck in the full out position. A rod drop time of 2.7 seconds was assumed while also considering an additional 2 seconds for the signal processing delay time. Therefore, a total delay time of 4.7 seconds from the time of reactor trip signal to rod insertion to the dashpot was used in the small break LOCA analy:is.

2. Injection of borated water ensures sufficient flooding of the core to prevent excessive cladding temperatures.

m:\3254w.non\sec6 wpf.Ib-012997 6-10

7 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 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. De core heat transfer mechanisms associated with the small break transient include the break itself, the injected ECCS water, and the heat transferred from the RCS to the steam generator secondary side. Main Feedwater (MFW) is conservatively assumed to be isolated in 7 seconds following the reactor trip signal, consisting of a 2 second signal delay time and a 5 second main feedwater control valve stroke time. (At Farley, MFW isolation is initiated by the SI signal.) A continuous supply of makeup water 's also provided to the secondary using the auxiliary feedwater (AFW) system. AFW system actuation occurs coincident with loss of offsite power (LOOP), resulting in the delivery of AFW system flow within 60 seconds. Credit is taken for AFW flow from one motor-driven AFW pump and the turbine-driven AFW pump. (At Farley, the motor-driven AFW pump is started by the ESF bus loss of voltage, and the turbine-driven AFW pump is started by the RCP bus loss of voltage.) The heat transferred to the secondary side of the steam generator aids in the reduction of the RCS pressure. { i Should the RCS depressurize to approximately 585 psig (minimum), as in the case of the limiting ! 3-inch break and the 4-inch break, the cold leg accumulators begin to inject borated water into the i reactor coolant loops. In the case of the 2-inch break however, the transient is terminated without the I aid of accumulator injection. I Evaluations Upon completion of the small break LOCA analysis, an evaluation was performed to address potential effects of containment spray actuation during small break LOCA. His evaluation also accounts for the fact that Farley Units 1 and 2 may be subject to SI interruption or reduction while switching over to cold leg recirculation. Additionally, it accounts for the enthalpy increase in the delivered SI flow following switchover, ne results of this evaluation are discussed in Section 6.1.2.5. 6.1.2.4 Acceptance Criteria for Analyses / Evaluations ne acceptance criteria for the LOCA are described in 10 CFR 50.46 (Reference 1) as follows:

1. De calculated maximum fuel element cladding temperature shall not exceed 2200'F.

2. De calculated total oxidation of the cladding shall nowhere exceed 0.17 times the total cladding thickness before oxidation.

d 3. De calculated total amount of hydrogen generated from the chemical reaction of the cladding with water or steam shall not exceed 0.01 times the hypothetical amount that would be rn:\3254w.nonhec6*pf:lt>012997 6-11 l I % - ,- -- , _ __ --,a -

I generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the - ! cladding surrounding the plenum volume, were to react. )

4. Calculated changes in core geometry shall be such that the core remains amenable to cooling.

5. After any calculated successful initial operation of the ECCS, the calculated core temperature l shall be maintained at an acceptably low value and decay heat shall be removed for the extended period of time required by the long-lived radioactivity remaining in the core.

Criteria 1 through 3 are explicitly covered by the small break LOCA analysis at uprated conditions. 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) consideetions are not directly applicable to the small break LOCA transient, but are assessed in Section 6.1.4 as part of the evaluation of ECCS performance. The criteria were established to provide a significant margin in emergency core cooling system performance following a LOCA. 6.1.2.5 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 six cases were examined. These cases included the investigation of variables including upflow/downflow, 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. Each unit at each end of the full power temperature window was analyzed for the 3-inch break, which was expected to be limiting for the Farley units. From Table 6.1.2-2 the configuration with the highest PCT with respect to unit and core average temperature has been used for break size sensitivity calculations. In this analysis, Unit I with the low core average temperature was found to be limiting. The next set of calculations confirmed the limiting break size continues to be a 3-inch break, as shown in Table 6.1.2-4. All calculations shown in Tables 6.1.2-2 and 6.1.2-4 were performed assuming ZIRLO cladding at beginning-of-life (BOL) conditions (500 MWDMTU). The results of Reference 6 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 results are shown in Table 6.1.2-2 and Table 6.1.2-3. Inherent in the limiting small break analysis are several input assumptions (see Section 6.1.2.2 and Table 6.1.2-1), while Table 6.1.2-5 provides the key transient , event times. m:\3254w.non\sec6.wpr Ib-ol2997 6-12

i o A summary of the transient response for the limiting case is shown in Figures 6.1.2-4 through h 6.1.2-15. These figures present the response of the following parameters.

RCS Pressure
Core Mixture Level
Peak Cladding Temperature
Top Core Node Vapor Temperature
Pumped Safety Injection Mass Flow Rate for the Intact and Broken Loops l
Cold Leg Break Mass Flow Rate
Hot Spot Rod Surface Heat Transfer Coefficient
Hot Spot Fluid Temperature
Intact Loop Accumulator Flow a Primary Side and Intact Loop Secondary Side Pressure
Intact Loop Cold Leg Nozzle Liquid Mass Flow Rate
Intact Loop Cold Leg Nozzle Vapor Mass Flow Rate Upon initiation of the limiting 3-inch break, there is an initial rapid depressurization of the RCS followed by a intermediate equilibrium at around 1200 psia, which is then followed by a gradual depressurization past the accumulator injection setpoint (see Figure 6.1.2-4). 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 down. As such, normal upward flow is maintained through the core and core heat is adequately removed. Following reactor trip, the removal 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 temperature transient plots for the 3-inch break calculations given in Figures 6.1.2-5 and 6.1.2-6, respectively, it is seen that the peak cladding temperature occurs near the time when the core is most deeply uncovered and the top of the core is being cooled by steam. This time is characterized by the highest vapor superheating above the mixture level (refer to Figure 6.1.2-7). ; 1 A comparison of the flow 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 (Figures 6.1.2-8 and 6.1.2-9), indicates 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. At 3000 seconds, the pumped SI flow rate is about 64.5 lbm/see while the break flow rate is about 62.5 lbm/sec, yielding a net increase in system inventory. Figures 6.1.2-10 and 6.1.2-11 provide additional information on the hot rod surface heat transfer coefficient at the hot spot and fluid temperature at the hot spot, respectively. Figures 6.1.2-12, 6.1.2-13,6.1.2-14 and 6.1.2-15 show additional information on the intact loop accumulator flow, primary side and intact loop secondary side pressure, intact loop cold leg nozzle liquid mass flow rate, and intact loop cold leg nozzle vapor mass flow rate for the limiting 3-inch break low T,, case,

     -     respectively, m:\3254 w.non\sec6.wpf. I t>.012997                    6-13

The 10 CFR 50.46 criteria continue to be satisfied beyond the end of the calculated transient due to the following conditions.

1. The RCS pressure is gradually decaying.

2. The net mass inventory is increasing.

3. The core mixture level is recovered.

4. As the RCS inventory continues to gradually increase, the core mixture level will continue to increase and the 'uel cladding temperatures will continue to decline indicating that the temperature excursion is terminated.

Additional Break Cases Studies documented in Reference 6 have determined that the limiting small-break transient occurs for breaks of less than 10 inches in diameter. To ensure that the 3-inch diameter break was the most limiting, calculations were also performed with break equivalent diameters of 2 inches and 4 inches. The results of the limiting configuration case (3") is given in Table 6.1.2-2, while the results of the break spectrum cases are given in Tables 6.1.2-4 and 6.1.2-5. For the limiting configuration calculations for 3-inch breaks, plots of the following parameters are given in Figures 6.1.2-16 through 6.1.2-18 for Unit I high T,,,, Figures 6.1.219 through 6.1.2-21 for Unit 2 low T,,, and Figures 6.1.2-22 through 6.1.2-24 for Unit 2 high T,,,. Additionally, for the Unit I low T,,, break spectrum the plots of the following parameters are given in Figures 6.1.2-25 through 6.1.2-27 for the 2-inch break case and Figures 6.1.2 28 through 6.1.2-30 for the 4-inch break case.

1. RCS Pressure Transient

2. Core Mixture Level

3. Peak Cladding Temperature The PCTs for the 2-ir ch and 4-inch breaks are 1462*F and 1457'F, respectively. As shown in Table 6.1.2-4, these PCTs are less than the limiting 3-inch break case.

Limitine Temperature Conditions Reduced operating temperature typically results in a PCT benefit for the small break LOCA. However, due to 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. For Farley, the temperature window analyzed was based on a nominal vessel average temperature range of 567.2*F to 577.2 F with 6.0 F to bound uncertainties. A sensitivity analysis for the vessel m:\3254w.non\sec6 wpf.1t412997 6-14

1 average tempe.mture and upflow/downflow configuration was performed based on the limiting 3-inch break case from the break spectrum analyses previously described. The analysis showed that the l Unit I low T,y case is limiting. Time-in-Life Calculations Since burst at BOL conditions was not obtained for the ZIRLO-clad fuel, additional cases have been nm as a function of time-in-life to isolate the point at which rod burst occurs. At this point, there is a PCT excursion due to the Zirc-water reaction at the burst location and blockage in the flow channel. This PCT excursion is usually more limiting than ths BOL PCT and becomes more severe as the BOL PCT increases. For ZIRLO-clad fuel, burst was found to occur at 5500 MWD /MTU, and the resulting PCT is 1968'F for a 3-inch break for Unit 1, indicating that the net burst and blockage / time in life penalty is approximately 39'F based upon explicit calculations. See Table 6.1.2-3 for these transient ' results. The PCT plot for this case has been presented as Figure 6.1.2-31. Since ZIRLO- and Zirc-clad fuel have different physical characteristics as modelled by the SBLOCTA code, explicit calculations for Zirc-clad fuel have been performed. For Zirc-clad fuel, burst was found at BOL conditions for a 3-inch break for Unit 1, and the PCT of 2072*F was more limiting than that which was calculated for the ZIRLO-clad fuel. Since BOL burst was obtained, no additional PCT calculations were needed for time-in-life effects; however, an additional case was run at 6000 MWD /MTU The calculated PCT for Zire-clad fuel at 6000 MWD /MTU was found to be 1905'F (see Figure 6.1.2-32), which is less limiting than the ZIRLO-clad fuel PCT. At the time at which this analysis is implemented, no new Zirc-clad fuel is expected to be inserted into the core. All of the Zire-clad fuel will be' burned for at least one cycle, if not more, if ZIRLO-clad fuel is implemented at non-uprate conditions. The Zirc-clad minimum, core-wide, fuel-pin burnup is expected to be well in excess of 6000 MWD /MTU. Therefore, assuming that this is the case, the ZIRLO-clad fuel will be considered more limiting with a PCT of 1968'F in comparison to the 1905*F PCT. This confirmation will have to be explicitly verified as part of the RSAC process when the uprated ZIRLO-clad fuel is being implemented. If this burnup criterion can be satisfied during the reload, as is expected, then no additional PCT penalty will be needed for Zirc-clad fuel. The fuel temperatures / pressures used in these calculations account for any modifications to the helium release model that have been deemed necessary. This analysis has been performed using the most limiting temperature / pressure data (including Zire versus ZIRLO cladding and 1.5x 100 psig backfill IFBA versus non-IFBA) as calculated for VANTAGE 5 fuel. Since the LOPAR fuel F, is more restrictive than the VANTAGE 5 F, and since LOPAR fuel is expected to be placed in non-limiting power locations, no explicit calculations for LOPAR fuel have been or need to be performed as part of the power uprate project. If LOPAR fuel is to be loaded in any given cycle, this will be handled as part of the normal reload evaluation process. O mA3254w.non\sec6.wpf:lt>.012997 6-15 j

I Evaluation of Containment Spray Effects An evaluation to address the potential effects of containment spray actuation on small break LOCA O' resulted in no change to the predicted small break LOCA PCT for the various cases analyzed. This l calculation is performed as a conservative hand calculation apart from the NOTRUMP results. The time required to drain down the RWST is conservatively calculated based upon maximum containment spray and SI flows and minimum initial RWST level. This time was found to be sufficiently long enough such that the limiting transient PCT would be unaffected by the switchever to cold leg recirculation. 6.1.2.6 Conclusions l A break spectrum at the limiting vessel average temperature and upflow/downflow configuration was performed. Peak cladding temperatures of 1462',1929* and 1457'F were calculated for the 2-inch, 3-inch and 4-inch cold leg breaks, respectively, at BOL thus identifying the 3-inch equivalent diameter break as limiting. The sensitivity to vessel average temperature and upflow/downflow configuration yielded a limiting peak cladding temperature of 1929 F for the Unit I low T,y case. Therefore, the 3-inch equivalent diameter cold leg creak, low nominal vessel average temperature for Unit 1, is the limiting case. Time-in-life effects yield a limiting PCT of 1968"F for ZIRLO-clad fuel. Beyond 6000 MWDMrU, evaluations have been performed to determine that PCT for Zire-clad fuel is bounded by PCT for ZIRLO-clad fuel. ; 1 The analyses presented in this section show that the accumulator and high head safety injection subsystems of the Emergency Core Cooling System, together with the heat removal capability of the steam generator, provide sufficient core heat removal capability to maintain the calculated peak cladding temperatures below the required limit of 10 CFR 50.46. 6.1.2.7 References

1. " Acceptance Criteria for Emergency Core Cooling Systems for Light Water Cooled Nuclear Power Reactors," 10 CFR 50.46 and Appendix K of 10 CFR 50, Federal Register, Volume 39, l Number 3, January 1974, as amended in Federal Register, Volume 53, September 1988.

l

2. Meyer, P. E., "NOTRUMP - A Nodal Transient Small Break and General Network Code,"

WCAP-10079-P-A, (proprietary) and WCAP-10080-NP-A (non-proprietary), August 1985.

3. Lee, N. et al., " Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP 1

Code," WCAP-10054-P-A (proprietary) 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.

mT3254w.non\sec6.wpf.It412997 6-16

. . - - . . . . . . . - . _ - . . - . _ - . . . . . . - . . - . . . - . - - - _ . . _ . . ~ - - . - . . - - . - i l 5 Bordelon, F. M. et al., "LOCTA-IV Program: Loss-of-Coolant Transient Analysis," O WCAP-8301 (proprietary) and WCAP-8305 (non-proprietary), June 1974.

6. Rupprecht, S. D. et al., " Westinghouse Small Break LOCA ECCS Evaluation Model Generic Study with the NOTRUMP Code," WCAP-1Il45-P-A (proprietary), October 1986.

l l O I I l l i O m:0254w.nonwwpf:Ib-012997 6,g 7

TABLE 6.1.21 INPUT PARAMETERS USED IN TIIE SMALL BREAK LOCA ANALYSIS Parameter Value Reactor core rated thermal power"', (MWt) 2775 Peak linear powero .2', (kW/ft) 13.9 Total peaking factor (Ff) at peak

2.50 Power shape
See Figure 6.1.2-1 F, 1.70 Fuel Array 17x17 Accumulator water volume"', nominal (ft'/acc.) 980 Accumulator gas pressure, minimum (psig) 585 Pumped safety injection flow See Figure 6.1.2-2 Steam generator tube plugging level (%)* 20 average / peak Thermal Design Flow per loop. (gpm) 86,000 Vessel average temperature uncertainties, ('F) -6.0/+6.0 (Low /High)

Vessel average temperatmr without unc.eties, ('F) 567.2/577.2 (Low /High) Reactor coolant pressure with unattainties, (psia) 2300 Min. aux. feedwater flowrate, (gpm) 681 (1) Two percent is added to this power to account for calorimetric error. Reactor coolant pump heat is not modeled in the SBLOCA analyses. (2) This represents a power shape corresponding to a one-line segment peaking factor envelope, K(z), based on Ff = 2.50. (3) Maximum plugging level in all steam generators. (4) Does not include line volume of 45 ft'. l 9 m132W.non\sec6 wpf;lMl2997 6-]8

i a i O TABLE 6.1.2-2 SMALL BREAK LOCA ANALYSIS BOL FUEL CLADDING RESULTS LLMITING CONFIGURATION DETERMINATION FOR 3 INCH BREAK 1 Unit 1 Unit 2 Unit 1 Unit 2 High T,,, High T,,, Low T,,, Low T,,, l Peak Cladding Temperature (*F) 1923 4 1891 1929 - 1923 Peak Cladding Temperature Location (ft)* 12.00 12.00 12.00 12.00 1

Peak Cladding Temperature Time (sec) 1354 1397 1369 1402 Local Zr/H 2O Reaction, Max (%) 5.12 4.80 5.28 5.41 Local Zr/H2O Reaction Location (ft)* 11.75 11.75 11.75 11.75 Total Zr/H 2O Reaction (%) < l.0 < l.0 < l.0 < l.0 Hot Rod Burst Time (sec) No Burst No Burst No Burst No Burst Hot Rod Burst Location (ft) N/A N/A N/A N/A

    *From bottom of active fuel b
                                                                                                                               )

1 I l I u V l m \3254w.non\sec6*pf:1b-012997 6.}9

TABLE 6.1.2-3 SMALL BREAK LOCA ANALYSIS FUEL CLAPDING RESULTS BURST /flME IN LIFE RESULTS FOR ZIRLO CLADDING Unit 1 Low Tm Peak Cladding Temperature (*F) 1968 Peak Cladding Temperature Location (ft)* 12.00 Peak Cladding Temperature Time (sec) 1369 Local Zr/H 2O Reaction, Max (%) 5.84 Local Zr/H 2O Reaction Location (ft)* 12.00 Rod Burst" Time (sec) 1233 Rod Burst" Elevation (ft)* 11.75 Burnup (MWD /MTU) 5500 From bottom of active fuel

    ** Burst is predicted for the hot assembly average rod and not the hot rod, thereby causing an effective O

blockage penalty at 5500 MWD /MTU. For 6000 MWD /MTU, both the hot assembly average rod and hot rod burst, but the resulting PCT was less limiting than the 1968'F shown piove. O mA3254w.non\sec6 wpf.lb-012997 6-20

    . _ ~ - - - - _ . - . . . . - . . - .                  . . - . _ . _ . . - - . . . . . . . ~ . - _ . _ _ . -                                   . . . - - - - _ . . - - - - - -

1 4 i j 4 i TABLE 6.1.2-4 i SMALL BREAK LOCA ANALYSIS FUEL CLADDING j RESULTS BREAK SPECTRUM '. 2-inch 3-inch 4-inch 1 i Peak Cladding Temperature (*F) 1462 1929 1457 1 2 Peak Cladding Temperature Location (ft)* 11.75 12.00 11.25 l i Peak Cladding Temperature Time (sec) 3442 1369 774

Local Zr/H 2O Reaction, Max (%) 0.55 5.28 0.30 2

! Local Zr/H2O Reaction Location (ft)* 11.50 11.75 11.25 l Total Zr/H 2O Reaction (%) < 1.0 < 1.0 < 1.0 1 i Hot Rod Burst Time (sec) No Burst No Burst No Burst i

Hot Rod Burst Location (ft) N/A N/A N/A

! *From bottom of active fuel 4 ( 1 l l 1 l l l- ) i a 4 i I i i h l 1 ! l 4 L .l -j m.\3254w.non\sec6 wpf.It412997 6 21 4 l ! t

TABLE 6.1.2-5 SMALL BREAK LOCA ANALYSIS TIME SEQUENCE OF EVENTS 2 inch 3 inch 4-inch Break Occurs (sec) 0.0 0.0 0.0 Reactor Trip Signal (sec) 32.7 13.9 8.2 Safety Injection Signal (sec) 43.0 19.7 10.6 Top of Core Uncovered (sec) 1197 518 461 Accumulator injection Begins (sec) (1) 1166 632 Peak Clad Temperature Occurs (sec) 3442 1369 774 Top of Core Covered (sec) 7409 (2) 5211 (2) 2631 (1) System pressure never drops below the accumulator cut-in pressure (600 psia). (2) To focus on the more important time period in these transients, the maximum time displayed in the figures has been reduced to a time less than that given for top of core covered. O i e m:\3254w.nen\sec6 wpf.1b-012997 6-22

4 1

O ,

1 3 l 25

                                                              , K(Z) CURVE

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                                      ' '     ' '                                               ' ' '                            ' ' ' ' ' ' '                  i 0

i 0 5 0 0 0 1'O 12 i l CORE ELEVATION (ft)

O

, Figure 6.1.21 Small Break Hot Rod Power Shape m:\3254w.non\sec6 wpf:Ib-012997 6-23

O ! l 350 - 30o . : FLOW TO INTACT LOOP FROM ONE HHSI PUMP n - E -

     @; 250 - -

v _ se 200 - - i e : z - O - E: 150 -- M - 2 t - 4 100 - - 5 FLOW TO BROKEN LOOP

FROM ONE HHSI PUMP So _ _

0 O 500 idOO 15'00 2dOO 2500 PRESSURE (psig) O Figure 6.1.2 2 Small Break Pumped Safety Injection Flow Rate - 1 HHSI Pump m:\3254w.non\sec6 wpf:Ib-012997 6-24

3 1 J lO

l j i 4 i i ! N L ! 0 0 T COM PRESSURE, COM C

p rp

                                     ^*                                           rIDY, MIITURE IREL,                                            A

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} C i O Figure 6.1.2-3 Code Interface Description for the Small Break LOCA Model mi1254w.non\sec6.wpf:lb-012997 6-25 l

l 9\

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               .                                                                            i
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g 1000 - - 500 - - I f f I f f I I I I I I I I I I I I I t t 9 f t t t t t t U !E0 10'00 1M M b M Time (s) O Figure 6.1.2 4 RCS Depressurization Transient, Limiting 3-Inch Break, Low T,y, Unit I m:\3254w.non\sec6.wpf:lt412997 6-26

i i

O 4

1 l 35 l 3 ! 3 . E v - l 25 - - U O % s 2 TOP OF CORE 20 - - 35

                                              , , , , , , , , , , ,               . . . . . . . . . .               '. . > > > i 0                500         IdOD           1$00           2dOO             2$00                        3000 Time (s)

O Figure 6.1.2 5 Core Mixture Level,3 Inch Break, Low T,,, Unit 1 m:\3254w.non\sec6 wpf:1t412997 6-27

l 4 i

't O

I 2000 I 1800 - - i 1 l

                       -                                                                              l 1600 --                                                                                 l n              -

l

u. -

l v - 1400 - - e .

          "             .                                                                             l 3 1200 -       -

o - u e - ca.10 0 0 - - E - e - w - 800 - - 600 - - 400 u ''''''''''''''''00 500 10'00 15'00 20 2500 3000 Time (s) O Figure 6.1.2-6 Peak Cladding Temperature Hot Rod,3-Inch Break, Low T,, Unit 1 m:\3254w.non\sec6 wpf.lM12997 6-28

I I 'O l E i i i 1400

! l l l l 1200- - i I

^ _ !

u_ i v - l { !

1000 - -
e u -

i = - j ~ u e 800 - - O. 4 1 E - e l w l 600 - l 1 400 O 500 10'00 15'00 20'00 25'00 3000 Time (s) O Figure 6.1.2-7 Top Core Node Vapor Temperature,3 Inch Break, Low T,, '! nit 1 m:V254wmon\sec6.wpf:lt>.012997 6-29

O 50

                  -                                                                         l lNTACT      LOOP                  :
     ^m40 -      -

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o 20 --

                    ~       ~

u. .

m - m .

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0 '''''''''''''''''''''''' O 500 10'00 15'00 20'00 25'00 3000 Time (s) Figure 6.1.2-8 ECCS Pumped Safety Injection - 3 Inch Break, Low T,y, Unit I 9l m:\3254w.non\sec6 wpf;lb-012997 6 30

O 2000 1

                    -                                                                               i l

l

     ^              _

co N 1500 - - E

     .o               -

l v es e O 1000 -. m ct:: , o ( so ca 500 - - 0 ~ 2 l

                                             -         _.n -                -

0 O 500 10'00 15'00 20'00 25'00 3000 Time (s) O 3 Figure 6.1.2 9 Cold Leg Break Mass Flow,3 Inch Break, L,ow T,, Unit 1 mMT54w.non\sec6 wpf:1M12997 6-31

l

4

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lL s o U 1$- =_ u : O : m . C u 1$-- o . O t- -1 iiiie ii ,e iiie iiiie ie i ie i i e 0 500 10'00 15'00 20'00 25'00 3000 Time (s) Figure 6.1.210 Hot Rod Surface Heat Transfer Coefficient Hot Spot,3-Inch Break, Low T,, Unit 1 m:\3254w.non\icc6.wpf.lb-012997 6-32

  . - - _ _ _ _ . . . . .           . - . . . . _ . . . - - -       - . . . - - .           . -        . . . - - - . - - - = .            - - - - . .

i 1 d ) 4 1 i. i i 2000 ! 1800- -

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1600- - j - w . i V - i l l 1400- - i . ) e a 3 1200- - lO : e - l n.1000- -

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i H _ 800- - l l l 600 -- 1 i 400 '''''''''''''''''''''''' ! O 560 10'00 15'00 20'00 25'00 3000 i Time (s) i i 4 O Figure 6.1.2-11 Fluid Temperature - Hot Spot,3-Inch Break, Low T., Unit 1 i

!                         m:\3254w.non\sec6.wpf;1b-012997                                   6-33 4

                                                                                          'l 300
                  ~                                                                         !
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250 - -

m ~

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200 v e> l e _ I O 150 -- cr -

3: ~ O u_ 10 0 - - m . M _ O - 2 50- - g

                      ''''''' '              d          a li       4% i , ,

0 0 500 10'00 15'00 20'00 25'00 3000 Time (s) O Figure 6.1.2-12 Intact Loop Accumulator Flow,3-Inch Break, Low T,y, Unit I m:\3254w.non\sec6.wpf;1b 012997 6 34

O i 2500 l i - 2000 - - i s , m o a e- , m j o.1500 -' v . INTACT LOOP STEAM GENERATOR

 ,       =s m 1000 -         f m

O s c_ . REACTOR COOLANT 500 - - SYSTEM 0 O 560 10'00 15'00 20'00 25'00 -3000 Time (s) l O Figure 6.1.2-13 Primary Side and Intact Loop Secondary Side Pressure,3-Inch Break, Low T,,,, Unit 1 i m:\3254w.non\sec6.wpf:lt412997 6-35 t

l l i O 20000 4 l 4 1 ^*15000 - '- l 1 N '-

i E , l 4 ! v .. 10000 - - , e - O , 1 ct:: I E o 5000 - - l A _ m - 4 m . l 0 3 "2E p' . j

            -5000 U               560     10'00      15'00       20'00      25'00      3000 Time          (s)                                      l l

l l Figure 6.1.2-14 Intact Loop Cold Leg Nozzle Liquid Mass Flow Rate,3-Inch Break, i Low T,,, Unit 1 I l m:\3254w.non\sec6.wpf:lt412997 6 36

l l l e 8

  \                                                                                                                               l l

1 1, ) 20 1 0 j m p 1 NN - ! " -2 0 - - 1 N _ l E - 4

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d 1 1 O l 2500 l i 2000 - - 3en1500 -- O - E m a 1000 - - 500 - - 0 ' '''''''''''''''''''' i 0 500 idOO I 1500 2d00 25'00 3000 lime (s) O Figure 6.1.2-22 RCS Depressurization Transient,3. Inch Break, High T,,,, Unit 2 m:\3254wmon\sec6a wpf.Ib-012997 6 44

1

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                      '             '''''''''''''''e                          ii' 800 O              1000             20'00      3(iOO      4(iOD      SiOO          9000 Time (s) l l

l i i I Figure 6.1.2-25 RCS Depressurir.ation Transient,2 Inch Break, Low T,y, Unit I mM254wmon\sec6mspf.Itw012997 6 47

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m-O 1000 1 1400 - - 1200 - - C v . 8 - O 1 1000 - - s

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                       .                                                                      i i ie i iiiiiiie iiiiiiiiii,iiiiii g

0 1d00 2dOD 3d00 4d00 50'00 0000 Time (s) i O Figure 6.1.2-27 Peak Cindding Temperature - Hot Rod,2 Inch Break, Low T., Unit I m:\3254w. mon \sec6a.wpf:lb-012997 6 49

O 2500 - - 2000 - -

     ? 1500 -    -

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O f Figure 6.1.2-29 Core Mixture Level,4-Inch Break, Low T , Unit 1 l

m:\3254w.non\sec6a.wpf.lb 012997 6-51

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O Figure 6.1.2-30 Peak Cladding Temperature - Hot Rod,4 Inch Break, Low T,,, Unit I mA3254w.non\sec6a wpf;lb-012997 6-52 L____________________. l

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1800 - -

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Figure 6.1.2-32 Peak Cladding Temperature - Hot Rod,3-Inch Break, Low T,, Unit 1, Zirc-4 Cladding,6000 MWD /MTU m:\3254w.non\sec6a wpf;Ito-012997 6 54

I 6.L3 Hot Leg Switchover I i Post-LOCA Hot 12g Switchover (HLSO) time is calctlated for inclusion in the emergency operating l procedures to ensure there is no boron precipitation in the reactor vessel following boiling in the core l after a large break LOCA. This calculation 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 50.46 continue to be met for the increase in core power from 2652 to 2775 MWt. Specifically, a new HLSO time is ! established at uprated conditions to show that boron concentrations will not build up to a point such I that boron precipitation occurs. Excessive boron precipitation may result in a change in core geometry which is not amenable to cooling or reduced heat transfer capability such that heat can not be removed i l for the extended period of time required by long lived radioactivity remaining in the core. i Currently, a HLSO time of 11 hours is calculated for Farley Units I and 2 based on a core power level of 2652 MWt. Although the boron concentrations of the RCS and ECCS are not changing as a l result of the uprating, the increase in core power to 2775 MWt necessitates a recalculation of the HLSO time and hot leg recirculation minimum required flow. 'Ihe increase in core power will reduce the HLSO time from the current value.

The new HLSO time based on an uprated core power of 2775 MWt is 7.5 hours. At the time of this l ' analysis, Farley used the alternating hot leg and cold leg recirculation method. For this method, the new time for cycling between hot leg and cold leg recirculation is 13 hours after initially switching {

over to hot leg recirculation. The requirement for cycling between hot leg and cold leg recirculation does not apply to the simultaneous hot leg and cold leg recirculation method and can be deleted if this { method is implemented at Farley. Since the HLSO time has been reduced, a revised set of hot leg recirculation minimum required flows were calculated. Table 6.1.3-1 provides the required SI flow rates and the corresponding available l flow rates for four different accident scenarios. As shown by the results in Table 6.1.3-1, the available j SI flow rates exceed the corresponding required flow rates for each scenario. l i l mV254w. mon \sec6a upf:1b-012997 6-55 l

l TABLE 6.1.3-1 ECCS MP'.WUM REQUIRED FLOW RATES j

                                      *dR FARL'EY UPRATING TO 2775 MWt Total Available SI Flow               Flow             i Break             MOV 8889                    Delivery                             Criteria Location                 Status      System     Location     epm       Ibm /sec (Ibm /see)

Cold Leg Operational LHS1 Hot Leg 3722.2i" 497.2") 35.1 HHSI Hot Leg (1.3 x boilof0 Hot leg Operational LHSI Hot Leg 1752.1"' 234.0'" 89.1 HHSI Hot Leg (3.3 x boilof0 Cold Leg Fail LHS! Cold Leg No Requirement No Requirement HHSI Hot Leg 548.8 73.3 35.1 (1.3 x boilof0 Hot leg Fail LHSI Cold Leg 3487.2 465.7 40.5 (1.5 x boilof0 HHSI Hot Leg No Requirement No Requirement '" SI flow from LHSI and HHSI 1 l l 4 1 l l 9 m:\3254 w .non\sec6a.wpf. I t>012997 6-$6

i r 6.1.4 Post.LOCA Long Term Core Cooling The Westinghouse licensing position for satisfying the requirements of 10 CFR 50.46 Paragraph (b) Item (5), "Long-Term Cooling," is documented in Reference 1. He Westinghouse position is that the core will remain suberitical post-LOCA by borated water from various ECCS water sources residing in the RCS and containment sump. Since credit for control rod 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 suberitical assuming that all control rods remain withdrawn from the core. Although uprated power is not part of the calculation, the T,,, range will have an effect 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 to determine the containment sump boron concentration include the water mass of the RCS, Since the T,., range will lower the RCS operating temperature, which will increase the density of fluid, there is i a potential for the post-LOCA sump boron concentration to decrease. However, the effect of this density change on the RCS water mass is relatively small (<1%), and the impact of the density change on the total water inventory of all water sources is extremely small (<0.1%). %erefore, the T., range has a negligible effect on the post-LOCA sump boron concentration calculation. For the uprated power analysis, credit was not taken for RWST water volume after the low level signal is reached. Elimination of credit for RWST delivery after the low level signal resulted in a reduction of the post-LOCA sump boron concentration curve of approximately 25 ppm. Figure 6.1.4-1 shows this curve for the uprated power. The decision to neglect additional RWST delivery below the low level signal is consistent with current Westinghouse analysis practices for this event. Credit for some additional RWST delivery below the low level signal is contingent on containment spray actuation. It is generally believed that break sizes which are large enough to preclude control rod insertion will likely produce mass and energy releases large enough to actuate containment spray. However, detailed calculational data for these break sizes, with assumptions appropriate for this application, are very sparse. Therefore, when margin is available, the current Westinghouse standard practice conservatively neglects credit for additional RWST delivery. In summary, the uprated conditions including a T , range and RWST delivery volume to the low level signal only have been considered, and it is concluded that the core should remain subcritical post-LOCA and that decay heat can be removed for the extended period of time required by the long-lived radioactivity remaining. The revised post-LOCA long term core cooling boron limit curve is used to qualify the fuel and core loading arrangement on a cycle-by-cycle basis during the fuel reload process. 6.1.4.1 References

1. Bordelon, F. M., et al., " Westinghouse ECCS Evaluation Model - Summary," WCAP-8339 (Non-Proprietary), July,1974.

mA3254w.non\sec6a wpf;lt9012997 6-57 . l

l 1 O. i y 2,250 , O. _ b - (2000,2201.5) c - Straight line equation "

   .j 2,200 I y = 0.181(x) + 1839.5                       -

2,150

                  ~
                                                                          /

/

8 5 2,100

                                                              /                                l
                                                                                               )'

3 . m -

E 2,050 ' 4 2 i

                                         /
                                                /                                       .

2,600

    ,5 E

7 O 0 1,950 . 4 . E - (500, 1930) l o - , CL, 1,900 4 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2,200 l

      .                           Pre-Trip Boron Concentration (ppm) l l

I 4 l O Figure 6.1.4-1 Post-LOCA Suberiticality Boron mA3254w.non\sec6a wpf.lM12997 6-58

6.1.5 Rod Ejection Accident Analysis As part of the uprating program, the Rod Ejection accident for mass releases was evaluated and the t results were provided for use in the radiological doses analysis. This evaluation takes a conservative i approach to the rod ejection mass releases in order to achieve a bounding dose analysis. This evaluaJon has been performed to calculate the initial mass of the secondary side to be released through the MSSVs (conservatively large), the minimum time required for the initial mass to exit the MSSVs (conservatively short), and the time required for the primary to semdary pressures to equalize (conservatively long). The rod ejection evaluation results for Farley Units I and 2 at the uprated power conditions (2775 MWt core power) are as follows:

1. 550,000 lbm of primary inventory release instatly to containment;

2. 426,000 lbm of secondary inventory release through the MSSVs in 98 seconds; and

3. Primary and secondary pressures equalize in 2500 seconds, at which time the primary-to-secondary leakage is assumed to terminate.

O i I I l m :\3254w .non\sec6a.wpf;1 b-012997 6-59 l

6.2 Non Loss of Coolant Accident (Non LOCA) Transients i 6.2.0 Introduction 1 All of the FSAR Chapter 15 non-LOCA analyses applicable to the Farley Nuclear Plant (FNP) were , reviewed to determine their continued acceptability based upon plant operation at the upad conditions. Most analyses performed for the Farley Nuclear Plant VANTAGE 5 fuel upgrade license amendment conservatively modeled uprated conditions. For this reason, a complete reanalysis of all non-LOCA FSAR Chapter 15 events was not required. The following non-LOCA events were either reanalyzed or evaluated for Farley Units 1 and 2 for the uprated conditions identified in Table 2.1-2. Uncontrolled Rod Cluster Control Assembly Bank Withdrawal from a Suberitical Condition (Section 6.2.1)"8 Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power (Section 6.2.2)<2a3 Rod Cluster Control Assembly Misalignment (Section 6.2.3)o.23 Uncontrolled Boron Dilution (Section 6.2.4)"J' Partial Loss of Forced Reactor Coolant Flow (Section 6.2.5)"8 Startup of an Inactive Reactor Coolant Loop (Section 6.2.6)"' Loss of External Electrical Load and/or Turbine Trip (Section 6.2.7)5 Loss of Normal Feedwater (Section 5.2.8)* Loss of All Offsite Power to. the Plant Auxiliaries (Section 6.2.9)* Excessive IIcat Removal Due To Feedwater System Malfunctions (Section 6.2.10)") Excessive Load Increase Incident (Section 6.2.11)"'

Accidental Depressurization of RCS (Section 6.2.12)(223

 " Evaluation of current analysis performed in support of FNP uprate.

Reanalysis performed in support of FNP uprate. l

 *NRC review and approval received as part of OTAT/OPAT setpoint revisions. Not included in this report.

mA3254w.non\sec6a.wpf Ib-012997 6-60 l

i l i l

Accidental Depressurization of Main Steam System (Section 6.2.13)"'

i ' e i inadvertent Operation of Emergency Core Cooling System (ECCS) During Power Operation I (Section 6.2.14)"'

Minor Secondary System Pipe Breaks (Section 6.2.15)"' l
Inadvertent Loading of a Fuel Assembly into an Improper Position (Section 6.2.16)"8 i

                       *-       Complete Loss of Forced Reactor Coolant Flow (Section 6.2.17)oas

Single Rod Cluster Control Assembly Withdrawal at Full Power (Section 6.2.18)"'
Rupture of a Main Steam L.ine (Section 6.2.19)"'
Rupture of a Main Feedwater Pipe (Section 6.2.20)"8 l

a Single Reactor Coolant Pump Locked Rotor (Section 6.2.21)"' R

                       *-        Rupture of a Control Rod Drive Mechanism Housing [ Rod Cluster Control Assembly Ejection]
   ,                            (Section 6.2.22)"#8 a         Steam System Piping Failure at Full Power (Section 6.2.23)">'

he analyses and evaluations of each of the above events are discussed in their respective sections. Where applicable, the non-LOCA analyses continue to employ the Revised hermal Design Procedure , (RTDP) methodology (Reference 1). De RTDP methodology statistically convolutes the uncenainties of the plant operating parameters (power, temperature, pressure and flow) into the design limit Depanure from Nucleate Boiling Ratio (DNBR) value.' Dese design limit DNBR values are then utilized to determine the safety analysis limit DNBR values which are assumed as an acceptance criterica in the DNBR-related non-LOCA analyses. The revised Overtemperature AT and Overpower AT (OTAT/OPAT) setpoints with implementation of RAOC (Reference 2) were applied in the analyses supponing the plant uprate. He safety analysis OTAT/OPAT setpoint values applied with the plant uprate are as follows. l l !

Evaluation of current analysis performed in support of FNP uprate.

! "1teanalysis performed in suppon of FNP uprate.

                       *NRC review and approval received as pan of OTAT/OPAT serpoint revisions. Not included in this

! repon. au254.=%.pr.iwi29n 6-61 4

OT6T OP6T K l . ,,, = 1.33 K4. ,,,, = 1.166 K2 = 0.017 K6 = 0.00109 K3 = 0.000825 f(AI) =0 f(AI) + wing = 15%, %Al = 2.05%

                 - wing = 23%, %Al = 2.48%

in conjunction with support of the plant uprate, safety analyses have also been performed or evaluated for degraded safety injection system pump performance and optimized rod control system parameters. For the safety injection system, the non-LOCA analyses support high head safety injection flows associated with 10% degraded pump performance. Only the high head charging pumps are credited for accident mitigation in the non-LOCA analyses; therefore, system pe formance for the low head injection pumps does not impact the analyses. Rod control system parameters intended to provide optimized system response were also considered in non LOCA event analyses and evaluations. Specifically, the non LOCA analyses support a lead / lag compensation on the measured T.,, and T,,, filter time constant of 40 seconds /10 seconds and 10 seconds, respectively, and power mismatch non-linear gain breakpoint of 2 2%. In addition to thc safety injection and rod control system assumptions, Table 6.2.01 summarizes key analysis assumptions .:onsidered in the Farley Units I and 2 Uprate non-LOCA analyses and evaluations. Reactor Trio There are various instrumentation delays associated with each reactor trip function which are modeled directly and considered in the non-LOCA safety analyses. The total delay time is defined as the time delay from the time that trip conditions are reached to the time the rods are free to ials. The safety analysis trip setpoint and maximum time delay assumed for each reactor trip function are as follows. m 02%oome t ib-olm O r 6-62

O Reactor Trip Function Tirce Delay (seconds) Maximum Trip Setpoint Assumed for Analysis Power Range Flux (high setting) 0.5 118 % Power Range Flux (Iow setting) 0.5 35 % Overtemperature AT 12.0* Variable (see above) Overpower AT 12.0* Variable (see above) High Pressurizer Pressure 1.0 " 2425 psig Low Pressurizer Pressure 2.0 1825 psig Low Reactor Coolant Flow 1.0 85% of loop flow Low-Low Steam Generator Water Level i (LONF/ LOOP events) 2.0 16% NRS (Feedline Break event) 2.0 0% NRS High-High Steam Generator Water Level (Feedwater Isolation) 7.0 100% NRS (Turbine Trip) 2.5 100% NRS Reactor Trip (following Turbine Trip) 1.0 N/A Resp 9nse time modeled in non-LOCA FSAR Chapter 15 safety analyses as a 10 second lag function followed by a 2 second electronics (pure) delay. This increased delay (from 8 seconds) was incorporated into the FNP licensing basis analyses in conjunction with Reference 2. This is a change from the current licensing basis value of 2.0 seconds. The results of all of the analyses and evaluations demonstrate that applicable safety analysis acceptance criteria have been satisfied at the uprated conditions detailed in Table 2.1-2. The non-LOCA accidents are considered either American Nuclear Society (ANS) Condition II, III, or IV events. The ANS categorizes events based upon expected frequency of occurrence and severity as follows. Condition I: Normal Operation and Operational Transients Condition II: Faults of Moderate Frequency Condition III: Infrequent Faults , Condition IV: Limiting Faults i \ m:\3254w.non\sec6a wpf.1b-012997 6-63

Condition I events are normal operation incidents which are expected to occur frequently or regularly. These occurrences are accommodated with margin between any plant parameter and the value of that ' parameter which would require either automatic or manual protective action. I Condition II evenis (which are the majority of the non-LOCA events) are incidents of moderate frequency which may reasonably occur during a calendar year of operation. These faults, at worst, result in a reactor trip with the plant capable of retuming to power operations after corrective actions. Condition II incidents shall not genente a more serious accident (Condition III or IV) without other incidents occurring independently. Condition III events are infrequent faults which may reasonably occur during the lifetime of a plant. These faults shall not cause more than a small fraction of fuel elements to be damaged. No consequential loss of function of the RCS or containment as fission product barriers can occur. The release of radioactive materials to unrestricted areas may exceed 10 CFR Part 20 limits; however, they shall not be sufficient to interrupt or restrict public use of those areas beyond the exclusion radius. Condition III incidents shall not generate a more serious accident (Condition IV) without other incidents occurrir.g independently. . Condition IV events are limiting faults which are not expected to occur but are postulated because their consequences would include the potential for significant radioactive releases. The release of radioactive material shall not result in an undue risk to public health and safety exceeding the guidelines of 10 CFR 100. No consequential loss of function of systems required to mitigate the event may occur. References

1. Friedland, A. J. and Ray, S., " Revised Thermal Design Procedure," WCAP-11397-P-A (Proprietary), WCAP-ll397-A (Non Proprietary), April 1989.

2. Letter from USNRC to SNC, September 3,1996, " Issuance of Amendments - Joseph M. Farley Nuclear Plant Units 1 and 2 (TAC Nos. M95700 and M95701)," which responded to SNC letter dated June 12,1996, " Technical Specification Change Request, Revision to Core Limits and OTDT & OPDT Setpoints and Implementation of RAOC."

O m:\3254w.non\sec6agf;1b-012997 6-64

_ _ . ~ TABLE 6.2.0-1 O(T NON LOCA KEY ACCIDENT ANALYSIS ASSUMITIONS FOR FNP UPRATE NSSS 'Ihermal Design Flow (per Loop) 86,000 gpm Minimum Measured Flow (per Loop) 87,800 gpm Programmed Full Power RCS Average Temperature (per Loop) 577.2'F maximum 567.2'F minimum ** Maximum Steam Generator Tube Plugging Level 20% average / peak MaxFm (VANTAGE 5 Fuel) 1.70 (LOPAR Fuel) 1.30 " Max Fo 2.50* DNB Methodology (where applicabic) RTDP Max EOL MDC 0.50 Ak/g/cc l Max BOL MTC +7 pcm/'F 5,70% RTP ramping to 0 at 100% RTP l Initial Condition Uncertainties: Power +/- 2% RTP Temperature +/- 6'F Pressure +/- 50 psi Steam Generator Water Level +/- 7% NRS"* Pressurizer Water Level +/- 5% span Non-LOCA analyses conservatively model an Fo of 2.50 for both VANTAGE 5 and LOPAR fuel types.

             "      Revised assumption from VANTAGE 5 fuel upgrade.
              "* Analyses also justify the presence of a -5% NRS bias on steam generator level indication due to velocity head effects on the lower tap associated with steam generator level tap relocation.

l l I i l l mA3254w.nonisec6ampf:tb-012997 6-65 i

6.2.1 Uncontrolled RCCA Withdrawal From a Subcritical Condition 6.2.1.1 Identification of Causes and Accident Description O 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, sucia a transient could be caused by operator action or a malfunction of the reactor control rod drive system. His could occur with the reactor either subcritical or at power. The "at power" occurrence is discussed in Section 6.2.2. 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 result from changing boron concentration. The 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 system to prevent core damage. Should a continuous RCCA withdrawal be initiated and assuming the source and intermediate range indication and annunciators are ignon:d, the transient will be terminated by the following automatic protective functions.

a. Source range neutron flux reactor trip - actuated when either of two independent source range channels indicates a flux level above a preselected, manually adjustable value. This trip function may be manually bypassed when either intermediate range flux channel indicates a flux level above a specified level. It is automatically reinstated when both intermediate channels indicate a flux level below a specified level,

b. Intermediate range neutron flux reactor trip - actuated when either of two independent intermediate range channels indicates a flux level above a preselected, manually adjustable 1 value. This trip function may be manually bypassed when two of the four power range I

          < annels are reading above approximately 10 percent of the full-power flux and is                  l j          automatically reinstated when three of the four channels indicate a flux level below this value. l l c.       Power range neutron flux reactor trip (Iow setting)- actuated when two out of the four power range channels indicate a flux level above approximately 25 percent of the full-power flux.

This trip function may be manually bypassed when two of the four power range channels mA3254w.nonkT .wpf:ltH)12997 6-66 I i

r

                                                                                                                             *l b                                                                                                                                \

l g 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 salue.

l

d. Power range neutron flux reactor trip (high setting)- actuated when ~wo out of the four power l range channels indicate a power level above a prent setpoint (for FNP 5109 percent of the j full-power flux). This trip function is always active.

e. High positive neutron flux rate reactor trip - actuated when the positive rate of change of 3

neutron flux (5%/2 seconds) on two out of four power range channels indicates a rate above the preset setpoint. This trip function is always active. 1 The neutron flux response to a continuous reactivity insertion is characterized by a very fast flux j l inucase terminated by the reactivity feedback effect of ti.s negative Doppler coefficient. This ( self-limitation of the initial power increase results from a fas negative fuel temperature feedback ; (Doppler effect) and is of prime importance during a startup transient since it limits the power to an ! l acceptable level prior to protection system action.- After the initial power increase, the nuclear power is momentarily reduced and then, if the incident is not terminated by a reactor trip, the nuclear power ; increases again, but at a much slower rate. ) Termination of the startup transient by the above protection channels prevents core damage. In O addition, the reactor trip from high pressurizer pressure (a trip function which is always active when a 1 RCCA withdrawal event can occur) serves as backup to terminate the event before an overpressure I condition could occur. 6.2.1.2 Input Parameters and Assumptions The accident analysis employs the Standard Thermal Design Procedure (STDP) methodology since the conditions resulting from the transient are outside the range of applicability of the RTDP methodology. In order to obtain conservative results for the analysis of the uncontrolled RCCA bank withdrawal l from suberitical event, the following assumptions are made conceming the initial reactor conditions: f

a. 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, a conservatively low (least negative) 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. m:\3254w.nonisec6a.wpf:1b-012997 6-67 i

1

c. 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 tran;f-r 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 l 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 (K,n) 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 instmmentation 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 nomirial value of 25 percent to a value of 35 percent; no credit is taken for the source and intermediate range protection. During the transient, the rise in nuclear power is so rapid that the effect of error in the trip serpoint 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 positsn.

e. The maximum positive reactivity insertion rate assumed is greater than that for the simultaneous withdrawal of the two sequential contml banks having the greatest combined )

I worth at the maximum speed (45 in/ min, which corresponds to 72 steps / min).

f. The DNB analysis assumes the most-limiting axial and radial power shapes possible during the fuel cycle associated with having the two highest cord >ined worth banks in their highest worth position.

g. 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.

h. The analysis assumes two RCPs to be in operation (Mode 3 Technical Specification allowed operation). This is conservative with respect to the DNB transient.

i. This accident analysis employs the Standard Thermal Design Procedure (STDP) methodology.

The use of STDP stipulates that the RCS flow rates will be based on a fraction of the thermal design flow for two RCPs operating. Since the event is analyzed from hot zero power, the steady-state non-RTDP uncertainties are not considered in defining the initial conditions. O mms 4w.nonsec6a v paib-ol't997 6-68

I l l

  ,_   6.2.1.3 Description of Analysis                                                                                j t

The analysis of the uncontrolled RCCA bank withdrawal from suberiticality is performed in three stages. First, a spatial neutron kinetics computer code. TWINKLE (Reference 1), is used to calculate 1 the core average nuclear power transient, including the various core feedback effects, i.e., Doppler and moderator reactivity. Next, the FACTRAN computer code (Reference 2) uses the average nuclear l power calculated by TWINKLE and performs a fuel rod transient heat transfer calculation to determine the average heat flux and temperature transients. Finally, the average heat flux calculated by l FACTRAN is used in the THINC-IV computer code (References 3 & 4) for transient DNBR calculations. l l 6.2.1.4 Acceptance Criteria l The uncontrolled rod cluster control assembly bank withdrawal from suberitical event is considered an ANS Condition II event, a fault of moderate frequency, and is analyzed to ensure that the core and j reactor coolant system are not adversely affected. This is demonstrated by showing that there is little i likelihood of DNB and core damage. It must also be shown that the peak hot spot fuel and clad l temperatures remain within acceptable limits, although for this event, the heat up is relatively small. 6.2.1.5 Results r~' (N) The current licensing basis analysis, performed in suppon of the Farley Nuclear Plant VANTAGE 5 Reload Transition Safety Report (RTSR) conservatively bounds the plant uprate conditions. Therefore, I the transient results presented in FSAR Section 15.2.1 remain valid. The results of the FSAR analysis I l determined that the DNBR safety analysis limit is met and that the peak fuel centerline temperature is less than the temperature at which fuel melt occurs. 6.2.1.6 Conclusions t in the event of an RCCA withdrawal event from the suberitical condition, the core and the RCS are not adversely affected since the combination of thermal power and coolant temperature results in a minimum DNBR greater than the safety analysis limit value. Furthermore, since the maximum fuel temperatures predicted to occur during this event are much less than those required for fuel melting to occur (4800'F), no fuel damage is predicted as a result of this transient at the uprated conditions. Clad damage is also precluded. 6.2.1.7 References

1. Barry, R. F., Jr. and Risher, D. H., "Tv7 INKLE, a Multi-dimensional Neutron Kinetics Computer Code," WCAP-7979-P-A, Jem.ary 1975 (Proprietary) and WCAP-8028-A, O January 1975 (Non-proprietary).

V mu254w.nonw6 wpr.1b-012997 6-69

f

2. Hargrove, H. G., "FACTRAN - A FORTRAN IV Code for Thermal Transients in a UO2 Fuel Rod," WCAP-7908, D>cember 1989.

3. Chelemer, H , and Hochreiter, L. E., " Application of the THINC-IV Program to PWR Design,"

WCAP-81'/5, February 1989.

4. Chelemer, H., Chu, P. T., and Hochreiter, L. E., "THINC-IV - An Improved Program for Thermal-Hydraulic Analysis of Rod Bundle Cores, "WCAP-7956, February 1989.

6.2.2 Uncontrolled RCCA Bank Withdrawal At Power NRC review and approval for this event was received as part of OTAT/OPAT setpoint revisions. The details are not included in this report. O O m:\3254w.non'ac6a.wpf.1M)12997 6-70

6.23 Rod Cluster Control Assembly Misalignment i 6.23.1 Identification of Causes and Accident Description l RCCA misalignment accidents include the following:

a. One or more dropped RCCAs within the same group;

b. A dropped RCCA bank; and

c. A statically misaligned RCCA.

Each RCCA has a position indicator channel which displays the position of the assembly in a display grouping that is convenient to the operator. Fully inserted assemblies are also indicated by a rod at bottom signal which actuates a local alarm and a control room annunciator. Group demand position is also in.iicated. RCCAs move in preselected banks, and the banks always move in the same preselected sequence. Each bank of RCCAs consists of two groups. He rods comprising a group operate in parallel through multiplexing thyristors. De two groups in a bank move sequentially such that the first group is , always within one step of the second group in the bank. A defimite schedule of actuation (or deactuation) of the stationary gripper, movable gripper, and lift coils of the control rod drive mechanism withdraws the RCCA held by the mechanism. Mechanical failures are in the direction of j

 /                                                                                                                        '

k insertion or immobility. A dropped RCCA, or RCCA bank is detected by:

a. Sudden drop in the core power level as seen by the nuclear instmmentation system;

b. Asymmetric power distribution as seen on out-of-core neutmn detectors or core exit thermocouples;

c. Rod at bottom signal;

d. Rod deviation alarm; and/or

e. Rod position indication.

i Dropping of a full-length RCCA is assumed to be initiated by a single electrical 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 resulting negative reactivity insertion causes nuclear power to j rapidly decrease. An increase in the hot channel factor may occur due to the skewed power h distribution representative of a dropped rod configuration. For this event, it must be shown that the DNB design basis is met for the combination of power, hot channel factor, and other system ( conditions which exist following a dropped rod. i m:\3254w.non\sec6a wpf;It>012997 6-7l l l l J

I Misaligned RCCAs are detected by:

a. Asymmetric power distribution as seen on out-of-core neutron detectors or core exit OlI thermocouples;

b. Rod deviation alarm; and/or l l

c. Rod position indicators. l The resolution of the rod position indicator channel is 15 percent of span (27.2 in.). Deviation of any RCCA from its group by twice this distance (10 percent of span or 14.4 in.) will not cause power distributions worse than the design limits. The deviation alarm alens the operator to rod deviation with respect to the group position in excess of 5 percent of span. If the rod deviation alarm is not operable, the operator is required to log the RCCA positions in a prescribed time sequence to confinn alignment.

If one or more rod position indicator channels is out of service, the operator must follow detailed operating instructions to ensure the alignment of the non-indicated RCCAs. Rese operating instmetions require selected pairs of core exit thermocouples to be monitored in a prescribed time sequence and following significant motion of the non-indicated assemblies. The operating instructions also call for the use of moveable incore neutron detectors to confirm core exit thermocouple indication of assembly misalignment. 6.2.3.2 Input Parameters and Assumptions For a RCCA(s) or Bank Drop, the analysis assumes the following conservative assumptions. l 1

a. This event is analyzed with the Revised Thermal Design Procedure (Reference 1). Therefore, )

initial reactor power, pressure, and RCS temperature are assumed at their nominal values. l Uncenainties in initial conditions are included in the limit DNBR.

b. A range of moderator temperature coefficients from 0 pcm/'F to -35 pcm/ F was analyzed, which bounds the limiting time in life,

c. A range of negative reactivity insertions from 100 pcm to 1000 pcm is assumed to simulate the Dropped RCCA event.

d. Pressurizer pressure control and reactor control are modeled in the automatic control mode.

For a Statically Misaligned RCCA the most-severe misalignment situations with respect to DNBR at significant power levels arise from cases in which one RCCA is fully inserted or where bank D is fully inserted with one RCCA fully withdrawn. Multiple independent alarms, including a bank insenion limit alarm, i.e., the RIL alarm., alert the operator well before the transient approaches the mA3254wson\sec6ampf;It412997 6-72 \

l i b l postulated conditions. The bank can be insened to its insenion limit with any one assembly fully withdrawn without the DNBR falling below the safety analysis limit value. t 6.2.3.3 Description of the Analysis j Dronoed RCCAfs) or Bank j The transient response following a dropped RCCA event is calculated by a detailed digital simulation i I i l of the plant. The dropped rod causes a step decrease in reactivity and the core power generation is determined using the LOFTRAN code (Reference 2). The code simulates the neutron kinetics, RCS, ; pressurimr, pressuriur relief and safety valves, pressuriur spray, rod control system, steam generators, j l and steam generator safety valves. The code computes peninent plant variabics including j temperatures, pressures, and power level. Since LOFTRAN employs a point neutron kinetics rnodel, 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. Statepoints are calculated and nuclear models are used to obtain a hot channel factor consistent with l the primary system conditions and teactor power. By incorporating the primary conditions from the l 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 ase performed in accordance with the tuvyyed rod methodology described in WCAP-11394 (Reference 3). I The Dropped RCCA event was conservatively analynd at uprated conditions in support of the Farley Nuclear Plant VANTAGE 5 fuel upgrade. For the plant uprate, the impact on the analysis is primarily l l due to the revised rod control system parameters discussed in Section 6.2.0. To address the change in { the rod control system response, calculations were performed to establish conservative penalties to be L !- applied to the current dropped rod statepoints. The statepoim penalties were then used in the nuclear analysis, which confirmed that the DNB design basis is met. l 4 Statically Misaliened RCCA , For the Statically Misaligned RCCA event, steady-state power distributions are analyzed using appropriate nuclear physics computer codes. The analysis examines the case of the worst rod withdrawn from bank D inserted at the insenion limit with the reactor initially at full power. The analysis assumes this incident to occur at beginning of life since this results in the minimum value of the moderator temperature coefficient (least negative). This assumption maximius the power rise and ' minimius the tendency of the large moderator temperature coefficient (most negative) to flatten the power distribution. Analyses for the RCCA misalignment events were last performed for the VANTAGE 5 fuel upgrade and included uprated power (2775 MWt core) assumptions. An evaluation of the statically misaligned l l RCCA analysis confirmed that the current licensing basis calculation remains bounding, mA3254w. mon \sec6a.wpf:lt>-012997 6-73

l l J 6.2.3.4 Acceptance Criteria Based on the frequency of occurrence, an RCCA Misaligned occurrence is considered a Condition II O I event as defined by the American Nuclear Society. The primary acceptance criterion for these events is that the critical heat flux should not be exceeded. This is demonstrated by precluding Depanure from Nucleate Boiling (DNB). ; 6.2.3.5 Results l Dropped RCCA(s) or Bank Following a dropped RCCA(s) or Bank event, with or without automatic rod withdrawal, the plant will establish a new equilibrium condition. The transient response of a representative case is presented in FSAR Figure 15.2-11. In all cases, the minimum DNBR remains greater than the limit value; therefore, the acceptance criteria is met. Statically Misaligned RCCA The most-severe misalignment situations with respect to DNBR at significant power levels arise from cases in which one RCCA is fully insened or where bank D is fully insened with one RCCA fully withdrawn. Multiple independent alarms, including a bank insertion limit alarm, alen the operator well before the transient approaches the postulated conditions. He bank can be insened to its insertion limit with any one assembly fully withdrawn without the DNBR falling below the safety analysis limit value. The insertion limits in the Technical Specifications may vary from time to time depending on several limiting criteria. The full-power insertion limits on control bank D must be chosen to be above that position which meets the minimum DNBR and peaking factors. The full power insenion limit is usually dictated by other criteria. Detailed results will vary from cycle to cycle depending on fuel arrangements. For this RCCA misalignment, with bank D inserted to its full-power insenion limit and one RCCA fully withdrawn, DNBR does not fall below the safety analysis limit value. The analysis of this case assumes that the initial reactor power, pressure, and RCS temperature are at the nominal values, with the increased radial peaking factor associated with the misaligned RCCA. I 1 1 For RCCA misalignment with one RCCA fully inserted, the DNBR does not fall below the safety l analysis limit value. 'Ihe analysis of this case assumes that initial reactor power, pressure, ar.d RCS temperatures are at the nominal values, with the increased radial peaking factor associated with the misaligned RCCA. ) O m A3254w.non\sec6a. wpf: l t>.012997 6-74

4 d 6.2.3.6 Conclusions 4 O Following a dropped RCCA(s) event the plant will retum to a stabilized condition. Results of the analysis show that a dropped RCCA event, with or without a reactor trip, does not adversely affect the core since the DNBR remains above the limit value for a range of dropped RCCA worths. i ] DNB does not occur for the RCCA misalignment incident; thus, there is no reduction in the ability of the primary coolant to remove heat from the fuel rod. After identifying an RCCA group misalignment condition, the operator must take action as required by the plant Technical Specifications and operating 2 instructions. 4 6.2.3.7 References 4 j 1. Friedland, AJ., and Ray, S., " Revised Thermal Design Procedure," WCAP-ll397-P-A (Proprietary), WCAP-11397-A (Non-Proprietary), April 1989. 3 2. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary), l, WCAP-7907-A (Non-Proprietary), April 1984.

3. Haessler, R.L., et al, " Methodology for the Analysis of the Dropped Rod Event,"

WCAP-11394 (Proprietary) and WCAP-11395 (Non-Proprietary), April 1987. 2 ) 1 l l i k 1 l 4 i } i 1 J mA3254w.non\sec6a.wpf:Ib412997 6-75

6.2.4 Uncontrolled Boron Dilution NRC review and approval for this event was received as pan of OTAT/OPAT setpoint revisions. The i details are not included in this repon. l O l 1 { O m:u254wmonw6 ..pr;isoi2997 6-76

                .    - - . -        ~           -          -        .   . _ - - - - =

p 6.2.5 Partial Loss of Forced Reactor Coolant Flow d 6.2.5.1 Identification of Cr,uses M Accident Description A partial loss of forced coolant flow accident may result from a mechanical or electrical failure in a reactor coolant pump (RCP), or from a fault in the power supply to these pumps. If the reactor is at power at the time of the event, the immediate effect from the loss of forced coolant flow is a rapid increase in the coolant temperature. This increase in coolant temperature could result in departure from nucleate boiling (DNB), with subsequent fuel damage, if the reactor is not promptly tripped. The following signals provide protection against a partial loss of forced reactor coolant flow incident:

Low reactor coolant loop flow;
Undervoltage or underfrequency on reactor coolant pump power supply buses; and l
Pump circuit breaker opening.

The reactor trip on low primary coolant loop flow provides protection against loss of flow conditions. This function is generated by two-out-of-three low flow signals per reactor coolant loop. Above Permissive P-8, low flow in any imp will actuate a reactor trip. Between approximately 10 percent I power (Permissive P-7) and the power level corresponding to Permissive P-8 (approximately 30% RTP), low flow in any two loops will actuate a reactor trip. A steady state calculation, which assumes an RCS flow consistent with N-1 RCPs operating, is performed to determine a conservative P-8 setpoint. Reactor trip on low flow is blocked below Permissive P-7. The reactor trip on reacter coolant pump undervoltage is provided to protect against conditions which can cause a loss of voltage to all reactor coolant pumps, i.e., loss of offsite power. An RCP undervoltage reactor trip serves as an anticipatory backup to the low reactor coolant loop flow trip. j The undervoltage trip function is blocked below approximately 10 percent power (Permissive P-7). The reactor coolant pump underfrequency trip is provided to trip the reactor for an underfrequency condition resulting from frequency disturbances on the power grid. The RCP underfrequency reactor trip function is blocked below P-7. In addition, the underfrequency function will open all RCP breakers whenever an underfrequency condition occurs (no P-7 or P-8 interlock) to ensure adequate l RCP coastdown. This trip function also serves as an anticipatory backup to the low reactor coolant l loop flow trip. 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 from any pump will actuate a reactor trip, and between P-7 and P-8, a breaker open signal from any two pumps will actuate a reactor trip. Reactor ; trip on reactor coolant pump breakers open is blocked below Permissive P-7. m:u2sunonisec6a wptib-012997 6-77 1

6.2.5.2 Input Parameters and Assumptions This accident is analyzed using the Revised Thermal Design Procedure (Reference 1). Initial core O power, reactor coolant temperature, and pressure are assumed to be at their nominal values consistent with steady-state, full-power operation. Uncenainties 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 (+7 pcm/*F) is assumed since this results in the maximum core power and hot spot heat flux during the initial pan of the transient when the minimum DNBR is reached. Normal reactor contml systems and engineered safety systems (e.g., Safety Injection) 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. 6.2.5.3 Description of Analysis A partial loss of flow involving the loss of one reactor coolant pump with three loops in operation was analyzed, and an evaluation was subsequently performed to confirm that the conclusions in the FSAR remain valid for the plant uprate. The transient was analyzed using three digital computer codes. First, the LOFTRAN code (Reference 2) was used to calculate the loop and core flow transients, the nuclear power transient, and the primary system pressure and temperature transients. His code simulates a multiloop system, neutron kinetics, the pressurizer, pressurizer relief and safety valves, pressurizer spray, the steam generators, 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. His momentum balance is combined with the continuity equation, a pump momentum balance, and the as-built pump characteristics, and is based on conservative system pressure loss estimates. The FACTRAN code (Reference 3) was then used to calculate the heat flux transient based on the nuclear power and flow from LOFTRAN. Finally, the THINC code (References 4 and 5) was used to calculate the DNBR during the transient based on the heat flux from FACTRAN and the flow from LOFTRAN The DNBR results are based on the minimum of the typical and thimble cells. 6.2.5.4 Acceptance Criteria A panial loss of forced reactor coolant flow incident is classified by the American Nuclear Society (ANS) as a Condition II event. The immediate effect from a panial loss of forced reactor coolant flow is a rapid increase in the reactor coolant temperature and subsequent increase in reactor coolant system (RCS) pressure. The following three items summarize the criteria associated with this event. m:\3254w.nonisec6ampf:Ib-012997 6-78

De 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 their respective design pressures.
De peak linear heat generation rate should not exceed a value which would cause fuel centerline melt.

6.2.5.5 Results The partial loss of forced reactor coolant flow event is the least DNB-limiting transient among all of the loss of flow cases. Reactor trip for the partial loss of flow case occurs on a loop low flow signal. He THINC-IV (Reference 5) analysis confirms that the minimum DNBR is greater than the safety analysis limit value. Fuel clad damage criteria are not challenged in the partial loss of forced reactor coolant flow event since the DNB criterion is met. l De analysis of the partial loss of flow event also demonstrates that the peak Reactor Coolant System and Main Steam System pressures are well below their respective limits. 6.2.5.6 Conclusions The analysis and evaluation performed at uprated conditions demonstrate that for the partial loss of flow incident, the DNBR does not decrease below the safety analysis limit value at any time during the transient; thus, no fuel or clad damage is pied,xd. De peak primary and secondary system pressures remain below their respective limits at all times. All applicable acceptance criteria are therefore. met. The protection features presented in Section 6.2.5.1 provide mitigation for the partial loss of forced reactor coolant flow transient such that the above criteria are satisfied. l I I i m:\3254wmon\sec6a.wpf:Ib-012997 6-79

1 i 6.2.5.7 References

1. Friedland, A. J. and Ray, S.,' Revised Thermal Design Procedure," WCAP-11397-P-A, April 1989.

2. Bumett, T.W.T et al., "LOFTRAN 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 UO2 Fuel Rod," WCAP-7908-A, December 1989.

4. Shefcheck, J., " Application of the THINC Pmgram to PWR Design," WCAP-7359-L, August 1%9.

5. Chelemer, H., Chu, P. T., Hochreiter, L. E., "THINC-IV - An Improved Program for Thermal-Hydraulic Analysis of Rod Bundle Cores," WCAP-7956, Febmary 1989.

O O mms 4w.non\wc6a.wpt;iwi2997 6-80

I 3

I i 6.2.6 Startup of an Inactive Reactor Coolant Loop ~ i 6.2.6.1 Identification of Causes and Accident Description i l 4 j If the plant were to operate with one pump out of service, there would be reverse flow through the l 3 inactive loop due to the pressure difference across the reactor vessel. The cold leg temperature in an j ! inactive loop is identical to the cold leg temperature of the active loops (the reactor core inlet 1 temperature). If the reactor is operated at power with an inactive loop, and assuming the secondary

side of the steam generator in the inactive loop is not isolated, there is a temperature drop across the steam generator in the inactive loop. With the reverse flow, the hot leg temperature of the inactive 3 loop is lower than the reactor core inlet temperature.

) } Starting an idle reactor coolant penp without first bringing the inactive loop hot leg temperature close j to the core inlet temperature would result in the injection of cold water into the core, which would l cause a reactivity excursion and subsequent power increase due to the moderator density reactivity ! feedback effect. l Based on the expected frequency of occurrence, the Startup of an Inactive Loop event is classified as a 3 Condition II event (an incident of moderate frequency as defined by the American Nuclear Society l Nuclear Safety Criteria for the Design of Stationary PWR Plants). i

6.2.6.2 Description of Evaluation 1

Following the startup of the inactive reactor coolant pump, the flow in the inactive loop will accelerate j to full flow in the forward direction over a period of several seconds. Since the Technical j Specifications require all reactor coolant pumps to be operating while in Modes I and 2, the nmximum j initial core power level for the Startup of an Inactive Loop transient is approximately 0 MWt. Under l j these conditions, there can be no significant reactivity insertion because the RCS is initially at a nearly I i uniform temperature. Furthermore, the reactor will initially be suberitical by the Technical i Specification requirement. Thus, there will be no increase in core power, and no automatic or manual protective action is required. 6.2.6.3 Conclusions I The Startup of an Inactive Reactor Coolant Loop event was considered in the original design basis for ! the Farley Nuclear Plant when potential operation with a loop out of service (i.e., N-1 loop operation) ' f

was considered. However, subsequent to initial plant startup, N-1 loop operation was not pursued. l l.

Plant operation at power with a loop out of service is precluded by the current Technical l j Specifications which require that all three reactor coolant pumps be operating. Therefore, since at i } power initial conditions associated with N-1 loop operation are prohibited, no analysis is required to i show that the minimum DNBR limit is satisfied for this event. i 4 mA3254w.non\sec6a.wpf:lb-012997 6-81 l 4

6.2.7 Loss of External Electrical Load and/or Turbine Trip 6.2.7.1 Identification of Causes and Accident Description 9 A major load loss on the plant can result from either a loss of extemal electrical load or from a turbine trip. A loss of extemal electrical load may result from an abnormal variation in network frequency or other adverse network operating condition. For either case, offsite power is available for the continued operation of plant components such as the reactor coolant pumps. The case of loss of all non-emergency ac power is presented in Section 6.2.9. For a loss of extemal electrical load without subsequent turbine trip, no direct reactor trip signal would be 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 genemtor water level control, and steam dumps). The automatic steam dump system, with 40% dump capacity to the condenser, together with the rod control system, is able to accommodate 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 trip above the P-9 serpoint (nominally 50%), the reactor would be tripped directly from a signal derived from the turbine autostop low oil pressure (a two out of three signal) or closure of the throttle valves (a four out of four signal). Reactor coolant temperatures and pressure do not significantly increase if the steam dump system and pressurizer pressure control system are 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 pressurizer pressure signal, the high pressurizer water level signal or the overtemperature 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-side 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 overpressure for all load losses without assuming the operation of the steam dump , system, pressurizer spray, pressurizer power-operated relief valves, automatic rod control, or the direct reactor trip on turbine trip. The pressurizer safety valve capacity is sized based on a complete loss of heat sink with the plant initially operating at the maximum calculated turbine load along with operation of the steam generator safety valves. The pressurizer and steam generator safety valves are then able to maintain the RCS and Main Steam System pressures within 110% of the corresponding design pressure without a direct reactor trip on turbine trip. The Farley Units 1 and 2 Reactor Trip System (described in FSAR Chapter 7) 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 (i.e., steam dumps). m:\3254 w .non\sec6a.wpf: I b-ol 2997 6-82

6.2.7.2 Input Parameters and Assumptions Two cases are analyzed for a total loss of load from full power conditions: a) minimum reactivity feedback with pressure control; and b) minimum reactivity feedback without pressure control. 'Ihe primary concem for the case analyzed with pressure control is minimum DNBR: the primary concem for the case analyzed without pressure control is maintaining reactor coolant and main steam system pressures below 110% of the design pressure. The major assumptions used in the analyses are summarized in the following. Initial Operatine Conditions The case with pressure control is ar'.yzed using the Revised Thermal Design Procedure. Initial core , power, reactor coolant temperature, and pressure are assumed to be at their nominal values consistent v ith steady-state full power operation. Minimum Measured Flow is modeleu. Uncertainties in initial conditions are included in the departure from nucleate boiling ratio (DNBR) limit as described in Reference 1. He case without pressure control is analyzed using the Standard Thermal Design Procedure. Initial uncertainties on core power, reactor coolant temperature, and pressum are applied in the conservative g direction to oHain the initial pet conditions for the beginning of the transient. The analysis models N Thermal Design Flow. Reactivity Coefficients l The total loss of load transient is analyzed with minimum reactivity feedback (BOL). The case with pressure control assumes a +7 pcm/*F moderator temperature coefficient, and the case without pressure control assumes a zero moderator temperature coefficient at full power. Both cases assume the least. negative Doppler coefficient. Reactor Control From the standpoint of the maximum pressures attained, it is conservative to assume that the reactor is in manual rod control. If the 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 ne loss of load event is analyzed both with and without pressurizer pressure control. The pressurizer PORVs and sprays are assumed operable for the case with pressure control. The case with pressure [ control minimizes the increase in primary pressure which is conservative for the DNBR criterion. The case without pressure control maximizes the pressure increase which is conservative for the RCS m:\3254 w.non\sec6a.wpf. l b-012997 6-83

overpressurization criterion. In all cases, the steam generator and pressurizer safety valves are operable. The pressurizer safety valves are modelled including the effects of the pressurizer safety valve loop I seals using the WOG methodology (Reference 3). A total pressurizer safety valve setpoint tolerance of i 11% is supported in the analysis. For the case which is analyzed primarily for DNBR (pressurizer pressure control case), the negative tolerance is applied to conservatively reduce the setpoint. For the . case which is analyzed primarily for peak RCS pressure, the positive tolerance is applied to f conservatively increase the setpoint pressure. In the peak RCS pressure case, the pressurizer safety valve includes a total 1.9% uncertainty (0.9% set pressure shift due to the loop seals and a 1% set pressure tolerance) over the nominal setpoint of 2500 psia. Additionally, no steam flow is assumed until the water in the valve loop seals is purged (a 1.6 second water purge time is assumed in the peak pressure case). 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, eventually auxiliary feedwater flow would be initiated and a stabilized plant condition would be reached. Reactor Trio Only the overtemperature AT, high pressurizer pressure, and low-low steam generator water level reactor trips are assumed operable for the purposes of this analysis. A reduced response time for the high pressurizer pressure trip function from 2 seconds to 1 second is modeled in the analysis. No credit is taken for a reactor trip on high pressurizer level or the direct reactor trip on turbine trip. Steam Release No credit is taken for the operation of the steam dump system or steam generator atmospheric relief valves. This assuu Mion maxirpizes secondary pressure. The main steam safety valve model includes an allowance for dety valve sapoint tolerance and accumulation. 6.2.7.3 Description of Analyses For the Loss of External Electrical Load / Turbine Trip Event, the behavior of the unit is analyzed for a complete loss of steam load from full power without a direct reactor trip. This assumption is made to show the adequacy of the pressure-relieving devices and to demonstrate core protection margins, by delaying reactor trip until conditions in the RCS result in a trip due to other signals. Thus, the 1 analysis assumes a worst-case transient. In addition, no credit is taken for steam dump. Main feedwater flow is terminated at the time of turbine trip, with no credit taken for auxiliary feedwater 1 (except for long-term recovery) to mitigate the consequences of the transient. 1 mA3254w.non\sec6a wpf.Ib-012997 6-84

1 l I 1 A detailed analysis using the LOFTRAN (Reference 2) computer code is performed to determine the plant transient conditions following a total loss of load. He 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. 6.2.7.4 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 follow s. He 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. He peak linear heat generation rate should not exceed a value which would cause fuel centerline melt. 6.2.7.5 Results The calculated sequer cc of events for the two Loss of Extemal Electrical Load / Turbine Trip cases are presented in Table 6.2.7-1. Case 1: Figures 6.2.7-1 through 6.2.7-3 show the transient response for the total loss of load event under BOL ! conditions, including a +7 pcm /*F moderator temperature coefficient, with pressure control. De reactor is tripped on high pressurizer pressure. De neutron flux increases until the reactor is tripped, and although the DNBR value decreases below the initial value, it remains well abo've the safety l analysis limit throughout the entire transient. The pressurizer power-operated relief valves and sprays l 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. The maximum peak linear heat generation does not exceed that which would cause fuel centerline melt.

Case 2: 1 Figures 6.2.7-4 through 6.2.7-6 show the transient response for the total loss of load event under BOL conditions, including a zero moderator temperature coefficient, without pressure control. The reactor is tripped on high pressurizer pressure. The neutron flux remains essentially constant at full power ; m:\3254w.non\sec6awpf.lb-012997 6-85 )

until the reactor is tripped, and the DNBR remains above the initial value for the duration of the transient. The pressurizer safety valves are actuated and 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. The maximum peak linear heat generation does not exceed that which would cause fuel centerline melt. 6.2.7.6 Conclusions The results of this analysis show that the plant design is such that a total loss of extemal electrical load without a direct reactor trip presents no hazard to the integrity of the RCS or the main steam system. All of the applicable acceptance criteria are met. The minimum DNBR for each case is greater than the safety analysis limit value. The peak primary and secondary system pressures remain below 110% of design at all times. The protection features presented in Section 6.2.7.2 provide mitigation of the Loss of Extemal Electrical Loadfrurbine Trip transient such that the above criteria are satisfied. 6.2.7.7 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.

O mA3254w.non\sec6a wpf:1b-012997 6-86

    . . - _ - _ _ . - - . .. -                            - . _ . _ _ -       -      . . - = . . ..-_ . . . . ..__. __. - - . . .   . . _ . .

M 4

TABLE 6.2.7-1 j SEQUENCE OF EVENTS LOSS OF LOAD /rURBINE TRIP EVENT Case Event Time (Sec) 4

1. With pressurizer pressure Loss of Electrical Loadfrurbine Trip 0.0 i control (minimum reactivity I

feedback) High Pressurizer Pressure Reactor trip Setpoint 9.9 reached i Peak pressurizer pressure occurs 11.1 Rods begin to drop 11.9 i Minimum DNBR occurs 13.6

2. Without pressurizer pressure Loss of Electrical Load / Turbine Trip 0.0 control (minimum reactivity feedback) High Pressurizer Pressure Setpoint reached 6.2 Rods begin to drop 7.2 Peak pressurizer pressure occurs 9.1 Minimum DNBR occurs l

                *Never falls below initial value                                                                                                   l l

m:\3254w.non\sec6a.wpf:Ib-012997 6-87

1.4 ,

                          .                                                                      1 12-        -

l 1- _ 8- - 8 . 6- - E : 4- -

                         -                                                                       1 2-    -
                         ~

0 l l l l O 20 40 60 80 160 11!0 TIME (s) 2800

                                                                                                 \
                         -                                                                       1 2600-       -

2400--

2200- - 2000 - - 1800 l l l l U 20 40 60 80 100 11!0 TIME (s) Figure 6.2.7-1 Total Loss of External Electrical Load with Pressure Control Nuclear Power and Pressurizer Pressure versus Time m:\3254w.noo\sec6a.wpf: l b-012997 6-88

I (3 GI 6 5- - 4- - 1 E 3- -

j . . . . . . . . . . . . . . . . . . . . . . . 0 2'0 4'O 6'O 8'O 100 120 TIME (s) O 570 - 560- - 550 - C - 540 - El : 530 - - 520 - 510 l l l O 20 4'0 60 80 100 120 TlWE (s) Figure 6.2.7-2 Total Loss of External Electrical Load with Pressure Control l DNBR and Steam Temperature versus Time ! l l m:\3254w.non\sec6a wpf:Ib-012997 6-89 , I

O 1800--- . 1600 - - 1400 - - g 1200 -,- ] 1000 - - 800 -

600 l l O 2c 40 60 80 100 120 TIME (s) 700 W - 650-_ l _

hC - 1 g' 600 - - l v 550 --

500 l ' 4- A l l O 20 40 60 80 100 120 i TlWE (s) Figure 6.2.7-3 Total Loss of External Electrical Load with Pressure Control Pressurizer Water Volume and Vessel Average Temperature versus Time m:\3254 w.non\sec6a.wpf: I b-012997 6-90

i i i O i 1.4 .

1. 2 _-

1- - 8- - " 8 _ 6- - l

                         .4-.
                          '~.

E C '''iii...... . i 0 i 0 2'O 4'O 6'O 8'O 160 120 , TWE (s) O 2800 i I 2600 - - 2400 - - n . 2200 - Ik 2000 - 1

                                    ' ' '''''''''''''iii 1800 0                2'0          4'O        6'O                  8'O        160       120 TWE (s)                                               !

O , ( Figure 6.2.7-4 Total Loss of External Electrical Load without Pressure Control Nuclear Power and Pressurizer Pressure versus Time ! m:\3254w.non\sec6a.wpf:lt412997 6 91

I O 6 5- - 4 . 3- - 2- _ j i i i e i i e i i e i e i i . . i i i i i i O 2'O 4'O 6'O 8'O 160 120 TIME (s) 570 . O: <

                                                                                                             \
                       .                                                                                     l 560 -    -

550- . C 8 540- -

530 -: . 520 -

510 l l l 0 20 40 6'O 80 160 120 j TlWE (s) ;

Figure 6.2.7 5 Total Loss of External Electrical Load without Pressure Control DNBR and Steam Temperature versus Time m13254wmon\sec6a wpf.1t>.012997 6-92 l I _l

  . . _ - .      - - . .                -       . - -       .              . _ . - . . = . - - -        . . . . . - - - - - - - . . . . - - - - - .

i l i i; i ! ! 180F - i i 1600- - - t i 1400- - 4 i - l t E[ 1200- - l l ' 1000 - 1 l 800- - 800 ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' il 2'O 4'O 8'O 8'O 160 120 i TME (e) 700

a i

!                            650-  -

r . l 800- - 550 - - 500 l l ll ' 2l0 4l0 80 80 160 120 TWE (e) Figure 6.2.7-6 Total Loss of External Electrical Load without Pressure Control Pressurizer Water Volume and Vessel Average Temperature versus Time m:u2m.nonuwpr:15012997 6-93

6.2.8 Loss of Normal Feedwater 6.2.8.1 Identification 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 altemative 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. The loss of normal feedwater that occurs as a result of the loss of ac power is discussed in Section 6.2.9. 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 relief valves are automatically opened to the atmosphere. Steam dump to the condenser is assumed not to be available. If the atmospheric relief 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 relief valves (or the self-actuated safety valves, if the atmospheric relief 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. Two motor-driven auxiliary feedwater (AFW) pumps that are started on:

1. L iw-low water level in any steam generator;

2. Any safety injection signal;

3. Loss of offsite power (automatic transfer to diesel generators);

4. Trip of both unit main feedwater pumps; and

5. Manual actuation.

m:\3254w.non\sec6b wpf.Ib 012997 6-94

c. One turbine-driven AFW pump that is staned on:

1. Low-low water level in any two steam generators;

2. Undervoltage on any two of three reactor coolant pump buses; and

3. Manual actuation.

The 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 secondary side, water relief from the pressurizer, and uncovery of the reactor core. 6.2.8.2 Input Parameters and Assumptions ne following assumptions are made in the analysis.

a. The plant is initially operating at 102% of the NSSS power (2785 MWt), which includes a maximum reactor coolant pump heat of 15.0 MWt. The RCPs are assumed to continuously operate throughout the transient providing a constant reactor coolant volumetric flow equal to the Thermal Design Flow value. Although not assumed in the analysis, the reactor coolant pumps could be manually tripped at some later time in the transient to reduce the heat addition to the RCS caused by the operation of the pumps.

b. The initial reactor vessel average coolant temperature is conservatively assumed to be 7.0*F higher than the nominal value (high end of the T,, window) to account for the temperature uncertainty on nominal temperature and also includes a -1.0*F bias due to cold leg streaming.

De initial pressurizer pressure uncertainty is 50 psi and is conservatively subtracted from the nominal pressure value.

c. Reactor trip occurs on steam generator low-low water level at 16.0% of narrow range span.

d. It is assumed that two motor-driven AFW pumps am available to supply a minimum of 350 gpm to two steam generators,60 seconds following a low-low steam generator water level signal. (he worst single failure, which is modeled in the analysis, is the loss of the turbine-driven AFW pump.) l

e. He pressurizer sprays and PORVs are assumed operable. His maximizes the pressurizer water volume. If these control systems did not operate, the pressurizer safety valves would prevent the RCS pressure from exceeding the RCS design pressure limit during this transient.

f. Secondary system steam relief is achieved through the self-actuated main steam safety valves.

Note that steam relief will, in fact, be through the steam generator atmospheric relief valves or condenser dump valves for most cases of loss of normal feedwater. However, since these valves and controls are not safety grade, they have been assumed unavailable. m:\3254w.non\sec6b.wpf:Ib-012997 6-95

g. T'ae main steam saferv valves are modeled assuming a 3% tolerance and a conservative ,

accumulation model (3% accumulation for banks 1,2, & 3,2% accumulation for bank 4, and 10 psi accumulation for bank 5, respectively, beginning with valve with the lowest setpoint).

h. Core residual heat generation is based on the 1979 version of ANS 5.1 (Reference 2).

ANSI /ANS-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.

i. Steam generator tube plugging levels from 0% to 20% were considered.

j. The AFW system is actuated by a low-low steam generator water level signal. AFW flow begins following a 60 second delay. The AFW line purge volume is conservatively assumed to be the maximum value for either unit of 140 ft' and the initial AFW enthalpy is assumed to be 80.83 Btu /lbm.

6.2.8.3 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. l l l l 6.2.8.4 Acceptance Criteria Based on its frequency of occurrence, the loss of normal feedwater accident is considered a Condition Il event as defined by the American Nuclear Society. The followi.,g items summarize the acceptance criteria associated with this event:

The critical heat flux shall not be exceeded. This is 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.

With respect to DNB, the loss of normal feedwater accident is bounded by the loss of load accident reported in Section 6.2.7. For ease in interpreting the transient results following a loss of normal feedwater, the following restrictive acceptance criterion is used: the pressurizer shall not become water solid. mA3254w.non\ :c6b wpf;Ib412997 6-96

 ,     6.2.8.5 Results The calculated sequence of events for this accident is listed in Table 6.2.8-1. Figures 6.2.8-1 through 6.2.8-4 present transient plots of the significant plant parameters following a loss of normal feedwater with the assumptions listed in Section 6.2.8.2.

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 continues to dissipate the stored and generated heat. One minute following the initiation of the low-low level trip, the motor-driven AFW pumps automatically start, consequently reducing the rate at which the steam generator water level is decreasing. The capacity of the motor-driven AFW pumps enables sufficient heat transfer from the two steam generators receiving auxiliary feedwater to dissipate the core residual heat without the pressurizer reaching a water solid condition (as shown in Figure 6.2.8-1). This precludes any water relief through the RCS pressurizer relief or safety valves. l 6.2.8.6 Conclusions I With respect to DNB, the loss of normal feedwater accident is bounded by the loss of load accident

   . which demonstrates that the minimum DNBR is greater than the safety analysis limit value.

The results of the analysis show that pressivizer does not reach a water solid condition. Therefore, the loss of normal feedwater event does not adversely affect the core, the RCS, or the main steam system. 6.2.8.7 References

1. Burnett, T. W. T., et al, "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary),

WCAP-7907-A (Non-Proprietary), April 1984.

2. ANSI /ANS-5.1 - 1979, "American National Standard for Decay Heat Power in Light Water Reactors," August 1979.

ms254 .nonewpr:it4:2997 6-97

l i l TABLE 6.2.81 TIME SEQUENCE OF EVENTS FOR LOSS OF NORMAL FEEDWATER FLOW Time Event (seconds) Main feedwater flow stops 10 Low-low steam generator water level reactor trip setpoint reached 38.3 Rods begin to drop 60.3 i Flow from two moter-driven AFW pumps is initiated 118.3 Feedwater lines an: purged and cold AFW is delivered to two Steam Generators 477.4 Peak water level in pressurizer occurs 4080.0 I Core decay and RCP heat decreases to AFW heat removal capacity - 4248.0 9 O m:u254w.nonw6b wpr:its012997 6-98

t

O 2800 -

2600 - - l 2400 - - i e 2200 - i 4 2000 -- - i 1800- -

;                                          :                                                                                       L 1600           '''l 18                1$                      Id                         id                      1d TlWE(s)

O 2000 w _ 3 1500 - - g . g . Em -

                    *g 1000 -              -

I 500 -_ .

0 , 18 1$ Id 1d id TIME (s) O Figure 6.2.84 Loss of Normal Feedwater, Pressurizer Pressure and Level versus Time m:\3254w.non\sec6b.wpf:Ib412997 6-99

-- ._. . _ . - . . ._. . _ . _- _ _ _ ._. . = . . -. O 1.4 . 12- _ 1 8-- Ei . 6- . 4- . 2-_ - b ! 0 o '1 't 's 4 10 10 10 10 10 TlWE (s) : 1 14 .

1. 2 - .

1-_ - 1

                      .8-    -

b 6- - b )

                      .2-     -
                                                    .          i e i ieiisi              ,                            iii i i            ise                                 ,              ..

g 18 1$ 18 18 18 TlWE (s) 9 Figure 6.2.8 2 Loss of Normal Feedwater, Nuclear Power and Core Heat Flux versus Time 1 m:\3254w.non\sec6b.wpf.It412997 6-100

(

700 ,

650 -: MN 1 Ic

                             -          l                        -                                                  1
             '                                                     I 600-:

[ : me \ v 550-- l f ______

500 'l . 0 1 2 3 4 . 10 10 10 10 10 4 VME (s) 4 700 650-: MS l

e - -

I ! 600 -: h[' : . COLD LED y

4

    }    a g

v 550 l 9 :

l , 500 '"l '; l 18 id Id 18 id VME (s) 700 Y 5 650-: EE e : ___I_______ - I ! 600 -: i h[' : com tro \ nv 550--

I _f - -

s

500 0 1 2 3 4

1 10 10 10 10 10

;                                                                  BME(s)
 . O Figure 6.2.8 3 Loss of Normal Feedwater, RCS Loop Temperatures versus Time mA3254w.non\sec6b.wpf:Ib-012997                        6-101

O l 2000 l

1

                          -                                                                                                   l 1500-      -
                          -                                                                                                  \

{1000-in - 500 - - i

                          -                                                                                                  \
                                '   ' ' ' ' ' ' "      ' ' ' ' "             ' ' ' ' ' ' ' "         ' ' ' ' ' ' ' '      l 0                          !                        I                     i                            1

< 0 1 2 3 4 10 10 10 10 10 TIME (s) g STEW GENERATORS RECDANG MDOLWW FEDWATER W

- - - STEM GENERATOR NOT REEEMNG MDQUARf FEIDWATER 140000 120000 -3

! 100000- f m 80000 - b b 60000 - - d 40000 -

      @                     :                                                   's 20000-[                                                                 's     --- _ _ - .

I I I I tlitt I iiI Itill I e I I Itill i I I I I 191 0 I I i 18 10 Id 18 Id TlWE (s) d W Figure 6.2.8-4 Loss of Normal Feedwater, Steam Generator Pressure and Mass versus Time 9 mA3254w.non\sec6b wpf.1b-012997 6-]O2

6.2.9 Loss of Non-emergency ac Power to the Plant Auxiliaries 6.2.9.1 Identification of Causes and Accident Description A complete loss of non-emergency ac power will result in a loss of power to the plant auxiliaries, i.e., the reactor coolant pumps, condensate pumps, etc. The loss of power may be caused by a complete loss of the offsite grid accompanied by a turbine generator trip or by a loss of the onsite ac distribution system. De events following a loss of ac power with turbine and reactor trip are described in the sequence listed below,

a. De emergency diesel generators will start on a loss of voltage on the plant emergency buses and begin to supply plant vital loads,

b. Plant vital instruments are supplied by emergency power sources.

c. As the steam system pressure rises following the trip, the steam system power-operated relief valves are automatically opened to the atmosphere. Steam dump to the condenser is assumed not to be available. If the steam generator power-operated relief 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,

d. As the no-load temperature is approached, the steam system power-operated relief valves (or the self actuated safety valves, if the power-operated relief 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 a loss of all ac power,

a. Reactor trip on low-low water level in any steam generator.

b. Two motor-driven auxiliary feedwater pumps that are started on

1. Low low level in any steam generator

2. Trip of both main feedwater pumps

3. Any safety injection signal

4. Loss of offsite power (automatic transfer to diesel generators); and

5. Manual actuation.

c. One turbine-driven auxiliary feedwater pump that is started on:

1. Low-low level i.n any two steam generators

2. Undervoltage on any two reactor coolant pump buses; and l

3. Manual actuation.

l The auxiliary feedwater (AFW) system is initiated as discussed in the loss of normal feedwater analysis (Section 6.2.8). The turbine-driven pump utilizes steam from the secondary system and

i mA3254w.nonwe6b.wpf;tb 012997 6-103 l

exhausts it to the atmosphere. The motor-driven AFW pumps are supplied by power from the diesel generators. The AFW pumps are normally aligned to take suction from the condensate storage tank for delivery to the steam generators. A backup source of water for the pumps is provided by the safety-related portion of the service water system (see FSAR Section 6.5). The Reactor Protection System and AFW system design ensure that reactor trip and AFW flow will occur following any loss of normal feedwater. 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. Heat removal is maintained by natural circulation in the RCS loops. Following the RCP coastdown, the natural circulation capability of the RCS will remove decay heat from the core, aided by the AFW flow in the secondary system. Demonstrating that acceptable results can be obtained for this event proves that the resultant r.atural circulation ficw in the RCS is adequate to remove decay heat from the core. The first few seconds after a loss of ac power to the RCPs closely resembles the analysis of the complete loss of flow event (Section 6.2.17) in that the RCS would experience a rapid flow reduction transient. This aspect of the loss of ac power event is bounded by the analysis performed for the complete loss of flow event which demonstrates that the DNB design basis is met. The analysis of the loss of ac power event demonstrates that RCS natural circulation and the AFW system are capable of removing the stored and residual heat, and consequently will prevent RCS or main steam system ) overpressurization and core uncovery. The plant would therefore be able to return to a safety condition. 6.2.9.2 Input Parameters and Assumptions l The major rsumptions used in this analysis are identical to those used in the loss of normal feedwater ana:ysis (Section 6.2.8) 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 I 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. l l

l

c. A heat transfer coefficient in the steam generators associated with RCS natural circulation is l assumed following the RCP coastdown.

d. The RCS flow coastdown is based on a momentum balance around each reactor coolant loop and across the reactor core. This momentum balance is combined with the continuity mA3254w.nonwec6b mpf:1b-012997 6-104

equation, a pump momentum balance, the as-built pump characteristics and conservative estimates of system pressure losses.

e. De worst single failure assumed to occur is in the AFW system. This results in the availability of two motor-driven AFW pumps supplying minimum flow to two steam generators,60 seconds following a low-low steam generator water level signal.

6.2.9.3 Description of Analysis A detailed analysis using the LOFTRAN (Reference 1) computer code is performed in order to determine the plant transient following a loss of all ac power. The code describes 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, and reactor coolant average temperature. 6.2.9.4 Acceptance Criteria Based on its frequency of occurrence, the loss of non-emergency ac power accident is considered a Condition II event as defined by the American Nuclear Society. he following items summarize the acceptance criteria associated with this event: The critical heat flux shall not be exceeded This is demonstrated by precluding Departure from Nucleate Boiling (DNB). Pressure in the reactor coolant and main steam systems :, hall be maintamed below 110% of the design pressures. With respect to DNB, the loss of non-emergency ac power accident is bounded by the loss of flow accident reported in Section 6.2.17. For case in interpreting the transient results following a loss of normal feedwater, the following restrictive acceptance criterion has been used: the pressurizer shall not become water solid. 6.2.9.5 Results Figures 6.2.9-1 through 6.2.9-4 present transient plots of plant parameters following a loss of non-emergency ac power with the assumptions listed in Section 6.2.9.2. The calculated sequence of events for this accident is listed in Table 6.2.9-1. 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 closely resembles the complete loss of flow incident, where core damage due to rapidly increasing core temperatures is prevented by the reactor trip, which, for a m:\3254w.non\sec6b.wpf. l b-O t 2997 6-105

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 l coolant and main steam systems. The LOFTRAN 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 coastdown. i Figure 6.2.9-1 illustrates that the pressurizer never reaches a water solid condition. Hence, no water relief from the pressurizer occurs. 6.2.9.6 Conclusions With respect to DNB, the loss of non-emergency ac power event is bounded by the complete loss of flow event which demonstrated that the minimum DNBR is greater than the safety analysis limit value. The results of the analysis show that pressurizer does not reach a water solid condition. Therefore, the loss of offsite power event does not adversely affect the core, the RCS, or the main steam system. 6.2.9.7 Reference

1. Burnett, T. W. T., et al, "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary),

WCAP-7907-A (Non-proprietary), April 1984. I l 9 m:\3254wson\sec6b.wpf.Itw012997 6-106 i

, . _ . . . _ _ . . . _ . _ - - . - .._ _ . - _ . . _ _ . . _ _ _ _ . ~ . - - _. _ _ _ _ . _ _ i a l 4 i

                                                                                                        ^                               ~~

TABLE-'6.2.9 1 4

i TIME SEQUENCE OF EVENTS FOR LOSS OF NON EMERGENCY AC POWER l Event Time (seconds) l Main feedwater flow stops 10 Low-low steam generator water level reactor trip setpoint reached 58.3 Rods begin to drop 60.3 Reactor coolant pumps begin to coastdown 62.3 Flow from two motor-driven AFW pumps is initiated 118.3 Feedwater lines are purged and cold AFW is delivered to twe Steam Generators 477.4 Peak water level in pressurizer occurs (post reactor trip) 1466.0 Core decay heat decreases to AFW heat removal capacity -1610.0 i l J l m:u2hnonw6b.wpf.lb-012997 6-107 l i

N

    . ..                    .      . . . .            m    en                *                 ** *     .-    M + * *       * *        - *

1 2800 .

2600 -- . W : l' { 2400 - - 2200 - 2000 - - 1

                          -                                                                                                                   1 1800 --    .

_ 4 4 - 1 1 1600 ''"l "l '"l

                                                                                                    ' ' ' ' ' ' "                             l 0                         1                   2                    3                      4 10                         10                   10                   10                   to

.; TlWE (s) 2000 i w . 1500 - -

l; - m - g 1000 - A

- ~
500 --

0 0 't 'I '3 4 10 10 10 10 to 11ME (s) G Figure 6.2.91 Loss of ac Power to the Plant Auxiliaries, Pressurizer Pressure and Level versus Time mM254w.non\sec6b.wpf.It>.012997 6-108

                                                                                  .                   .- _ _ _ . . _ .          .                   . . .~.. _ _ . _ . - -       _ _ _ . , . . ~ . . . . . .

k 1 l l I .

  .        . . . . .              ..              ..        ..........m                    - -. ....                      .. ..         ~. .             -. .. .-            -. -                        - . - - - - + - - - - ' - -

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=.

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.6--

d i. 4-- i e i 1 i . , 2- - 1 0 b ' ' ' ' " ' ' ' ' ' ' ' " Y ' ' -- " I 5 5 TIME (s) l I 14 l 12-- . 1- -

                                               .8-    -

98 .- 6- .

                                                .4--

2- -

t t t t tI999 9 I I I I I t il i n .. ' ' I90 0 t . 1 18 1$ 1d 1d 1d TIME (e)

Figure 6.2.9 2 Loss of ac Power to the Plant Auxiliaries, Nuclear Power and Core Heat Flux versus Time m:\3254w.non\sec6b.wpf. I b-012997 6-109

I i

  . ~ w. .. . . . .      . . , . . . .   . . _ .        . .    ..      .   . . - - . - . - . . . . - . .          4.. . . . . --.  . _ . . - - . . . .   .m i                      700            _

650 - EN ,

___1_______

                                                                           -                                                                                i c.

1 600 -2 s_ " ~-'~ - [ : coin tm

I f-550 --

500 '"l '"l 4 0 1 2 3 4 10 10 10 10 10 TlWE (s) I d i 700 650 -: NN c : ___I_______ - . I ~~'~ 600 -: s_ " - l BI

on .

550 -- l .f 500 '

                                                 "l                 '"l Id                      Id                       Id                           Id                   Id TIME (s) 4 700 W                        i l                       650 -:             EN I

ei -

                                                                              \                ,___,

M en 600 -- s_- W8 : coin ta n" : I f 550--

500 "l "l '"l e 1 2 3 4 10 10 10 10 10 TlWE (s) 4 Figure 6.2.9-3 Loss of ac Power to the Plant Auxiliaries, RCS Loop Temperatures versus Time m:u254w.nonssec6b wpub-012997 6 110

? 1 2 l , j . l

.. - - .. . .. . . . - . . .- - . - - - . - . . . . . - - - - - - - - - - - - - - - - - - - - - ~ - - - - - - '

2000

i .

1500--

E 1000 -- b - 1 l 2 - l 500- -

I, . . ...... . i i . ..... . . . . ..... .iiii. o i , i ! l i 18 10 Id Id 1d 1 d i a TIME (s) 5v SEAM GENERUDRS RECEMNG AUXUW FIIDWMER j - - - STEAM GEMRUDR NOT RECEMNG AUXUW FEIDWUER 4 140000 .! 120000 -- g - l 3 100000 -3 i m 80000 - - k 60000 -- b !> 40000 - -

                                                    -                                                              s
.                                                                                                                     s s

s 1 20000 -_ s - _ _ _ _ _ . a - ! . . . . . . . . . . . . . . . . .....iii ..iii . O i i i 4 18 1$ Id Id Id j TlWE (s) 4 i i 1 ~ Figure 6.2.9-4 Loss of ac Power to the Plant Auxiliaries, Steam Generator Pressure and Mass versus Time m:u2w.non\iec6b.wpr:Ib.ol2997 6-111 2

6.2.10 Excessive Heat Removal Due To Feedwater System Malfunctions 1

                                                                                                -- - - -     -'          '     * ^ ~

. . . - . . - . . . - . . . . . . . . . - . . . ~ - - - -- 6.2.10.1 Identification of Causes and Accident Description l Reductions in feedwater temperature or excessive feedwater additions are means of increasing core power above full power. Such transients are attenated by the thermal capacity of the RCS and the secondary side of the plant. The overpower /ovenempenture protection functions (neutron high flux, ovenemperature AT, and overpower AT trips) prevent any power increase that could lead to a DNBR 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 ermr. At power, this excess flow causes a greater load demand on the RCS due to increased subcooling in the steam generator. With the plant at no-load conditions, the addition of cold feedwater may cause a decrease in RCS temperature and thus a reactivity insenion due to the effects of the negative moderator temperature coefficient of reactivity. Continuous excessive feedwater addition is prevented by the steam generator high-high water level trip. A second example of excess heat removal is the transient associated with failure of one or more of the low-pressure heaters resulting in an immediate reduction in feedwater temperature. At power, this increased subcooling will create a greater load demand on the RCS. 6.2.10.2 Input Parameters and Assumptions l The reactivity insenion 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 Revised Thermal Design Procedure as described in Reference 1. Therefore, the initial reactor power, pressure, and RCS average temperature are assumed to be at the nominal values. Uncenainties in initial conditions are included in the DNBR limit calculated using the methodology described in Reference 1.

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 184% of nominal full power feedwater flow to one steam generator,

c. For the feedwater control valve accident at zero-load condition, a feedwater valve malfunction occurs that results in an increase in flow to one steam generator from zero to the nominal full-load value for one steam generator. Feedwater temperature is at a conservatively low 32*F.

d. The initial water level in all the steam generators is a conservatively low level.

mA329wmon\sec6c.wpf.It412997 6-112

4 V i i e ! e. No credit is taken for the heat capacity of the RCS and steam generator metal mass in

                                                                                                     '         ~ ~ ~ '         ' ~~      ' ~ ~ ~

j- - - attenuating thc resulting plant ~coold6wn. ~ ' ; l f. The feedwater flow resulting from a fully open control valve is temunated by the steam . ! generator high-high water level signal that closes all feedwater main control and feedwater l control bypass valves, indirectly closes all feedwater pump discharge valves, and trips the main I , feedwater pumps and turbine generator. t.

The reactor protection system features, including Power-Range High Neutron Flux, Overpower AT, j and Turbine Trip on High-High Steam Generator Water Level, are available to provide mitigation of j the feedwater system malfunction transient.

I j Normal reactor control systems and engineered safety systems (efs SI) are not assumed to function. i The reactor protection system may actuate to trip the reactor due to an overpower condition. No j single active failure in any system or component required for mitigation will adversely affect the consequences of this event. I j 6.2.10.3 Description of Analysis 4 j The excessive heat removal due to a feedwater system malfunction transient is analyzed with the LOFTRAN (Reference 2) computer code. This code simulates a multiloop system, neutron kinetics, j the pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and main steam l safety valves. 'Ihe code computes pertinent plant variables including temperatures, pressures, and s

power level.

9 The excessive feedwater flow event assumes an accidental opening of one feedwater control valve with the reactor at both full and zero power conditions with both automatic and manual rod control. Both i the automatic and manual rod control cases assume a conservatively large moderator density coefficient characteristic of EOL conditions. The current FSAR analysis, performed in support of the VANTAGE 5 fuel upgrade, also considered ! the uprated power level (2775 MWt core power). An evaluation of the Feedwater Malfunction analysis, including the effects of revised rod control system parameters, was performed. The current FSAR analysis demonstrated that a feedwater temperature reduction of 60*F was bounded I by the Excessive Load Increase Incident presented in FSAR Section 15.2.11. A feedwater temperature reduction of 65'F due to the loss of one or more low-pressure heaters has also been considered. 6.2.10.4 Acceptance Criteria Based on its frequency of occurrence, the feedwater system malfunction event is considered a Condition II event as defined by the American Nuclear Society. Even though DNB is the primary mu254 aone.wpubol2997 6-113

1 concem in the analysis of the Feedwater Malfunction event, the following 3 items summarize the !

 - criteria associated with this transient.      -   -              -    -

l 1 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 shall be maintained below 110% of the i design pressures.

The peak linear heat generation rate should not exceed a value which would cause fuel l centerline melt. I l

1 6.2.10.5 Results ' l The excessive feedwater flow full-power case (EOL maximum reactivity feedback with automatic rod control) gives the largest reactivity feedback and results in the greatest power increase. A turbine trip, which results in a reactor trip, is actuated when the steam generator water level in the affected 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 function for this event; however, assuming that the rod control system is operable yields a slightly more limiting l transient. I l 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 bypass valves, a trip of the feedwater pumps, and a turbine trip on high-high steam generator water level. In addition, the feedwater discharge isolation valves will automatically close upon receipt of the feedwater pump trip ! signal. 1 Following turbine trip, the reactor will automatically be tripped, either directly due to the turbine trip l or due to one of the reactor trip signals discussed in Section 6.2.7 (Loss of Extemal Electrical Load and/or Turbine Trip). If the reactor was in automatic rod control, the control rods would be inserted at I the maximum rate following the turbine trip, and the resulting transient would not be limiting in terms ! of peak RCS pressure. The effect of conditions associated with the plant uprate, including revised rod control system response ) characteristics were evaluated and concluded that there is no significant impact on the curTc... analysis l presented in the FSAR. Therefore, the conclusions presented in the FSAR remain valid. l The loss of one or more low-pressure heaters causes a reduction in the feedwater temperature which l increases the thermal load on the primary system. The reduction in the feedwater temperature is less than 65"F, resulting in an increase in the heat load on the primary system of less than 10 percent of full power. The increased thermal load due to the low-pressure heater failure would result in a m:u:54w.nonssec6cwf: b-oi2997 6-114 l l

 .- .- .                  - . - _ - - - - -                   . . . ~ - - . -                  ~.. - ..      . ~ . .               . . . . -

1

i i transient very similar (but of reduced magnitude) to the Excessive Load Increase Incident presented in j

         .Section 6.2.11. Thus, the results of this event are bounded by the Excessive Load Increase event.                      -

6.2.10.6 Conclusions 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. . s The decrease in feedwater temperature transient due to the failure of one or more low-pressure heaters is less severe than the excessive load increase event (see Section 6.2.11). Based on the results i presented in Section 6.2.11, the applicable acceptance criteria for the decrease in feedwater temperature event have been met. The protection features presented in Section 6.2.10.2 provide mitigation of the feedwater system malfunction transient such that the above criteria are satisfied. 6.2.10.7 References

1. Friedland, A. J., and Ray, S. " Revised Thermal Design Procedure," WCAP-11397-P-A (Proprietary), WCAP-11397-A (Non-proprietary), April 1989

2. Burnett, T. W. T. et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Non-proprietary)", April 1984 t

m:\3254 w.non\sec6c.wpf. I b-012997 6-115

6.2.11 Excessive Load Increase Incident 6.2.11.1 Identification of Cause and Accident Description An excessive load increase incident is defined as a mpid increase in the steam flow that causes a power mismatc' .etween 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 system 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 6.2.19. i Protection against an excessive load increase accident, if necessary, is provided by the following reactor protection system signals.

=       Overtemperature AT
=       Overpower AT
=       Power range high neutron flux
=       Low pressurizer pressure 6.2.11.2 Input Parameters and Assumptions The analysis includes the following conservative assumptions.
-       This accident is analyzed with the Revised Thermal Design Procedure as described in 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.

mA3254w.nonhec6c.wpf.lb-012997 6-116

          - The evaluation is performed for a step load increase of 10 percent steam flow from 100 -

percent of Rated Thermal Power.

   *-       This event is analyzed in both automatic and manual rod control.

De excessive load increase event is analyzed for both the beginning-of-life (minimum reactivity feedback) and end-of-life (maximum reactivity feedback) conditions. 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. 6.2.11.3 Description of Analysis Historically, four cases are analyzed, and presented in the FSAR, to demonstrate the plant behavior following a 10% step-load increase from rated load. These cases are as follows. Reactor in manual rod control with BOL (minimum moderator) reactivity 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 LOFTRAN computer code (Reference 2) to deternune the plant transient conditions following the excessive load increase. 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. De code computes pertinent plant variables including DNBR, temperatures, pressures, and power level. 1 At BOL, minimum moderator feedback cases, the core has the least-negative moderator temperature coefficient of reactivity and the least-negative Doppler only power coefficient curve; therefore, the least-inherent transient response capability. Since a positive moderator temperature coefficient would provide a transient benefit, a zero moderator temperature coefficient was assumed in the minimum feedback cases. For the EOL maximum moderator feedback cases, the moderator temperature coefficient of reactivity has its most-negative value and the most-negative Doppler only power coefficient curve. This results in the largest amount of reactivity feedback due to changes in coolant 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 assume automatic rod control ale analyzed to ensure that the worst case is presented. The automatic function is not required. The reactor protection system is assumed to be operable; however, reactor trip is not encountered for the cases analyzed. No single active failure in any system or component required for mitigation will adversely affect the consequences of this accident. i m$3254w.nonhec6c.wpf;lb-012997 - 6-117

The current FSAR analysis was performed for the VANTAGE 5 fuel upgrade and assumed an uprated core power level or 2775 MWt. An evaluation of this event was performed. ~ ----- ' 6.2.11.4 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 i 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. The peak linear heat generation rate (expressed in kw/ft) should not exceed a value which would cause fuel centerline melt. 6.2.11.5 Results The evaluation confirms that the DNBR limit is met for this transient. The transient results presented in FSAR Section 15.2.11 provide an accurate representation of this event. 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 6 2.7. 6.2.11.6 Conchisions It has been demonstrated that for an excessive load incirase, the aninimum DNBR during the transient will not go below the safety analysis limit value and the peak linear heat generation does not exceed the limit value; thus ensuring the applicable acceptance criteria for critical heat flux and fuel centerline melt are met. Following the initial load increase, the plant reaches a stabilized condition. In addition, RCS and main steam system pressures do not exceed 110% of design. 6.2.11.7 References

1. Friedland, A. J., and Ray, S., " Revised Thermal Design Procedure", WCAP-11397-P-A, (Proprietary), WCAP-11397-A (Nonproprietary), April 1989

2. Burnett, T. W. T., et al., "LOFFRAN Code Description," WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary), April 1984 mA3254w.non\sec6 cat f .It42997 6-118

i ! 1 I i l ) ! j 6.2.12 Accidental Depressurization of the RCS L_ .. -. , d i NRC review and approval for this event was received as pan of OTAT/OPAT setpoint revisions.' The i details are not included in this report. 1 s 1 i e ( l 4 1 i i i 4 ! 4 i A

i l l ] .i 4 1 } s a 1 i I I 7 ! i i ( l 4 1 l a i t i i i 1 i .1 i . i a 1 l e , 4 i i i 1 a i 4 i i 1 I I 4 1 i 1 1 l i m:\3254w.non\sec6c.wpf:Ib-012997 6.} } 9 i i ! i e->- - - --. , ,,- ,,.v. +, -

1 6.2.13 Accidental Depressurization of the Main Steam System I l 6.2.13.1 Identification of Causes and Accident Description I The most severe core conditions resulting from an accidental depressurization of the main steam system, which is classified as an ANS Condition II event, are associated with an inadvertent opening of a single steam dump, relief, or safety valve. The analysis of the rupture of a main steam pipe, which is classified as an ANS Condition IV event, is discussed in Section 6.2.19. The steam released as a consequence of this accident results in an initial increase in steam flow that decreases during the accident as the steam pressure falls. The energy removal from the RCS causes a reduction of coolant temperature and pressure. In the presence of a negative moderator temperature coefficient, the cooldown results in an insertion of positive reactivity and subsequent reduction of core shutdown margin. The analysis is performed to demonstrate that the following criterion is satisfied: assuming a stuck RCCA and a single failure in the engineered safety features (ESF), the limit DNBR value will be met after reactor trip for a steam release equivalent to the spurious opening, with failure to close, of the largest of any single steam dump, power-operated relief, or safety valve. De following systems provide the necessary mitigation of an accidental depressurization of the main steam system.

a. ECCS safety injection system (SIS) actuation from any of the following:

1. Two-out-of-three low pressurizer pressure signals; and

2. )

High steamline differential pressure. I

b. The overpower reactor trips (neutron flux and AT) and the reactor trip which occurs in conjunction with receipt of the safety injection (SI) signal.

c. Redundant isolation of the main feedwater lines is provided because sustained high feedwater flow would cause additional cooldown. Therefore, a safety injection signal will rapidly close all main feedwater control and bypass control valves, trip the main feedwater pumps, and indirectly close the feedwater isolation valves (2/2 steam generator feedwater pump tripped).

6.2.13.2 Description of Analysis The core response to an accidental depressurization of the main steam line event has been evaluated and shown to be bounded by the core response to a rupture of a main steamline. O mA3254w.non\sec6c.wpf:Ib-012997 6-120

4 l 4 6.2.13.3 Acceptance Criteria

, O)

Based on its frequency of occurrence, the accidental depressurization of a main steamline event is ! 4 considered a Condition II event as defined by the American Nuclear Society. The most pertinent , acceptance criteria associated with this event is that the critical heat flux not be exceeded. This is demonstrated by precluding Departure from Nucleate Boiling (DNB). ] 6.2.13.4 Results The core response to an accidental depressurization of the main steam line event is bounded by the core response of the mpture of a main steamline. The analysis of the main steamline rupture [ presented in Section 6.2.19 demonstrates that analysis limits are met. 6.2.13.5 Conclusion As discussed in Section 6.2.19.6 the analysis for the mpture of a main steamline showed that the DNB design basis was met; therefore, the DNB design basis is met for the accidental depressurization of the main steam system. l i l 5 i s i ? 4 k l I l 1 l l m \3254w.non\sec6c.wpf:Ib-012997 6-121

6.2.14 Inadvertent Operation of the Emergency Core Cooling System (ECCS) During Power Operation 6.2.14.1 Identification of Causes and Accident Description Inadvertent operation of the Emergency Core Cooling System (ECCS) at power could be caused by operator error, test sequence error, or a false electrical actuation signal. An inadvertent manual actuation would start both ECCS trains. A spurious signal initiated after the logic circuitry in one solid-state protection system train for any of the following Engineered Safety Feature (ESF) functions could cause this incident by actuating the ESF equipment associated with the affected train.

a. High containment pressure

b. Low pressurizer pressure

c. High steamline differential pressure

d. Low steamline pressure Following the actuation signa', the suction of the charging pumps diverts from the volume control tank to the refueling water storage tank. Prior to Boron Injection Tank (BIT) removal, the valves isolating the BIT from the charging pumps and the valves isolating the BIT from the injection header automatically open and the normal charging line isolation valves close. The charging pumps force the borated water from the RWST through the pump discharge header, the BIT, the injection line, and into g the cold leg of each loop. The analysis model assumes instantaneous ECCS injection, and thereby, W bounds conditions with or without the BIT. The passive accumulator tank safety injection and low head safety injection system are available. However, they do not provide flow when the reactor coolant system (RCS) is at normal pressure. j l

I A safety injection (SI) signal normally results in a direct reactor trip and a turbine trip. However, any single fault that actuates the ECCS will not necessarily produce a reactor trip. If an SI signal generates a reactor trip, the operator should determine if the signal is spurious. If the SI signal is determined to be spurious, the operator should tertninate SI and maintain the plant in the hot-standby condition as determined by appropriate recovery procedures. If repair of the ESF actuation system j instrumentation is necessary, future plant operation will be in accordance with the Technical i Specifications. If the reactor protection system does not produce an immediate trip as a result of the spurious SI signal, the reactor experiences a negative reactivity excursion due to the injected boron, which causes a decrease in reactor power. The power mismatch causes a drop in T , and consequent coolant shrinkage. The pressurizer pressure and water level decrease. Load decreases due to the effect of reduced steam pressure on load after the turbine governor valves are fully open. If automatic rod control is used, these effects will lessen until the rods have moved out of the core. The transient is eventually terminated by the reactor protection system low pressurizer pressure trip or by manual trip. m:\3254 w.non\sec6c.wpf. l b-012997 6-122

4- :' l i , t- ! i 4 The time to trip is affected by initial operating conditions. These initial conditions include the core burnup history which affects initial boron concentration, rate of change of boren concentration, and

Doppler and moderator coefficients.

J l 6.2.14.2 Input Parameters and Assumptions 1 l 1 Three cases are analyzed for an inadvertent operation of the ECCS from full power conditions: l a) minimum reactivity feedback with T,,, = $77.2 F; b) maximum reactivity feedback with

T,,, = 577.2*F; and c) maximum reactivity feedback with T,,, = 567.2*F. The primary concern for the case analyzed with minimum feedback is minimum DNBR; the primary concem for the cases analyzed j

with maximum feedback is precluding a water-solid pressurizer condition when the pressurizer is at or above the set pressure of the pressurizer safety relief valves (PSRVs). ne major assumptions used in the analyses are summarized in the following. } Initial Operatine Conditions l 4 The DNB case is analyzed using the Revised Thermal Design Procedure (Reference 1). Initial core g power, reactor coolant temperature, and pressure are assumed to be at their nominal values consistent j with steady-state full power operation. Uncenainties in initial conditions are included in the departure i I from nucleate boiling ratio (DNBR) limit as described in Reference 1. l De pressurizer fill cases are analyzed using the Standard Dermal Design Procedure. Both cases are j analyzed at full power; one with conditions corresponding to a nominal T,,, = 567.2*F and the other to j j a nominal T,,, = 577.2*F. Initial condition uncertainties on core power, reactor coolant temperature, j pressurizer pressure, and pressurizer water level are applied in the most conservative direction to obtain the initial plant conditions for the beginning of the transient. Reactivity Coefficients 4 i The inadvertent ECCS event is analyzed with both minimum and maximum reactivity feedback. The , 4 2 DNB case (minimum feedback) assumes a positive moderator temperature coefficient and the least-negative Doppler coefficient. De pressurizer fill (maximum feedback) cases assume a large l l (absolute value) negative moderator temperature coefficient and the most-negative Doppler power j coefficient. I s i I Reactor Control i i i . For the DNB case (trip on low pressurizer pressurc), it is conservative to assume that the reactor is in j manual rod control. If the reactor were in automatic rod control, the control rod banks would move i prior to trip and reduce the severity of the transient. For the pressurizer fill case (trip on SI), the

!                       reactor is assumed to trip at the time of the SI signal. Thus, the reactor control mode is of no 4

3 consequence. . mM254w.non\sec6c.wpf:Ib-012997 6-123

Pressurizer Pressure Control Pressurizer heaters are assumed to be inoperable. This assumption yields a higher rate of pressure O decrease for the DNB case which is conservative. Pressurizer spray is assumed available for each case in order to minimize RCS pressure. PORVs are also assumed operable in the DNB case. PORVs are not assumed as an automatic pressure control function for the pressurizer filling case. Operation of the PORVs results in the pressurizer pressure not reaching the PSRV set pressure (i.e., the event criterion to preclude a water-solid pressurizer condition concurrent with the pressurizer at or above the PSRV set pressure would be automatically met). Manual operation of the PORVs and block valves is assumed with a combined valve stroke time of 40 seconds. Boro, Iniection At the initiation of the event, two charging pumps inject borated water into the cold leg of each loop. The analysis assumes zero injection line purge volume for calet.lational simplicity; thus, the boration transient begins immediately in the analysis. Turbine Load For the DNB case, the turbine load remains constant until the governor drives the govemor valves wide open. After the throttle valve is full open, turbine load decreases as steam pressure drops. In the case of pressurizer filling, the reactor and turbine both trip at the time of SI actuation with the tuttine load dropping to zero simultaneously. Reactor Trio Reactor trip is initiated by a low pressurizer pressure signal for the DNB case. The pressurizer filling case assumes an immediate reactor trip on the initiating SI signal. Decay Heat The decay heat has no impact on the DNB case (i.e., minimum DNBR occurs prior to reactor trip), whereas in the pressurizer filling cases, the availability of decay heat and its expansion effects on the RCS liquid volume has been taken into account. Core residual heat generation is based on the 1979 version of ANS 5.1 (Reference 2). ANSI /ANS 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. Operator Action Time The PSRVs must not be exposed to subcooled liquid discharge as a result of reaching a water solid pressurizer condition. Consequently, PORV availability must be assured by manually opening a block valve to allow the associated PORV to actuate on demand. Per ANSI /ANS-58.8-1984 (Reference 3), m:\32s4wmon\sec6c wpf:ltF012997 6-124

the operator action times for event indication are based on specific time tests. Time test I requires I (_h 5 minutes and time test 2 requires I + n

1 minutes where "n" signifies the number of discrete manipulations required. PORVs would be expected to be available unless they were blocked due to a :

leaking PORV condition. Therefore, any operator action associated with assuring PORV availability consists of manually opening a block valve to allow the associated PORV to actuate on demand. The appropriate time to assume initial operator action is 7 minutes. This consists of 5 minutes to evaluate the incident and decide upon corrective measures plus I minute fixed time delay to receive simple readout information, i.e., status of PORV block valves, and 1 minute to begin the appropriate action. Pressurizer Safety Valves The safety valves are assumed to open at a pressure of 2475 psia which corresponds to a tolerance of

    -l% relative to the set pressure of 2500 psia. The valves are assumed to close at a pressure of 2375 psia which corresponds to a blowdown of 5% below the set pressure of 2500 psia.

l 6.2.14.3 Description of Analyses i A detailed analysis using the LOFIRAN (Peference 4) computer code is performed to determine the plant transient conditions following an Inadver:ent Operation of the ECCS During Power Operation event. 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 l Q,fs system; and computes peninent variables, including the pressurizer pressure, pressurizer water volume, reactor coolant average temperature, DNBR, and steam flow. I 6.2.14.4 Acceptance Criteria l Based on its frequency of occurrence, the Inadvenent Operation of the ECCS at Power accident is considered a Condition II event as defmed by the American Nuclear Society. The criteria are as ( follows:

Pressure in the reactor coolant and main steam systems should be maintained below 110% of y the design values; j f

    .        Fuel cladding integrity shall be maintained by ensuring that the minimum DNBR remains j

above the safety analysis limit value; and, l

An incident of moderate frequency should not generate a more serious plant condition without other faults occurring independently. It is easy to conclude that the third criterion is met if it can be demonstrated that the pressurizer does p not become water-solid in the minimum allcwable operator action time. However, if ECCS flow is b not tenninated before the pressurizer becomes water solid, it is more difficult to demonstrate that this Condition II event does not lead to a more serious plant condition. m:\3254w.non\sec6c.wpf Ib-012997 6-125

ANS St.1/N18.2-1973 (Reference 5), lists Example 15 of a Condition Il event as a " minor reactor coolant system leak which would not prevent orderly reactor shutdown and cooldown assuming makeup is provided by normal makeup systems only." In Reference 5, normal makeup systems is defined as those systems normally used to maintain reactor coolant inventory under respective ] conditions of startup, hot standby, power operation, or cooldown using on-site power. Since the cause of the water relief is the ECCS flow, the magnitude of the leak will be less than or equivalent to that of the ECCS (i.e., operation of the ECCS maintains RCS inventory during the postulated event and I establishes the magnitude of the subject leak). Therefore, the above example of a Condition II event is met provided " orderly reactor shutdown" is also met. To ensure " orderly reactor shutdown" can occur, the RCS pressure boundary must ultimately be isolatable once the source of the ECCS flow is terminated. To ensure the RCS pressure boundary can be isolated, the PSRVs must function as designed and the Power-Operated Relief and/or block valves must be available to the operator (after the minimum allowable operator action time) to provide isolation functions. The capability of the PSRVs to function properly following the discharge of significantly subcooled water through the PSRVs has not been demonstrated and, therefore, is not certain. Hence, for continued conservatism in the safety analysis methodology, it is assumed that PSRVs must not pass water in order to ensure their integrity and continued availability. With one or more PORVs available, the PSRV setpoint will not be reached. Any water discharge from the RCS would be through the PORV(s). Isolation of the RCS following operator action to terminate ECCS flow would then be obtainable via the PORV block valve (s). Therefore, to address the third criterion, the analysis uses the following criterion:

"A water-solid pressurizer condition be precluded when the pressurizer is at or above the set pressule of the PSRVs."

For the potential condition of the plant operating with all the PORVs blocked, either action to terminate the ECCS flow to avec a water-solid condition or to confirm that at least one PORV is unblocked and available for relief prior to reaching a water solid condition must be taken. This addresses any concems regarding subcooled water relief through the plant PSRVs. Should water relief through the pressurizer power-operated relief valves (PORVs) occur, the PORV block valves would be ; available to isolate the RCS, if the PORV fails to close. 6.2.14.5 Results The transient responses for the DNB and pressurizer filling cases are shown in Figures 6.2.14-1 through 6.2.14-9. Table 6.2.14-1 shows the calculated sequence of events. O. l rnA3254w.non\sec6c.wpf its012997 6-126

t 5 a DNB Case: Nuclear power starts decreasing immediately due to boron injection, but steam flow does not decrease until later in the transient when the turbine governor valves are wide open. The mismatch between 4 load and nuclear power causes T,,,, pressurizer water level, and pressurizer pressure to drop. The ( reactor trips and control rods start moving into the core when the pressurizer pressure reaches the pressurizer low pressure trip setpoint. The DNBR increases throughout the transient. lc i Pressurizer Filling Cases:

Reactor trip occurs at event initiation followed by a rapid initial cooldown of the RCS. Coolant { ! contraction results in a short-term reduction in pressurizer pressure and water level. The combination } of the RCS heatup, due to residual RCS heat generation, and ECCS injected flow causes the pressure ! and level transients to rapidly turn around. Pressurizer water level then increases throughout the , transient. At seven minutes, the analysis assumes that the operator takes action to open a PORY (i.e., i opens PORV block valve). A 40.0 second delay is assumed from initial operator action until the time l j one PORV is fully open. At this point in the transient, the operational PORV begins relieving water l l and steam from the pressurizer. His occurs prior to the pressurizer reaching a water solid condition i j for both cases. Also, pressure never rises above the PORV setpoint. Dus the analysis demonstrates j that water relief through the pressurizer safety valves is precluded. 1

6.2.14.6 Conclusions 4

Results of the analysis show that spurious ECCS operation without immediate reactor trip does not l

present any hazard to the integrity of the RCS with respect to DNBR. The minimum DNBR is never I

j less than the initial value. Thus, there should be no cladding damage and no release of fission

products to the RCS. If the reactor does not trip immediately, the low pressurizer pressure reactor trip

! will provide protection. This trips the turbine and prevents excess cooldown, which expedites recovery ! from the incident. i. ! With respect to pressurizer filling, the pressurizer will not reach a water-solid condition prior to the j operator opening a PORV block valve and PORV, thereby maintaining the RCS pressure below that l which would actuate the pressurizer safety valves. l l 6.2.14.7 References I i j 1. Friedland, A. J. and Ray, S.,

Revised Thermal Design Procedure," WCAP-11397-P-A l (Proprietary), April 1989.

! i i

2. ANSI /ANS-5.1-1979, Decay Heat Power in Light Water Reactors," August 29,1979.

j 3. ANSI /ANS-58.8-1984, " Time Response Design Criteria for Nuclear Safety Related Operator Actions." m'0254w.non\sec6c.wpf:Ib-012997 6-127

4. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907 P-A (Proprietary), ;

l WCAP-7907-A (Non-proprietary), April 1984.

5. ANS-51.1/N18.2-1973, " Nuclear Safety Criteria for the Design of Stationary Pressurized Water Reactor Plants."

1 i l l a l l i i i 9 m:\3254w.non\sec6capf;1b-012997 6-]28

TABLE 6.2.141 SEQUENCE OF EVENTS INADVERTENT ECCS AT POWER EVENT Time ! t Case Event (See)

1. DNBR (minimum SI pumps begin injecting borated water 0.0 reactivity feedback, T,,,

           = 577.2'F)

Low pressuriar pressure reactor trip setpoint reached 51.4 Rods begin to drop 53.4 i Minimum DNBR occurs *

2. Pressuriur Fill SI pumps begin injecting borated water, rods begin to 0.0 (maximum reactivity drop feedback, T,,, = $77.2*F)

Operator action to confirm one PORV available 420.0 One PORV is fully open 460.0 3 Parssuriur becomes water solid 462.0 ( 3. Pressuriar Fill SI pumps begin injecting borated water, rods begin to 0.0 (maximum reactivity drop feedback, T,., = 567.2'F) Operator action to confirm one PORV available 420.0 One PORV is fully open 460.0 ; Pressuriur becomes water solid 467.5

 *Never falls below initial value                                                                   I i

l l O nru254w.monssec6c.wpf.lb-012997 6-129

I Ol 12 _ i 1-9 .

                .e-      .

B .s.: _ 1 4- _ 2- _ u o ........ u 160 260 360 460 560 suo TlWE (s) 12 . 1 2 Z 8- . 8 6- - 4-v _ ; 2- -

i 0 O 160 200 360 460 500 600 TIME (s) l Figure 6.2.141 Inadvertent Operation of ECCS at Power DNBR Case, T,,, = 577.2'F O Nuclear Power and Steam Flow versus Time 1 mA3254w.non\sec6c.wpf:Ib-012997 6 130

I i I i 1 j 2800 - 2600 - - 2400 - _ d O , 2200- - 4 j 2000- - i 1 , 17'60 3 - - 1600 _ '''''''''''''''''''''''' 1 l 0 100 260 360 460 560 600 TIME (s) !O 4 2000 a - 1500 - - l l i, _ [ 1000- -

                                -                                                                                                             l 500 --
                                 ~

0 O 160 260 360 460 500 600 TlWE (s) O Figure 6.2.14 2 Inadvertent Opereilon of ECCS at Power DNBR Case, T., = 577.2'F Pressurizer Pressure and Water Volume versus Time mA3254w.non\sec6c.wpf.lb-012997 6-131

l O 600 - 580- . 560 - - cn 540 - - 520 -- . 500 -_- 480 - _

460 O 160 260 360 460 560 6u0 TIME (s) 7 6- - 5- - E 5 5 : l 1 4- _ 3-- _ 2 O 100 200 300 400 560 600 TIME (s) l Figure 6.2.14 3 Inadvertent Operation of ECCS at Power DNBR Case, T,,, = 577.2'F

               -             Core Average Temperature versus Time i

m:\3254w.non\w.c6c.wpf:lb-012997 6-132

4 4 A i a i 12 . 1- - 8- -

i 8 .6- - 4- -

v . l

                                           ~
                                                                                                                                                       \

2- - i 0 ' ' ' ' ' ' ' ' ' ' ' ' ' '''''''' ' O 100 200 300 400 500 600 TlWE (s) O 12 . 1

                              .8-        -

8 6- - 4- - v 2- ; f f I I f f f f I I I f f I I 0 I i f f f f 9 I I i i i i 0 10 20 30 40 50 TIME (s) t, Figure 6.2.14 4 Inadvertent Operation of ECCS at Power Pressurizer Fill Case, T,,, = 577.2'F Nuclear Power and Steam Flow versus Time m:\3254 w.non\sec6c.wpf: I b-012997 6-133

O 2800 2600 - - Y _ 2400- - 2200-2000- - 1800- -

1600 ' ' ' ' O 100 200 300 400 500 600 TIME (s) 2000 O w - 1500- - i[1000- . 500 - - 0 O 100 200 300 400 500 600 TIME (s) Figure 6.2.14 5 Inadvertent Operation of ECCS at Power Pressurizer Fill Case, T,,, = 577.2'F O Pressurizer Pressure and Water Volume versus Time m:\3254w.non\sec6c.wptib 012997 6-134

I

t i 1 i i 1 4 i ! 600 4

l 580 -- ! !. - l j . i i 1 60 ;;[ l 5 ( i i C 540 -- . I

!                           520 -     -
                                      ~

i g . 8 500 - - l I

i l 480 - - 460 O 100 200 300 400 560 600 TIME (s) Figure 6.2.14-6 Inadvertent Operation of ECCS at Power Pressurizer Fill Case, T,,, = 577.2*F Core Average Temperature versus Time m:\3254w.non\sec6c.wpf:lb 012997 6-135

O 12 . i_ . 8- - I : 8 .s- j 4- . 2- - o kie i . ........................ u 160 260 360 460 500 600 VME (s) 1 1.2 - _ 4 1- - -

                     -                                                                                     \

8- - I 8 .s- - 4- - v

               .2-.

g e i i e i i e i e i e i i e i e i i i e i i e i u 10 20 30 40 50 VME (s) l Figure 6.2.14 7 Inadvertent Operation of ECCS at Power Pressurizer Fill Case, T,,, = 567.2*F Nuclear Power and Steam Flow versus Tune m:\3254w.non\sec6c.wpf.It412997 6.]36

) i lO i 2600 2600 - - i - 2400- -

_ j-3, f2200-{.[ - l i 2000- - I 1800- - 4, - i 1600 ' ' ' ' '''''''''''''''''''' ! 0 100 260 300 400 560 600 i

TWE (s)

? , 2000 1 1500-- I

5 1 { 1000 -- - J i 500- - i

l 1 0 i 0 160 260 360 460 560 600 i TWE (s) i Figure 6.2.14-8 Inadvertent Operation of ECCS at Power Pressurizer Fill Case, T,y = 567.2'F Pressurizer Pressure and Water Volume versus Time i

l m: \3254 w.non\sec6c.wpf: l b-012997 6-137 l

O l i I l l l 600 580 --

       @         560 -       -

n 540 - - I 520 -- e j 500-j 480 - - 460 20 30 40 50 600 TIME (s) l Figure 6.2.14-9 Inadvertent Operation of ECCS at Power Pressurizer Fill Case, T,,, = 567.2*F Core Average Temperature versus Time mM254wmonwc6cmpf:1bo12m M l

f i ! i , } 6.2.15 Minor Secondary System Pipe Breaks ! e i 6.2.15.1 Identification of Causes and Accident Description j i i ! Included in this grouping are ruptures of secondary system lines which would result in steam release ! j rates equivalent to a 6-inch diameter or smaller break. 7 i t 4 r j 6.2.15.2 Description of Analysis ; p i Minor secondary system pipe breaks must be accommodated with the failure of only a small fraction j of the fuel elements in the reactor. Since the results of analyses presented in Section 6.2.19 for major t secondary system pipe ruptures also meet this criteria, separate analysis for minor breaks is not i

required. !

i De analysis of the more probable accidental opening of a secondary system steam dump, relief, or !

safety valve is presented in Section 6.2.13 and is illustrative of a pipe break equivalent in size to a l
single valve opening. t l

j 6.2.15.3 Conclusions !

De analysis presented in Section 6.2.19 demonstrates that the consequences of a minor secondary pipe ;

break are acceptable since'a departure from nucleate boiling ratio (DNBR) of less than the limit value ! j{ does not occur even for the more limiting major secondary system pipe break. Derefore, the - l conclusions presented in FSAR Section 15.3.2 remain valid. [ t

6.2.16 Inadvertent Loading of a Fuel Assembly into an Improper Position !

! 6.2.16.1 Identification of Causes and Accident Description ! Fuel and core loading errors such as can arise from the inadvertent loading of one or more fuel ; j assemblies into improper positions, the loading a fuel rod during manufacture with one or more pellets - i of the wrong enrichment, or the loading of a full fuel assembly during manufacture with pellets of the { wrong enrichment will lead to increased heat fluxes if the error results in placing fuel in core positions I calling for fuel of lesser enrichment. Also included among possible core loading errors in the f inadvertent loading of one or more fuel assemblies requiring bumable poison rods into a new core j j- without bumable poison rods. , i i i Any error in enrichment, beyond the normal manufacturing tolerances, can cause power shapes which : I are more peaked than those calculated with the correct enrichments. Dere is a 5 percent uncertainty ; margin included in the design value of the power peaking factor assumed in the analysis of l

;                                         Condition I and Condition II transients. De 'ncore system of moveable flux detectors which is used                   !
,                                         to verify power shapes at the start of lie is capable of revealing any assembly enrichment error or                  ,

4 loading error which causes power shapes to be peaked in excess of the design value. I j- m u254 mon w pr.it4 :2997 6-139

To reduce the probability of core loading errors, each fuel assembly is marked with an identification number and loaded in accordance with a core loading diagram. During core loading, the identification number will be checked before each assembly is moved into the core. Serial numbers read during fuel movement are subsequently recorded on the loading diagram as a funher check on proper placement after the loading is complet:d. He power distortion due to any combination of misplaced fuel assemblies would significantly raise peaking factors and would be readily observable with incore aux monitors. In addition to the flux monitors, thermocouples are located at the outlet of about one-third of the fuel assemblies in the core. Here is a high probability that these thermocouples would also indicate any abnormally high coolant enthalpy rise. Incore flux measurements are taken during the stanup subsequent to every refueling operation. 6.2.16.2 Description of Analysis Power distribution in the x-y plane of the core and resulting thermal hydraulic conditions are analyzed with the steady-state computer programs briefly described in Chapter 4 of the FSAR. A discrete representation b used wherein each individual fuel rod is described by a mesh interval, he assembly power distributions in the x-y plane for correctly loaded core, based on associated enrichments, are also given in Chapter 4. 6.2.16.3 Results De analysis presented in Section 15.3.3 of the FSAR was reviewed with respect to plant operation at uprated power conditions. He evaluation concluded that operation at uprated power conditions does not affect the ability of the in-core instrumentation to detect the inadvenent loading and subsequent operation with a fuel assembly in an improper position; therefore, the conclusions presented in FSAR Section 15.3.3 remain valid. 6.2.16.4 Conclusions Fuel assembly enrichment errors would be prevented by adminc ative procedures implemented in fabrication. In the event that a single pm or pellet has a higher enrichment than the nominal value, the consequences in terms of reduced DNBR and increased fuel and clad temperatures will be limited to the incorrectly loaded pin or pins. Fuel assembly loading errors are prevented by administrative procedures implemented during core loading. In the unlikely event that a loading error occurs, analyses in this section confirm that resulting power distribution effects will either be readily detected by the incore moveable detector system or will cause a sufficiently small perturbation to be within the uncertainties allowed between nominal and design power shapes. m u:54..onw6c .pr it4 con 6-140

r i

l

6.2.17 Complete Loss of Forced Reactor Coolant Flow i -!

l 6.2.17.1 Identification of Causes and Accident Description ! l i A complete loss of forced coolant flow accident may result from a simultaneous loss of electrical i power supply to all of the reactor coolant pumps (RCPs). If the reactor is at power at the time of the i event, the immediate effect from the loss of forced coolant flow is a rapid increase in the coolant i temperature. His increase in coolant temperature could result in departure from nucleate boiling (DNB), with subsequent fuel damage, if the reactor is not promptly tripped. l i l The following signals provide protection against a complete loss of forced reactor coolant flow i incident: i i

Low reactor coolant loop flow;
Undervoltage or underfrequency on reactor coolant pump power supply buses; and l
Pump circuit breaker opening.

j De reactor trip on low primary coolant loop flow provides protection against loss of flow conditions. j his function is generated by two-out-of-three low flow signals per reactor coolant loop. Above l Permissive P-8, low flow in any loop will actuate a reactor trip. Between approximately 10 percent !Q power (Permissive P-7) and the power level corresponding to Permissive P-8 (approximately i V 30% RTP), low flow in any two loops will actuate a reactor trip. Reactor trip on low flow is blocked below Permissive P-7. De reactor trip on reactor coolant pump undervoltage is provided to protect against conditions which can cause a loss of voltage to all reactor coolant pumps, i.e., loss of offsite power. An undervoltage reactor trip serves as an anticipatory backup to the low reactor coolant loop flow trip. De undervoltage trip function is blocked below approximately 10 percent power (Permissive P-7). De underfrequency reactor trip is provided to trip the reactor for an underfrequency condition resulting from frequency disturbances on the power grid. He reactor coolant pump underfrequency reactor trip function is blocked below P-7. In addition, the underfrequency function will open all RCP ; breakers whenever an underfrequency condition occurs (no P-7 or P-8 interlock) to ensure adequate RCP coastdown. His trip function also serves as an anticipatory backup to the low reactor coolant loop flow trip. 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 from any pump will actuate a reactor trip, and between P-7 and P-8, a breaker open signal from any two pumps will actuate a reactor trip. Reactor i trip on reactor coolant pump breakers open is blocked below Permissive P-7. m:\3254w.noe\sec6c.wpf: l b-012997 6.]4)

6.2.17.2 Input Parameters and Assumptions nis accident is analyzed using the Revised Thermal Design Procedure (Reference 1). Initial core O 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 analysis also conservatively bounds a +7 penfF moderator temperature coefficient (MTC) below 70% RTP, ramping to O pcm/*F at 100% RTP, by assuming a +2 pcm/*F MTC at hot full power conditions. 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., Safety Injection) 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. 6.2.17.3 Description of Analysis The following complete loss of forced reactor coolant flow cases were analyzed for FNP. The limiting case was subsequently reanalyzed in support of the plant uprate.

1. Complete loss of all three reactor coolan: pumps with three loops in operation

2. Frequency decay event resulting in a complete loss of forced reactor coolant flow These transients were analyzed by three digital compu;er codes. First, the LOFTRAN code (Reference 2) was used to calculate the loop and core flow transients, the nuclear power transient, and the primary system pressure and temperature transients. His code simulates a multiloop system, neutron kinetics, the pressurizer, pressurizer relief and safety valves, pressurizer spray, the steam gensators, 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 conservative system pressure loss estimates.

The FACTRAN code (Reference 3) was then used to calculate the heat flux transient based on the nuclear power and flow from LOFTRAN. Finally, the THINC code (References 4 and 5) was used to calculate the DNBR during *.he transient based on the heat ilux from FACTRAN and the flow from LOFTRAN. The DNBR r;sults are based on the minimum of the typical and thimble cells. 6.2.17.4 Acceptance Criteria A complete loss of forced reactor coolant flow incident is classified by the American Nuclear Society (ANS) as a Condition III event; however, for conservatism, the incident is analyzed to Condition II mA3254w.non\sec6c.wpf.lM12907 6-142

l l i i l criteria. The immediate effect from a complete loss of forced reactor coolant flow is a rapid increase 3 in the reactor coolant temperature and subsequent increase in reactor coolant system (RCS) pressure. l j The following three items summarize the criteria associated with this event. ! l The critical heat flux should not be exceeded. This is ensured by demonstrating that the i 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 j their respective design pressures. The peak linear heat generation rate should not exceed a value which would cause fuel centerline melt. 6.2.17.5 Results ) Both the Undervoltage and Underfrequency cases are assumed to trip on a low reactor coolant loop flow signal. For the Farley uprate, the limiting case, i.e., the frequency decay transient, was analyzed.

The THINC-IV (Reference 5) analyses for these scenarios confirmed that the minimum DNBR values j are greater than the safety analysis limit value. Fuel clad damage criteria are not challenged in either i

of the complete loss of forced reactor coolant flow cases since the DNB criterion is met. Ih i V The analysis of the complete loss of flow event also demonstrates that the peak Reactor Coolant l System and Main Steam System pressures are well below their respective limits. 2 The updated sequence of events for the limiting Underfrequency case is presented in Table 6.2.17-1. The transient results for this case are presented in Figures 6.2.17-1 through 6.2.17-6. 6.2.17,6 Conclusions The analysis of the limiting case, performed at uprated conditions, demonstrates that for the aforementioned complete loss of flow cases, the DNBR does not decrease below the safety analysis limit value at any time during the transients; thus, no fuel or clad damage is predicted. De peak ! primary and secondary system pressures remain below their respective limits at all times. All ! applicable acceptance criteria are therefore met. I ne protection features presented in Section 6.2.17.1 provide mitigation for the complete loss of forced reactor coolant flow transients such that the above criteria are satisfied. . O rnA3254w.non\sec6c.wpf:Ib-012997 6-143

I l i l 6.2.17.7 References l

1. Friedland, A. J. and Ray, S.," Revised Thermal Design Procedure", WCAP-ll397-P-A, O

April 1989 l l l

2. Burnett, T.W.T et al., "LOFTRAN 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 UO2 Fuel Rod", WCAP-7908-A, December 1989

4. Shefcheck, J., " Application of the THINC Program to PWR Design," WCAP-7359-L, August 1969

5. Chelemer, H., Chu, P. T., Hochreiter, L. E., "THINC-IV - An Improved Program for Thermal-Hydraulic Analysis of Rod Bundle Cores," WCAP-7956, February 1989 l

l l O 1 l l 9 mA3254wison\sec6c wpf.lb-012997 6-144

l l l l i i l TABLE 6.2.171 l 1 SEQUENCE OF EVENTS - COMPLETE LOSS OF FORCED

 ;                                                  REACTOR COOLANT FLOW EVENT 1

j Case Event Time (sec) Complete loss of forced reactor Frequency decay begins 0.0 j coolant flow (Underfrequency) l Low reactor coolant flow trip setpoint reached 1.9 )

!                                                        Rods begin to drop                                                2.9 3

- Minimum DNBR occurs 5.0 I l ) i 1 1 ! I i 1 4 i e l i 1 i 4 h i I m:\3254w.nonwc6c.wpf:Ib-012997 6-145

l l [ l O l 3 1.4 1 E 2 1.2 - (L O i Z 1 I 0.8 - 6 l

   .J 0.6  -

g W W 0.4 - E 0.2 - m ' ' ' ' ' ' ' l E O O 1 2 3 4 5 6 7 8 9 10 TIME (SEC) l Figure 6.2.17-1 Complete Loss of Forced Reactor Coolant How (Frequency Decay) Core Row versus Time l l 6-146 m:U254w.non\uc6c.wpf.lM12997

i i

O l Y

i i i i i l 3 1.4 4 Z h 1.2 - Z lL O 1 z O b

                     < 0.8 E

b Og 0.6 - 2 0.4 - E 0.2 - 8 Z 0 O 1 2 3 4 5 6 7 8 9 10 TIME (SEC) O Figure 6.2.17 2 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay) Nuclear Power versus Time m:u254w.non\a6c.wpf:1w12m 6-147

O 2,500

 $ 2,400      -

in b w W 2,300 - 3 to (4 y 2,200 - Q. W

 $ 2,100      -

l I W l 2,000 - W C Q. 1,900 - 1,800 10 TIME (SEC) Figure 6.2.17 3 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay) l Pressurizer Pressure versus Time mu254*aonwe6c wpf:IM12997 6-148

  . . ~ - . - _ . .                _ _ .   . _     . = .        . . . -      . -.   ..       .    . . - - . _ . . . - -      - - . .

1 ! I 1 I i i J i i ! 1.4 l 1 y 1.2 - J 8 a

                      <       1 i                      Z i                 I                                                                                                                   ,

! J W 0.8 - a Z 2 11

                 <O i

bZ 0.6 - tu 0.4 - i i h<v 0.2 - 0 i 0 1 2 3 4 5 6 7 8 9 10 TIME (SEC) Figure 6.2.17-4 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay) Average Channel Heat Flux versus Time m:u254w.noassec6c.wpr.1b-012997 6-149

l l l I I l 1.4 1.2 - X D3 4 [3< F-Io Iz 0.8 - . JLL WO z Im 0.6 - O ! 00 $$ 0.4 - Ib O.2 - i 1 0 O 1 2 3 4 5 6 7 8 9 10 TIME (SEC) Figure 6.2.17 5 Complete Loss of Forced Reactor Coolant Flow (Frequency Decay) Ilot Channel IIcat Flux versus Time m:\3254w.non\wc6c.wpf:Ib-012997 6 150

I

l 1

i i !4 ' i : i 4 i t I i 4 ( J ' 2.6 t i 2.4 - l i i. I 2.2 - l 2 - ! E co z 1.8 - i 0 1 1.6 - 1 1.4 - 4 l 4 1 1.2 - 4 4 1 1 t O 2 4 6 8 10 l TIME (SEC) i 4 4 1 i

i

!              Figure 6.2.17-6         Complete Loss of Forced Reactor Coolant Flow (Frequency Decay) 3                                       DNBR versus Time 1

m:u254w.none.wpr Ib-012997 6-151

6.2.18 Single Rod Cluster Control Assembly Withdrawal at Full Power 6.2.18.1 Identification of Causes and Accident Description O No single electrical or mechanical failure in the rod control system could cause the accidental withdrawal of a single rod cluster control assembly (RCCA) from the inserted bank at full-power operation. The event analyzed must result from multiple wiring and/or component failures, multiple significant operator errors, or subsequent and repeated operator disregard of event indication. The probability of such a combination of conditions is low such that the limiting consequences may include slight fuel damage. RCCA banks are generally divided into two groups of four mechanisms each. The rods comprising a group operate in parallel through multiplexing thyristors. De two groups in a bank move sequentially such that the first group is always within one step of the second group in the bank. A definite schedule l of actuation (or deactuation) of the stationary gripper, moveable gripper, and lift coils associated with the four RCCAs of a rod group are driven in parallel. Any single failure which would cause withdrawal would affect a minimum of one group, or four RCCAs. Mechanical failures are in the direction of insertion or immobility. Note, the operator can deliberately withdraw a single RCCA in a control or shutdown bank since this feature is necessary in orden to retrieve an assembly should one be accidentally dropped. In the unlikely event of simultaneous electrical failures which could result in single RCCA withdrawal, the plant annunciator will display both the rod deviation and rod control urgent failure, and the rod position indicators will indicate the relative positions of the RCCAs in the bank. The urgent failure alarm also inhibits automatic rod motion in the group in which it occurs. Withdrawal of a single RCCA by operator action, whether deliberate or by a combination of errors, would result in activation of the same alarm and the same visual indication. The OTAT reactor trip provides automatic protection for this event, although due to the increase in local power density, it is not possible to always provide assurance that the core safety limits will not be exceeded. Hence, this function is not credited in the analysis for this event. 6.2.18.2 Input Assumptions and Description of Analysis Power distributions are analyzed using appropriate nuclear physics computer codes. The peaking factors are then used as input to the THINC code to calculate the DNBR. The analysis examines the case of the worst rod withdrawn from bank D, inserted at the insertion limit with the reactor initially at full power. The analysis of the single rod withdrawal event considers the following two cases.

a. If the reactor is in the manual rod control mode, continuous withdrawal of a single RCCA results in both an increase in core power and coolant temperature and an increase in the local hot channel factor in the area of the withdrawing RCCA. In terms of the overall system m A3254 w .non\sec6c.wpf; 1 t>-012997 6-152

  . _.._._.-_m.                     _ _ _ _ _ ___._ _ __._._.- _.                                     -___ ___..__ _-.___

i 4 response, this case is similar to those presented in Section 6.2.2; however, the increased local { power peaking in the area of the withdrawn RCCA results in lower DNBRs than for the withdrawn bank cases. Depending on initial bank insertion and location of the withdrawn } RCCA, automatic reactor trip may not occur quickly enough to prevent the mhtimum DNBR from falling below the safety analysis limit value. Evaluation of this case at the power and coolant conditions at which the OTAT trip would trip the plant shows that an upper limit for the number of rods with a DNBR less than the safety analysis limit value is 5 percent.

                - b.         If the reactor is in the automatic rod control mode, the multiple failures that result in the withdrawal of a single RCCA cause immobility of the other RCCAs in the cor4 trolling bank.
                             'Ihe transient will then proceed in the same manner as Case A, described above. For such cases, a reactor trip will uhimately ensue, although not quickly enough in all cases to prevent a minimum DNBR in the core of less than the safety analysis limit value. Following reactor trip, plant operating procedures are followed.

6.2.18.3 Acceptance Criteria The single RCCA withdrawal event is classified as a Condition III incident. No single electrical or mechanical failure in the rod control system could cause the accidental withdrawal of a single RCCA from the inserted bank at full power operation. The probability of such a combination of conditions is considered low such that the limiting consequences may included slight fuel damage. The i;mit of fuel damage is set at 5% of the total fuel rods present in the core. 6.2.18.4 Results Uprated plant conditions were considered in the analysis performed in support of the VANTAGE 5 fuel upgrade program. An evaluation performed for the plant uprate confirmed that the VANTAGE 5 analysis remains conservative for the Farley Units 1 and 2 uprate program. 6.2.18.5 Conclusions'- For the case of the accidental withdrawal of a single RCCA, v.ith the reactor in the automatic or manual control mode and initially operating at full power with bank D at the insertion limit, the j l number of fuel rods experiencing DNBR is less than 5 percent of the total fuel rods in the core. ! For both cases discussed, the indicators and alarms mentioned would function to alent the operator to the malfunction before DNB would occur. For Case B, discussed above, the insertion limit alarms (Iow l and low-low alarms) would serve in this regard. ! O m:\3254w.non\sec6c.wpf:Ib-012997 6-153

i l 6.2.19 Rupture of a Main Steam Line 6.2.19.1 Identification of Causes and Accident Description O The steam release arising from a rupture of a main steamline will result in an initial increase in steam flow that decreases during the accident as the steam pressure falls. The energy removal from the RCS causes a reduction of coolant temperature and pressure. In the presence of a negative moderator temperature coefficient, the cooldown results in a positive reactivity insertion and subsequent reduction in core shutdown margin. If the most-reactive RCCA is assumed stuck in its fully withdrawn position after reactor trip, there is an increased possibility that the core will become crit':al and retum to power. A return to power following a steam pipe rupture is a potential problem mainly because of the high power peaking factors that would exist assuming the most-reactive RCCA to be stuck in its fully withdrawn position. The core is ultimately shut down by boric acid injection delivered by the ECCS and accumulators. The mpture of a major steamline is the most-limiting cooldown transient. It is analyzed at zero power with no decay heat since decay heat would retard the cooldown, thus reducing the retum to power. A detailed discussion of this transient with the most-limiting break size (a double-ended rupture) is presented below. The following functions provide the necessary protection against a steam pipe rupture.

a. Safety injection system actuation from any of the following:

1. Two-out-of-three low pressurizer pressure signals;

2. High steamline differential pressure;

3. Low main steamline pressure in two-out-of-three steamlines; and

4. Two-out-e-three high-1 containment pressure signals.

b. The overpower reactor trips (neutron flux and AT) and the reactor trip occurring in conjunction with receipt of the Safety injection (SI) signal.

l

c. Redundant isolation of the main feedwater lines: to prevent sustained high feedwater flow l I

which would cause additional cooldown. Therefore, in addition to the normal control action which will close the main feedwater control valves, a safety injection signal will rapidly close all feedwater control valves, trip the main feedwater pumps, and indirectly close the feedwater j isolation valves that backup the control valves. In addition, trip of the main feedwater pumps results in automatic closure of the respective pump discharge isolation valve. O mA3254w.non\sec6d.wpf Ib-012997 6-154

d. Trip of the fast-acting Main Steamline Isolation Valves (MSIVs, assumed to close in Q 10 seconds stroke time) and Main Steamline Isolation Bypass Valves (MSIBVs, assumed to close in 10 seconds stroke time) after receipt of an ECCS or main steamline isolation signal on:

1. High steam flow in two-out-of-three main steamlines (one-of-two per line) coincident l with two-out-of-three low-low T,, signals;

2. Low steamline pressure signal on two-out-of-three steamlines; and !

3. Two-out-of-three high-high (Hi-2) containment pressure signals. l For breaks downstream of the isolation valves, closure of all valves will completely terminate the blowdown. For any break, in any location, no more that one steam generator would experience an ;

uncontrolled blowdown even if one of the isolation valves fails to close. Circuit design assures that the MSIBVs are automatically closed whenever the MSIVs are automatically closed. Following a steamline break, only one steam generator can blow down completely. Each main j steamline is provided with two isolation valves located outside of the containment immediately downstream of the steamline safety valves. The isolation valves are signal-actuated valves which close to prevent flow in the normal (forward) flow direction. 'Ihe valves on all three steamlines will be driven closed and isolate the other steam generators. Thus, only one steam generator can blowdown, minimizing the potential steam release and resultant RCS cooldown. In addition, the remaining two steam generators will still be available for dissipation of any decay heat after the initial transient is V over. In the case of loss of offsite power, this heat is removed to the atmosphere via the atmospheric elief valves which have been sized to handle this situation. Steam flow is measured by monitoring the pressure difference between pressure taps located in the steam drum and downstream of the integral flow restrictor nozzles. The effective throat diameter of the flow restrictor nozzles of 14 inches is considerably smaller than the diameter of the main steam pipe. These restrictors are located in the steam generators outlet nozzle and serve to limit the maximum steam flow for any break at any location. 6.2.19.2 Input Parameters and Assumptions The following conditions were assumed to exist at the time of a main steamline break accident.

a. End-of-Life (EOL) shutdown margin at no-load, equilibrium xenon conditions, and the most-reactive assembly stuck in its fully withdrawn position. Operation of the control rod banks during core burnup is restricted in such a way that addition of positive reactivity in a steamline break accident will not lead to a more adverse condition than the case analyzed.

b. The negative moderator coefficient corresponding to the EOL rodded core with the most-reactive rod in the fully withdrawn position. The variation of the coefficient with

 -           temperature and pressure has been included. The k,y versus coolant average temperature at 1000 psia corresponding to the negative moderator temperature coefficient plus the Doppler mA3254w.non\sec6d.wpf:lb-012997                     6-155

                                                                                                              ,l temperature effect used is shown in FSAR Figure 15.2-40 along with the effect of power              !

generated in the core on overall reactivity. 1 All reactivity physics parameters are weighted toward the core sector exposed to the greatest l cooldown from the faulted loop. Weighting is of the ratios 0.65:0.175:0.175 where the 0.65 ; corresponds to the loop with the break.

c. Minimum capability for injection of high concentration boric acid (2300 ppm) solution corresponding to the most-restrictive single failure in the ECCS. The 2300 ppm boron solution corresponds to the minimum boron concentration in the Refueling Water Storage Tank j (RWST). A boric acid solution of 0 ppm is assumed in the Boron Injection Tank (BIT) which I is also conservative for operation with the BIT removed. No credit has been taken for the low concentration of boric acid that must be swept from the ECCS lines downstream of the RWST

isolation valves prior to the delivery of the concentrated boric acid (2300 ppm from the RWST) to the reactor coolant loops. The safety injection flow corresponds to that delivered by one charging / safety injection pump delivering full flow to the cold leg header. The variation of the mass flow rate due to water density changes is included in the calculations, as is the variation in flow rate in the ECCS due I to changes in the RCS pressure. The ECCS flow calculation includes the line losses as well as l the charging / safety injection pump head curve. The modeling of the ECCS in LOFTRAN is l described in Reference 1. ; l The boric acid solution from the ECCS is assumed to be uniformly delivered to the three reactor coolant loops. The boron in the loops is then delivered to the inlet plenum where the coolant (and boron) from each loop is mixed and delivered to the core. The calculation assumes the boric acid is mixed with and diluted by the water flowing in the RCS prior to j entering the core. The concentration after mixing depends on the relative flow rates of the l RCS and the ECCS. The stuck RCCA is assumed to be conservatively located in the core j sector near the faulted steam generator. For the case where offsite power is assumed, the sequence of events in the ECCS is the following. After the generation of the SI signal (appropriate delays for instrumentation, logic, and signal transport included), the appropriate valves begin to operate and the charging / safety injection pump starts. In 27 seconds, the valves are assumed to be in the final position and the pump is assumed to be at full speed and to be drawing suction from the RWST. The 27 seconds includes 2 seconds for electronic delay,10 seconds for the RWST valve (s) to open, and 15 seconds for the VCT valve (s) to close. (The charging / safety injection pump (s) start, normal charging isolation, and high-head injection header alignment occur in conjunction with the RWST valve alignment.) The volume containing the low concentration (0 ppm assumed) borated water is swept from the ECCS before the 2300 ppm boron reaches the core. This delay in 2300 ppm boron solution reaching the core is inherently included in the LOFTRAN modeling. m:\3254 w .non\sec6d.wpf: I b-012997 6-156

i i

In cases where offsite power is not available, an additional 15-second delay is assumed to start l
- the diesels and to reenergize the ESF electrical buses. That is, after a total of 42 seconds l
following the time an SI setpoint is reached at the sensor, the ECCS is assumed to be capable ;

of delivering flow to the RCS. 1 l 1 , ! d. To maximize primary-to-secondary heat transfer,0% tube plugging is assumed. ( a i 2 ! e. Since the steam generators are provided with integral flow restrictors with a 1.069 ft throat l 2

area, any rupture with a break greater than 1.069 ft , regardless of the location, would have the j same effect on the nuclear steam supply system as the 1.0692 ft break. The following two l cases have been considered in determining the core power and RCS transients. l I: 1. Complete severance of a pipe, with the plant initially at no-load conditions, and full l reactor coolan' flow (Thermal Design Flow) with offsite power available, and l; 2. Complete severance of a pipe with the plant initially at no-load conditions with offsite power unavailable. Loss of offsite power results in reactor coolant pump coastdown.; f. Power peaking factors corresponding to ene stuck RCCA and non-uniform core inlet coolant temperatures are determined at EOL. The coldest core inlet temperatures are assumed to occur p in the sector with the stuck rod. The power peakmg factors account for the effect of the local V void in the region of the stuck control assembly during the return-to-power phase following the steamline break. This void, in conjunction with the large negative moderator coefficient, partially offsets the effect of the stuck assembly. The power peakmg factors depend on the core power, operating history, temperature, pressure, and flow, and thus are different for each case studied.

j 1 Both cases assume initial hot-standby conditions at event initiation since this represents the most-conservative initial condition. Should the reactor be just critical or operating at power at the time of a steamline break, the reactor will be tripped by the normal overpower protection when the power level (high flux) or AT reaches a trip setpoint. Following a trip at power, the RCS contains more stored energy than at no-load, the average coolant temperature is higher than at no-load, and there is appreciable energy stored in the fuel. Thus, the additional stored energy is removed via the cooldown caused by the steamline break before the no-load conditions of RCS temperature and shutdown margin assumed in the analyses are reached. After the additional stored energy has been removed, the cooldown and reactivity insertions proceed in the same manner as in the analysis which assumes no-load condition at time zero. In addition, since the initial steam generator water inventory is greatest at no-load, the magnitude and duration of the RCS cooldown are less for steamline breaks occurring at power.

g. In computing the steam flow during a steamline break, the Moody Curve (Reference 2) for fl/D = 0 is used. The Moody multiplier is I with a discharge at dry saturated steam conditions.

ms254w.nonsxcawpf.ib 012997 6-157

h. Perfect moisture separation in the steam generator is assumed. The assumption leads to conservative results since, in fact, considerable water would be discharged. Water carryover would reduce the magnitude of the temperature decrease in the core.

l

i. The maximum feedwater flow is assumed. Increasing the feedwater flow rate further increases the cooldown in accidents such as steamline rupture. All main and auxiliary feedwater pumps are assumed to be operating at full capacity when the rupture occurs.

1

j. The effect of heat transferred from thick metal in the pressurizer and reactor vessel upper head is not included in the cases analyzed. Studies previously performed show that the heat transferred from these sources is a net benent in DNBR and RCS energy when the effect of the extra heat on reactivity and peak power is considered.

6.2.19.3 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 main steam line break. The code models the core neutron kinetics, RCS, pressurizer, steam geruators, safety injection system and the auxiliary feedwatu system; and computes perti=at variables, including the core heat flux, RCS temperature and pressure. A conservative selection of those conditions are then used to develop core models which provide input to the detailed thermal and hydraulic digital computer code, THINC, to determine if DNB occurs. 6.2.19.4 Acceptance Criteria A major break in a pipe line is classified as an ANS Condition IV event. Minor secondary system pipe, breaks are clanified as ANS Condition III events. All of these events are a'4 zed to meet CondiEon 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 i ensuring that the minimum DNBR does not go below the limit value at any time during the transient. 6.2.19 7 '? sults The time sequence of events for postulated steamline rupture accidents with and without offsite power are prewnted in Table 6.2.19-1. The results presented are a conservative indication of the events that l would occur assuming a steamline rupture since it is postulated that all of the conditions described in I the prior section occur simultaneously. l Figures 6.2.19-1 through 62 '9-6 show the reactor cociant system transients and core heat flux following a main steam f.ye rupture. Offsite power is assumed to be available such that full reactor coolant flow exists. The transient shown assumes n uncontrolled steam release from only ow steam generator. l mA3254w.non\sedd wpf Ib-ol2997 6-158

As can be seen, the core attains criticality with RCCAs inserted (with the design minimum shutdown (j margin and assuming one stuck RCCA), but is quickly retumed to a subcritical condition as a boric acid solution at 2300 ppm (from the RWST) enters the RCS. The delay time consists of the time to receive and actuate the safety injection signal, to start the charging / safety injection pumps, and to { completely align valve trains in the ECCS lines, including VCT isolation. The charging / safety' l injection pumps are then ready to deliver flow. At this stage, a further delay is incurred before 2300 ppm boron solution can be injected to the RCS due to the low concentration solution being swept from the SI lines. Should a partial loss of offsite power occur such that power is lost to the l ESF functions, an additional SI delay of 15 seconds would occur while the diesel generators start up and reenergize the ESF buses. Allowing for these delays, a peak core power well below the nominal

full-power value is attained.

4 Should the core be critical at near zero power when the rupture occurs, the initi-' ion of the SI signal by high steamline dif'erential pressure, low steamline pressure, or high containment pressure will trip the reactor. Steam release from more than one steam generator will be prevented by automatic closure of the isolation valves in the steamlines by low steamline pressure, a high steam flow signal in coincidence with low-low RCS temperature, or high-high containment pressure. The MSIVs and MSIBVs are assumed to be fully closed in 10 seconds (stroke time) after receipt of a closure signal. This analysis conservatively assumed 2 seconds to account for signal processing. Figures 6.2.19-7 through 6.2.1912 show the responses of the salient parameters for the case discussed y/ above with a total loss of offsite power at the time of the rupture. This assumption results in a coastdown of the reactor coolant pumps. In this case, the core power increases at a slower rate and reaches a lower peak value than in the cases in which offsite power is available to the reactor coolant pumps. The ability of the emptying steam generatche axtract heat from the RCS is reduced by the 1 decreased flow in the RCS. It should be noted that following a steamline break, only one steam generator blows down completely. Thus, the remaining steam generators are still available for dissipation of decay heat after the initial transient is over. In case of a loss of offsite power, this heat is removed to the atmosphere via the steamline safety valves. Following blowdown of the faulted steam generator, the plant can be brought to a stabilized hot-standby condition through control of the auxiliary feedwater flow and safety injection flow as described by plant operating procedures. The operating procedures would call for operator action to limit RCS pressure and pressurizer level by terminating safety injeccion flow and to control steam generator level and RCS coolant temperature using the auxiliary feedwater system. Any action required of the operator to maintain the plant in a stabilized condition will be in a time frame in excess of 10 minutes following safety injection. p 6.2.19.6 Conclusions G A DNB analysis was performed for the above cases. It was found that the DNB design basis is met. mu254w.nonsec6d wpr:ib-012997 6-159

6.2.19.7 References

1. Burnett, T. W. T., et al, "LOFFRAN Code Description," WCAP-7907-P-A (Proprietary),

WCAP-7907-A (Non-proprietary), April 1984

2. Moody, F. S., " Transactions of the ASME, " Joumal of heat Transfer, Page 134, February 1965 l

O l l l l 9 mM254w.non\sec6d wpf.It412997 6-160

1

/" TABLE 6.2.191 \ TIME SEQUENCE OF EVENTS FOR THE RUPTURE OF A MAIN STEAMLINE Event Time (See) With Offsite Power: Steamline ruptures 0.0 Low steamline pressure setpoint reached 0.8 Steamline isolation occurs 12.8 Pressurizer empties 13.9 SI injection begins 27.8 Borated water form the RWST reaches the core 41.5 Criticality attained 44.3 Accumulators actuate 146.5 Peak core heat flux occurs 250.1 Without Offsite Power: Steamline ruptures 0.0 Low steamline pressure setpoint reached 0.8 Si signal generated 2.8 l l Loss of ac power and RCPs begin coastdown 3.0 Steamline isolation occurs 12.8* Pressurizer empties 15.5 Si injection begins 42.8 Borated water from the RWST reaches the core 60.8 Criticality attained 61.3 Peak core heat flux occurs 373.1 Time of main steamline isolation. '!he main steamline isolation bypass valves close following diesel l generator stan. The additional blowdown through the main steamline isolation valve bypass lines does ' not impact the limiting transient results. l s 1 1 1 m:u254w.nonwec6d wpr ib.oi3097 6-161

O 3_ 25 -: _ .2-: b lb 15-2 l .1 - E 5E : 0 o 160 260 360 460 500 TlWE (s) 2500 O e 2000 - . 1500- -

                  ~
    ^

e 1000 - - 500- -

                  -                                                                                    1
                   ~p      g   l   I   I  I f I I   I  f   f  I   I  I  f I   i  I  i i  f  f  I o                   160          260               360            400           500 TlWE (s)

Figure 6.2.191 Steamline Break Transient With Offsite Power 1.069 ft: Double Ended Rupture Core IIcat Flux and RCS Pressure versus Time m:u254w.nonw6d wpf:1M12997 6-162

O 600

550-

500 - c 450 -:

400 - _ i 350- - 300-: _ 250 "' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '' I O 160 260 360 460 500 I TWE (s) , i O 600 l I

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lc 450 - -

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       &         350-     _
                                                             ~~~~~~                                      ~~
                          -                                                                FAutan toop 300 -:   _

250 "' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '' O 160 260 360 460 500 TWE (s) Figure 6.2.19 2 Steamline Break Transient With Offsite Power 1.069 ft" Double Ended Rupture Core Average Temperature and RV Inlet Temperature versus Time m:\3254w.non\sec6dspf.Ib-012997 6-163

O 800 600- - Nk 400-200o 0- ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' O 100 200 300 460 500 TIME (s) 1.4 O l

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                    .                                                                                 1 12-     -
                                                                                                      )
                    ~

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O O 100 200 360 460 500 TIME (s) Figure 6.2.19-3 Steamline Break Transient With Offsite Power 1.069 ft2 Double Ended Rupture Pressurizer Water Volume and Core Flow versus Time m \3254w.nonw6d wpf.lb-012W7 6-l M

i

O 1

500 1 400 - _ 1 300-{ ] I 200-:

100-: .

0 _

                                -100 ~ ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '

O 100 260 360 460 500 TlWE (s) O 3000 _ 2000 - . 1000-- - l

{ 0-- i

                            -1000 -          _

i l

                            -2000 -          -
                                             ~
                            -3000 O                100           260               360           400           500 TIME (s)

O Figure 6.2.19 4 Steamline Break Transient With Offsite Power 1.069 ft2 Double Ended Rupture Core Baron and Reactivity versus Time m:\3254w.non\sec6d.wpf- l b-012997 . 6-165

1 0 1200 1000- - 800 - - n 600- .

                                                                  , ' M M LOOPS l

400 -- -

                                                                                 ,~~~__

ra nDt00P 200-- _ l

0 ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' O 160 200 360 400 500 11ME (s) 8 O 6- - p8 4--

                      .I v

2- -l

                      -l                                               FAULTfD LDOP i                                                  I
                             - mm LOOPS 0           ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '

O 100 200 360 460 500 TlWE (s) Figure 61.19-5 Steamline Break Transient With Offsite Power 1.069 ft' Double Ended Rupture Steam Pressure and Steam Flow versus Time m:\3254wmon\sec6d wpf:Ib-012997 6-166

                                         .    - - . . .        -       - . ~ .     - - .    , -     .-_.--.-. ~

l l. i -t

,1 3

a. J I l l I 1 1 i 1 + 1 4 i l 4 25 2 -

                                      .                                                                                  i' i                                      -

} j 2-- 4 . 1 ~ 2 t C i 4

1. 5 - -

1

l 8 , 1 i i

1--

j v - i 4 . i 5-- s . I " i, l ) 0 i U 160 200 300 460 500 1 i TlWE (s) 3 j l 1 i l 1 Figure 6.2.19-6 Steamline Break Transient With Offsite Power 1.069 ft: Double Ended Rupture Total Feedwater Flow versus Tune m:\3254w.non\sec6d.wpf.lb412997 6-167

l l O 3 . I 25 - -

                   .2-      -

E : ! bb

c 15 - . ,

                   .1 --                                                                                       1 w

5E . 0 i 0 100 260 360 460 500 VME (s) 2500 . Y 2000 - . j 1500- -

1 -

1000-- . 500 - - 0 O 100 260 360 460 500 BWE(s) Figure 6.2.19-7 Steamline Break Transient Without Offsite Power 1.069 ft Double Ended Rupture Core Heat Flux and RCS Pressure versus Time m:\3254w.nonisec6d.wpf;tb 012997 6-168

1 6 I i i i iO ! I

l. 600 _ {

l'

'                                                    ~

550-500-3 l Icw 450 -3 400-5 g 350-3 0 : 300-3 250 " ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '

U 160 269 360 460 500 TWE (s)

O 600 ~ 550-500-

                                                     ;                                                          sa crLoors

s\ I le 450- -

l . \ [ : \ v 400 - - s

s

                                                     -                         s
                      &                350 -3
                                                                                    's s

's 300-- '% FAutun Loop

', l 250 ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '~T"'

O 160 260 360 460 500 TWE (s) Figure 6.2.19-8 Steamline Break Transient Without Offsite Power 1.069 ft2 Double Ended Rupture Core Average Temperature and RV Inlet Temperature versus Time m:\3254w.non\sec6d.wpf:11412997 6-169

O 800 600- - 400-

l200- - l

                                                                                      /                    l l

a , , . , , , , . . . , , , , , , , , , , , , o , 0 100 200 300 400 500 TIME (s) 14 , , O 1 2 -.

     ^           1-  i-E        .g..

8 ; i f .6- - l 1 v 4-_ - 2-. -

O ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' O 100 200 300 400 500 TlWE (s) Figure 6.2.19-9 Steamline Break Transient Without Offsite Power 1.069 ft2 Double Ended Rupture Pressurizer Water Volume and Core Flow versus Time m:\3254wmonisec6d.wpf.lb412997 6-170

t i l i 1 i 1 500 i 400-: - 300-200- : 1 .

100- .

0 .

                                     ~
                              -100       ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' i '

O 160 260 360 460 500 TWE (s) O 3000 ,e 2000 - - 1000- -

                   ?                 :                                                                                                                                  '

I-f 0-.-

                          -1000 -    .
                          -2000 -    -
                          -3000          ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '

O 160 260 360 460 500 1WE(s) Figure 6.2.10 10 Steamline Break Transient Without Offsite Power 1.069 ft: Double Ended Rupture Core Boren and Reactivity versus Time m:u2W.non\sec6d.wpf:Ib 012997 6-}7]

O 1200 1000 - - 800 -

                          <~,'                                     sur Loops 600 -      /

_ _ _ - l 400 - - 200 - - FAULTED LOOP s w I i 0

                         ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' '''                                       I U               100            200             300              400           500 TlWE (s)
              .8 i

6- - I8 .4--

_I v '

              .2-      ,
                     ~1 FAULTD LOOP 3

1 g -urnct 0 O 100 200 300 460 500 TlWE(s) Figure 6.2.1911 Steamline Break Transient Without Offsite Power 1.069 ft2 Double Ended Rupture Steam Pressure and Steam Flow versus Time m:u254 .nonvec6d wpub-ol2997 6-172

1 5 i (. i I i l l l 1 1 l 2.5 2- -

1. 5 - -

8 . 1-- w - 5-- 0 ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' ' O 100 200 360 400 500 TWE (s) i i i l l Figure 6.2.19 12 Steamline Break Transient Without Offsite Power 1.069 ft2 Double Ended Rupture j Total Feedwater Flow versus Time ! l m11254w.non\sec6d.wpf;lM12997 6.]73

6.2.20 Major Rupture of a Main Feedwater Pipe 6.2.20.1 Identification of Causes and Accident Description O A major feedwater line rupture is defined as a break in a feedwater pipe large enough to prevent the addition of sufficient feedwater to the steam generators to maintain shell-side fluid inventory in the steam generators. If the break is postulated in a feedline between the check valve and the steam generator, fluid from the steam generator may also be discharged through the break. Further, a break in this location could preclude the subsequent addition of auxiliary feedwater to the affected steam generator. A break upstream of the feedline check valve would affect the NSSS only as a loss of feedwater. This case is covered by the evaluation in Section 6.2.8. A feedline rupture reduces the ability to remove heat generated by the core from the RCS. The Auxiliary Feedwater System is provided to ensure that adequate feedwater will be available to provide decay heat removal. 6.2.20.2 Input Parameters and Assumptions The primary assumptions for the major feedwater supture analysis are as follows.

a. The plant is assumed to be initially operating at a conservative NSSS power level of 2790 MWt, including a conservatively large RCP heat input of 15 MWt.

b. Uncertainties on initial operating conditions (power level, RCS temperature and pressurizer pressure) are applied in the limiting direction.

1

c. No credit is taken for pressurizer spray or PORVs or for the high pressurizer pressure reactor trip. 1

d. Main feed to all steam generators is assurned to stop at the time the break occurs (i.e., all main ,

feedwater spills). l

e. Saturated liquid discharge (no steam) is assumed from the affected steam generator through the feedline rupture, thereby, minimizing the energy removal from the NSSS during blowdown.

f. No credit is taken for the low-low steam generator water level protection function until the water level reaches 0% NRS.

g. The worst possible break area is assumed; i.e., one that empties the effected steam generator and causes a reactor trip on low-low steam generator water level as assumed above. This assumption minimizes the steam generator fluid inventory at the time of trip, and thereby, maximizes the resultant heatup of the reactor coolant.

mA3254w.non\sec6c.wpf.lb-012997 6-174

i 1

h. No credit is taken for heat energy deposited in reactor coolant system metal during the reactor

! coolant system heatup. i i

i. Loss of offsite electrical power is assumed after the reactor trip, and teactor coolant flow '

f decreases to natural circulation. J. No credit is taken for charging and letdown. ; s

k. Steam generator heat transfer area is assumed to decrease as the shell-side liquid inventory l l decr.:ases. )

i

1.

i De ANS-5.1-1979 standard residual decay heat model (Reference 1) is assumed based on long j term oleration at the initial power level preceding the trip. ) m. Ausiliary feedwater delivery is assumed to be initiated following a conservative delay for l AFW pump startup, operator action to isolate the faulted loop, and an additional delay is assumed before the feedlines are purged and the relatively cold AFW enters the unaffected steam generators. Additional discussion with respect to AFW assumptions for Cases A and B is provided in FSAR subsection 15.4.2.2. 6.210.3 Description of Analysis He toasient response following a Feedwater Pipe Rupture event is calculated by a detailed digital simulation of the plant. De analysis models a simultaneous loss of main feedwater to all steam generators and subsequent reverse blowdown of the faulted steam genemtor. The analysis is performed using the LOFTRAN code (Reference 2). De code simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generators, and steam generator safety valves. De code computes pertinent plant variables including temperatures, pressures, and power level. 6.2.20.4 Acceptance Criteria i ne feedline rupture accident is an ANS Condition IV occurrence. Condition IV events are faults that are not expected to occur, but are postulated because their consequences would include the potential for release of significant amounts of radioactive material. He Standard Review Plan (Rev.1) requires that the specific criteria used in evaluating the consequences of the feedline rupture shall be:

1. Pressure in the reactor coolant and main steam systems should be maintained below 110% of the design pressures; mA3254w.non\sec6c.wpf.lb 012997 6-175

2. Any fuel damage that may occur during the transient should be of a sufficiently limited extent so that the core will remain in place and geometrically intact with no loss of core cooling capability; and

3. Any activity release must be such that the calculated doses at the site boundary are within a small fraction of the guidelines of 10 CFR Part 100.

To conservatively assure meeting these basic criteria, the intemal criterion established within Westinghouse is that no bulk boiling occurs in the primary coolant system following a feedline rupture prior to the time that the heat removal capability of the steam generators, being fed auxiliary feedwater, exceeds NSSS residual heat generation. 6.2.20.5 Results The current FSAR analysis of the Feedwater Pipe Rupture event, in support of steam generator level tap relocation, considered the uprated power level as discussed in subsection 6.2.20.2 above. An evaluation of the net effect of plant operating conditions associated with the power uprate on the current analysis concluded that the analysis criteria continue to be raet. Therefore, the results and conclusions presented in the FSAR remain valid. 6.2.20.6 Conclusions Results of the evaluation show that for the postulated feedline rupture, the assumed AFW system O capacity is adequate to remove core decay heat, to prevent overpressurizing the RCS, and to prevent uncovering the reactor core. 6.2.20.7 References

1. ANSI /ANS-5.1-1979, "American National Standard for Decay Heat Power in Light Water Reactors, August 29,1979

2. Bumett, T.W.T et al., "LOFTRAN Code Description", WCAP-7907-P-A (Proprietary),

WCAP-7907-A (Non-proprietary), April 1984 O m:\3254w.nonssec6e , wpf. I t>012997 6-176

6.2.21 Single Reactor Coolant Pump Locked Rotor 6.2.21.1 Identification of Causes and Accident Description The event postulated is an instantaneous seizure of a reactor coolant pump (RCP) rotor or the sudden break of the shaft of the RCP. Flow through the affected reactor coolant loop is rapidly reduced, leading to initiation of a reactor trip on a low reactor coolant loop 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 Reactor Coolant System (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 rete 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 scenarios. The analysis considers only one scenario; it represents the most-limiting combination of conditions for the locked rotor and pump shaft break events. 6.2.21.2 Input Parameters and Assumptions Tv.o 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 trarsient. This is done using the Standard Thermal Design Procedure. Initial core power, reactor coolant temperature, and pressure are assumed to be at their maximum values consistent with the uprated full-power conditions including allowances for calibration and instrument errors. This assumption results in a conservative calculation of the coolant insurge into the pressurizer, which in turn results in a maximum calculated peak RCS pressure. The second case is an evaluation of DNB in the core during the transient. This case is 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. m:\3254w.non\sec6e.wpf:!b-012997 6-177

Uncertainties in initial conditions are included in the departure from nucleate boiling ratio (DNBR) limit value as described in Reference 1. The RCS pressure case conservatively assumes a +7 pcm/*F moderator temperature coefficient (MTC); however, this is only permitted, via the plant Technical Specifications, below 70% RTP and ramps to O pcm/ F at hot full power (HFP) conditions. In contrast, the DNB case removes some of the inherent analytical conservatism by assuming a O pcm/*F moderator temperature coefficient at HFP. Both cases include a conservatively large (absolute value) of the Doppler-only power coefficient. Furthermore, the negative reactivity from control rod insertion / scram for both cases is conservatively based on 4.8% Ak/k trip reactivity from HFP. Normal reactor control systems and engineered safety systems (e.g., Safety Injection) 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. 6.2.21.3 Description of Analysis The following locked rotor / shaft break cases were previously analyzed and an evaluation was subsequently performed to support operation at uprated conditions.

1. Peak RCS pressure resulting from a locked rotor / shaft break in one-of three loops 2 Number of rods in-DNB resulting from a locked rotor / shaft break in one-of-three loops The pressure case is analyzed using two digital computer codes. The LOFTRAN code (Reference 2) is used to calculate the resulting loop and core flow transients following the pump seizure, the time of reactor trip based on the loop flow transients, the nuclear power following reactor trip, and the peak RCS pressure. The reactor coolant flow coastdown analysis performed by LOFfRAN 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, the as-built pump characteristics, and is based on conservative system pressure loss estimates. The thermal behavior of the fuel located at the core hot spot is investigated using the FACTRAN code (Reference 3) which uses the core flow and the nuclear power values calculated by LOFTRAN. The FACTRAN code includes a film boiling heat transfer coefficient.

The case analyzed to evaluate core DNB uses LOFTRAN, FACTRAN and the THINC code (References 4 and 5). The LOFTRAN and FACTRAN codes are used in the same manner previous case. The THINC code is used to calculate the DNBR during the transient based on the heat flux from FACTRAN and the flow from LOFTRAN. For the peak RCS pressure evaluation, the initial pressure is conservatively estimated as 50 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 m:\3254w.non\sec6e.wpf;ltr012997 6-178

4 i j 1 4 l drops are added to the calculated pressurizer pressure. The pressure response reported in Table 6.2.21-2 is at the point in the RCS having the maximum pressure, i.e., at the outlet of the RCP l in the faulted loop. l For a conservative analysis of fuel rod behavior, the hot spot evaluation assumes that DNB occurs at l the initiation of the transient and continues throughout the event. This assumption reduces heat l' I transfer to the coolant and results in conservatively high hot spot temperatures. i

. Evaluation of the Pressure Transient i

After pump seizure, the neutron flux rises due to the temperature increase and positive MTC and then f is rapidly reduced by control rod insertion. Rod motion is assumed to begin one second after the flow l j in the affected loop reaches 85 percent of nominal flow. No credit is taken for the pressure-reducing l effect of the pressurizer power-operated relief valves, pressurizer spray, steam dump or contro!!ed j 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 not including their effect. 1 The pressurizer safety valve model includes a 1% valve tolerance plus 3% valve accumulation above the nominal setpoint of 2500 psia. Evaluation of DNB in the Core Durine the Event ! j For this event, DNB is assumed to occur in the core; therefore, an evaluation of the consequences with ] j respect to fuel rod thermal transients is performed. Results obtamed from analysis of this " hot spot" ! condition r present the upper limit with respect to clad temperature and zirconium-water reaction. In the evaluation, the rod power at the hot spot conservatively considers anqF of 2.50. De number of {.

rods-in-DNB are conservatively calculated for use in dose consequence evaluations, i

I Film Boiline Coefficient The film boiling coefficient is calculated in the FACTRAN code (Reference 3) using the Bishop-Sandberg-Tong film boiling correlation. The fluid properties are evaluated at the film temperatum (average between the wall and bulk temperatures). De program calculates the film coefficient at every time step based upon the actcal heat transfer conditions at the time. The neutron flux, system pressure, bulk density, and mass flow rate as a function of time are used as program input. For this analysis, the initial values of the pressure and the bulk density are used throughout the transient since they are the most conservative with respect to the clad temperature response. As indicated earlier, DNB was assumed to occur from the beginning of the transient. mu254 .nonwc6e.wpr:ib.ci2997 6-179

Fuel Clad Gap Coefficient The magnitude and time dependence of the heat transfer coefficient between the fuel and clad (gap O coefficient) has a pronounced influence on the thermal results. The larger the value of the gap coefficient, the more heat is transferred between the pellet and clad. For the initial portion of the transient, a high pp coefficient produces higher clad temperatures since the heat stored and generated in the fuel redistributes itself in the cooler cladding. 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 Btu /hr-ft2 *F at the initiation of the transient. Thus, the large amount of energy stored in the fuel is released to the , clad at the initiation of the transient. l Zirconium-Steam Reaction The zirconium-steam reaction can become significant above 1800 F (clad temperature). The Baker-Just parabolic rate equation (Reference 3) is used to define the rate of the zirconium-steam reaction. The reaction heat is 1510 cal /g. The effect of zirconium-steam reaction is included in the calculation of the " hot spot" clad temperature transient. 6.2.21.4 Acceptance Criteria O! The RCP locked rotor accident is classified by the American Nuclear Society (ANS) as a Condition IV event. A RCP locked rotor results in a rapid reduction in forc ed reactor coolant loop flow which increases the reactor coolant temperature and subsequently causes the fuel cladding temperature and RCS pressure to increase. The following items summarize the criteria associated with this event. l = Fuel cladding damage, including melting, due to increased rcactor coolant temperatures must be prevented. This is precluded by demonstrating that the maximum clad temperature at the core hot spot remains below 2700*F, and the zirconium-water reaction at the core hot spot is less than 16 weight percent. Pressure in the reactor coolant system should be maintained below 110% of the design pressure. = Rods-in DNB (dose calculation) should be less than or equal to 20%. O m:\3254w.non\wc6e+pf;1b-012997 6-180

g 6.2.21.5 Results The calef , sequence of events is presented in Table 6.2.21-2 for the Locked Rotor event. With respect to the peak RCS pressure, peak clad temperature, zirconium-steam reaction, and maximum predicted rods-in-DNB, the analysis demonstrated that there is no significant impact on the transient results due to operation at uprated conditions. The results of the calculations (peak pressure, peak clad temperature, and zirconium-steam reaction) are summarized in Tab?.e 6.2.21-1. The rods-in-DNB criteria of less than 20% was also been met. The transient results for the peak pressure / hot spot case, which is also presented in Chapter 15 of the FSAR, are provided in Figures 6.2.21-1 through 6.2.21-6. 6.2.21.6 Conclusions The analysis performed at uprated conditions demonstrates that, for the Locked Rotor event, 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. Under such conditions, the core will remain in place and intact with no loss of core cooling capability. The analysis also confirms that the peak RCS pressure reached during the transient is less than 110% of the RCS design pressure, and thereby, the integrity of the primary coolant system is not endangered. , The rods-in-DNB design criteria is also met. Therefore, the conclusions presented in the FSAR remain I valid. The protection features described in Section 6.2.21.1 provide mitigation for a locked rotor transient such that the above criteria are satisfied. 1 6.2.21.7 References :

1. Friedland, A. J. and Ray, S.," Revised Thermal Design Procedure", WCAP-ll397-P-A, April 1989. (Proprietary) l 2. Burnett, T.W.T et al., "LOITRAN CoJe 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 UO2 Fuel Rod", WCAP-7908-A, December 1989

4. Shefcheck, J., " Application of the THINC Program to PWR Design," WCAP-7359-L, August 1969

5. Chelemer, H., Chu, P. T., Hochreiter, L. E., "THINC-IV - An Improved Program for Thermal-

   /           Hydraulic Analysis of Rod Bundle Cores," WCAP-7956, February 1989 mA3254w.non\sec6e.wpf:1b-012997                    6 ]81

/ TABLE 6.2.21 1

SUMMARY

OF RESULTS FOR THE LOCKED ROTOR TRANSIENT 3 Loops initially Operating, One Criteria Locked Rotor Limit Maximum Clad Temperature at Core Hot Spot, 'F 2165 2700.0 Maximum Zr-H 2O Reaction at Core Hot Spot, wt. % l.0 16.0 Maximum RCS Pressure, psia 2701 2748.5 TABLE 6.2.212 SEQUENCE OF EVENTS - LOCKED ROTOR TRANSIENT Time Event (sec) Rotor on one pump locked or the shaft breaks 0.0 Low flow reactor trip setpoint reached 0.03 I Rods begin to drop 1.03 Remaining pumps lose power and begin to coastdow1 3.03 Maximum RCS pressure occurs 3.1 Maximum clad temperature occurs 3.8 1 l l m:\3254w.non\sec6e wpf;1b-012997 6-182

4 l 4 l U ! T 2,800 k l g 2,700 -

,          3 f

h 2,600 - l E l 2 2,500 - u) 2,400 - O. m 2,300 - g 2,200 2,100 - m 2'M ' O 1 2 3 4 5 6 7 8 9 10 TIME (SEC) I I O Figure 6.2.21 1 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Reactor Coolant System Pressure versus Time m:u2w.nonsec6e wpr.1b-012997 6-183

l 1 0' k1.4 Z_ 2 0 1.2 - z 1 0 1 - z O { 0.8 0.8 - b s N g 0.4 - 8 g 0.2 - .J ho h 0 1 2 3 4 5 6 7 8 9 10 TIME (SEC) 2 g 1.4 G z 1.2 - u. O 1 - 2 0 0 .8 - b 0.6 g b 0.4 - 3C 0.2 - a 0 (0.2) (0.4) 0 1 2 3 k 6 7 8 10 1 TIME (SEC) Figure 6.2.212 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Total RCS and Faulted Loop Flow versus Time i m:\3254w.non\sec6e wpf.lb-012997 6-184

1 4 O i 2 .2 Er l E 2 - 1.8 - b 1.6 - 1.4 - 1.2 - m 1 - 0.8 - l E 0.6 - 6 g0.4 -

0.2 -

1 0 ! O 1 2 3 4 5 6 7 8 9 10 TIME (SEC) l l O Figure 6.2.213 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Nuclear Power versus Time m:\3254 w .non\sec6e .wpf. l b-012997 6-185

1 O i l i 1.4 x 1.2 - o W H 2 1 d< ZZ i db z 0.8 - $zu. zO Oz 0.6 - tu O O 5 0.4 - 0.2 -

                              '      '         '       '       '     '       '      '       '              l 0                                                                                             !

0 1 2 3 4 5 6 7 8 9 10 TIME (SEC) j I 1 O Figure 6.2.21-4 All Loops initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Average Channel Heat Flux versus Tirae m:\3254w. mon \sec6e wpf:lb-012997 6-186

l I - 1 I i e

O i

4 l 1 l 1.4 1 1.2 - 8 i 1 f \ I 0.8 - w OXd 0.6 3 I I 0.4 - d Z Z

     < 0.2       -

I O

     @       0 O         1           2        3        4                 5        6 7    8   9       10 TIME (SEC)

O Figure 6.2.215 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Hot Channel Heat Flux versus Time m:\3254wmon\sec6e wpf;Ib-012997 6-]87

O 3,000 2,750 - C L 2,500 - W C 2,250 - w 2,000 - 2 1,750 m

 @     1,500    -

a o 1,250 - 5 0 1,000 750 - 500 O 1 2 3 4 5 6 7 8 9 10 TIME (SEC) O Figure 6.2.21-6 All Loops Initially Operating, One Locked Rotor (Peak Pressure / Hot Spot) Clad Inner Temperature versus Time m:\3254w.non\sec6e wpf.1b-012997 6-188

l l 1 p 6.2.22 Rupture of a Control Rod Drive Mechanism Housing (Rod Cluster Control V Assembly Ejection) l 6.2.22,1 Identification of Causes and Accident Description l l 1 This accident is defined 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 insenion together with an adverse core power j 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 l by reactor trip actuated by high nuclear power signals. l 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 4100 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.

(O/

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 I components.

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. In general, the reactor is operated with the rod cluster control assemblies inserted only far enough to control design neutron flux shape. Reactivity changes caused by the core depletion are compensated by boron changes. 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 control assemblies is continuously indicated in the control room. An alann will occur if a bank of rod mu2sawnonssec6e wptit 012997 6-189

cluster control assemblies approaches its insenion limit or if one control rod assembly deviated from its bank. There are low and low-low level insertion alarm circuits for each bank. The control rod position monitoring and alann systems are described in Reference 1. 6.2.22.2 Input Parameters and Assumptions input parameters for the analysis are conservatively selected on the basis of values calculated for this type of core. The most important parameters are discussed below. Table 6.2.22-1 presents the parameters used in this analysis. Eiected Rod Wonhs and Hot Channel Factors l l The values for ejected rod wonhs and hot channel factors are calculated using either three-dimensional ' static methods or a synthesis of one-dimensional and two-dimensional calculations. Standard nuclear design codes are used in the analysis. No credit is taken for the flux flattening effects of reactivity feedback. The calculation is performed for the maximum allowed bank insertion at a given power level, as determined by the rod insertion limits. The analysis assumes adverse xenon distributions to j provide worst-case results. Appropriate margins are added to the ejected rod worth and hot channel factors to account for any calculational uncertainties, including an allowance for nuclear power peaking due to fuel densification. Power distributions before and after ejection for a worst case" can be found in Reference 1. During plant stanup physics testing, ejected rod wonhs and power distribu'. ions have been measured in the zero and full power configurations and compared to v.Jues used in the analysis. Experience has shown that the ejected rod worth and power peaking factors are consistently over predicted in the analysis. Delayed Neutron Fraction. B 1

Calculations of the effective delayed neutron fraction ( .n) typically yield values of approximately 0.65 percent at beginning of life and 0.48 percent at end of life. The ejected rod accident is sensitive to if the ejected rod wonh is equal to or greater than ,,, as in the zero-power transients. In order to allow for future fuel cycle flexibtitty, conservative estimates of of 0.54 percent at beginning of cycle and 0.45 percent at end of cycle are used in the analysis. Reactivity Weichtine Factor The largest temperature rises, and hence the largest reactivity feedbacks, occur in channels where the power is higher than average. Since the weight of a region is dependent on flux, these regions have high weights. This means tha, the reactivity feedback is larger than that indicated by a simple 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. mu:54w.nonsec6e.wnt:itwo 2997 6-190

l

p Reactivity changes were compared and effective weighting factors determined. These weighting d factors take the form of multipliers which, when applied to single-channel feedbacks, correct them to effective whole-core feedbacks for the appropriate Hux shape. In this analysis, a one-dimensional l (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 Dyly, Coefficient The critici h , r ncentrations at the beginning of life and end of life are adjusted in the nuclear code in orce c .s . lin moderator density coefficient curves which are conservative when compared to the actual design. conditions for the plant. As discussed above, r.o weighting factor is applied to these i 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 5 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 j The FACTRAN (Reference 2) code used to determine the hot spot transient r.ontains 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. Tne 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 Bru/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. 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 second order changes in the cladding and centerline fuel temperatures. All zero power analyses for both average core and the hot spot have been conducted assuming two pumps in operation. mmw nonsec6e wpt.id-oi2997 6-191

 'Trin Reactivity Insertion The trip reactivity insertion is assumed to be 4.8% Ap from hot full power and 1.77% Ap from hot O

zero power, including the effect of one stuck RCCA. These values are also reduced by the ejected rod. The shutdown reactivity is simulated by dropping a rod of the required worth into the core. The start of rod motion occurs 0.5 seconds after reaching the power range high neutron flux trip setpoint. It is assumed that insertion to dashpot does not occur until 2.7 seconds after the rods begin to fall. The time delay to full insertion, combined with the 0.5 second trip delay, conservatively delays insertion of shutdown reactivity into the core. The minimum design shutdown margin available for this plant at hot zero power (HZP) may only occur at end of life in the equilibrium cycle. This value includes an allowance for the worst stuck rod, an adverse xenon distribution, conservative Doppler and moderator defects, and an allowancegr calculational uncertainties. Physics calculations have shown that two stuck RCCAs (one of which is the worst ejected rod) reduce the shutdown margin by about an additional 1% Ap. Therefore, following a reactor trip resulting from an RCCA ejection accident, the reactor will be suberitical when the core returns to HZP. 6.2.22.3 Description of Analysis This 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, first 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 t .uicus 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 I generation by the hot channel factor and performing a fuel rod transient heat transfer cale.,lation. The I 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, l 1 Averare Core l The spatial-kinetics computer code, TWINKLE (Reference 3) 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 multi-region, transient fuel-clad-coolant heat , transfer model for calculation of pointwise Doppler and moderator feedback effects. This analysis l i 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 mA3254w.non\sec6e.wpf:Ib-012997 6-192

dimension is missing, it is still necessary to employ very conservative methods (described below) of calculating the ejected rod worth and hot channel factor. i Hot Soot Analysis i In the hot spot analysis, the initial heat flux is equal to the nominal times the design hot channel i 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. Therefore, 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 l region will necessarily be depressed. l l 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 I code, FACTRAN (Re'erence 2). T .is computer code calculates the transient temperature distribution in a cross section of a metal clad UO2 fuel rod, and the heat flux at the swface of the rod, using as input the nuclear power versus time and local coolant conditions. De zirconium-water reaction is explicitly represented, and all material properties are represented as functions of temperature. A parabolic radial power distribution is assumed within the fuel rod. i l l FACTRAN uses the Dittus-Boelter or Jens-Lottes correlation to determine the film heat transfer before \. DNB, and the Bishop-Sandberg-Tong cor elation (Reference 4) to determine the film boiling coefficient after DNB. The Bishop-Sandberg-Tong correlation is conservatively used assuming zero bulk fluid quality. De DNB heat flux is not calculated, instead the 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 to force the full-power, steady-state temperature distribution to agree with fuel heat transfer design codes. Reactor Protection The protection for this accident, as explicitly modeled in the analysis, is provided by the power range ; high neutron flux trip (high and low settings). The power range high neutron flux positive rate trip, as ! noted in the bases of the FNP Technical Specifications, complements the high and low flux trip ! functions to ensure that the criteria are met for rod ejection from partial power. 6.2.22.4 Acceptance Criteria Due to the extremely low probability of a rod cluster control assembly ejection accident, this event is classified as an ANS Condition IV event. As such, some fuel damage could be considered an acceptable consequence. Comprehensive studies of the threshold of fuel failure and of the threshold of significant conversion of the fuel thermal energy to mechanical energy have been carried out as part of the SPERT project by m:\3254w .non\sec6e.wpf. l b-012997 6-193

i i the Idaho Nuclear Corporation (Reference 5,. Extensive tests of UO2 zirconium-clad fuel rods i representative of those present in pressurized water reactor-type cores have demonstrated failure ! thresholds in the range of 240 to 257 cal /gm. However, other rods of a slightly different design . exhibited failure as low as 225 cal /gm. These results differ significantly from the TREAT ! (Reference 6) results which indicated a failure threshold of 280 cal /gm. Limited results have indicated that this threshold decirased 10 percent with fuel bunup. The clad failure mechanism appears to be melting for unirradiated (zero bumup) rods and brittle fracture for irradiated rods. The conversion ratio of thermal to mechanical energy is also important. This ratio becomes marginally detectable above 300 cal /gm for unirradiated rods and 200 cal /gm for irradiated rods; catastrophic failure (large fuel dispersal, large pressure rise), even for irradiated rods, did not occur below 300 cal /gm. 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 ensure fuel dispersal in the coolant, gross lattice distortion or severe shock waves will not occur. In view of the above experimental results, and the conclusions of WCAP-7588, Rev. I-A (Reference 1) and Reference 7, the limiting criteria are:

a. Average fuel pellet enthalpy at the hot spot must be maintained below 225 cal /gm for unitradiated and 200 cal /gm for irradiated fuel (the 200 cal /gm limit is applied);

b. Peak reactor coolant pressure must be less than that which could cause RCS stresses to exceed the faulted-condition stress limits; and

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.

6.2.22.5 Results i 4 I The current analysis of the Rod Ejection event, presented in FSAR Section 15.4.6, was performed at the uprate power level of 2775 MWt core power. Hence, the current analysis is conservative with respect to plant parameters directly related to operation at uprated conditions. In support of ZIRLO l clad fuel being implemented at the Farley units, revised fuel average and surface temperatures were incorporated into revised HFP rod ejection analyses supporting the plant uprate. The increased fuel temperatures impact the Rod Ejection calculations performed at hot full power only. The current rod ejection analyses at HZP conditions remain valid for the plant uprate. 1 Results of the analyses performed for the Rod Ejection event, which cover beginning and end-of-life conditions at hot full power, are discussed below. O l m:U254w.nonhec6e.wpf:Ib-012997 6-194 1

                          . __ . . - -   _ -           _.        .-     --    --       _~. -_-             .  ._ -

i . l l Beginning of Cycle. Full Power 5

4 Control bank D is assumed to be inserted to its insertion limit. The worst ejected rod wonh and hot channel factor are conservatively calculated to be 0.20% AK and 6.0, respectively. The peak hot spot average fuel pellet enthalpy is 175.5 cal /gm compared to 175 cal /gm previously reponed in the FSAR. The peak fuel centerline temperature reached the BOL melt temperature of 4900*F however, fuel melting remains well below the limiting criterion of 10 percent of total pellet volume at the hot spot. , Hence, the effect of the increase fuel temperatures, due to ZIRLO clad fuel, is minimal. l 8 , End of Cycle. Full Power j Control bank D is assumed to be insened to its insertion limit. The ejected rod wonh and hot channel factors are conservatively calculated to be 0.21% AK and 7.0 respectively. The peak hot spot average fuel pellet enthalpy is 168.0 cal /gm compared to 165.2 cal /gm previously reported in the FSAR. The j peak fuel centerline temperature reached melting, conservatively assumed at 4800*F; however, fuel

melting remains well below the limiting criterion of 10% of the pellet volume at the hot spot. Hence,
the effect of the increase fuel temperatures, due to ZIRLO clad fuel, is minimal.

1 A summary of the parameters used in the Rod Ejection analyses, and the analysis results, are presented j in Table 6.2.22-1. The results presented for the hot zero power cases are from the current licensing c basis analysis, which also bounds operation at uprated conditions. The updated sequence of events for the revised hot full power analyses are presented in Table 6.2.22-2. The revised BOL HFP transient { results do not vary significantly from the results presented in FSAR Figures 15.4-40 and 15.4-41. Figures 6.2.22-1 and 6.2.22-2 show the new transient curves. A detailed calculation of the pressure rurge for an ejected rod wonh of one dollar at beginning of life, 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 funher adverse effects to the RCS. 6.2.22.6 Conclusions Despite the conservative assumptions, the analyses indicate that the described fuel and clad limits are not exceeded. It is concluded that there is no danger of sudden fuel dispersal into the coolant. Since the peak pressure does not exceed that which would cause stresses to exceed the faulted condition stress limits, it is concluded that there is no danger of funher consequential damage to the RCS. The analyses demonstrate that the fission product release as a result of fuel rods entering DNB is limited to less than 10 percent of the fuel rods in the core.

   =\ W

m a\sec6e *Pf:1tw012997 6.}95

6.2.22.7 References

1. Risher, D. H., "An Evaluation of the Rod Ejection Accident in Westinghouse Pressurized Water Reactors using Special Kinetics Methods," WCAP-7588; Rev. I A, January 1975

2. Hargrove, H. G., "FACTRAN, a FORTRAN IV Code for Thermal Transients in a UO2 Fuel Rod," WCAP-7908-A, December 1989

3. Bany, R. F., Jr. and Risher, D. H., " TWINKLE, a Multi-dimensional Neutron Kinetics Computer Code," WCAP-7979-P-A, January 1975 (Propnetary) and WCAP-8028-A, January 1975 (Non-Proprietary)

4. Bishop, A. A., Sandberg, R. O. and Tong, L. S., " Forced Convection Heat Transfer at High Pressure After the Critical Heat Flux," ASME 65-HT-31, August 1965

5. Taxebius, T. G., ed., " Annual Report - SPERT Project, October 1968 - September 1969,"

IN-1370 Idaho Nuclear Corporation, June 1970

6. Liimatainen, R. C. and Testa, F. J., " Studies in TREAT of Zirealoy 2-Clad, UO2-Core Simulated Fuel Elements," ANL-7225, P 177, November 1966

7. 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

mV254w.non\sec6c.wpf.lb-012997 6-196

l TABLE 6.2.221 RESULTS OF THE ROD CLUSTER CONTROL ASSEMBLY EJECTION ACCIDENT ANALYSIS l Beginning of Beginning End of End of Cycle of Cycle Cycle Cycle Power level, percent 102 0 102 0 Ejected rod worth percent AK 0.20 0.75 0.21 0.945 Delayed neutron fraction, percent 0.54 0.54 0.44 0.44 Feedback reactivity weighting 1.30 2.07 1.3 3.19 Trip reactivity percent AK 4.8 1.52 4.8 1,715 F, before rod ejection 2.50 -- 2.50 - F, before rod ejection 6.0 13.0 7.0 22.0 I Number of operational pumps 3 2 3 2 ; Max fuel pellet average temperature. 'F 4023 3316 3878 3833 Max fuel centerline temperature. *F > 4900 3935 > 4800 4319 Max fuel stored energy, cal /g 175.5 139.4 168.0 165.7 Fuel melt at the hot spot percent < 10 0 < 10 0 m.\3254w .non\secfc. wpf. l b.012997 6-197

TABLE 6.2.22-2 l SEQUENCE OF EVENTS RCCA EJECTION ACCIDENT Event Time (sec) l Case BOL, full power Initiation of Rod Ejection 0.0 Power Range High Neutron Flux Setpoint Reached 0.05 Peak Nuclear Power Occurs 0.13 I Rods Begin to Fall 0.55 Peak Fuel Average Temperature Occurs 2.44 Peak Clad Temperature Occurs 2.56

Peak Heat Flux Occurs 2.57 EOL, full power Initiation of Rod Ejection 0.0 Power Range High Neutron Flux Setpoint Reached 0.05 Peak Nuclear Power Occurs 0.13 Rods Begin to Fall 0.55 Peak Fuel Average Temperature Occurs 2.18 Peak Clad Temperature Occurs 2.30 Peak Heat Flux Occurs 2.31 a

1

J O m:\3254w.non\sec6e wpf.It>012997 6-198

 .-. _.. -.. -.              .-                 _ - . . . _ - _ . . - - . - . - . - .           -- .   - =.-._ -.           .- - - - - . . . . ..

1 I i l l 1 i I i 1 l \ ;

3. l l l-1 1 1 2.5' l

er 2.< i

                        -   ,.5 I

5 d i l 1. l I 1 l

                              .5 1

e.e 1 2 & 4 s a 7 a e to TMAE(s) l l l Figure 6.2.22-1 RCCA Ejection, BOL HFP, Nuclear Power versus Time m:u254w.noom.wpf.ib.ot2997 6-199

... . _ _ . - _ . _ . . - . - . - - - . ~ . . _ _ - - . . . _ _ - . _ . - . . _ . . . . _ - _ _ - . _ . . . O

                         .ooo run, DELT!Is 4900'F .

sooo< FUEL CDITER TDP E ** ' y f FUEL AVERAGE TDFERA1ME sono < CLAD TDFERA tooo ' o o 1 2 3 4 s s 7 s TME(s) O Figure 6.2.22 2 RCCA Ejection, BOL HFP, Hot Spot Fuel and Clad Temperatures versus Time m:\3254w.non\sec6e.wpf;1b-012997 6-200

6.2.23 Steam System Piping Failure at Full Power NRC review and approval for this event was received as part of OTAT/OPAT setpoint revisions. The details are not included in this repon. m:\3254w.monWc6e.wpf:Ib-012997 6-201

6.3 Steam Generator Tube Rupture Transient 6.3.1 Introduction O. In suppon of the Farley Units 1 and 2 uprating program, a steam generator tube rupture (SGTR) thermal-hydraulic analysis for offsite activity release has been performed. The SGTR analysis incorporates a T,,, window range of 567.2*F up to 577.2*F as pan of the plant uprating effort. Plant secondary side conditions (e.g., steam pressure, flow, temperature) are based on high and low tube plugging (0% up to 20% average / peak) to bound all possible conditions 'Iherefore, four separate cases have been analyzed as follows.

1. T,,, = 577.2*F and SGTP = 20% average / peak

2. T,,, = 577.2*F and SGTP = 0%

3. T,,, = 567.2*F and SGTP = 20% average / peak

4. T,., = 567.2*F and SGTP = 0%

The major hazard associated with an SGTR event is the offsite doses resulting from the transfer of radioactive reactor coolant to the secondary side of the ruptured steam generator (SG) and subsequent release of radioactivity to the atmosphere. Acceptance criteria for offsite doses are expressed as maximum allowed gamma body and thyroid doses at the exclusion area boundary and low population zone as defined in 10 CFR 100 and Standard Review Plan 15.6.3. The primary thermal-hydraulic parameters which affect the calculation of offsite doses for an SGTR include the amount of reactor coolant transferred to the secondary side of the ruptured steam generator and the amount of steam released from the ruptured steam generator to the atmosphere. The accident analyzed is the double-ended rupture of a single steam generator tube. It is assumed that the primary-to-secondary break flow following an SGTR results in depressurization 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 atmo:phere via the steam generator atmospheric relief valves (ARVs) and/or safety valves. Following xtuation, it is assumed that the RCS pressure stabilizes at the value where the SI and break fic rates are equal. The equilibrium primary-to-secondary break flow is assumed to persist until 30 m nutes after the initiation of the SGTR, at which time it is assumed that the operators have completed the actions necessary to terminate the break flow and the steam release from the ruptured steam generator. After 30 minutes, it is assumed in the FSAR analysis 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 residual heat removal (RHR) system operating conditions. It is assumed that plant cooldown to RHR operating conditions is accomplished within 8 hours after initiation of the SGTR and that steam releases are terminated at that time. A primary and secondary side mass and energy balance is used to mA3254w.non\sec6fgf.lM12997 6-202

_ _ . _ . . ~ . _ . . _ . . .___..__m._ - _ _ _ _ ._ _._.. _ _ _ _ _ ._ _ _ l {

<                                                                                                                                                            I

calculate the steam release and feedwater flow for the intact steam generators from 0 to 2 hours and l
from 2 to 8 hours. i 1 i i

6.3.2 Input Parameters and Assumptions j i . i 4 1 d He primary and secondary side operating conditions used in this analysis are summarized in Chapter 2 of this report. A summary of key input assumptions for the SGTR event follows. l 3 Hirh Head Safety Iniection (HHSI) Flow Rates !

t i

i A larger SI flow rate results in a greater RCS equilibrium pressure and, consequently, higher break . i flow. Maximum HHS1 flowrates were therefore assumed for this analysis. ! I ! } RHR Cut-in Time l i i I 4 The RHR cut-in time based on the RCS heat load and RHR heat removal capacity is conservatively j calchlated and modeled in the SGTR analysis. His cut-in time affects the duration of long term steam l l } rele: des from the intact steam generators to the atmosphere following termmation of the break flow. i 9

The effect of RHR cut-in time on long term doses, however, is not significant since the radiation !

] released from the intact steam generators is small relative to that released by the ruptured steam l generator. An RHR cut-in time of eight hours has been assumed and shown to be sufficient. j ) I Miscellamus Parameter Assumptions I 3

Low pressurizer pressure SI actuation setpoint = 1864.7 psia 3

i a Lowest SG safety valve rescat pressure = 950.2 psia - includes 13% MSSV blowdown which j covers the -3% safety valve setpoint tolerance i I I 6.3.3 Description of Analyses Pe formed l l l A T,,, window of 567.2'F up to 577.2*F is considered as part of the plant uprating effort. Chapter 2 documents six Performance Capability Working Group (PCWG) cases which have been used for the l Farley plant uprating. Cases 1, 2, and 3 are analyzed at a T,,, of 577.2*F, while Cases 4,5, and 6 are analyzed at a T,,, of ; i 567.2*F. Cases 3 and 6 support a uniform tube plugging level of 20%, while Cases 1 and 4 are 1 performed with no tube plugging. He cases with 15% average SGTP (Cases 2 and 5) are not j considered since they are bounded by the other cases. All the cases support an uprating to 2785 MWt ] (NSSS power), thermal design flow (TDF) of 86,000 gpm/ loop, and the curient 17 x 17 V5 fuel. i l 4 m:\3254w.monWf wpf.lb-012997 6-203

             - er .                           _ , - . , . - _ . -
                                                                         , , - .    .-     _ ,       ._ _ , ,   ,_.,,m- ,__ _ , . . .,,,, ,, .- - - . .e - ,

In total, four PCWG cases are considered in the SGTR therrral-hydraulic analysis to cover the plant uprating. Note that these four PCWG cases are individually an.slyzed in order to determine the steam releases and break flow for the offsite dose evaluation between 0 and 30 minutes (break flow termination). A single calculation is performed to calculate long term steam releases from the intact steam generators for the time interval 30 minutes to 2 hours. From 2 hours to RHR cut-in at 8 hours, the same four sets of PCWG parameters are used in the calculation. 6.3.4 Results ne tube rupture break flow, atmospheric steam releases, and feedwater flows for the four different SGTR cases, as discussed in Section 6.3.3, are summarized in Table 6.3-1. Based on the results of these four SGTR cases, bounding values for break flow and steam releases are provided in Table 6.3-2 for use in radiological doses analysis. For example, the bounding values for steam release and break flow between 0 and 30 minutes (time of break flow termination) are based on the four different SGTR cases as discussed in Section 6.3.3. The bounding values in Table 6.3 2 are approximately 5% higher I than the worst-case results shown in Table 6.3-1. For an SGTR event, the amount of radioactivity ; released to the atmosphere is directly proportional to the amount of steam released through the safety ; valves associated with the ruptured steam generator. Therefore, the worst radiological consequences result from the SGTR case with the greatest amount of steam released. Likewise, a greater break flow results in greater radiological contamination of the secondary side which in turn results in a greater amount of activity released along with the steam. Maximum break flow and steam release, therefore, < represent bounding values which are conservative for an offsite dose evaluation. He SGTR thermal-hydraulic analysis results for the power uprating can be compared to the Farley i FSAR results. Per the Farley FSAR, 139,100 lbm of reactor coolant are discharged into the ruptured steam generator and 65,500 lbm cf steam are released to atmosphere during the 30 minute period assumed for isolation of the affected steam generator. Table 6.3-2 shows that for the power uprate ! analysis, 150,000 lbm (7.8% increase) of reactor coolant are discharged into the steam generator and 73,300 lbm (11.9% increase) of steam are released to atmosphere. , ne 7.8% increase in primary-to-secondary break flow can be attributed to a significantly lower steam generator safety value rescat pressure (950 vs.1057 psia) following reactor trip. This factor contributes to a larger primary-to-secondary pressure drop and, hence, break flow rate for the plant uprate. Note that the lower steam generator pressure following reactor trip is due to an increase in the assumed MSSV blowdown to 13%, which covers the MSSV setpoint tolerance of -3%. l The 11.9% increase in steam released to the atmosphere during the 30 minute period assumed for isolation of the ruptured steam generator is due to the following factors: (1) 4.7% increase in thermal power; (2) lower MSSV rescat pressure as discussed above; and (3) greater priraary-to-secondary break flow (150,000 lbm vs.139,100 lbm). O mV254w.non\sec6f.wpf.lb-012997 6-204

1 1 6.3.5 Conclusions The SGTR thermal hydraulic analysis for offsite activity release has been completed in support of the Farley 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 system operating conditions. For Farley, it was assumed that plant cooldown to RHR operating conditions can be accomplished within 8 hours after initiation of the SGTR event and that steam releases 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 hours and from 2 to 8 hours. The SGTR thermal-hydraulic analysis results were compared to the Farley FSAR results. For the plant uprating, the resultant primary to-secondary break flow and steam releases were increased. The results of the SGTR analysis were provided for use in the radiological dose analysis (see BOP Licensing Report). s O m:u254. ons c6turt:ib-os2997 6-205

TABLE 6.3 I SGTR THERMAL-HYDRAULIC RESULTS FOR FARLEY Tube Rupture Break Flow for 0 - 30 Minutes T.,, = 577.2'F,20% SGTP 141,952 lbm T,,, = 577.2*F,0% SGTP 141,561 lbm T.,, = 567.2*F,20% SGTP 142,562 lbm T , = 567.2*F,0% SGTP 142,224 lbm Steam Release from Ruptured SG for 0 - 30 Minutes T,., = 577.2*F,20% SGTP 66,926 lbm T,., = 577.2'F,0% SGTP 69,752 lbm T.,, = 567.2'F, 20% SGTP 61,460 lbm T , = 567.2*F,0% SGTP 64,178 lbm Steam Release from Intact SGs for 0 - 2 Hours T , = 577.2'F,20% SGTP 375,117 lbm 380,768 lbm T,,, = $77.2*F,0% SGTP T,,, = 567.2'F,20% SGTP 364,185 lbm T,., = 567.2'F,0% SGTP 369,621 lbm Feedwater Flow to Intact SGs for 0 - 2 Houn T,,, = 577.2'F, 20% SGTP 304,079 lbm T.,, = 577.2*F,0% SGTP 303,876 lbm l T ., = 567.2'F 20% SGTP 304,392 lbm T,., = 567.2'F,0% SGTP 304,220 lbm Steam Release from Intact SGs for 2 - 8 Houn 845,563 lbm j T,,, = 577.2*F,20% SGTP l T,,, = 577.2'F,0% SGTP 845,251 lbm l 1 846,640 lbm l T ., = 567.2*F, 20% SGTP 846,471 lbm T,,, = 567.2'F,0% SGTP O l m:\3254w.nonisec6f.wpf.It>412997 6-206

f 1 TABLE 6.3-1 (cont.) 1 SGTR THERMAL-HYDRAULIC RESULTS FOR FARLEY

Feedwater Flow to Intact SGs for 2 - 8 Hours i

i T , = 577.2'F,20% SGTP 889,282 lbm T,., = $77.2'F,0% SGTP 888,584 lbm i T,,, = 567.2*F, 20% SGTP 891,677 lbm a T , = 567.2'F,0% SGTP 891,298 lbm 2 Initial Ruptured SG Water Mass T,,, = 577.2*F,20% SGTP 102,912 lbm i T.,, = 577.2*F,0% SGTP 105,043 lbm T,,, = 567.2*F, 20% SGTP 100,250 lbm T,., = 567.2'F,0% SGTP 102,664 lbm Final Ruptured SG Water Mass at 30 Minutes j T , = 577.2'F,20% SGTP 104,464 lbm i T,., = 577.2*F,0% SGTP 103,548 lbm 107,610 lbm T,,, = 567.2'F,20% SGTP T,,, = 567.2*F,0% SGTP 107.117 lbm l i i i 1 i i s j i 4 4 m:\3254w.non\sec6f.wpf:lb-012997 6-207

TABLE 6.3-2 BOUNDING SGTR THERMAL HYDRAULIC RESULTS FOR FARLEY RADIOLOGICAL DOSE ANALYSIS Tube Rupture Break Flow for 0 - 30 Minutes 150,000 lbm Steam Release from Ruptured SG for 0 - 30 Minutes 73,300 lbm Steam Release from Intact SGs for 0 - 2 Hours 400,000 lbm Steam Release from Intact SGs for 2 - 8 Hours 889,000 lbm l O l l l i l 1 m:\3254w.non\sec6f wpf:1t412997 6-208

6.4 LOCA Mass and Energy Releases The uncontrolled release of pressurized high temperature reactor coolant, termed a Loss-cf-Coolant Accident (LOCA), will result in release of steam and water into the containment. His, in turn, will result in increases in the local subcompanment pressures, and an increase in the global containment pressure and temperature. Derefore, there are both long and short term issues reviewed relative to a l postulated LOCA that must be considered at the uprated conditions for Farley Units I and 2. The long-tenn LOCA mass and energy releases are analyzed to approximately 10' seconds and are utilized as input to the containment integrity analysis, which demonstrates the acceptability of the containment safeguards systems to mitigate the consequences of a hypothetical large break LOCA. ! The containment safeguards systems must be capable of limiting the peak containment pressure to less than the design pressure and to limit the temperature excursion to less than the Environmental Qualification (EQ) acceptance limits. For this program, Westinghouse generated the mass and energy releases using the March 1979 model, described in Reference 1. He NRC review and approval letter is included with Reference 1. Even though this is a first time application of this methodology for Farley Units I and 2, it has also been utilized and approved on many plant-specific dockets. Section 6.4.1 discusses the long-term LOCA mass and energy releases generated for this program. The resuks of this analysis were provided for use in the containment integrity analysis and environmental qualification (EQ) reviews (see BOP Licensing Repon). The short-term LOCA-related mass and energy releases are used as input to the subcogipizat analyses, which are performed to ensure that se walls of a subcompartment can maintain their structural integrity during the short pressure pulse (generally less than 3 seconds) accompanying a high energy line pipe rupture within that subcompartment. De subcoriprents evaluated include the steam generator compartment, the reactor cavity region, and the pressurizer compartment. For the steam generator compartment and the reactor cavity region, the fact that Farley is approved for leak-Before-Break (LBB) was used to qualitatively demonstrate that any changes associated with the ) uprating program are offset by the LBB benefit of using the smaller RCS nozzle breaks, thus l demonstrating that the current licensing bases for these subcompartments remain bounding. For the pressurizer compartment, the critical mass flux correlation utilized in the SATAN computer program l l (Reference 4) was used to conservatively estimate the impact of the changes in RCS temperatures on the short term releases. De evaluation showed that the releases would increase by 18% Section 6.4.2 discusses the short-term evaluation conducted for this program. De results of this evaluation were provided for use in the pressurizer subcompartment evaluation (see BOP Licensing Repon). . i I 6.4.1 Long-Term LOCA Mass and Energy Releases The mass and energy release rates described in this section form the basis of further computations by f , SCS to evaluate the containment following the postulated accident. Discussed in this section are the I l l l mA3254w.non\sec6f.wpf.Ib 012997 6-209 , l E .-. __ -

long-term LOCA mass and energy releases for the hypothetical double-ended pump suction (DEPS) rupture and double-ended hot leg (DEHL) rupture break cases. 6.4.1.1 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. Where appropriate, bounding inputs are utilized and instrumentation uncertainties are included. For example, the RCS operating temperatures are chosen to bound the highest average coolant temperature range of all operating cases, and a temperature uncenainty allowance of (+6.0*F) is then added. Nominal parameters are used in cenain instances. For example, the reactor coolant system (RCS) pressure in this analysis is based on a nominal value of 2250 psia plus an uncertainty allowance (+50 psi). All input parameters are chosen consistent with accepted analysis methodology. Some of the most-critical items are the RCS initial conditions, core decay heat, safety injection flow, and primary and secondary metal mass and steam generator heat release modeling. Specific assumptions conceming each of these items are next discussed. Tables 6.4.1-1 through 6.4.1-3 present key data assumed in the analysis. The core rated power of 2775 MWt adjusted for calorimetric error (+2 percent of power) was used in the analysis. As previously noted, the use of RCS operating temperatures to bound the highest nyerage coolant temperature range were used as bounding analysis conditions. The use of higher temperatures is conservative because the initial fluid energy is based on coolant temperatures which are at the maximum levels attained in steady state operation. Additionally, an allowance to account for instrument error and deadband is reflected in the initial RCS temperatures. The selection of 2250 psia as the limiting pressure is considered to affect the blowdown phase results only, since this represents the initial pressure of the RCS. The RCS rapidly depressurizes from this value until the point at which it equilibrates with containment pressure. The rate at which the RCS blows down is initially more severe at the higher RCS pressure. Additionally the RCS has a higher fluid density at the higher pressure (assuming a constant temperature) and subsequently has a higher RCS mass available for releases. Thus,2250 psia plus uncertainty was selected for the initial pressure as the limiting case for the long-term mass and energy release calculations. The selection of the fuel design features for the long-term mass and energy release calculation is based on the need to conservatively maximize the energy stored in the fuel at the beginning of the postulated accident (i.e., to maximize the core stored energy). The margin in core stored energy was chosen to be +15 percent. Thus, the analysis very conservatively accounts for the stored energy in the core. Mmgin in RCS volume of 3% (which is composed of 1.6% allowance for thermal expansion and 1.4% for uncertainty) is modeled. m:u254w.nonwr.wpr.ib.oi2997 6-210

l l l

   ,m   A uniform steam generator (SG) tube plugging level of 0% is modeled. This assumption maximizes
 ;    s l y)     the reactor coolant volume and fluid release by virtue of consideration of the RCS fluid in all SG tubes. During the post-blowdown period the steam generators are active heat sources since significant energy remains in the secondary metal and secondary mass that has the potential to be transferred to the primary side. The 0% tube plugging assumption maximizes heat transfer area and therefore the transfer of secondary heat across the SG tubes. Additionally, th;s assumption reduces the reactor coolant loop resistance, which reduces the Ap upstream of the break for the pump suction breaks and increases break flow. Thus, the analysis very conservatively accounts for the level of steam generator tube plugging.

Regarding safety injection flow, the mass and energy release calculation considered configurations / failures to conservatively bour.d respective alignments. The cases include: (a) a Minimum Safeguards case (1 CH/SI and 1 LHSI Pumps); and (o) a Maximum Safeguards case, (2 CH/SI and 2 LHSI Pumps). The following assumptions were employed to ensure that the mass and energy releases are conservatively calculated :hereby maximizing energy release to containment.

1. Maximum expected operating temperature of the reactor coolant system (100% full power conditions)

(M i ) ( ,/ 2. Allowance for RCS temperature uncertainty (+6.0 F)

3. Margin in RCS volume of 3% (which is composed of 1.6% allowance for thermal expansion, and 1.4% for uncertainty)

4. Core rated power of 2775 MWt 5.

Allowance for calorimetric error (+2 percent of power)

6. Conservative heat transfer coefficients (i.e., steam generator primary / secondary heat transfer and reactor coolant system metal heat transfer)

7. Allowance in core stored energy for effect of fuel densification

8. A margin in core stored energy (+15 percent to account for manufacturing tolerances)

9. An allowance for RCS initial pressure uncertainty (+50 psi) l 10. A maximum containment backpressure equal to design pressure (54 psig) l 11. Allowance for RCS flow uncertainty (-2.1%)

mV254w.non\6ec6fspf;lb-012997 6-211 d

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 op upstream of the break for the pump suction breaks and increases break flow Additionally, there are some differences between Unit I and Unit 2. Unit 1 is of upflow design, whereas Unit 2 is downflow. Separate models were generated for both units and were used for the calculations. Limiting releases bounding for both units are provided herein. Thus, based on the previously discussed conditions and assumptions, a bounding analysis of Farley Units 1 and 2 was made for the release of mass and energy from the RCS in the event of a LOCA at 2775 MWt. 6.4.L2 Description of Analyses The evaluation model used for the long-term LOCA mass and energy release calculations is the March 1979 model described in Reference 1. This evaluation model has been reviewed and approved generically by the NRC. The approval letter is included with Reference 1. Even though this is a first time application for Farley Units 1 and 2, it has also been utilized and approved on the plant-specific dockets for other Westinghouse PWRs. This report section presents the long-term LOCA mass and energy releases generated in support of the Farley Units I and 2 uprating program. These mass and energy releases are then subsequently used in the containment integrity analysis. 6.4.1.3 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 plenurn is being filled by accumulator and ECCS water. At the end of blowdown, a large amount of water remains in the cold legs, downec<mer, 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 unirserrupted release of mass and energy to containment. Thus, the refill period is conservatively neglected in the mass and energy release calculation.

mA3254w.non\sec6f.wpf:lb-012997 6-212

p 3. Reflood - begins when the water from the lower plenum enters the core and ends when the h core is completely quenched.

1

4. Post-reflood (Froth)- describes the period following the reflood phase. For the pump suction break, a two-phase mixture exits the core, passes through the hot legs, and is superheated in l the steam generators prior to exiting the break as steam. After the broken loop steam
generator cools, the break flow becomes two-phase.

6.4.1.4 Computer Codes ' 5 He Reference 1 mass and energy release evaluation model is comprised of mass and energy release versions of the following codes: SATAN VI, WREFLOOD, FROTH, and EPITOME. These codes were used to calculate the long-term LOCA mass and energy releases for Farley Units 1 and 2. SATAN VI calculates blowdown, the first portion of the thermal-hydraulic transient following break i initiation, including pressure, 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 transient where the core reflooding phase occurs after the primary coolant system has depressurized (blowdown) due to the loss of water through the break and when water supplied by the Emergency Core Cooling System refills the reactor vessel j i and provides cooling to the core. The most important feature of WREFLOOD is the steam / water j mixing model (see subsection 6.4.1.8.2). FROTH models the post-reflood portion of the tranwent. De FROTH code is used for the steam generator heat addition calculation from the broken and intact loop steam generators. EPITOME continues the FROTH post-reflood portion of the transient from the time at which the secondary equilibrates to containment design pressure to the end of the transient. It also compiles a summary of data on the entire transient, including formal instantaneous mass and energy release tables and mass and energy balance tables with data at critical times. 6.4.1.5 Break Size and Location Generic studies have been performed with respect to the effect of postulated break size on the LOCA mass and energy releases. The double ended guillotine break has been found to be limiting due to larger mass flow rates during the blowdown phase of the transient. Durmg the reflood and froth phases, the break size has little effect on the releases. Three distinct locations in the reactor coolant system loop can be postulated for pipe rupture for any n release purposes: mA3254w.non\sec6f.gf:Ib-012997 6-213

1. Hot leg (between vessel and steam generator);

2. Cold leg (between pump and vessel); and

3. Pump suction (between steam generator and pump).

The break locations analyzed for this program are the double-ended pump suction (DEPS) rupture 2 (10.48 ft 2) and the double-ended hot leg (DEHL) rupture (9.18 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. He 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 vents directly to containment bypassing the steam generators. As a result, the reflood mass and energy releases are reduced significantly as compared to either the pump suction or cold leg break locations where the core exit mixture must pass through the steam generators before venting through the break. For the hot leg break, generic studies have confinned 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 cortainment 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 j greatly reduced, and this results in a considerably lower energy release into containment. Studies have determined that the blowdown transient for the cold leg is, in general, less limiting than that for the pump suction break. During reflood, the flooding rate is greatly reduced and the energy release rate into the containment is reduced. Therefore, the cold leg break is bounded by other breaks and no l funher evaluation is necessary. - 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 RCS in calculating the releases to containment. 6.4.1.6 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. m.\32s4 w .non\sec6f.wpf: I b-012997 6-214

 ,_. . __ _ . . _ . _ ._ _ _ _                             . _ . _     ____                 _ _ _ _ _ . _ . ~ .                 . . _ . _ ._ .

J 1 i , Two cases have been analyzed to assess the effects of a single failure. De first case assumes j minimum safeguards SI flow based on the postulated single failure of an emergency diesel generator. } This results in the loss of one train of safeguards equipment. De other case assumes maximum i safeguards SI flow based on no postulated failures that would impact the amount of ECCS flow. The analysis of the cases described provides confidence that the effect of credible single failures is j bounded. i 6.4.1.7 Acceptance Criteria for Analyses i A large break loss-of-coolant accident is classified as an ANS Condition IV event, an infrequent fault. To satisfy the Nuclear Regulatory Commission acceptance criteria presented in the Standard Review j Plan Section 6.2.13, the re!.vant requirements are as follows. I l a. 10 CFR 50, Appendix A l b. 10 CFR 50, Appendix K, paragraph I.A i j In order to meet these requirements, the following must be addressed. l 1. Sources of Energy i 2. Break Size and Location

3. Calculation of Each Phase of the Accident

! 6.4.1.8 M&E Release Data i I 6.4.1.8.1 Blowdown Mass and Energy Release Data 1 i The SATAN-VI code is used for computing the blowdown transient. De code utilizes the control ! volume (element) approach with the capability for modeling a large variety of thermal fluid system ! configurations. The fluid properties are considered uniform and thermodynamic equilibrium is assumed in each element. A point kinetics model is used with weighted feedback effects. The major j feedback effects include moderator density, moderator temperature, and Doppler broadening. A ! critical flow calculation for subcooled (modified Zaloudek), two-phase (Moody), or superheated break ! flow is incorporated into the analysis. De methodology for the use of this model is described in 2 Reference 1. i Table 6.4.1-4 presents the calculated mass and energy release for the blowdown phase of the DEHL break. For the hot leg break mass and energy release tables, break path I refers to the mass and energy exiting from the reactor vessel side of the break; break path 2 refers to the mass and energy exiting from the steam generator side of the break. Table 6.4.1-7 presents the calculated mass and energy releases for the blowdown phase of the DEPS break. For the pump suction breaks, break path 1 in the mass and energy release tables refers to the mA3254w.non\sec6f wpf.It412997 6-215

l l l 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. 6.4.1.8.2 Reflood Mass and Energy Release Data l , ne 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. He two models are coupled through the interchange of the boundary conditions applied at the l 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 l 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 I 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 ECCS 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 / water mixing only in the intact loop and not in the broken loop, the justification, applicability, and NRC approval for using the mixing model in the broken loop has been documented (Reference 2). Moreover, this assumption is supported by test data and is further discussed below. 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 was 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. 1 A group of 1/3-scale tests corresponds directly to containment integrity reflood conditions. The j injection flowrates for this group cover all phases and mixing conditions calculated during the reflood l transient. The data from these tests were reviewed and discussed in detail in Reference 1. For all of m:\3254 w.nonisec6f.wpf: l b-012997 6-216

,i i' 4 i-i 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 l wholly supported by the 1/3-scale steam / water mixing data. 1 Additionally, the following justification is also noted. The post-blowdown limiting break for the containment integrity peak pressure analysis is the pump suction double ended rupture break. For this break, there are two flowpaths available in the RCS by which mass and energy may be released to l containment. One is through the outlet of the steam generator, the other via reverse flow through the

reactor coolant pump. Steam which is not condensed by ECCS injection in the intact RCS loops i

passes around the downcomer and through the broken loop cold leg and pump in venting to } containment. This steam also encounters ECCS injection water as it passes through the broken loop i cold leg, complete mixing occurs and a portion of it is condensed. It is this portion of steam which is j condensed that is taken credit for in this analysis. This assumption is justified based upon the postulated break location, and the actual physical presence of the ECCS injection nozzle. A description of the test and test results are contained in References 1 and 3. l l Tables 6.4.1-8 and 6.4.1-13 present the calculated mass and energy releases for the reflood phase of

the pump suction double-ended rupture, minimum safeguards and maximum safeguards cases, f respectively.

l The transient response of the principal parameters during reflood are given in Tables 6.4.1-9 and j 6.4.1-14 for the DEPS cases. 6.4.1.8.3 Post-Reflood Mass and Energy Release Data The FROTH code (Reference 4) is used for computing the post-reflood transient. The FROTH code f calculates the heat release rates resulting from a two-phase mixture present in the steam generator tubes. The mass and energy releases that occur during this phase are typically supe: heated due to the i depressurization and equilibration of the broken loop and intact loop steam generators. During this i phase of the transient, the RCS has equilibrated with the containment pressure, but the steam l generators contain a secondary inventory at an enthalpy that is much higher than the primary side. 4 Therefore, there is a significant amount of reverse heat transfer that occurs. Steam is produced in the l core due to core decay heat. For a pump suction break, a two-phase fluid exits the core, flows ! through the hot legs, and becomes superheated as it passes through the steam generator. Once the l broken loop cools, the breek ' low becomes two-phase. During the FROTH calculation ECCS injection

is addressed for both the injection phase and the recirculation phase. The FROTH code calculation l stops when the secondary side equilibrates to the saturation temperature (T.) at the containment j design pressure, after this point the EPITOME code completes the SG depressurization (see sub-
section 6.4.1.8.5 for additional information).

j The methodology for the use of this model is described in Reference 1. The mass and energy release

 ]               rates are calculated by FROTH and EPITOME until the time of containment depressurization. After i

4 i m A3254w.monisec6f.wpf:lt> 012997 6-217 1

l containment depressurization (14.7 psia), the mass and energy release available to containment is generated directly from core boiloff/ decay heat. l i Tables 6.4.1-10 and 6.4.1-15 present the two-phase post-reflood mass and energy release data for the ) pump suction double-ended cases. 6.4.1.8.4 Decay Heat Model I 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 with the following input specific for Farley Nuclear Plant Units 1 and 2. The primary assumptions which make this calculation specific for Farley ) Nuclear Plant are the enrichment factor, minimum / maximum new fuel per cycle, and cycle length. A l conservative lower bound for enrichment of 3% was used. Table 6.4.1-21 lists the decay heat curve used in the Farley power uprate mass and energy release analysis. Significant assumptions in the generation of the decay heat curve for use in the LOCA mass and energy releases analysis include the following.

1. Decay heat sources considered are fission product decay and heavy element decay of U-239 and Np-239.

2. Decy heat power from fissioning isotopes other than U-235 is assumed to be identical to that of U-235.

3. Fission rate is constant over the operating history of maximum power level.

4. 'Ihe 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' seconds.

6. The number of atoms of U-239 produced per second has been assumed to be equal to 70% of the fission rate. I

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.

O mA32s4wmon\sec6f3pf.Ib-012997 6-218

I Based upon NRC staff review, Safety Evaluation Report (SER) of the March 1979 evaluation model (Reference 1), 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. l 6.4.1.8.5 Steam Generator Equilibration and Depressurization , i Steam generator equilibration and depressurization is the process by which secondary side energy is I removed from the steam generators in stages. The FROTH computer code calculates the heat removal from the secondary mass until the secondary temperature is the saturation temperature (T.) at the containment design pressure. After the FROTH calculations, the EPITOME code continues the - FROTH calculation for SG cooldown removing steam generator secondary energy at different rates (i.e., first and second stage rates). The first stage rate is applied until the steam generator reaches T. at the user specified intermediate equilibration pressure, when the secondary pressure is assumed to reach the actual containment pressure. Then the second stage rate is used until the final depressurization, when the secondary reaches the reference temperature of T. at 14.7 psia, or 212*F. The heat removal of the broken loop and intact loop steam generators are calculated separately. During the FROTH calculations, steam generator heat removal rates are calculated using the secondary side temperature, primary side temperature and a secondary side heat transfer coefficient determined using a modified McAdam's correlation. Steam generator energy is removed during the FROTH transient until the secondary side temperature reaches saturation temperature at the containment design pressure. The constant neat removal rate used during the first heat removal stage is based on the final heat removal rate calculated by FROTH. 'Ihe SG energy available to be released during the first stage interval is determined by calculating the difference in secondary energy available at the containment design pressure and that at the (lower) user specified intermediate equilibration pressure, assuming saturated conditions. This energy is then divided by the first stage energy removal rate, resulting in an intermediate equilibration time. At this time, the rate of energy release drops substantially to the second stage rate. The second stage rate is determined as the fraction of the difference in secondary energy available between the intermediate equilibration and final depressurization at 212*F, and the time difference from the time of the intermediate equilibration to the user specified time of the final depressurization at 212*F. With current methodology, all of the secondary energy remaining after the intermediate equilibration is conservatively assumed to be released by imposing a mandatory cooldown and subsequent depressurization down to atmospheric pressure at 3600 seconds, i.e.,14.7 psia and 212'F. 6.4.1.8.6 Sources of Mass and Energy ! The sources of mass considered in the LOCA mass and energy release analysis are given in Tables 6.4.1-5,6.4.1-11, and 6.4.1-16. These sources are the reactor coolant system, accumulators, and pumped safety injection. l m:o254w.monssec6rnf;ib.ol2997 6-219

The energy inventories considered in the LOCA mass and energy release analysis are given in Tables 6.4.1-6,6.4.1-12, and 6.4.1-17. The energy sources are listed below.

1. Reactor Coolant System Water

2. Accumulator Water (all three inject)

3. Pumped Safety Injection Water

4. Decay Heat

5. Core Stored Energy

6. Reactor Coolant System Metal (includes SG tubes)

7. Steam Generator Metal (includes transition cone, shell, wrapper, and other internals)

8. Steam Generator Secondary Energy (includes fluid mass and steam mass)

9. Secondary Transfer of Energy (feedwater into and steam out of the steam generator secondary)

The energy reference points are as follows.

1. Available Energy: 212*F; 14.7 psia

2. 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

4. End of reflood time

5. Time of broken loop steam generator equilibration to pressure setpoint

6. Time of intact loop steam generator equilibration to pressure setpoint

7. Time of full depressurization (3600 seconds)

In the mass and energy release data presented, no Zirc water reaction heat was considered because the clad teruperature is assumed not to rise high enough for the rate of the Zirc-water reaction heat to be of any significance. The sequence of events for the LOCA transients are sht 4n in Tables 6.4.1-18 through 6.4.1-20. 6.4.1.8.7 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 review guidelines presented in Standard Re view Plan Section 6.2.1.3 have been satisfied. The results of this analysis were provided for use in the containment integrity analysis (see BOP Licensing Report). rnA3254w.non\sec6f wpf:1b 012997 6-220

2 1 1 TABLE 6.4.11

                                                             ' SYSTEM PARAMETERS i:                                            INITIAL CONDITIONS FOR THERMAL UPRATE Parameters                                                                 Value Core Thermal Power (MWt)                                                                                     2830.5 Reactor Coolant System Total Flowrate (Ibm /sec)                                                             26677.75                         '

Vessel Outlet Temperature ('F) 619.3 Core Inlet Temperature (*F) 547.1 Vessel Average Temperature ('F) 583.2 Initial Steam Generator Steam Pressure (psia) 798 Steam Generator Design Model 51 Steam Generator Tube Plugging (%) 0 Initial Steam Generator Secondary Side Mass (Ibm) 127202.9 Assumed Maximum Containment Backpressure (psia) 68.7 Accumulator Water Volume (ft') per accumulator 1040 N 2Cover Gas Pressure (psia) 599.7 Temperature ('F) 120 Safety Injection Delay, total (sec) (from beginning of event) 30.1 Note: Core Thermal Power, RCS Total Flowrate, RCS Coolant Temperatures, and Steam Generator Secondary Side Mass include appropriate uncertainty and/or allowance. m:\3254 w.non\sec6f.wpf:l b-012997 6-221

l TABLE 6.4.12 SAFETY INJECTION FLOW MINIMUM SAFEGUARDS RCS Pressure Total Flow (psig) (gpm) l INJECTION MODE (REFLOOD PHASE) 0 4411.2 20 4163.4 40 3897.1

60 3603.8 80 3275.0 100 2900.8 120 2190.7 140 1619.5 160 482.7 180 480.0 INJECTION MODE (POST-REFLOOD PHASE) 54 3691.8 COLD LEG RECIRCULATION MODE O 3997.8 O m:\3254w.non\sec6f.wpf:IM12997 6-222

   . . . . - -          -             . - - . _ _ . _ .                  - .    . . . _         . . - . . . - . ~ . . - - .              . . -              - -         . . .

4 J 1 3 f 4 TABLE 6.4.13 SAFETY INJECTION FLOW MAXIMUM SAFEGUARDS RCS Pressure Total How l (psig) (sym) j INJECTION MODE (REILOOD PHASE) i 0 8575.0 y < 20 8094.4 i

40 7581.5 l 60 7028.8 80 6425.3 l 100 5752.0 120 4976.6 140 4327.8 3530.3 O

160 180 2376.1 INJECTION MODE (POST-REFLOOD PHASE) 54 7194.6 j COLD LEG RECIRCULATION MODE 0 8575.0 l l l 1 O m:\3254w.non\sec6f.wpf;1b-012997 6-223 h-

l TABLE 6.4.1-4 DOUBLE ENDED HOT LEG BREAK BLOWDOWN MASS AND ENERGY RELEASES Break Path No.1 Flow

Break Path No. 2 Flow" Time Thousand Thousand (seconds) Obm/sec) (Btu /sec) Obrn/sec) (Btu /sec) l

               .0000                      .0                  .0         .0                .0
               .00109               45770.1            29243.4     45768.1          29240.9
               .00312               45398.8            29005.8     44848.2          28641.1
               .101                 41515.0            27051.9     27163.2           17317.8
               .201                 35022.6            22938.6     23607.9           14966.9
               .301                 34206.8            22392.7     20922.1           13106.9
               .402                 33786.4            22114.2     19545.7           12041.3
               .502                 33619.8            22018.2      18763.0          11361.8
               .702                 32552.5            21423.8      17678.6          10393.8
               .902                 30877.9            20514.2      17016.2           9780.2 1.10                  30199.7            20332.2      16481.7           9311.1 1.40                  28224.3            19315.1      16139.2           8940.4 1.60                  27159.1            18810.9      16172.5           8867.0 1.80                  25541.5             17892.2     16285.6           8852.8 2.20                  22783.3             16314.1     16567.0           8895.2    l 2.50                  20987.9             15166.0     16722.1           8929.4 2.80                   19600.4            14177.3     16754.6           8919.3 3.10                   18650.7            13413.8     16652.4           8852.3 3.40                   18006.8            12822.0     16430.1           8732.2 3.70                   17558.9            12356.6     16102.4           8564.6 4.20                   17145.5            11831.6     15326.6           8180.0 4.60                   17378.6            11761.7     14557.5           7803.4 4.80                   17763.3            11828.8     14066.4           7558.5 5.20                   18826.4            12083.8     13062.9           7058.0 5.40                   14583.6            10',17.0    12587.8           6822.0 5.80                   14882.4            10121.4     11561.6           6305.7 9

m:\3254w.non\sec6f wpf:1t412997 6-224

1 i TABLE 6.4.14 (cont.) DOUBLE ENDED HOT LEG BREAK BLOWDOWN MASS AND ENERGY RELEASES $s Bak Path No. I mw* Break Path No. 2 Nw** 1 Time Thousand Thousand (seconds) (Ibm /sec) (Btu /sec) Obai/sec) (Btu /sec) 6.20 15050.6 10055.3 10621.9 5829.7 7.00 15165.7 9884.5 9121.8 5057.5 j 7.20 14921.5 9733.3 8809.8 4895.3 j 7.80 15125.5 9661.0 7991.2 4470.3 8.20 15104.7 9531.6 7512.3 4222.7 i 8.80 14775.0 91 %.0 6854.5 3885.1 i j 9.20 14334.5 8877.2 6445.3 3677.6 { l0.0 13107.2 8107.2 5686.8 3301.2

10.8 11745.4 7317.8 5005.4 2974.5

} I 1.2 11076.4 6946.0 4697.6 2830.9 l 12.6 8311.3 5544.5 3584.9 2329.8

13.4 6666.5 4855.3 2790.9 2004.2 l v

l 14.0 5555.3 4406.0 2347.1 1792.0

14.4 4714.6 4073.1 2163.6 1685.9 14.8 3626.9 3573.2 2019.4 1598.2 4 -

, 15.6 2278.6 2618.2 1667.3 1453.4 16.8 1386.8 1721.1 1220.2 1278.1 a'

I7.6 996.8 1248.8 1038.0 1188.7 l

! l8.0 806.2 1015.5 825.0 1007.8

18.4 567.3 717.1 778.7 952.8 j 18.8 416.5 528.3 811.3 981.6 4

l 19.2 307.1 391.3 614.9 753.6 i 19.6 60.4 77.1 392.5 484.4 j 20.0 .0 .0 .0 .0

mass and energy exiting from the reactor vessel side of the break i " mass and energy exiting from the SG side of the break iO i

I q m:u254w.nonssec6f.wpr.lb-ol2997 6-225

TABLE 6.4.15 DOUBLE-ENDED HOT LEG BREAK MASS BALANCE , l Time (Seconds) .00 20.00 20.00 Mass (Thousand Ibm) Initial In RCS and ACC 603.47 603.47 603.47 Added Mass Pumped Injection .00 .00 .00 Total Added .00 .00 .00

                        *** TOTAL AVAILABLE *"                  603.47      603.47    603.47 Distribution                          Reactor Coolant          410.51        72.24     92.04 Accumulator              192.96       137.53    117.73 Total Contents           603.47      209.77    209.77 Effluent                              Break Flow                    .00    393.68    393.68 ECCS Spill                    .00        .00       .00 i                                       Total Effluent                .00    393.68    393.68
                     *" TOTAL ACCOUNTABLE "*                    603.47      603.45    603.45 l

l l l 9 m u254w.noossec6r3rr ;ib-ol2997 6-226

TABLE 6.4.16 DOUBLE ENDED HOT LEG BREAK ENERGY BALANCE Time (Seconds) .00 20.00 20.00 Energy (Million Btu) Initial Energy in RCS, ACC, S GEN 631.79 631.79 631.79 Added Energy Pumped Injection .00 .00 .00 Decay Heat .00 5.38 5.38 Heat From Secondary .00 -6.38 -638 Total Added .00 1.00 -1.00

                       *" TOTAL AVAILABLE *"                   631.79         630.79   630.79 Distribution                            Reactor Coolant        241.14           15.%     17.73 Accumulator               17.28         12.31    10.54 Core Stored               18.95          7.46     7.46 Primary Metal           117.81         110.10   110.10 Secondary Metal           33.82         33.13    33.13 Steam Generator         202.78         197.37   197.37 Total Contents          631.79         376.32   376.32 Break Flow                  .00       253.98   253.98 Effluent ECCS Spill                  .00           .00      .00 Total Effluent              .00       253.98   253.98
                     "* TOTAL ACCOUNTABLE "*                     631.79        630.30   630.30 m:\3254w.non\sec6f.wpf:lb 012997                         6-227

TABLE 6.4.1-7 DOUBLE ENDED PUMP SUCTION BREAK BLOWDOWN MASS AND ENERGY RELEASES (SAME FOR ALL DEPS RUNS) Break Path No.1 Flow

Break Path No. 2 Flow'*

Time Thousand Thousand (seconds) (1bm/sec) (Btu /sec) (Ibrn/sec) (Btu /sec)

               .00000                        .0                .0          .0                .0
               .00106                 92764.9            50029.8     40303.2           21678.4
               .101                   40099.4            21638.4     20680.9           11118.4
               .201                   40755.1            22129.0     22658.6           12192.1
               .301                   43464.5            23796.6     23047.3           12417.4
               .401                   43976.4            24316.5     22681.9           12237.3 l               .601                   43931.2            24875.2     21381.2           11554.2
               .801                   44372.8            25702.9     20287.8           10969.2 1.00                    42842.4            25301.6      19437.6          10511.2 1.30                    39393.8            23853.0      18924.9          10237.0 1.80                    34761.5            21987.1      18496.6          10002.2  l 2.30                    29024.5            19346.3      17711.1           9572.8 2.50                    26365.0             17935.2     17085.5           9233.0 2.60                    22725.4             15576.3     16797.1           9077.1 2.70                    20463.9             14171.7     16509.1           8921.4 2.90                     17437.1            12275.2     15908.2           8597.2 3.10                     14896.5            10622.0     15401.2           8324.9 3.40                     12856.7             9304.4     14757.8           7980.7 4.00                     11061.9             8118.2     13610.8           7366.4 5.00                       9269.7            6953.6     12417.4           6727.0 5.20                       9028.3            6776.0     12200.0           6610.0 5.40                       8822.0            6611.8     13066.6           7084.2  l 5.80                       8550.5            6360.6     12655.7            6861.8 6.40                       8446.0            6170.8     12282.9            6668.3 6.80                       9009.0            6602.5     12078.6            6563.4 7.20                       7504.7            6258.7     11763.8            6393.7 mA3254w.nonisec6f wpf.Ib-012997                     6-228

i l l l l i t I TABLE 6.4.17 (cont.) DOUBLLENDED PUMP SUCTION BREAK i BLOWDOWN MASS AND ENERGY RELEASES l (SAME FOR ALL DEPS RUNS) Break Path No.1 Nw* Break Path No. 2 Nw" ! Thee Thousand Thousand (seconds) Obavsec) (Btu /sec) Obin/sec) (Btu /sec) { 7.60 7161.2 5908.7 11449.9 6222.7 j 9.00 7263.4 5410.2 10410.1 5648.9 1 i 9.80 6938.0 5121.1 9837.7 5335.1 10.40 6544.1 4894.9 9413.9 5103.7 12.2 5334.0 4235.8 8177.0 4432.0 13.0 4886.7 3970.5 7674.5 4160.2 14.4 4007.3 3389.6 6626.9 3326.2 14.6 3909.5 3306.3 6797.7 3337.3 14.8 3825.5 3242.2 6146.8 2964.0 15.0 3746.8 3191.9 6302.8 2968.7 O 15.2 3648.6 3136.1 7957.3 3709.1 15.4 3555.3 3099.7 5919.9 2755.2 15.6 3483.1 3083.6 5350.5 2470.0 15.8 3393.0 3054.6 5583.4 2502.9 16.0 3282.8 3021.0 6977.6 3078.1 16.4 3062.1 3005.5 5245.4 2306.0 16.6 2947.0 3011.8 5037.2 2197.0 17.0 2515.5 2867.8 5024.4 2134.9 17.6 1816.8 2241.1 4258.5 1709.1 . 1 18.2 1328.9 1652.3 4538.7 1650.8 18.8 931.8 - 1165.3 3561.7 1190.9 ! 19.6 566.9 712.1 1745.1 522.2 20.2 438.7 551.9 172.0 49.0 21.8 .0 .0 .0 .0

mass and energy exiting the SG side of the break

                             "        mass and energy exiting the pump side of the break
                                                                                     \

m:u254w nonw6f.wpf:1b-ot2997 6-229

TABLE 6.4.1-8 DOUBLE ENDED PUMP SUCTION BREAK MINIMUM SAFEGUARDS REFLOOD MASS AND ENERGY RELEASFS Break Path No.1 Flow

Break Path No. 2 Flew" Time Thousand Thousand (seconds) Obm/sec) (Btu /sec) Obm/sec) (Btu /sec)

, 21.8 .0 .0 .0 .0 22.7 .0 .0 .0 .0 22.8 108.2 127.8 .0 .0 22.9 44.7 52.8 .0 .0 23.0 43.0 50.7 .0 .0 23.8 85.5 100.9 .0 .0 24.8 122.5 144.7 .0 .0 25.8 151.5 178.9 .0 .0 26.8 480.3 570.2 4672.2 604.1 l 27.3 487.8 579.3 4719.8 620.0 27.3 483.2 573.8 4678.2 616.7 28.8 471.4 559.6 4571.1 605.8 29.8 459.2 545.0 4457.5 593.8 30.9 474.5 563.3 4624.2 609.0 31.9 463.1 549.7 4518.0 597.6 32.9 452.3 536.8 4416.3 586.5 33.9 442.0 524.5 4318.2 575.8 34.9 432.2 512.8 4223.6 565.4 35.9 422.8 501.6 4132.6 555.4 36.9 413.9 490.9 4045.0 545.8 37.9 405.4 480.7 3960.6 536.5 39.9 389.4 461.7 3800.9 518.9 41.9 374.8 444.2 3652.1 502.5 43.9 361.3 428.1 3512.9 487.2 44.9 293.2 347.2 2483 0 402.9 45.9 273.6 323.7 2512.4 382.7 m:\32W.non\sec6f.wpf it412997 6-230

TABLE 6.4.1-8 (cont.) DOUBLE-ENDED PUMP SUCTION BREAK MINIMUM SAFEGUARDS REFLOOD MASS AND ENERGY RELEASES Break Path No.1 How* Break Path No. 2 Mow" Time Thousand Thousand (seconds) (Ibm /sec) (Btu /sec) (Ibm /sec) (Btu /sec) 46.9 269.3 318.6 2463.0 377.1 3 48.0 313.4 371.0 283.5 159.5 ! 50.0 302.1 357.6 279.1 153.6 l

54.0 279.8 331.1 270.4 141.9 j 56.0 269.8 319.2 266.5 136.8 -

60.0 251.3 297.2 259.4 127.4 64.0 234.4 277.2 253.1 119.0 68.0 219.2 259.1 247.5 111.5 70.0 212.2 250.9 244.9 108.2 74.0 199.4 235.6 240.2 102.1 78.0 188.0 222.1 236.1 96.8 82.0 177.9 210.2 232.5 92.2 89.0 163.4 193.0 227.5 85.7 97.0 150.9 178.3 223.3 80.3 109.0 138.9 164.0 219.3 75.2 123 0 131.8 155.6 216.9 72.2 133.0 129.6 153.0 216.1 71.2 149.0 128.8 152.1 215.6 70.6 167.0 129.9 153.4 215.7 70.7 I85.0 132.5 156.5 216.6 71.5 189.0 133.7 157.9 219.2 72.4 193.0 134.8 159.2 223.5 73.6 201.0 135.9 160.5 235.1 76.4 203.1 135.9 160.5 238.6 77.1 mass and energy exiting the SG side of the break O mass and energy exiting the pump side of the break m:\3254w.non\sec6f wpf.lb.012997 6-231

B d 2 TABLE 6.4.19 ? 5 DOUBLE-ENDED PUMP SUCTION BREAK MINIMUM SAFEGUARDS k -> PRINCIPLE PARAMETERS DURING REFLOOD { Injection g Monding Total Accum Spill Core Downcomer

3 Time Temp Rate Carryover Height Height Mow Enthalpy 3 Seconds *F In/sec Fraction (ft) (ft) Frac (Pounds Mass per Second) Btu /lbm 21.8 183.1 .000 .000 .00 .00 .333 .0 .0 .0 .00 22.5 180.9 23.806 .000 .55 2.02 .000 8134.5 8134.5 .0 89.54 22.7 179.1 29.472 .000 1.11 2.03 .000 8018.8 8018.8 .0 89.54 23.7 1783 2.947 3 05 1.50 5.71 .409 7628.2 7628.2 .0 89.54 24.7 1783 2.805 .439 I.65 9.71 .440 7311.2 7311.2 .0 89.54 26.8 178.2 5.289 .605 1.93 15.65 .682 5956.3 59563 .0 89.54 27.3 178.1 5.120 .631 2.02 15.66 .680 5797.6 5797.6 7 .0 89.54 27.8 178.0 4.935 .650 2.09 15.66 .680 5692.0 5692.0 .0 89.54 29.8 178.0 4.458 .690 234 15.66 .675 5339.0 5339.0 .0 89.54 30.9 178.1 4.489 .702 2.46 15.66 .681 5507.8 5065.9 .0 89.42 313 178.2 4.432 .706 2.51 15.66 .680 5449.7 5006.6 .0 89.41 36.4 179.4 3.912 .727 3.00 15.66 .666 4832.7 43753 .0 89.39 42.5 181.6 3.519 .735 3.51 15.66 .650 4265.5 3795.6 .0 8937 46.9 183.5 2.827 .731 3.82 15.66 .591 2959.5 2468.8 .0 89.28 48.0 184.0 3.120 .735 3.89 15.47 .620 481.5 .0 .0 88.00 49.7 184.9 3.033 .735 4.01 15.14 .618 483.1 .0 .0 88.00 58.0 190.6 2.654 .733 4.53- 13.82 .607 490.2 .0 .0 88.00 66.5 197.7 2349 .730 5.00 12.90 .594 4953 .0 .0 88.00 77.0 207.4 2.060 .727 5.52 12.23 .578 4993 .0 .0 88.00 87.8 217.4 1.848 .725 6.00 11.93 .561 501.8 .0 .0 88.00 e _ -_

O O

  . . . . . . . _ . _ _ .    . _ _  . - . . . . . . . . . . . _ - . . . . _ . . _ . . . _ . - - , . . _ . - . - _ _ _ _ _ _ _ . . - _ - - _ . _ . . -                                    .__._.-.m       . m_ _ . _ . _ ..._. ..

i , B f a TABLE 6.4.1-9 (cent.) ~ l DOUBLE-ENDED PUMP SUCTION BREAK - MINIMUM SAFEGUARDS PRINCIPLE PARAMETERS DURING REFLOOD 4 + i=>ction Total Accuen Syllt . 3 Fleeding .g Rate Carryever Height Hel81d Row Enthalpy l , h Tinse Teeny (Founds Mass per Second) Beullben j Seconds 'F in/sec Frhoen (ft) (ft) Frec

               @u 101.0         22't.8                 1.652                    .725                654                       Il.94             .544 503.6           .0           .0        88.00 236.1                  1.593                    .726                7.00                      12.18             .534 504.5           .0           .0        88.00 113.5                                                                                                                                                                                                            '

i 244.8 1.539 - .728 7.55 12.65 .528 505.0 .0 .0 88 00 129.0 251.I 1.519 .732 8.00 13.10 .526 505.2 .0 .0 88.00 142.0 257.6 1.51I .736 8.5I I3.66 .527 505 4 .0 .0 88.00 , 157.0 i 260.8 1.510 .738 8.77 13.97 .528 505.2 .0 .0 88.00 165.0 172.1 263.4 1.511 .741 9.00 14.24 .529 505.1 .0 .0 88.00

                                                                                                                                                                                            .0        88.00                                  ;

I

              .bw 189.0        269.1                  1.524                    .746                9.55                      14.88             .534 504.9           .0 W            197.0        271.5                  1.529                    .749                9.81                      15.31             .538 504.8           .0           .0        88.00                                  ;

i 273.3 1.524 .751 10.00 15.29 .539 504.7 .0 .0 88.00 - 203.1 - t i r r t i t _, _5

TABLE 6.4.110 DOUBLE-ENDED PUMP SUCTION BREAK MINIMUM SAFEGUARDS POST REFLOOD MASS AND ENERGY RELEASES Break Path No.1 Flow Break Path No. 2 Flow Time Thousand Thousand (seconds) (Ibm /sec) (Btu /sec) Obm/sec) (Btu /sec) 203.1 121.0 150.5 387.1 103.2 208.1 120.7 150.0 387.5 103.1 213.1 121.0 150.5 387.1 102.8 223.1 120.3 149.6 387.8 102.7 228.1 120.6 150.0 387.5 102.5 238.1 119.9 149.1 388.2 102.3 243.1 120.2 149.5 387.9 102.1 253.1 119.5 148.6 388.6 102.0 258.1 119.8 149.0 388.3 101.7 268.1 119.1 148.I 389.0 101.6 , 273.1 119.4 148.5 388.7 101.3 283.1 118.7 147.5 389.5 101.2 l 288.1 119.0 147.9 389.2 101.0 298.1 118.2 147.0 389.9 100.9 303.1 118.5 147.3 389.6 100.6 313.1 117.7 146.4 390.4 100.5 328.1 117.9 146.6 390.3 100.0 338.1 117.1 145.6 391.1 99.8 353.1 117.2 145.7 391.0 99.3 363.1 116.3 144.7 391.8 99.2 388.1 116.2 144.5 391.9 98.4 398.1 115.3 143.4 392.8 98.3 413.1 115.6 143.7 392.6 97.7 423.1 114.9 142.9 393.2 97.5 448.1 115.0 143.0 393.1 96.7 458.1 114.3 142.1 393.8 96.5 m:\3254 w.nonisec6f.wpf:l b.012997 6-234

  .- _ _ --. . _ . _ ~..______ . _ . _ _ _ . _ _ _ _

1 l 1 ! 3 t TABLE 6.4.1 10 (cont.) I, DOUBLE ENDED PUMP SUCTION BREAK MINIMUM SAFEGUARDS l POST REFLOOD MASS AND ENERGY RELEASES Break Path No.1 Nw Break Path No. 2 mw { Thee Thousand Thousand (seconds) Oban/sec) (Stu/sec) Obni/sec) (Btu /sec) , 463.1 114.5 142.4 393.6 %3 508.1 113.4 141.0 394.7 973 . 518.1 113.7 141.4 394.4 96.8 533.1 113.0 140.5 395.1 96.4 i ! 548.1 112.7 140.2 395.4 95.9 95 3 : 563.1 112.9 140.4 395.2 588.1 112.4 139.8 395.7 94.4 j ! 633.1 111 3 138.4 3%.8 95.1 653.1 111.4 138.5 3%.7 94.2 _

       %                                            693.1          110.5                    137.4                                        397.6              94.8 703.1          110.7                    137.6                                        397.4               943 h

738.I 110.0 136.7 398.2 92.8 743.1 65.7 81.6 442.5 104.6 I 1048.3 65.7 81.6 442.5 104.6 l 1048.4 69.6 82.1 438.5 100.6 69.5 85.6 438.6 100.1 1310.4 65.4 75 3 442.7 44.5 1310.5 58.0 66.8 450.1 45.8 2139.0 58.0 66.8 475.9 94.6 2139.1 50.9 58.6 483.0 95.9 3600.0 41.5 47.8 492.4 86.2 3600.1 30.0 34.6 503.9 88.2 10000.0 16.6 19.1 517.3 90.6 100000.0 7.1 8.2 526.8 923 1000000.0 O mA3254w.non\sec6f.wpf:Ib.012997 6-235

TABLE 6.4.111 DOUBLE-ENDED PUMP SUCTION BREAK MASS BALANCE MINIMUM SAFEGUARDS Mass Balance Time (Seconds) .00 21.80 21.80 203.06 IN8.42 1310.44 3600.00 Mass (Thousand Ibm) Initial in RCS and ACC 602.63 602.63 602.63 602.63 602.63 602.63 602.63 Added Mass Pumped injection .00 .00 .00 86.11 515.63 648.77 1849.81 Total Added .00 .00 .00 86.11 515.63 648.77 1849.81

      "* TOTAL AVAILABLE *"             602.63   602.63    602.63    688.74    1118.27 1251.40 2452.44 Distnbution     Reactor Coolant      409.68     51.15    70.N      I19.62    119.62  119.62  119.62 Accumulator          192.96    142.32   123.43        .00       .00     .00      .00 Total Contents       602.63    193.47   193.47    119.62     119.62  119.62  119.62 Effluent        Break Flow              .00   409.15    409.15    560.27     989.80 1122.94 2323.97 ECCS Spill              .00       .00      .00        .00       .00     .00      .00 Total Effluent          .00   409.15    409.15    560.27     989.80 1122.94 2323.97
    *" TOTAL ACCOUNTABLE *"             602.63   602.62    602.62    679.89    1109.42 1242.56 2443.59 1

1 l 9 m:\3254w.non\sec6f wpf:Ib-012997 6-236

1 TABLE 6.4.112 DOUBLE ENDED PUMP SUCTION BREAK ENERGY BALANCE MINIMUM SAFEGUARDS l 1 Energy Balance Time (Seconds) .00 21.80 21.80 203.06 1048.42 1310.44 3600.00 Energy (Million Btu) Inical in RCS, ACC. 629.13 629.13 029.13 629.13 629.13 629.13 629.13 Energy S GEN Added Pumped injection .00 .00 .00 7.58 45.38 57.09 230.75 Decay Heat .00 5.44 5.44 22.65 79.08 93.80 199.05 Heat From .00 -5.75 -5.75 -5.75 2.57 2.05 2.05 Secondary Total Added .00 . 31 .31 24.47 121.89 148.84 427.75

      *" TOTAL AVAILABLE *"                629.13      628.82      628.82      653.60     751.01     777.97    1056.88 Distribution       Reactor Coolant       241.17       10.94       12.63       31.37      31.37      31.37      31.37 Accumulator             17.28      12.74       11.05          .00        .00        .00        .00 Core Stored             18.95       9.53        9.53        4.05       3.90       3.78       2.71 Primary Metal         115.09      108.76      108.76       87.11      56.55      51.72      37.79    ;

Secordary Metal 33.86 33.85 33.85 30.38 20.50 18.21 13.43 Eteam Generator 202.78 202.37 202.37 178.19 117.82 104.92 77.69 Total Contents 629.13 378.20 378.20 331.11 230.15 209.99 162.99 Effluent Break Flow .00 250.14 250.14 314.28 512.65 549.25 876.34 ECCS Spill .00 .00 .00 .00 .00 .00 .00 l Total Effluent .00 250.14 250.14 314.28 512.65 549.25 876.34

    "* TOTAL ACCOUNTABLE "*                  629.13     628.34      628.34      645.39     742.80     759.24    1039.33 L) m:\3254 w .non\nc6f.wpf. I t>.012997                       6-237

l l 1 I TABLE 6.4.113 DOUBLE-ENDED PUMP SUCTION BREAK MAXIMUM SAFEGUARDS REFLOOD MASS AND ENERGY RELEASES l Break Patt No.1 How Break Path No. 2 How Time Thousand Thousand (seconds) (Ibm /sec) (Btu /sec) (Ibm /sec) (Btu /sec) 21.8 .0 .0 .0 .0 22.7 .0 .0 .0 .0 22.8 108.2 127.8 .0 .0 22.9 44.7 52.8 .0 .0 23.0 43.0 50.7 .0 .0 23.8 85.5 100.9 .0 .0 24.8 122.5 144.7 .0 .0 25.8 151.5 178.9 .0 .0 26.8 480.3 570.2 4672.2 604.1 27.3 487.8 579.3 4719.8 620.0 27.8 483.2 573.8 4678.2 616.7 ; 28.8 471.4 559.6 4571.1 605.8 29.8 459.2 545.0 4457.5 593.8 30.9 500.6 594.7 4886.6 634.3 31.9 489.3 581.1 4781.1 623.6 32.9 478.7 568.4 4683.7 612.8 33.9 468.6 556.3 4589.6 602.4 i l 34.9 458.9 544.7 4498.8 592.4 35.9 449.7 533.7 4411.4 582.7 l l 36.2 447.0 530.5 4385.8 579.9 36.9 440.9 523.2 4327.1 573.4 37.9 432.5 513.1 4245.8 564.4 38.9 424.4 503.4 4167.4 555.6 39.9 416.7 494.2 4091.7 547.2 40.9 409.3 485.3 4018.6 539.1 41.9 402.1 476.8 3948.0 531.3 i 1 mA3254w.non\sec6f wpf.1t>412997 6-238

         . . - .                     -                   -         - _.  -           -.           =    . - . . .

( TABLE 6.4.1 13 (cont.) DOUBLE ENDED PUMP SUCTION BREAK ! MAXIMUM SAFEGUARDS ) REFLOOD MASS AND ENERGY RELEASES Break Path No.1 Flow Break Path No. 2 Flow Time Thousand Thousand (seconds) (Ibm /sec) (Btu /sec) (Ibm /sec) (Btu /sec) 42.9 395.3 468.7 3879.7 523.7 43.9 388.7 460.8 3813.5 516.3 44.9 382.3 453.2 3749.4 509.2 ] 45.9 302.7 358.4 2876.9 418.3 I I 46.9 298.4 353.2 2828.8 412.8 47.9 173.0 204.4 657.3 160.1 , 1 62.9 166.7 197.0 672.0 157.9 64.9 166.0 196.1 673.8 157.6 1 71.9 163.3 192.9 680.0 156.6 (g 79.9 160.2 189.2 687.1 155.4 80.9 159.8 I88.8 688.0 155.3 88.9 156.7 185.2 695.1 154.1 94.9 154.4 182.4 700.5 153.3 102.9 151.3 178.7 707.5 152.2 104.9 150.5 177.8 709.3 151.9 112.9 147.4 174.1 716.2 150.7 114.9 146.6 173.1 7I8.0 150.4 J 122.9 143.4 169.4 724.8 149.2 154.9 130.3 153.9 751.7 144.4 168.9 126.5 149.4 759.7 143.9 170.9 126.0 148.8 760.7 143.8 186.9 122.0 144.0 768.6 143.0 194.9 120.0 141.7 772.5 142.5 200.7 118.7 140.1 775.2 142.2 i i I m:\3254w.mm\sec6f.wpf.lb.012997 6-239

i I B c TABLE 6.4.1-14 f, i 3 DOUBLE-ENDED PUMP SUCTION BREAK- MAXIMUM SAFEGUARDS f PRINCIPLE PARAMETERS DURING REFLOOD Injection { Flooding Total Accum Spill g Core Dow Temp Rate Carryover Height Height flow Enthalpy G ~Ilme in/sec Fraction (ft) (ft) Frac (Pounds Mass per Second) Btu /lbm

  $  Seconds   'F
                             .000        .000          .00         .00        333        .0           .0         .0        .00 21.8   183.1 180.9        23.806         .000          .55        2.02        .000  8134.5       8134.5          .0     89.54 22.5 29.472         .000        1.11         2.03        .000  8018.8       8018.8          .0     89.54 22.7   179.I 305         1.50        5.71         .409  7628.2       7628.2          .0     89.54 23.7   1783          2.947 2.805         .439        1.65        9.7I         .440  7311.2       7311.2          .0     89.54 24.7   1783 5.289         .605        1.93       15.65         .682  59563        59563           .0     89.54 26.8   175.2 5.120         .631        2.02       15.66         .680  5797.6       5797.6          .0     89.54 p   273   178.1 15.66         .680  5692.0       5692.0          .0     89.54 Z

o 27.8 178.0 4.935 .650 2.09 178.0 4.458 .690 234 15.66 .675 5339.0 5339.0 .0 89.54 29.8 4.678 .703 2A6 15.66 .690 5812.6 49593 .0 8931 30.9 178.1 4.618 .707 2.5I I5.66 .680 5752.1 4896.9 .0 89.31 313 178.2 4.111 .729 3.01 15.66 .677 5174.3 4292.5 .0 89.28 36.2 179.2 1813 3.734 .736 3.50 15.66 .664 4651.0 3748.0 .0 89.24 41.9 183.9 2.214 .722 3.95 15.66 .491 986.6 .0 .0 88.00 47.9 184.4 2.207 .722 4.00 15.66 .491 986.6 .0 .0 88.00 49.0 190.9 2.142 .724 4.55 15.66 .491 986.6 .0 .0 88.00 59.9 2.089 .726 5.00 15.66 .492 986.6 .0 .0 88.00 693 198.2 80.9 208 3 2.024 .728 5.55 15.66 492 986.6 .0 .0 88.00 217.5 1.967 .731 6.00 15.66 .493 986.7 .0 .0 88.00 91.0 227.5 1.901 .733 6.51 15.66 493 986.7 .0 .0 88.00 102.9 0 - 0 0

O O O is d y TABLE 6.4.1-14 (cont.) 5 ' 8 DOUBLE-ENDED PUMP SUC1' ION BREAK- MAXIMUM SAFEGUARDS h PRINCIPLE PARAMETERS DURING REFLOOD 5 inlection Hooding Total Accum Spill g Core Do-G Time Temp Rate Carryover Height Height Flow Enthalpy

$ Seconds   'F          in/see        Fraction                         (ft)       (ft)           Frec          (Pounds Moss per Second)      Btm%m i14.7   236.1           1.836             .735                      7.00        15.66            .493     986.8              .0       .0      88.00         l 128.9   245.0           1.758             .737                      7.56        15.66            .494     986.9              .0       .0      88.00 140.5  251.2           1.695             .739                      8.00        15.66            .494     987.0              .0       .0      88.00 154.9  257.8           1.618             .741                      8.52        15.66             493     987.1              .0       .0      88.00 169.1  263.4           1.558             .743                      9.00        15.66            .4 %     987.1              .0       .0      88.00 184.9  268.8           1.495             .746                      9.51        15.66            .499     987.0              .0       .0      88.00 200.7   273.5           1.434             .748                     10.00        15.66            .502     986.9              .0       .0      88.00 p

TABLE 6.4.115 DOUBLE ENDED PUMP SUCTION BREAK MAXIMUM SAFEGUARDS POST REFLOOD MASS AND ENERGY RELEASES Break Path No.1 Flow Break Path No. 2 Flow Time Thousand Thousand (seconds) Obm/sec) (Btu /sec) Obm/sec) (Btu /sec) 200.8 131.0 163.2 859.1 142.7 205.8 130.6 162.7 859.5 142.6 210.8 130.9 163.2 859.1 142.4 220.8 130.1 162.2 859.9 142.3 225.8 130.4 162.6 859.6 142.0 230.8 130.0 162.1 860.0 142.0 235.8 130.4 162.5 859.7 141.7 245.8 129.5 161.4 860.5 141.6 250.8 129.8 161.8 860.2 141.4 255.8 129.4 161.3 860.6 141.3 260.8 129.7 161.7 860.3 141.1 270.8 128.9 160.6 861.2 141.0 275.8 129,1 161.0 860.9 140.7 285.8 129.0 160.8 861.0 142.8 290.8 128.5 160.2 861.5 142.8 305.8 128.6 160.3 861.4 142.2 127.9 159.4 862.1 141.3 335.8 126.5 157.6 863.5 140.4 370.8 i 126.8 158.0 863.2 140.0 380.8 125.9 156.9 864.2 139.7 395.8 126.2 157.3 863.8 139.2 405.8 125.5 156.4 864.5 138.9 420.8 125.8 156.8 864.2 138.4 430.8 125.4 156.2 864.7 138.4 435.8 125.6 156.6 864.4 137.9 445.8 125.1 156.0 864.9 137.9 450.8 m:\3254w.non\sec6f wpf.1b.012997 6-242

TABLE 6.4.1 15 (cont.) DOUBLE ENDED PUMP SUCTION BREAK MAXIMUM SAFEGUARDS i POST REFLOOD MASS AND ENERGY RELEASES Break Path No.1 Flow Break Path No. 2 Flow Time Thousand Thousand l (Btu /sec) (seconds) (Ibm /sec) (Btu /sec) (Ibm /sec) 460.8 125.3 156.2 864.7 137.4 465.8 124.8 155.6 865.2 137.4 485.8 125.0 155.8 865.0 136.6 ; 530.8 123.8 154.3 866.2 137.3 l 1 535.8 124.2 154.8 865.8 137.0

550.8 123.5 154.0 866.5 136.6

- 555.8 123.7 154.2 866.3 136.3 ! 570.8 123.2 153.6 866.8 135.8 l 590.8 123.1 153.5 866.9 135.0 152.4 867.7 135,5 630.8 122.3 Os 640.8 122.5 152.7 867.5 135.0 660.8 122.1 152.2 867.9 134.2 665.8 67.3 83.9 922.7 148.8 l 907.2 67.3 83.9 922.7 148.8 907.3 71.3 85.1 918.7 145.0 1264.6 71.2 88.0 918.8 144.7 1264.7 65.5 75.4 924.5 86.7 64.9 74.7 925.1 86.8 1311.6 1311.7 64.9 74.7 1094.4 164.6 50.5 58.1 1108.9 167.2 3600.0 40.2 46.2 1119.2 159.3 3600.1 29.1 33.4 I130.3 160.8 10000.0 16.1 18.5 1143.3 162.7 100000.0 6.9 7.9 1152.5 164.0 1000000.0 O m:\3254w .non\sec6f.wpf. l b-012997 6-243

TABLE 6.4.1 16 DOUBLE ENDED PUMP SUCTION BREAK MASS BALANCE MAXIMUM SAFEGUARDS Mass Ba'ance Time (Seconds) .00 21.80 21.80 200.71 907.27 1264.56 3600.00 Mass (Thousand Ibm) Initial in RCS and ACC 602.63 602.63 602.63 602.63 602.63 602.63 602.63 Added Mass Pumped injection .00 .00 .00 166.65 866.05 1219.77 3919.40 Total Added .00 .00 .00 166.65 866.05 1219.77 3919.40

    '" TOTAL AVAILABLE *"             602.63    602.63   602.63    769.28    1468.69  1822.41 4522.03 Distribution     Reactor Coolant     409.68     51.15    70 04     120.39    120.39   120.39  120.39 Accumulator         192.96    142.32   123.43        .00       .00      .00     .00 Total Contents      602.63    193.47   193.47     120.39    120.39   120.39  120.39 i

Effluent Break Flow .00 409.15 409.15 640.04 1339.45 1693.17 4392.79 ECCS Spill .00 .00 .00 .00 .00 .00 .00 Total Effluent .00 409.15 409.15 640.04 1339.45 1693.17 4392.79 ;

  *" TOTAL ACCOUNTABLE "*             602.63    602.62   602.62    760.43    1459.84' 1813.56 4513.17   )

O m:\3254w. mon \wc6f wpf.1tK)l:997 6-244

1 l l TABLE 6.4.117 1 DOUBLE ENDED PUMP SUCTION BREAK ENERGY BALANCE } MAXIMUM SAFEGUARDS

Energy a i -

Time (Seconds) .00 21.80 21.80 200.71 907.27 1264.56 3600.00 Energy (Milhos Beu) 1- Initial in RCS, ACC, 629.13 629.13 629.13 629.13 629.13 629.13 629.13 j Energy S GEN ! Added Pumped injection .00 .00 .00 14.66 76.21 107.34 488.97 i Decay Heat .00 5.44 5.44 22.46 70.78 91.28 198.97 i Wat From .00 -5.75 -5.75 5.75 -3.09 -2.20 -2.20 econdary j Total Added .00 .31 .31 31.37 143.90 1%.41 685.73 ]

TOTAL AVAILABLE
629.13 628.82 628.82 660.50 773.03 825.54 1314.86

+ Distribution Reactor Coolant 241.17 10.94 12.63 31.58 31.58 31.58 31.58 Accumulator 17.28 12.74 11.05 .00 .00 .00 .00 2 Core Stored 18.95 9.53 9.53 4.05 3.90 3.74 2.71 l Primary Metal 115.09 108.76 108.76 86.57 58.01 51.37 37.72 { ! Secondary Metal 33.86 33.85 33.85 30.32 21.29 18.11 13.39 l 4 , ! Steam Generator 202.78 202.37 202.37 177.64 122.15 104.24 77.32 ' t ! Total Contents 629.13 378.20 378.20 330.17 236.92 209.04 162.72 ! 1 t l Effluent Break Flow .00 250.14 250.14 322.11 527.89 59R.77 1138.04 f ECCS Spill .00 .00 .00 .00 .00 .00 .00 ! l

Total Effluent .00 250.14 250.14 322.11 527.89 598.77 1138.04 i

1

TOTAL ACCOUNTABLE
629.13 628.34 628.34 652.28 764.81 807.81 1300.76

) m:U254w.non\sec6f*pf;tb-012997 6-245 d

i TABLE 6.4.118 DOUBLE ENDED HOT LEG BREAK SEQUENCE OF EVENTS Time (sec) Event Description 0.0 Break Occurs, Reactor Trip and Loss of Offsite Power are assumed 2.6 Low Pressurizer Pressure SI Setpoint - 1714.7 psia reached by SATAN 11.1 Broken loop Accumulator Begins Injecting Water 11.3 Intact Loop Accumulator Begins Injecting Water 20.0 End of Blowdown Phase

O I 1 l l 9 m:u254w.noisec6f wpf.lb-012997 6-246

 ..-. -.   . ..-.~. ...-_...-                            - . . - . - _ - - - _ . - . . - _ - _ _ . . .         _ . - . . . . - _ . . . . _ . , ._ -

I . i TABLE 6.4.1-19 4 ~' DOUBLE ENDED PUMP SUCTION BREAK MINIMUM SAFEGUARDS SEQUENCE OF EVENTS Time (sec) Event Description 0.0 Break Occurs, Reactor Trip and Loss of Offsite Power are assumed 3.1 Low Pressurizer Pressure SI Setpoint - 1714.7 psia reached by SATAN 13.2 Broken Loop Accumulator Begins injecting Water 13.4 Intact Loop Accumulator Begins injecting Water 21.8 End of Blowdown Phase 30.1 Safety injection Begins 44.8 Broken Loop Accumulator Water injection Ends 46.9 Intact Loop Accumulator Water injection Ends 203.1 End of Reflood Phase 2139.0 Cold Leg Recirculation Begins 1.0E+06 Transient Modeling Terminated 1 1 nru254w.nonssec6r3pt.it>ol2997 6-247

TABLE 6.4.I.20 DOUBLE-ENDED PUMP SUCTION BREAK MAXIMUM SAFEGUARDS SEQUENCE OF EVENTS Time (see) Event Description 0.0 Break Occurs, Reactor Trip and Loss of Offsite Power are assumed 3.1 Low Pressurizer Pressure SI Setpoint - 1714.7 psia reached by SATAN 13.2 Broken Loop Accumulator Begins Injecting Water 13.4 Intact Loop Accumulator Begins injecting Water 21.8 End of Blowdown Phase 30.1 Safety injection Begins 45.2 Broken Loop Accumulator Water Injection Ends l l 47.4 Intact Loop Accumulator Water Injection Ends 200.7 End of Reflood Phase 1311.6 Cold Leg Recirculation Begins 1.0E+06 Transient Modeling Terminated j l l l l 4 O mM254w.non\sec6f.wpf.tt>012997 6-248

_ _ _ _ . _ _ _ _ _ _ . . _ . . . . _ _ _ . _ _ . _ _ _ _ _ _ _ _ _ _ . . _ _ _ _ . . . . . . _ _ _ _ _ _ . ._m. 4 ' F l F TABLE 6.4.121

LOCA MASS AND ENERGY RELEASE ANALYSIS l CORE DECAY HEAT FRACTION Time (sec) Decay Heat Generation Rate (Btu /br) 10 0.0052293 15 0.049034 i 20 0.047562 40 0.041504 60 0.038493 80 0.036410 100 0.034842 150 0.032180 200 0.030432 400 0.026664 600 0.024486 1 800 0.022943 1 1000 0.021722 1500 0.019483 2000 0.017903 4000 0.014386 6000 0.012684 8000 0.011645 10000 0.010916 15000 0.010130 20000 0.009368 40000 0.007784 60000 0.006976 80000 0.006439 100000 0.006034 150000 0.005336 200000 0.004859 400000 0.003781 600000 0.003212 800000 0.002644 1000000 0.002589 O m:u2m.non\=6f.wpf.It412997 6-249

6.4.2 Short-Term LOCA Mass and Energy Releases s. 6.4.2.1 Purpose An evaluation was conducted to determine the effect of a power uprate on the shon-term LOCA-related mass and energy releases that support subcompartment analyses discussed in Chapter 6.2 of the Farley FSAR. From the FSAR (Reference 7), a double-ended circumferential rupture of the reactor coolant cold leg forms the basis for the steam generator companments, a 100 in2 reactor vessel inlet break forms the basis for the reactor cavity region, and both a spray line break and a surge line break were considered for the pressurizer companment. This evaluation addresses the impact of the power uprate and other relevant issues on the current licensing basis for these four breaks. 6.4.2.2 Discussion and Evaluation The subcompartment analysis is performed to ensure that the walls of a subcompartment can maintain their structural integrity during the shon pressure pulse (generally less than 3 seconds) which accompanies a high energy line pipe rupture within the subcompartment. The magnitude of the pressure differential across the walls is a function of several parameters, which include the blowdown M&E release rates, the subcompanment volume, vent areas, and vent flow behavior. The blowdown M&E release rates are affected by the initial RCS temperature conditions. Since short-term releases are linked directly to the critical mass flux, which increases with decreasing temperatures, the short-term LOCA releases wculd be expected to increase due to any reductions in RCS coolant temperature conditions. Shon term blowdown transients are characterized by a peak mass and energy release rate that occurs during a subcooled condition, thus the Zaloudek correlation, which models this condition, is currently used in the shon term LOCA mass and energy release analyses with the SATAN computer program. This calculation was used to conservatively evaluate the impact of the changes in RCS temperature conditions due to the power uprate on the shon term releases. This was accomplished by maximizing the reservoir pressure and maximizing the RCS inlet and outlet temperatures for the current analysis of record, and, by minimizing the RCS inlet and outlet temperstures for the power uprate data. Since this maximizes the change in short-term LOCA mass and energy releases, data representative of the lowest inlet and outlet temperatures with uncenainty subtracted was used for the power uprate evaluation. Any changes in RCS volume, steam generatcr liquid / steam mass and volume, and differences in units, such as upflow versus downflow, have no effect on the releases because of the short duration of the postulated accident. Any volumetric changes are smad and have no impact on the subcompartment model. Therefore, the only change that needs to be addressed for this program is the decreased RCS coolant temperatures. For this evaluation, a RCS pressure of 2250 psia, a vessel outlet temperature of 603.8'F, and a vesseV. :nlet temperature of 530.6*F were considered for the uprating. Considering the temperature mA3254w.non\sec6f.wpf Ib-012997 6-250

uncertainty of 6'F and the current licensing basis initial conditions, the following RCS temperature ranges were used for the evaluations herein.

Vessel Outlet 616.9'F to 597.8'F
Vessel / Core Inlet 563.I'F to 524.6*F A pressure uncenainty of 50 psi was also included in the evaluation.

Based upon the results of the evaluation, the current design basis LOCA-related mass and energy releases, including the spray line and the surge line releases, could increase by a factor of 1.18 due to RCS temperature effects. Per Reference 6, Farley is approved for Leak-Before-Break (LBB). LBB eliminates the dynamic effects of postulated primary loop pipe ruptures from the design basis. This means that the current breaks (a double-ended circumferential rupture of the reactor coolant cold leg break for the steam generator companments, and a 144 in2 reactor vessel inlet break for the reactor cavity region) no longer have to be considered for the shon term effects. Since the RCS piping has been eliminated from consideration, the large branch nonles must be considered for design verification. This includes the surge line, accumulator line, and the RHR line. These smaller breaks, which are outside the cavity region, would result in minimal asymmetric pressurization in the reactor cavity region. Additionally, compared to the large RCS double-ended ruptures, the differential loadings are significantly reduced. For example, the peak break compartment pressure can be reduced by a factor of greater than 2, and the peak differential across an adjacent wall can be reduced by a factor of greater than 3, if the nonle breaks are considered. Herefore, since Farley is approved for LBB, the decrease in mass and energy releases associated with the smaller RCS nonle breaks, as compared to the larger RCS pipe breaks, more than offsets the increased releases associated with decreased RCS initial coolant temperatures. The current licensing basis subcompartment analyses that consider breaks in the RCS remain bounding. 6.4.2.3 Results and Conclusion he short-term LOCA-related mass and energy releases discussed in Chapter 6.2 of the Parley FSAR have been reviewed to assess the effects associated with the Farley Power Uprate Project. Results show that the current design basis spray line and surge line releases would increase 18% due to RCS temperature effects. The mass rates (lb/s) in FSAR Tables 6.2-16 and 6.2-17 are multiplied by 1.18. The results of this evaluation were provided for use in the pressurizer subcompartment structural analysis (see BOP Licensing Report). Since Farley is approved for LBB, the decrease in mass and energy releases associated with the smaller RCS nonle breaks, as compared to the larger RCS pipe breaks, more than offsets the increased releases associated with decreased RCS initial coolant temperatures. The current licensing basis subcompanment analyses that consider breaks in the primary loop reactor coolant system piping (i.e., steam generator subcompanments and reactor cavity region), therefore, remain bounding, mA3254w.non\sec6f wpf:Ib 012997 6-251

6.4.3 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 (Nonproprietary).

2. Docket No. 50-315. " Amendment No.126, Facility Operating License No. DPR-58 (TAC No. 7106), for D. C. Cook Nuclear Plant Unit 1," June 9,1989.

1 i

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

4. " Westinghouse Mass and Energy Release Data For Containment Design," WCAP-8264-P-A, Rev.1. August 1975 (Proprietary), WCAP-8312-A (Nonproprietary).

5. ANSI /ANS-5.1 1979, "American National Standard for Decay Heat Power in Light Water Reactors," August 1979.

6. WCAP-12825, " Technical Justification for Eliminating Large Primary Loop Pipe Rupture as a Structural Design Basis for the Joseph M. Farley Units 1 and 2 Nuclear Power Plants,"

l January 1991.

7. Joseph M. Farley Nuclear Plant Unit I and Unit 2 Final Safety Analysis Report Update, Section 6.2.

Gl l 9 ms254 monwr.wpt.ib4:2997 6-252

  .~ . _     _ . . _ . _ _ _ _ _ - ~ _ _ - - _ . _ . _ . . _ . _ - . _ . -                                           _   __ . _ _ _

i l 1 l

6.5 Main Steamline Break Mass and Energy Releases i ,

6.5.1 Main Steamline Break Mass and Energy Releases Inside Containment i 6.5.1.1 Identification of Coures and Accident Description b { i j Steamline ruptures occurring inside a reactor containment structure may result in significant releases of j high-energy fluid to the containment environment, possibly resulting in high containment temperatures 4 and pressures. The quantitative nature of the releases following a steamline rupture is dependent upon i i the plant operating conditions and the size of the rupture as well as the configuration of the plant ] steam system and the containment design. The analysis considers a variety of postulated pipe breaks , j encompassing wide variations in plant operation, safety system performance, and break size in determining the main steamline break (MSLB) mass and energy (M&E) releases for use in containment integrity analysis. j 6.5.1.2 Input Parameters and Assumptions i The postulated break area can have competing effects on blowdown results. Larger break areas will be j- more likely to result in large amounts of water being entrained in the blowdown. However, larger j breaks also result in earlier generation of protective trip signals following the break and a reduction of 4 both the power production by the plant and the amount of high-energy fluid available to be released to i the containment. ) a l To determine the effects of plant power level and break area on the mass and energy releases from a j suptured steamline, spectra of both variables have be n 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 l l are defined as the following. ! 1. A full double-ended rupture (DER) downstream of the flow restrictor in one steamline. Note ; 4 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 I

entrainment occurs. 4 3. A small break at the steam generator nozzle having an area just smaller than that at which water entrainment occurs. ]

4. A small split rupture that will neither generate a steamline isolation signal from the Engineered i Safety Features nor result in water entrainment in the break effluent.

) Sixteen cases were chosen for power uprate analyses based on the results of the analyses presented in d the Farley Nuclear Plant (FNP) FSAR, Section 6.2.1.3.11. All cases were analyzed at the uprated s mA3254w.non\sec6f.wpf;lb-012997 6-253 a

i power condition assuming isolation is accomplished by the redundant swing-disc isolation valves in I each intact steamline. The important plant conditions and features that were assumed are discussed in l the following paragraphs. l Initial Power level Steamline breaks can be postulated to occur with the plant in any operating condition ranging from hot shutdown to full power. Since steam generator mass decreases with increasing power level, breaks occurring at lower power levels will generally result in a greater total mass release to the containment. However, because of increased 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 postulated to occur during full-power, or near full-power, operation may be greater than for breaks occurring with the plant in a low-power, or hot-shutdown, condition. Additionally, steam pressure and the dynamic conditions in the steam generators change with increasing power and have a significant influence on both the rate of blowdown and the amount of moistme entrained in the fluid leaving the break. Because of the opposing effects (mass versus energy release) of changing power level on steamline break releases, no single power level can be singled out as a worst case initial condition for a steamline break event. Therefore, several different power levels spanning from full- to zero-power conditions have been investigated for Farley Units 1 and 2 as presented in the FNP FSAR, based on the information in Reference 1. For this power upmting analysis, the power levels and steamline break sizes are noted in Section 6.5.1.3 of this report. In general, the plant initial conditions are assumed to be at the nominal value corresponding to the initial power for that case, with appropriate uncertainties included. Tables 6.5-1 and 6.5-2 identify the values assumed for RCS pressure, RCS vessel average temperature, pressurizer water volume, steam generator water level, and feedwater enthalpy corresponding to each power level analyzed. Single-Failure Assumptions To avoid unnecessary conservatism, bounding multiple failure assumptions were not made in the analysis. Each case analyzed considered only one single failure. The method of determining the steam system blowdown assumes no failure in steam or feedwater isolation. This blowdown is used in conjunction with minimum containment spray and fan coolers to allow for a failure of a train of containment safeguards features. The following single failures are postulated (discussed also in Reference 1) which may significantly affect the containment results.

a. Failure to Completely Isolate All the Main Steamlines The main steamline isolation function is accomplished via two redundant swing-disc isolation valves in each of the three steamlines. Both valves close on an isolation signal to terminate I steam flow from the associated steam generator. A single failure in one of the two valves has !

I m:\3254w.non\see6f.wpf. I t> 012997 6-254

a ; i 1 l

i. no effect for a main steamline rupture downstream of the valves since the isolation function !

4 will be performed by the other valve in the same steamline. However, a main steamline ! rupture upstream of these valves, as postulated for the inside-containment analysis, will create I

a situation in which the steam generator on the faulted loop cannot be isolated. De contents l

of this steam generator and any feedwater flow to it will blow down continually until the j' feedwater flow is terminated. Since these valves stop steam flow only in the forward j direction, the mass and energy release to containment was modified to include the entire steam i: piping volume downstream of the isolation valves for the other two steam generators, l including the steamline header and steam dump piping. The intent of this assumption is to , show that the protection logic which provides a signal _to close the isolation valves, and the ] associated delay time, is adequate to limit the amount of steam mass and energy discharged j l into containment such that the containment pressure limit is not exceeded.

b. Failure of the Feedwater Flow Control Valve (FCV) in the Faulted Loop If the FCV in the feedwater line to the faulted steam generator is assumed to fail in the open position, main feedwater flow would continue from the condensate and feedwater system until backup isolation is provided via the main feedwater isolation valve (MFIV) closure. His additional inventory would then be available to be released to containment.

c. Emergency Diesel Generator (EDG)

For the circumstance where offsite power is lost, power will be lost to the reactor coolant pumps (RCPs) and the EDGs will be relied upon to supply emergency power to the safeguards equipment. If one EDG fails in this situation, one train of safety injection (SI) as well as one train of the containment safeguards functions will be lost. De only effect on the mass and energy releases is the loss of one SI train, a longer delay until SI actuation, and RCP trip. As noted later, minimum SI flow is assumed for all cases. The effect of reduced containment safeguards is accounted for in the containment response analysis. The assumption of a trip of all the RCPs coincident with reactor trip is less limiting than with offsite power available since the mass and energy releases are reduced due to the loss of forced reactor coolant flow, ] resulting in less primary-to-secoef Hat transfer. l Maip,leedwater System j The rapid depressurization which occurs following a steamline rupture typically results in large amounts of water being added to the steam generators through the main feedwater system. Rapid-closing feedwater control valves in the main feedwater lines limit this effect. De feedwater addition which occurs prior to closing of the feedwater line control valves influences the steam generator l blowdown in several ways. First, the rapid addition increases the amount of entrained water in large ! break cases by lowering the bulk quality of the steam exiting the rupture. Secondly, because the water entering the steam generator is subcooled, it lowers the steam pressure thereby reducing the flow rate out of the break. Ar, the steam generator pressure decreases, some of the fluid in the feedwater lines mA3254w.non\sec6f.wpf:Ib-012997 6-255

downstream of the control valves will flash into the steam generators providing additional secondary fluid which may exit out of the rupture. Finally, the increased flow causes an increase in the heat transfer rate from the primary to secondary systems resulting in greater energy being released out of the break. Since these are competing effects on the total mass and energy release, no " worst case" feedwater transient can be defined for all plant conditions. Main feedwater flow was conservatively modeled by assuming that sufficient feedwater flow was provided to match the steam flow prior to reactor trip. The initial increase in feedwater flow (until fully isolated) is in response to increases in steam flow following initiation of the steamline break. This maximizes the total mass addition prior to feedwater isolation. The feedwater isolation response time, following the safety injection signal, was assumed to be a total of 7 seconds, consisting of 2 seconds for signal processing plus 5 seconds for the Feedwater Flow Control Valve (FCV) stroke time. For the circumstance in which there is failure of the FCV in the faulted loop to close, the feedwater isolation response time was assumed to be a total of 32 seconds, consisting of 2 seconds for signal processing plus 30 seconds for the feedwater isolation valve (FWIV) stroke time. 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 is maximized for the faulted loop and minimized for the intact loops. The energy in the unisolable volume is maximized by assuming recirculated feedwater from the condenser rather than " cold" water from the condensate storage tank. Auxiliary Feedwater System Generally, within the first minute following a steamline break, the auxiliary feedwater (AFW) system is initiated on any one of several protection system signals. Addition of auxiliary feedwater to the steam generators will increase the secondary mass available for release to containment as well as increase the heat transferTed to the secondary fluid. The auxiliary feedwater flow to the faulted and intact steam generators is a function of the backpressure in the steam generators. A higher AFW flowrate to the faulted loop steam generator is conservative for the steamline break event; therefore, these flows were maximized as a function of backpressure. Conversely. lower AFW flowrate is conservative for the intact loop steam generators; thus, these flows wen uunimized as a function of backpressure. Steam Generator Fluid Mass A maximum initial steam generator mass in the faulted loop steam generator was used in all of the analyzed cases. The use of a high faulted-loop initial steam generator mass maximizes the steam generator inventory available for release to containment. The initial mass was calculated as the value corresponding to the programmed level +12% narrow-range span. Minimum initial masses in the intact loop steam generators were used in all of the analyzed cases. The use of reduced initial steam mA3254w.non\sec6f wpf.lb 012997 6-256

ger.:rator masses minimizes the availability of the heat sink afforded by the steam generators on the V intact loops. The initial masses were calculated as the value corresponding to the programmed level

    -7% narrow-range span. All steam generator fluid masses are calculated assuming 0% tube plugging.

This assumption is conservative with respect to the RCS cooldown through the faulted loop steam generator resulting from the steamline break. Steam Generator Reverse Heat Transfer Once the steamline isolation is complete, the steam generators in the intact loops become sources of energy which can be transferred to the steam generator with the broken line. This energy transfer 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 the intact steam l generators resulting in energy being returned to the primary coolant. This energy is then available to be transferred to the steam generator with the broken steamline. The effects of reverse steam generator heat transfer are included in the results. Break Flow Model Piping discharge resistance,s were not included in the calculation of the releases resulting from the steamline ruptures [ Moody Curve for an f(# / D) = 0 was used). Steamline Volume Blowdown The contribution to the mass and energy releases frcm the secondary plant steam piping was included in the mass and energy release calculations. The flowrate was determined using the Moody correlation, the pipe cross-sectional area, and the initial steam pressure. Foc all steamline break cases 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 Steamline isolation is assumed in the two intact loops to terminate the blowdown from those steam generators. A delay time of 12 seconds was assumed (2-second signal processing time plus 10-second valve stroke time) with full steam flow assumed through the valve during the valve stroke. The 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 two redundant swing-disc isolation valves in each steamline. Isolation of the steam generator in the faulted loop is not assumed so as to simulate the steamline rupture upstream of the isolation valves (between the valves and the steam generator).

 'D mV254w.non\sec6f.wpf.lb-012997                     6-257

O Protection System Actuations , The protection systems available to mitigate the effects of a MSLB accident inside containment include reactor trip, safety injection, steamline isolation, and feedwater isolation. Analyses of the containment responses to the MSLB, which model the operation of the emergency fan coolers and containment spray, are contained in BOP Licensing Report. The protection system actuation signals and associated setpoints that were modeled in the analysis are identified in Table 6.5-3. The setpoints used are conservative values with respect to the Farley plant-specific values delineated in the Technical Specifications. For the 1.069 ft: DER MSLB at all power levels as well as the smaller breaks at powers of 102%, 70%, and 30%, the first protection system signal actuated is Low Steamline Pressure (lead / lag compensated in each channel) in 2 loops which initiates steamline isolation and safety injection; the safety injection signal produces a reactor trip signal. Feedwater system isolation occurs as a result of the safety injection signal. For the split-rupture steamline breaks at all power levels as well as the smaller breaks at hot-zero-power conditions, no mitigation signals are received from either the Reactor Protection System or the Engineered Safety Features Actuation System. The first protection system signal actuated is High Containment Pressure (2-of-3 channels) which initiates safety injection; the safety injection signal produces a reactor trip signal. Feedwater system isolation occurs as a result of the safety injection signal. The second protection system signal actuated is High-High Containment Pressure (2-of-3 channels) which actuates steamline isolation. Safety Iniection System Minimum safety injection system (SIS) flowrates corresponding to the failure of one SIS train are assumed in this analysis. A minimum SI flow is conservative since the reduced boron addition maximizes a retum to power resulting from the RCS cooldown. The higher power generation increases heat transfer to the secondary side, maximizing steam flow out of the break. The delay time to achieve full SI fiow is assumed to be 27 seconds for this analysis with offsite power available; with a coincident loss of offsite power, the delay time to achieve full SI flow is assumed to be 42 seconds. Reactor Coolant System Metal Heat Cariacity 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, m:\3254w . mon \sec6f.wpf. l b-012997 6-258

l l i l Core Decav Heat Cote decay heat generation assumed in calculating the steamline break mass and energy releases is l based on the 1979 ANS Decay IIcat + 20 model (Reference 2), j Rod Control i The rod control system is conservatively assumed to be in manual operation for all steamline break analyses. Core Reactivity Coefficients Conservative core reactivity coefficients corresponding to end-of-cycle conditions, including hot zero power (HZP) stuck-rod moderator density coefficients, are used to maximize the reactivity feedback effects resulting from the steamline break. Use of maximum reactivity feedback results in higher power generation if the reactor retums to criticality, thus maximizing heat transfer to the secondary side of the steam generators. 6.5.1.3 Description of Analysis The break flows and enthalpies of the steam release through the steamline break inside containment 5 are analyzed with the LOFTRAN (Reference 3) computer code. Blowdown mass and energy releases i determined using LOFTRAN include the effects of co e power generation, main and auxiliary feedwater additions, engineered safeguards systems, reactor coolant system thick metal heat storage, and reverse steam generator heat transfer. l l The Parley NSSS is analyzed using LOFTRAN to determine the transient steam mass and energy l releases inside containment following a steamline break event. The tables of mass and energy releases I are used as input conditions to the analysis of the containment response. The following licensing-basis cases of the MSLB inside containment were analyzed at the uprated power.

Case 1: Full double-ended (1.069 ft') rupture at 102% power - with entrainment
Case 2: 0.7 ft' double-ended rupture at 102% power - with entrainment
Case 3: 0.6 ft 2double-ended rupture at 102% power - without entrainment j 2

 =        Case 4:      0.528 ft split rupture at 102% power                                             )

Case 5: Full double-ended (1.%9 ft') rupture at 70% power - with entrainment
Case 6: 0.6 ft' double-ended rupture at 70% power - with entrainment
Case 7: 0.5 ft 2double-ended rupture at 70% power - without entrainment
Case 8: 0.561 ft2split rupture at 70% power i a Case 9: Full double-ended (1.069 ft') rupture at 30% power - with entrainment
Case 10: 0.5 ft double-ended rupture at 30% power - with entrainment m:u254w.monwwpr::w12997 6-259

l l . Case 11: 0.4 ft' double-ended rupture at 30% power - without entrainment

Case 12: 0.591 ft2split rupture at 30% power

= Case 13: Full double-ended (1.069 ft2 ) rupture at hot standby (0% power) - with l entrainment

Case 14: 0.2 ft 2double-ended rupture at hot standby (0% power)- with entrainment

. Case 15: 0.1 ft 2double-ended rupture at hot standby (0% power)- without entrainment j 2 . Case 16: 0.3 ft spl t rupture at hot standby (0% power) I For Cases 4, 8, and 12, the cross-sectional split-break area for power uprate analyses was reduced based on the assumption of a higher value for the Low Steamline Pressure setpoint of 551.7 psia. The I break area for these 3 cases as presented in Section 6.2.1.3.11 of the FNP FSAR assumes a Low Steamline Pressure serpoint of 443.7 psia. The higher value for the Low Steamline Pressure setpoint may be assumed since the pressure transmitters associated with this function are located outside containment and in a non-harsh environment. Therefore, adverse environmental effects need not be considered for a steamline break inside containment. l 6.5.1.4 Acceptance Criteria The main steamline break is classified as an ANS Condition IV event, an infrequent fault. Additional l clarification of the ANS classification of this event is presented in Section 6.2.19 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 an ; analysis which provides sufficient conservatism 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 l flow, steamline and feedwater isolation, and single failure such that the containment peak pressure and ) temperature are maximized. These analysis assumptions have been included in this steamline break mass and energy release analysis as discussed in Reference I and Section 6.5.1.2 of this report. The j tables of mass and energy release data for each of the steamline break cases noted in the previous l section are used as input to a containment response calculation to confirm the design parameters of the Farley Units I and 2 containment structure. l 6.5.1.5 Results Using Reference 1 as a basis, including parameter changes associated with the power uprating, the I mass and energy release rates for each of the steamline break cases noted in Section 6.5.1.3 were developed for use in containment pressure and temperature response analyses. Tables 6.5-4 and 6.5-5 provide the sequence of events for the two limiting steamline breaks (Cases 1 (i.e., peak temperature case) and 12 (i.e., peak pressure case)) inside containment. O m:\3254w.non\sec6f.wpf:lt412997 6-260

p 6.5.I.6 Conclusions The mass and energy releases from the sixteen steamline break cases have been analyzed at the uprated power conditions. He assumptions delineated in Section 6.5.1.2 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 have been provided for use in the containment response analysis in support of the Farley power uprating (see BOP Licensing Report). 6.5.2 Main Steamline Break Mass and Energy Releases Outside Containment 6.5.2.1 Identification of Causes and Accident Dscription Steamline ruptures occurring outside the reactor containment structure may result in significant releases of high-energy fluid to the structures surrounding the steam systems. Superheated steam blowdowns following the steamline break have the potential to raise compartment temperatures outside containment. The impact of the steam releases depends on the plant configuration at the time of the break, the plant response to the break, as well as the size and location of the break. Because of the interrelationship between many of the factors which influence steamline break mass and energy releases, an appropriate determination of a single limiting case with respect to mass and energy releases cannot be made. Therefore, it is necessary to analyze the steamline break event outside (~ \ containment for a range of conditions. 6.5.2.2 Input Parameters and Assumptions To determine the effects of plant power level and break area on the mass and energy releases from a ruptured steamline, spectra of both vr... ables have been evaluated (Reference 4). At plant power levels of 102% and 70%, various break sizes have been defined from the full double-ended rupture of a main steamline down to the break of the smallest line which cannot be isolated in the main steam system. Cases were chosen for power nprate analyses based on the results of the analyses presented in the Farley Nuclear Plant (FNP) FSAR, Appendix 3J - which is based on the many cases documented in Reference 4. A subset of the 32 cases noted in the FNP FSAR was analyzed at the uprated power condition tssuming isolation is accomplished by the redundant swing-disc isolation valves in each steamline. The important plant conditions and features that were assumed are discussed in the following para;traphs. Initial Power Igyel e The initial power which is assumed for steamline break analyses outside containment affects the mass and energy releases and steam genemtor tube bundle uncovery in two ways. First, the steam generator O mass inventory increases with decreasing power levels; this will tend to delay uncovery of the steam generator tube bundle, although the increased steam pressure associated with lower power levels will cause a faster blowdown at the beginning of the transient. Second, the amount of stored energy and m:u254w.nonssec6r.wpr.ib. ora 97 6-261

decay heat, as well as feedwater temperature, are less for lower power levels; this will result in lower primary temperatures and less primary-to-secondary heat transfer during the steamline break event. Overall, steamline breaks initiated from lower power levels result in lower levels of steam superheating than breaks analyzed at full-power conditions. For this reason, steamline break outside containment l mass and energy release calculations are limited to breaks initiated from full-power or near full-power conditions; specifically: l l l

full power - maximum allowable NSSS power plus uncertainty, i.e.,102% of rated power; and j
near full-power - 70% of maximum allowable NSSS power. l I

l J For this power uprating analysis, the power levels and steamline break sizes are noted in i Section 6.5.2.3 of this report. In general, the plant initial conditions are assumed to be at the nominal value corresponding to the initial power for that case, with appropriate uncertainties included. Tables 6.5-1 and 6.5-2 identify the values assumed for RCS pressure, RCS vessel average temperature, pressurizer water volume, steam generator water level, and feedwater enthalpy corresponding to each power level analyzed. Single-Failure Assumption The limiting single failure is the failure of the turbine-driven auxiliary feedwater (AFW) pump to start. AFW flow can have a significant impact on the calculated mass and energy releases following a steamline break outside containment. With respect to the production of superheated steam, increased AFW flow can have the beneficial effect of reducing the enthalpy of the mass release. Variations in AFW flow can affect steamline break mass and energy releases in a number of ways including break mass flow rate, RCS temperature, tube bundle uncovery time and steam superheating. The failure of the turbine-driven AFW pump results in a minimum AFW flow to the steam generators; minimum AFW flow is based on two motor-driven AFW pumps. Main Feedwater System The main feedwater system was conservatively modeled for the steamline break mass and energy releases outside containment by assuming the following.

Nominal main feedwater flow corresponding to the initial power until the time of reactor trip
Nominal main feedwater temperature corresponding to the initial power The rapid depressurization which typically occurs following a steamline rupture results in large amounts of water being added to the steam generators through the main feedwater system. However, l t

main feedwater flow was conservatively modeled by assuming no increase in feedwater flow in response to the increases in steam flow following the steamline break event. This minimizes the total mu254w.nonwc6f wpf.ib412997 6-262 1

I l l I mass addition and associated cooling effects in the steam generators. High main feedwater temperatures were assumed to minimize the cooling effect of the main feedwater. . Isolation of the main feedwater flow was conservatively assumed to be coincident with reactor trip, irrespective of the function which produced the reactor trip signal. This assumption reduces the total mass addition te the steam generators. Closing of the feedwater flow control valves in the main feedwater lines is assumed to be instr.ntaneous with no consideration of associated signal processing or valve stroke time. Auxiliary Feedwater System Generally, within the first few minutes following a steamline break, the auxiliary feedwater (AFW) l system (i.e., motor-driven AFW pumps) is initiated on any one of several protection system signals. l Addition of auxiliary feedwater to the steam generators will increase the secondary mass available to cover the tube bundle and is a benefit for the amount of superheated steam produced. For this reason, AFW flow is delayed and minimized to accentuate the depletion of the initial secondary side inventory, ne AFW flow to all steam generators is a function of the backpressure in the steam generators. Steam Generator Fluid Mass ,Dt - L/ A minimum initial steam generator mass in all the steam generators was used in all of the analyzed cases. De use of a reduced initial steam generator mass minimizes the avsilability of the heat sink afforded by the steam generators and leads to earlier mbe bundle uncovery. De initial mass was calculated as the value corresponding to the programmed level -7% narrow-range span. All steam generator fluid masses are calculated assuming 0% tube plugging, his assumption is conservative with respect to the RCS cooldown through the steam generators resulting from the steamline break.

   ' Break Flow Model Piping discharge resistances were not included in the calculation of the releases resulting from the steamline ruptures [ Moody Curve for an f(f / D) = 0 was used).

Main Steamline Isolation Steamline isolation is assumed in all loops to terminate the blowdown from those steam generators for all break sizes except for the smallest (0.05 ft2 ). The main steamline isolation function is accomplished via two redundant swing-disc isolation valves in each of the three steamlines. Both valves close on an isolation signal to terminate steam flow from the associated steam generator. A failure in one of the two valves has no effect for a main steamline rupture downstream of the valves since the isolation function will be performed by the other valve in the same steamline. Therefore, J once a signal to isolate the main steamlines is received (on a low steamline pressure setpoint), the steam blowdown is terminated. m:\3254w.non\sec6f.wpf: I b.012997 6-263 l l i

However, a main steamline rupture upstream of these valves will create a situation in which the steam generator on the faulted loop cannot be isolated. The contents of this steam generator and any AFW flow to it will blow down continually until the AFW flow is terminated. The main steamlines outside containment up to the isolation valves conform to Branch Technical Positions APCSB 3-1 and MEB 3-1; therefore, a rupture in these pipes is not postulated. The only postulated break outside containment upstream of the isolation valves is the 3-inch-diameter branch line to the turbine-driven AFW pump. This line is not part of the "no break zone" and a break must be postulated in this line. Thus, the only break upstream of the isolation valves which must be considered for Farley is the 3-in 2 (0.05 ft ) branch line to the turbine-driven AFW pump. A delay time of 12 seconds is assumed (2-second signal processing time plus 10-second valve stroke time) with full steam flow assumed through the valve during the valve stroke. Protection System Actuations The protection systems available to mitigate the effects of a MSLB accident outside containment include reactor trip, safety injection, steandine isolation, and auxiliary feedwater. The protection system actuation signals and associated setpoints that were modeled in the analysis are identified in Table 6.5-3. The setpoints used are conservative values with respect to the Farley plant-specific values delineated in the Technical Specifications. At 102% power for break sizes from 3.2 ft2down to 0.6 ft ,2the first protection system signal actuated is low Steamline Pressure (lead / lag ccmpensated in each channel) in 2 loops which initiates steamline isolation and safety injection; the safety injection signal produces a reactor trip signal. Main feedwater flow is conservatively assumed to be isolated at the time of reactor trip; motor-driven AFW initiation occurs as a result of the safety injection signal. For break sizes smaller than this, reactor trip is actuated following either the Overpower AT (2-of-3 channels) or Low-Low Steam Generator Water Level (2-of-3 channels in any loop) signal; safety injection is started as a result of a Low Pressurizer Pressure (2-of-3 channels) signal; steamline isolation occurs later due to Low Steamline Pressure. Main feedwater flow is conservatively assumed to be isolated at the time of reactor trip. For very small break sizes, <0.2 ft', the Low Pressurizer Pressure setpoint is not reached; safety injection and steamline isolation occur as a result of Low Steamline Pressure. Auxiliary feedwater flow is initiated following the Low-Low Steam Generator Water Level signal. At 70% power for break sizes from 3.2 ft 2down to 0.6 ft ,2the first protection system signal actuated is Low Steamline Pressure (lead / lag compensated in each channel) in 2 loops which initiates steamline isolation and safety injection; the safety injection signal produces a reactor trip signal. Main feedwater flow is conservatively assumed to be isolated at the time of reactor trip; motor-driven AFW initiation occurs as a result of the safety injection signal. For break sizes smaller than this, reactor trip and motor-driven AFW initiation are actuated following a Low-Low Steam Generator Water Level (2-of-3 channels in any loop) signal; safety injection is started as a result of a Low Pressurizer Pressure (2-of-3 channels) signal; steamline isolation occurs later due to Low Steamline Pressure. Main feedwater flow is conservatively assumed to be isolated at the time of reactor trip. For very m:\3254w.non\sec6f.wpf;It@12997 6-264

i F 2 small break sizes, <0.2 ft , the Low Pressurizer Pressure setpoint is not reached; safety injection and {f steamline isolation occur as a result of Low Steamline Pressure. l l l Safety Iniection System i Minimum safety injection system (SIS) flowrates corresponding to the failure of one SIS train are ' assumed in this analysis. A minimum SI flow is conservative since the reduced boron addition ' maximizes a return to power resulting from the RCS cooldown. The higher power generation I increases heat transfer to the secondary side, maximizing steam flow out of the break. The delay time to achieve full SI flow is assumed to be 27 seconds for this analysis with offsite power available. A coincident loss of offsite power is not assumed for the analysis of the steamline break outside containment since the mass and energy releases are reduced due to the loss of forced reactor coolant flow, resulting in less primary-to-secondary heat transfer. Reactor Coolant System Metal Heat Caneity As the primary side of the plant cools, the temperature of the reactor coolant drops below the temperature of the reactor coolant pirog, the reactor vessel, and the reactor coolant pumps. As this occurs, the heat stored in the metal F wailab!c to be transferred to the steam generritor with the broken line. Stored metal heat du i ot have a major impact on the calculated mass and energy releases. 'Ihe effects of this RCS acts' heat are included in the results using conservative thick metal masses and heat transfer coeffic!uts. Core Decav Heat Core decay heat generation assumed in calculating the steamline break mass and energy releases is based on the 1979 ANS Decay Heat + 20 model (Reference 2). The existing analysis assumed the use of the 1971 standard (+20% uncertainty) for the decay heat as noted on page 2-9 of Reference 4. Since the analysis assumptions documented in Reference 4 include the 1971 standard for decay heat, the assumption of using the 1979 version represents a deviation from the prior documented inputs. l This version of the decay heat input has been applied previously to the Farley licensing-basis safety { analyses. l Rod Control l i The rod control system is conservatively assumed to be in manual operation for all steamline break analyses. i t i Core Reactivity Coefficients l

Conservative core reactivity coefficients corresponding to end-of-cycle conditions are used to l maximize the reactivity feedback effects resulting from the steamline break. Use of maximum m \3254w.monisec6f.wpf: lt412997 6-265

                       ..          __            - - . .  - - . _ . .                  _ - . _ . . - - - . . - .                       _  . ~ _ . _ - .- _

reactivity feedback results in higher power generation if the reactor returns to criticality, thus maximizing heat transfer to the secondary side of the steam generators. 6.5.2.3 Description of Analysis The break flows and enthalpies of the steam release through the steamline break outside containment are analyzed with the LOFTRAN (Reference 3) computer code. Blowdown mass and energy releases determined using LOFTRAN include the effects of core power generation, main and auxiliary feedwater additions, engineered safeguards systems, reactor coolant system thick metal heat storage, and reverse steam generator heat transfer. The Farley NSSS is analyzed using LOFFRAN to determine the transient steam mass and energy releases outside containment following a steamline break event. He tables of mass and energy releases are used as input conditions to the environmental evaluation of safety-related electrical equipment in the main steam valve room. The following licensing-basis cases of the MSLB outside containment were analyzed at the uprated power.

At 102% power, break sizes of 3.2, 2.0, 1.4, 1.0, 0.9, 0.8, 0.7, 0.6, 0.5, 0.4, 0.3, 0.2, 0.1, and 0.05 ft
At 70% power, break sizes of 3.2, 2.0, 1.4, 1.0, 0.9, 0.8, 0.7, 0.6, 0.5, 0.4, 0.3, 0.2, 0.1, and 0.05 ft:

6.5.2.4 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 6.2.19 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 outside containment is based on an analysis which provides sufficient conservatism to assure that the equipment qualification temperature envelope is maintained. The specific criteria applicable to this analysis are related to the assumptions regarding power level, stored energy, the break flow model, steamline and feedwater isolation, and main and auxiliary feedwater flow such that superheated steam resulting from tube bundle uncovery in the steam generators is accounted for and maximized. These analysis assumptions have been included in this steamline break mass and energy release analysis as discussed in Reference 4 and subsection 6.5.2.2 of this report. The tables of mass and energy release data for each of the steamline break cases noted in the previous section are used as input to the environmental evaluation of safety-related electrical equipment in the main steam valve room. O l l r mv254 .nonw6tur .ib.012997 6-266

l I l 6.5.2.5 Results (O Q/ i

    - Using Reference 4 as a basis, including parameter changes associated with the power uprating, the mass and energy release rates for each of the steamline break cases noted in Section 6.5.2.3 were developed for use in the environmental evaluation of safety-related electrical equipment in the main steam valve room. Tables 6.5-6 and 6.5-7 provide the sequence of events for the various steamline          l break sizes at 102% and 70% power, respectively.

l 6.5.2.6 Conclusions The mass and energy releases from a subset of the steamline break cases have been analyzed at the uprated power conditions. The assumptions delineated in Section 6.5.2.2 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 have been provided for use in the environmental evaluation of safety-related electrical equipment in the main steam valve room in support of the Farley power i uprating (see BOP Licensing Repon). l 6.5.3 Steam Releases for Radiological Dose Analysis The vented steam releases have been calculated for the Loss of Loadfrurbine Trip and Steamline i Break events. The calculated values for the steam releases following a Loss of Load / Turbine Trip v event bound those that would be calculated for the Loss of Offsite Power and Locked Rotor events. Information documented in Tables 15.2-3 and 15.4-23 of the Farley FSAR includes steam releases and main feedwater flow; therefore data along the same lines is included herein. The following table summarizes the vented steam releases from the .nperable steam generators as well as main feedwater flows for the 0-2 hour time period and the 2 8 hour time period for each of these events. These two time periods are documented to support the current licensing-basis radiological calculations for Farley. Event Vented Steam Release Feedwcar Flow 0 2 hours 2-8 hours 0-2 hours 2-8 hours l Loss of Loadfrurbine Trip, 427,000 lbm 820,000 lbm 574,000 lbm 908,000 lbm l Loss of Offsite Power, and Locked Rotor Steamline Break 323,000 lbm 695,000 lbm 421,000 lbm 753,000 lbm For the Steamline Break event, additional steam is released through the faulted steam generator from the initiation of the transient up through the time at which isolation of auxiliary feedwater flow is assumed (at 1800 seconds into the event). This additional total steam mass is 458,000 lbm and is comprised of the initial steam generator inventory (168,000 lbm) plus main feedwater flow until ) (,) automatic isolation and auxiliary feedwater flow until manual isolation at 1800 seconds (290,000 lbm). Since auxiliary feedwater flow to the faulted steam generator is assumed to be isolated at ms254u=wec6tyr :b-ol2997 6-267

l 1800 seconds, the steam release from the faulted steam generator is confined to the 0-2 hour time period and does not contribute to the steam release beyond the 0-2 hour time period. No explicit assumption is considered in this analysis regarding steam generator blowdown isolation. The implied assumption is that the entire inventory of the steam generators is released to the environment and no loss of inventory through the blowdown line is accounted for. This provides a conservative calculation of the quantity of steam vented during the noted time periods. The steam releases discussed in this section have been provided as input to the radiological dose analysis in support of the Farley power uprating (see BOP Licensing Report). ti.5.4 References

1. Land. R. E., " Mass and Energy Releases Following a Steam Line Rupture," WCAP-8822 (Proprietary) and WCAP-8860 (Nonproprietary), September 1976.

2. ANSI /ANS-5.1-1979, "American National Standard for Decay Heat Power in Light Water Reactors," August 1979.

3. Burnett, T. W. T., et al., "LOFTRAN Code Description," WCAP-7907-P-A (Proprietary) and WCAP-7907-A (Nonproprietary)," April 1984.

4. Butler, J. C., and Love, D. S., "Steamline Break Mass / Energy Releases for Equipment Environmental Qualification Outside Containment," Report to the Westinghouse Owners Group High Energy Line Break /Superheated Blowdowns Outside Containment Subgroup, WCAP-10961-P, Rev.1, (Proprietary), October 1985.

O m:\3254w.non\sec6f wpf.lb-012997 6-268

l l TABLE 6.51 l FARLEY UNITS 1 AST 2 NOMINAL PLANT PARAMETERS FOR THERMAL UPRATE* l (MSLB M&E Releases) Nominal Conditions NSSS Power, MWt 2785 l Core Power, MWt 2775

Reactor Coolant Pump Heat, MWt 10 Reactor Coolant Flow (total), gpm 258,000 Pressurizer Pressure, psia 2250 Core Bypass, % 7.1 Reactor Coolant Temperatures *F Core Outlet 618.1 Vessel Outlet 613.3 Core Average 581.8 i

Vessel Average 577.2* ' Vessel / Core Inlet 541.1 Steam Generator l' Steam Temperature 'F 518.0 Steam Pressure, psia 798 Steam Flow (total),10' lbm/hr 12.27 Feedwater Temperature 'F 443.4 Zero-Load Temperature, 'F 547

Noted values correspond to plant conditions defined by 0% steam generator tube plugging and the high end of the RCS T,,, window.

m:\3254 w.non\sec6f.wpf. l b-012997 6-269

TABLE 6.5 2 FARLEY UNITS 1 AND 2 INITIAL CONDITION ASSUMPTIONS FOR THERMAL UPRATE* MSLB M&E Releases Inside Containment Initial Conditions Power Level (%) Parameter 102 70 30 0 hCS Average Temperature ('F) 584.2* 575.14* 563.06* 547.0 RCS Flowrate (gpm) 258,000 258,000 258,000 258,000 RCS Pressure (psia) 2250 2250 2250 2250 Pressurizer Water Volume (ft') 772.4 646.4 478.5 352.5 Feedwater Enthalpy (Btu /lbm) 423.0 377.5 304.7 70.0 SG Water Level, faulted / intact (% span) 70/51 70/51 70/51 66.5/47.5 MSLB M&E Releases Outside Containment Initial Conditions Power Level (%) Parameter 102 70 RCS Aserage Temperature ('F) 584.2* 575.14* RCS Flowrate (gpm) 258,000 258,000 RCS Pressure (psia) 2250 2250 Pressurizer Water Volume (ft') 835.1 " 709.1 " Feedwater Enthalpy (Btu /lbm) 423.0 377.5 SG Water Level (% span) 51 51 Noted values correspond to plant conditions defined by 0% steam generator tube plugging and the high end of the RCS T,,, window. Pressurizer water volume includes a level uncertainty of +5% of span. O m:\3254w.non\sec6f.wpf.lb 012997 6-270

{ TABLE 6.5-3 FARLEY UNITS 1 AND 2 PROTECTION SYSTEM ACTUATION SIGNALS AND l SAFETY SYSTEM SETPOINTS FOR THERMAL UPRATE ANALYSIS - MSLB M&E Releases Inside Containmat t Reactor Trio : 2/3 Low Pressure Pressure - 1840 psia l Safety injection Safety Iniection . I 2/3 Low Pressurizer Pressure - 1700 psia 1/1 Low Steamline Pressure in 2/3 loops - 443.7 psia (conservatively low value used in the analysis of the DERs and the small breaks at power)* 1/1 Low Steamline Pressure in 2/3 loops 551.7 psia (higher value used in the analysis of the split breaks and the small breaks at zero power)* dynamic compensation lead - 50 seconds lag - 5 seconds 2/3 High Containment Pressum " (implicit - used in the contairment pressure response analysis) Steamline Isolation 1/1 Low Steamline Pressure in 2/3 loops - 443.7 psia (conservatively low value used in the analysis of the DERs and the small breaks at power)* (higher value used in the analysis of l 1/1 Low Steamline Pressure in 2/3 loops - 551.7 psia the split breaks and the small breaks at zero power)* dynamic compensation lead - 50 seconds ! lag - 5 seconds 2/3 High-High Containment Pressure " (implicit - used in the containment pressure response analysis) Feedwater Isolation and Auxiliary Feedwater Initiation Safety injection ;

Both values for the low steamline pressure setpoint am less than the Technical Specifications limit. The higher value (551.7 psia) does not account for any adverse environmental effects since the pressure transmitters associated with this function are located outside containment and in a non4arsh environment.

The MSLB cases analyzed assuming the lower setpoint (443.7 psia) result in safeguards actution early enough in the transient such that the use of the higher value would not alter the mass and energy releases. t

 "    Setpoint not explicitly modeled in MSLb M&E release analyses.

m:u254w.non\sec6f.wpfib4:3097 6-271

TABLE 6.5 3 (cont.) FARLEY UNITS 1 AND 2 PROTECTION SYSTEM ACTUATION SIGNALS AND SAFETY SYSTEM SETPOINTS FOR THERMAL UPRATE ANALYSIS MSLB M&E Releases Outside Containment Reactor Trin 2/3 Low-Low Steam Generator Water level in any loop - 13% narrow-range span 2/3 Low Pressurizer Pressure - 1840 psia 2/4 Power-Range High Neutron Flux - 118% rated thermal power 2/3 Overtemperature AT K1 = 1.33 K2 = 0.017 K3 = 0.000825 dynamic compensation lead - 30 seconds lag - 4 seconds 2/3 Overpower AT K4 = 1.166 KS = 0.0 K6 = 0.00109 (set to 0 for indicated temperature < reference temperature) dynamic compensation rate lag - 10 seconds Safety Injection Safety Iniection 2/3 Low Pressurizer Pressure - 1700 psia 1/1 Low Steamline Pressure in 2/3 loops - 551.7 psia dynamic compensation lead - 50 seconds lag - 5 seconds Steamline Isolation 1/1 Low Steamline Pressure in 2/3 loops - 551.7 psia dynamic compensation lead - 50 seconds lag - 5 seconds Feedwater Isolation Coincident with Reactor Trip (Conservative assumption) Auxiliary Feedwater Initiation (Motor-driven AFW pumps) 2/~; Low-Low Steam Generator Water Level in any loop - 13% narrow-range span Safety Injection rr.:\3254w .non\sec6f.wpf. l b-0 D097 6-272

i 4 a TABLE 6.5-4 I FARLEY UNITS I AND 2 2 l I.06) ft MSLB HOT FULL POWER WITH CONTAINMENT SAFEGUARDS FAILURE

SEQUENCE OF EVENTS l

, (Peak Temperature Case) 1 Time (sec) Event Description J , 0.0 Main Steamline Break Occurs i 0.6 Low Steamline Pressure Setpoint (443.7 psia) Reached in 2 Loops

2.6 Rod Motion Starts (Low Steamline Pressure actuates SI which initiates Reactor Trip)

,' 3.5 High Containment Pressure Setpoint Reached

7.6 Feedwater Isolation Occurs i

i 12.6 Steamline Isolation Occurs (following receipt of the Low Steamline Pressure ) signal) I r !' 12.8 High-High Containment Pressure Setpoint Reached j 27.6 Safety Injection Flow Initiated i ! 90.5 Containment Fan Cooler (I cooler) Actuates 4

101.1 Containment Spray (1 train) Actuates i 101.1 Peak Containment Temperature (383*F) Occurs 1

l, 1811. Peak Containment Pressure (41.9 psig) Occurs 1' 1820. Mass and Energy Releases Terminate (SG Dryout) j i i i 1 i i i i j i J j m:\3254w.non\wc6f.wpf;1b-013097 6-273

i TABLE 6.5 5 FARLEY UNI 1S 1 AND 2 0.591 ft2 SPLIT MSLB AT 30% POWER %TTH CONTAINMENT SAFEGUARDS FAILURE SEQUENCE OF EVENTS (Peak Pressure Case) Time (see) Event Description 0.0 Main Steamline Break Occurs 20.0 High Containment Pressure Setpoint Reached 22.0 Rod Motion Starts (High Containment Pressure actuates SI which inidates Reactor Trip) 27.0 Feedwater Isolation Occurs 47.0 Safety Injection Flow Initiated 70.0 High-High Containment Pressure Serpoint Reached 82.0 Steamline Isolation Occurs (following receipt of the High-High Containment Pressure signal) i 97.8 Containment Fan Cooler (1 cooler) Actuates (following receipt of the High Containment Pressure signal)

            !68.0            Containment Spray (1 train) Actuates 168.0            Peak Containment Temperature (347'F) Occurs 1811.              Peak Containment Pressure (52.4 psig) Occurs 1870.             Mass and Energy Releases Terminate (SG Dryout)

O m:\3254w.non\sec6f.wpf.It413097 6-274

CN g V V V 9 b T TABLE 6.5-6 g FARLEY UN7'3 I AND 2 TRANSIENT

SUMMARY

FOR THE SPECTRUM OF BREAKS AT 102% POWER - OUISIDE COPfTAINMENT r Auxiliary 1" Power Level Break Size Reactor Trip 3*f"T Reactor Trip Feedweter Safety Steenanne SG T* Signal IMI'" Isolation (sec) lajection (sec) Isoletten (sec) Feedwater y g,,c) (% Nom) (h') (sec)

$                                                          Signal                                                                           (sec) 33 102                 3.2         LSP             LSP                2.8                 2.5           27.8             12.5        60.8       # 71.0 102                 2.0         LSP             LSP                2.95                2.95          27.95            12.9        60.95      # 72.5 102                 1.4         LSP             LSP                3.4                 3.4           28 4             13.4        61.4       # 74.5 102                 1.0         LSP             LSP                4.1                 4.1           29.1            14.1         62.1       # 78A 102                 0.9         LSP             LSP                4.4                 4.4           29.4            14.4         62.4       # 82.5 a

102 0.8 LSP LSP 4.9 4.9 29.9 14.9 62.9 # 88.0 ta j 102 0.7 LSP LSP 5.5 5.5 30.5 15.5 63.5 # 94.0 102 0.6 LSP LSP 6.8 6.8 31.8 16.8 64 8 # 103.0 102 0.5 OPAT LPP 42.3 42.3 133.0 168.7 157.2 # 209.0 102 0.4 LLSG LPP 157.I 157.I 269.0 314.4 215.1 228.0 102 0.3 LLSG LPP 202.7 202.7 347.8 447.4 260.7 288.0 102 0.2 LLSG LPP 293.6 293.6 521.6 535.2 351.6 397.0 102 0.1 LLSG LSP 564.8 564.8 615.9 600.9 622.8 # 635.0 102 0.05 LLSG LSP 1109 6 1109.6 1540.7 N/A 1167.6 1240.0 LSP - Low Steamline Pressure LPP - Low Pressurizer Pressure LLSG - Low-Low Steam Generator Water Level M - Manual Actuation

                  # Since Steamline Isciation is calculated to occur before SG tube uncovery, the transient is tenninated before uncovery occurs.

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_q 6.6 LOCA Hydraulic Forces i ) 6.6.1 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. De ; lower RCS temperatures associated with the plant uprate program dictates that RCS components be ! evaluated relative to the higher forces associated with the reduced RCS temperatures. 1 rhe 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 vary 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 l 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 exemption is generally referred to as " leak-before-break." For Farley, the applicability of a leak-before-break design basis was approved in Reference 1. Leak-before-break credit was previously used to calculate reduced steam generator forces for Farley. However, previous Farley vessel and loop LOCA forces analyses did not take credit for the leak-before-break licensing basis. l For the plant uprate program, leak-before-break credit is used to evaluate the increased loop and steam I generator LOCA hydraulic forces and to offset any increase in the vessel LOCA hydraulic forces. Leak-before-break licensing allows RCS components to be evaluated for LOCA integnty considering the next most limiting auxiliary line breaks. For Farley, the next most j limiting auxiliary line breaks are the pressurizer surge line break (103.87 in') on the hot leg and the accumulator line break (90.75 in') on the cold leg. Postulated residual heat removal (RHR) auxiliary line breaks are bounded by the accumulator line break. 6.6.2 Input Parameters and Analysis Assumptions The LOCA hydraulic forces analysis incorporates a reduction in T,,, associated with plant uprating. In addition, the analysis incorporates initial RCS condition uncertainties. For LOCA hydraulic forces, a higher initial pressure is conservative so that 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. For use in the uprating analysis, Tw was reduced to 597.8 F and T, was reduced to 524.6'F, while RCS pressure was increased to 2300 psia. m:\3254wmon\sec6f.wpf:11412997 6-277

l Steam generator and loop hydraulic forces are evaluated on the basis of established LOCA forces sensitivities to break size / 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 can be offset by the less severe accumulator line and pressurizer surge line breaks postulated under lerk-before-break licensing. Note that the analyses of record for the loop forces assumed double ended guillotine breaks which can be ignored in favor of these limiting auxiliary line breaks. For the steam generator hydraulic forces, sensitivities to temperature, pressure, and break modeling specific to the Farley Model 51 steam generator model were applied to demonstrate the current forces remain bounding. Pressure vessel / internals forces are analyzed using the NRC approved MULTIFLEX 1.0 computer code. 6.6.3 Analysis Methodology I The NRC-approved MULTIFLEX 1.0 computer code (Reference 2) is used to generate the transient hydraulic forcing functions on the reactor vessel and internals due to a postulated rupture in the RCS. Hydraulic forcing functions on the RCS loop piping and steam generators are evaluated using established LOCA forces sensitivities to changes in RCS temperatures and reduced break area associated with leak-before-break licensing. The MULTIFLEX code calculates the thermal-hydraulic j transient within the RCS and considers subcooled, transition and two-phase (saturated) blowdown regimes. The code employs the method of characteristics to solve the conservation laws, assuming one dimensional flow and a homogeneous liquid-vapor mixture. The RCS is divided into subregions in which each subregion is regarded as an equivalent pipe. A complex network of these equivalent pipes is used to represent the entire primary RCS. l A coupled fluid structure interaction is incorporated into the MULTIFLEX code by accounting for the deflection of the constraining boundaries, which are represented by separate spring-mass oscillator systems. For the reactor vessel /intemals analysis, the reactor core barrel is modeled as an equivalent i beam with the structural properties of the core barrel in a plane parallel to the broken inlet nozzle. l Horizontally, the barrel is divided into ten segments, with each segment consisting of three walls. l Mass and stiffness matrices that are obtained from an independent modal analysis of the reactor core l barrel are applied in the equations of structural vibration at each of the ten mass point locations. Horizontal forces are then calculated by applying the spatial pressure variation to the wall area at each of the elevations representative of the ten mass points of the beam model. 'Ihe resultant core barrel motion is then translated into an equivalent change in flow area in each downecmer annulus flow l channel. At every time increment, the code iterates between the hydraulic and structural subroutines of the program at each location confined by a flexible wall. For the reactor pressure vessel and specific vessel intemal components, the MULT1 FLEX code generates the LOCA pressure transient that is input to the LATFORC and FORCE 2 post-processing codes. These codes, in turn, are used to calculate the actual forces on the various components. l l mA3254w.non\sec6fgf:Ib 012997 6-278

4 I De LATFORC computer code (Reference 2) employs the field pressures generated by MULTIFLEX code, together with geometric vessel information (component radial and axial lengths), to determine

the horizontal forces on the vessel wall, core barrel, and thermal shield. De LATIORC code
represents the downcomer region with a model that is consistent wi'h the model used in the MULTIFLEX blowdown calculations. The downcomer annulus is subdivided into cylindrical j segments, formed by dividing this region into circumferential and axial zenes. The results of the

, MULTIFLEX/LATFORC analysis of the horizontal forces are calculated for the initial 500 msee of the .

blowdown transient and are stored in a computer file. These forcing functions, combined with venical j LOCA hydraulic forces, seismic, thermal and system shaking loads, are used by the cognizant
structural groups to determine the resultant mechanical loads on the reactor pressure vessel and vessel intemals.

The FORCE 2 computer code (Reference 2) calculates the hydraulic forces which the RCS coolant exens on the vessel intemals in the vertical direction. The FORCE 2 code uses a detailed geometric description of the vessel components and the transient pressures, mass velocities, and densities computed by the MULTIFLEX code. The analytical basis for the derivation of the mathematical equations employed in the FORCE 2 code is the one-dimensional conservationo' f linear momentum. Note that the computed vertical forces do not include body forces on the vessel intemals, such as deadweight or buoyancy. When the vertical forces on the reactor pressure vessel intemals are calculated, pressure diff:rential forces, flow stagnation forces, unrecoverable orifice losses, and friction losses on the individual components are consir'ered. Dese force components are then summed together, depending upon the significance of each, to yield the total vertical force acting on a given component. The results of the MULTIFLEX/ FORCE 2 analysis of the vertical forces are calculated for ! the initial 500 msee of the blowdown transient and are stored in a computer file. Dese forcing functions, combined with horizontal LOCA hydraulic forces, seismic, thermal and system shaking loads, were used in the structural evaluations previously presented to determine the resultant mechanical loads on the vessel and vessel internals. 6.6.4 LOCA Forces Analysis Results f 6.6.4.1 Reactor Vessel and Vessel Internals ' Vessel and vessel intemals LOCA hydraulic forcing functions were generated using two postulated auxiliary line breaks. An accumulator line break was analyzed using a flexible beam core banel MULTIFLEX model (for fluid-structure interaction) and a pressurizer surge line break was analyzed using the more conservative rigid core barrel model. Using these auxiliary line breaks and the new RCS conditions, the vessel /intemals LOCA hydraulic forces were computed and the results (horizontal and vertical LOCA hydraulic forces) were stored in computer files for access by the cognizant structural groups. The results of this analysis were compared with the previon (analysis of record) LOCA hydraulic forces analysis which supported the upflow conversion of Farley Unit 1. The break considered in the prior analysis was a 150 square inch limited displacement break in the reactor vessel inlet nozzle. m:\3254w.non\sec6f.wpf:lt412997 6-279

Comparing peak horizontal for:es (LATFORC) on the core barrel, reactor vessel, and thermal shield, it was apparent that the previous (analysis of record) LOCA forces were approximately twice as great as those calculated for the accumulator line break case for power uprate conditions, demonstrating that the reduction in break area was more than sufficient to offset the temperature and pressure changes associated with uprating. With regards to the venical forces (FORCE 2) on reactor internals, the change in forces was reasonable and consistent with the revised plant operating conditions. Most venical forces showed only slight reduction in the new analysis, although some were reduced by as much as half from the prior analysis of record peak venical forces.

 'Ihe acceptability of the reactor vessel / internals LOCA hydraulic forces is demonstrated in the structural analyses for these components as described in Section 5.2.

6.6.4.2 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 forces were last analyzed assuming postulated DEG pipe breaks. For the steam generator hydraulic forces, sensitivities to temperature, pressure, and break modeling specific to the Farley Model 51 steam generator model were applied to demonstrate the current forces remain bounding. RCS temperatures associated with power uprate were reduced in comparison to the analyses of record, resulting in an increase in loop and steam generator forces. However, the increase in 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 is concluded that the leak-before-break credit offsets the increase in loop /SG forces due to lower RCS temperatures and that the analyses of record forcing functions remain bounding for these components. 6.6.5 Conclusions The LOCA hydraulic forces analysis for Farley in suppon of the plant uprating incorporated a T that was reduced to 597.8'F, a T, that was reduced to 524.6*F and an RCS pressure that was increased to 2300 psia. (Note that these uprated conditions incorporate a temperature uncenainty of 6*F and a pressure uncertainty of 50 psi.) The forces analysis of the reactor vessel /intemals was based on the MULTIFLEX computer code and associated post-processors. The postulated break locations include two limiting branch line breaks, i.e., the accumulator and pressurizer surge lines, as allowed under leak-before-break licensing. The MULTIFLEX analysis assumes bounding uprated conditions and includes plant initial condition uncenainties. The results of the analysis, namely, horizontal and venical LOCA hydraulic forces, were stored on computer files for access by the cognizant structural groups. The acceptability of the reactor vessel / internals LOCA hydraulic forces is demonstrated in the structural analyses for these components as described in Section 5.2.

rn: u254w.nonvecawpf.itw12997 6-280

1 For the RCS loop piping and steam generators, evaluations were performed using established sensitivities to show that the current forces remain bounding at uprated conditions due to the reduction in effective break area as allowed under leak-before-break licensing. 6.6.6 References

1. WCAP-12825, " Technical Justification for Eliminating Large Primary Loop Pipe Rupture as a Structural Design Basis for the Joseph M. Farley Units 1 and 2 Nuclear Power Plants,"

January 1991.

2. Takeuchi, K., et al., "MULTIFLEX, A FORTRAN-IV Computer Program for Analyzing Thermal-Hydraulic-Structure System Dynamics," WCAP-8708-PA-VI (Proprietary), -

WCAP-8709-A (Non-Proprietary), September,1977. ; l I l \ l l l O i m:\3254w.non\sec6f.wpf;lb412997 6-281

6.7 Reactor Trip System / Engineered Safety Feature Actuation System Setpoints The Technical Specification Reactor Trip System / Engineered Safety Feature Actuation System (ESFAS) setpoints have been reviewed for plant operation at power uprate conditions including a core power level up to 2775 MWt. As part of the review, Technical Specifications changes were made consistent with Westinghouse setpoint methodologies (References 1,2,3, and 4). Tables 6.7-1 and 6.7-2 list both the current and power uprate values for each impacted function and parameter. Incorporating these Technical Specifications changes will ensure that the Farley Units 1 & 2 will operate in a manner consistent with the FSAR assumptions. 6.7.1 References

1. WCAP-12613, "RTD Bypass Elimination Licensing Repon for J. M. Farley Nuclear Plant Units 1 & 2," June 1990

2. WCAP-13751, " Westinghouse Setpoint Methodology for Protection Systems - Farley Nuclear Plant Units 1 & 2," June 1993

3. WCAP-13992, " Steam Generator Lower Level Tap Relocation Assessment for J. M. Farley Nuclear Plant Units 1 & 2," March 1994

4. NSD-NT-Oi'L-96-152, Revision 2, " Joseph M. Farley Nuclear Plant Units 1 & 2 Licensing Repon for Technical Specifications Changes Associated with Revised Core Limits, Revised OTAT/OPAT Trip Setpoints and inclusion of RAOC Control Strategy," May 1996 I

I l O mA3254w.nonisec6f.wpf:lb-012997 6-282

TABLE 6.71

SUMMARY

OF THE TECHNICAL 3PECIFICATION REACTOR TRIP SYSTEM SETPOINT CHANGES Power Range, Neutron Flux Reactor Trip Trip Setpoint Allowable Value Power Uprate Power Uprate Functional Unit 2 Current Value Value Current Value Value Low Setpoint 525.0% RU 525.0% RTP s26.0% RTP 525.4% RW High Setpoint $109.0% RTP 5109.0% RTP 5110.0% RTP 5109.4% RW Power Range, Neutron Hux, High Positive Rate Reactor Trip Trip Setpoint Allowable Value Power Uprate Power Uprate Functional Unit 3 Current Value Value Curnet Value Value High Setpoint 55.0% RW with 55.0% RTP with 55.5% RTP with 55.4% RTP with time constant time constant time constant time constant 2 2 seconds 2 2 seconds 2 2 seconds 2 2 seconds Power Range, Neutron Mux, High Negative Rate Reactor Trip Trip Setpoint Allowable Value Power Uprate Power Uprete Functional Unit 4 Current Value Value Current Value Value High Setpoint 55.0% RTP with 55.0% RW with 55.5% RTP with 55.4% RTP with time constant time constant time constant time constant 2 2 seconds 2 2 seconds 2 2 seconds 2 2 seconds Overtemperature AT Reactor Trip (Already Approved by NRC) Trip Setpoint Allowable Value Power Uprate Power Uprate Functional Unit 7 Current Value Value Current Value Value Ki 51.14 51.17 51.8 50.4 K2 0.025 0.017 N/A N/A K3 0.001275 0.000825 N/A N/A T' Reference T,,, Reference T,., N/A N/A , 5577.2'F 5577.2'F l m:u254w.non\iec6f.wpf.It> ol2997 6-283

TABLE 6.71 (cont.)

SUMMARY

OF THE TECHNICAL SPECIFICATION REACTOR TRIP SYSTEM SETPOINT CHANGES

 -Al Gain                          1.92                  2.48           N/A                 N/A
 +Al Gain                          2.17                  2.05           N/A                 N/A f(AI) Penalty                     -39,                  -23,           N/A                 N/A Dead-band                          to                    to
                                   +13                   +15 t(5)                           0 seconds            56 seconds         N/A                 N/A t(6)                          _0 seconds            56 seconds         N/A                 N/A Overpower AT Reactor Trip (Already Approved by NRC)

Trip Setpoint Allowable Value Power Uprate Power Uprate Functional Unit 8 Current Value Value Current Value Value K4 51.07 $1.10 52.3 50.4 K. 0.00165 0.00109 N/A N/A T" Reference T,y Reference T,y N/A N/A 5577.2'F $577.2*F t(5) O seconds 56 seconds N/A N/A t(6) 0 seconds 56 seconds N/A N/A Pressurizer Pressure-Low Reactor Trip Trip Setpoint Allowable Value Power Uprate Power Uprate Functional Unit 9 Current Value Value Current Value Value Low Setpoint 21865 psig 21865 psig 21855 psig 21862 psig Pressurizer Pressure-High Reactor Trip Trip Setpoint Allowable Value Functional Power Uprate Power Uprate Unit 10 Current Value Value Current Value Value High Serpoint 52385 psig $2385 psig $2395 psig 52388 psig m:u254w.nonssec6f.wpf.ib.012997 6-284

i

     )                                                   TABLE 6.7-1 (cont.)

4 t/

SUMMARY

OF THE TECHNICAL SPECIFICATION REACTOR TRIP SYSTEM . SETPOINT CHANGES Pressurizer Water Level-High Reactor Trip Trip Setpoint Allowable Value . Functional Power Uprate Power Uprate Unit 11 Current Value Value Current Value Value High Serpint 592% of span 592% of span 593% of span 592.4% of span i Less of How Reactor Trip '

Trip Setpoint Allowable Value Functional Power Uprate Power Uprate d

Unit 12 Current Value Value Current Value Value 1 4 Low Setpoint 290% MMF 290% MMF 288.5% MMF 289.7% MMF l

                                        / Loop               / Loop **       / Loop                   / Loop *)     {

Steam Generator Water Level Low-Low Reactor Trip I Trip Setpoint Allowable Value - 1 Functional Power Uprate Power Uprate i Unit 13 Current Value Value Current Value Value Low-Low 225.0 of span 2 25.0 of span 223.3 of span 224.6% of span Setpoint Reactor Trip System Interlocks l Trip Setpoint Allovable Value Functional Power Uprate Power Uprate Unit 20.B Current Value Value Current V !ae Value Low Power $10% RTP 510% RTP sil% RTP 510.4% RT Reactor Trips l Block, P-7 (P-10 j input) 4 Y' m:\3254w.non\sec6f.wpf.!t412997 6-285 1

1 l i I TABLE 6.71 (cont.)

SUMMARY

OF THE TECHNICAL SPECIFICATION REACTOR TRIP SYSTEM ) SETPOINT CHANGES Trip Setpoint Allowable Value Power Uprate Power Uprate Functional Value Current Value Value Unit 20.C Current Value

                                                $30% RTP       536% RTP            530.4% RTP Power Range                 535% RTP 1

Neutron Flux, P-8 l Trip Setpoint Allowable Value Power Uprate Power Uprate Functional Value Current Value Value Unit 20.D Current Value 28% RTP 27% RTP 27.6% RTP Power Range 28% RTP Neutron Flux, P-10 Trip Setpoint Allowable Value ,

Power Uprate Power Uprate Functional Value Current Value Value Unit 20.F Current Value 550% RTP 551% RTP 550.4% RTP Reactor Trip 550% RTP l Block Following Turbine Trip, P-9 I (a) Minimum Measured Flow is 89,290 gpm/ loop I (b) Minimum Measured Flow is 88,100 gpm/ loop l O m:\3254w.non\m:6f.wpf:lt412997 6-286

i 1 TABLE 6.7 2 s i

SUMMARY

OF THE TECHNICAL SPECIFICATION ESFAS SETPOINT CHANGES 1 ! Pressuriser Pressure - Low Safety Injection, Turbine Trip & Feedwater Isolation ! Trip Setpoint Allowable Value l l Functional Power Uprote Power Uprate < Unit 1.d Current Value Value Current Value Value I Low Setpoint 21850 psig . 21850 psig 21840 psig 21847 psig Steam Line How in Two Steam Lines High, Steam Line Isolation , Trip Setpoint Allowable Value . Functional Power Uprate Power Uprate

Unit 4.d Current Value Value Current Value Value t

, Hip Setpoint (0- 540%* s40%** $44.0%' 540.3 % "

20% load) 3 l Steam Line How in Two Steam Lines - High, Steam Line Isolation Trip Setpoint Allowable Value j Functional Power Uprote Power Uprate

, Unit 4.d Current Value Value Current Value Value High Setpoint (at st 10%* 5110 %** s111.5 %' 5110.3 % " 100% load) Low Low T,,, (Coincident with Steam Line How in Two Steam Lines - High), Steam Line Isolation Trip Setpoint Allowable Value Functional Power Uprate Power Uprate Unit 4.d Current Value Value Curswat Value Value Low-Low Setpoint 2543'F 2543'F 2540*F 2542.6*F Steam Generator Water Level - High High, Turbine Trip & Feedwater Iso'.ation Trip Setpoint Allowable Value Functional Power Uprate Power Uprete Unit 5.a Current Value Value Current V.alue Value High-High s79.2% of spou $78.5% of span s80.5% of span 578.9% of span Setpoint m:\3254w.non\sec6f.wpf:lb-012997 6-287

TABLE 6.7 2 (cont.)

SUMMARY

OF TPE TECHNICAL SPECIFICATION ESFAS SETPOINT CHANGES Steam Generator Water Level Low Low, Auxiliary Feedwater Trip Setpoint Allowable Value Functional Power Uprate Power Uprate Unit 6.b Current Value Value Current Value Value Low-Low Setpoint 225.0 of span 225.0 of span 223.3 of span 224.6% of span ESFAS Interlocks Trip Setpoint Allowable Value Functional Power Uprate Power Uprate Unit 8.a Current Value Value Current Value Value Pressurizer s2000 psig s2000 psig s2010 psig s2003 psig Pressure, P-11 Trip Setpoint Allowable Value Functional Power Uprate Power Uprate Unit 8.b Current Value Value Current Value Value Low-Low T,,,, 5544*F 5545'F $547'F 5545.4'F P-12 (Increasing) Trip Setpoint Allowable Value Functional Power Uprate Power Uprate Unit 8.b Current Value Value Current Value Value Low-Low T,,, 2543'F 2543*F 2540'F 2542.6'F P-12 (Decreasing) 5 A function defined as follows: A & corresponding to 40% Steam Flow between 0% and 20% load increasing linearly from 20% load to a value corresponding to 110% Steam Flow at full load.

 " s A function defined as follows: A & corresponding to 40% Steam Flow between 0% and 20% load increasing linearly from 20% load to a value corresponding to 110% Steam Flow at full load.
 # $ A fsnction defined as follows: A & corresponding to 44.0% Steam Flow between 0% and 20% load increasing linearly from 20% load to a value corresponding to 111.5% Steam Flow at full load.
 ## s A function defined as follows: A & corresponding to 40.3% Steam Flow between 0% and 20% load increasing linearly from 20% load to a vs.!ue corresponding to 110.3% Steam Flow at full load.

O mA3254w.non\sec6f wpf.Itr012997 6-288

7.0 NUCLEAR FUEL g This chapter discusses the analyses performed in support of the uprate project in the nuclear fuel and fuel related areas. Specifically, the chapter addresses fuel thermal-hydraulic design, fuel core design, fuel rod performance, heat generation rates, neutron fluence, and source terms. The results and conclusions of each of these analyses can be found within each subsection. 7.1 Core Thermal-Hydraulic Design 7.1.1 Introduction and Background This section describes the core thermal-hydraulic analyses and evaluations performed in support of the operation of FNP Units 1 and 2 at an uprated power level of 2775 MWt (core) over a range of reactor coolant system (RCS) temperatures. This effort is an extension of the DNBR analyses which were l performed to support the use of VANTAGE 5 fuel, Reference 1. A number of additional items were included in the scope of the power uprate program to improve operational margins and enhance operational flexibility for the FNP Units. De analyses to support these items were performed coincident with the power uprate program to maximize the synergistic benefits of the analyses. De additional items which had an impact on the DNBR analyses are: Revised Overtemperature AT/ Overpower AT (OTAT/OPAT) trip setpoints; Relaxed Axial Offset Control (RAOC) Strategy;

Implementation of ZIRLO cladding; and Rod control system optimization.

The analyses which were performed for the above items at the power uprate conditions have been used to support the implementation of these items prior to the uprating. De revised OTAT/OPAT trip setpoints, RAOC, ZIRLO cladding, and the rod control system optimization were implemented in Farley Unit 2, Cycle 12 (Reference 13) and will be implemented in Unit 1. Cycle 15. 7.1.2 Input Parameters and Assumptions Table 7.1-1 summarizes the design parameters used in the thermal-hydraulic analyses. The core inlet temperature used in the DNBR analyses is based on the upper bound of the RCS temperature range for the power uprate conditions. Use of the upper bound temperature is conservative for the DNBR analyses. The DNBR analyses also assume that the uprated core designs are primarily VANTAGE 5 fuel. Only a limited number of the low-parasitic (LOPAR) fuel assemblies may be used in the uprated core as a reload design. Any reinsertion of LOPAR assemblies will be handled via approved methods during the reload process. The DNBR analyses to support the continued insertion of the LOPAR fuel is addressed in Section 7.1.3.2.5. l 1 m:\3254w.non\sec7.wpf 1b 012997 7.I

7.1.3 Description of Analyses and Evaluations 7.1.3.1 Calculational Methods O The thermal-hydraulic design criteria and methods for the power uprate remain the same as those presented in the FNP FSAR (Reference 2), which addresses the transition from a full core of LOPAR fuel to an all VANTAGE 5 core in FNP Units 1 and 2. As discussed in Reference 2, the design method employed to meet the DNB design basis for the VANTAGE 5 fuel and LOPAR fuel is the Revised Thermal Design Procedure (RTDP), Reference 3. With the RTDP methodology, uncertainties in plant operating parameters, nuclear and thermal parameters, fuel fabrication parameters, computer codes and DNB correlation predictions are considered statistically to obtain DNB uncertainty factors. Based on the DNB uncertainty factors, RTDP design limit DNBR values are determined such that there is at least a 95% probability at a 95% confidence level that DNB will not occur on the most limiting fuel rod during normal operation and operational transients and during transient conditions arising from faults of moderate frequency (Condition I and D events as defined in ANSI N18.2). Uncertainties in the plant operating pvameters (pressurizer pressure, primary coolant temperature, reactor power, and reactor coolant system flow) were evaluated for the FNP Units 1 and 2 for the power uprate in Reference 4. 'Ihe DNBR analyses with RTDP were based on a set of plant operating parameter uncertainties which bound the values in Reference 4. The plant operating parameter uncertainties used in the RTDP DNBR analyses for FNP Units 1 and 2 power uprate are presented in Table 7.1-2. The current plant operating parameter uncertainties and the uncertainties used in the VANTAGE 5 RTDP analyses are also presented in Table 7.1-2 for comparison. Only the random portion of each plant operating parameter uncertainty is included in the statistical combination for RTDP. Any adverse instrumentation bias is treated as a direct DNBR penalty or as a direct analysis input. The RTDP design limit DNBR values specified in Reference 2 for FNP Units I and 2 remain applicable for the power uprate. In addition to the above considerntions for uncertainties, additional DNBR margin was maintained by performing the safety analyses to DNBR limits higher than the design limit DNBR values. Sufficient DNBR margin was ruaintained in the safety analysis DNBR limits to offset the rod bow DNBR penalty. The net remaining DNBR margin, after consideration of this penalty, is available for operating and design flexibility (e.g., VANTAGE 5 transition core DNBR penalty associated with the limited insertion of LOPAR fuel). As noted in Reference 2, the standard thermal design procedure (STDP) is used for those analyses where RTDP is not applicable. The DNBR limit for STDP is the appropriate DNB correlation limit increased by sufficient margin to offset the applicable DNBR penalties. m:\3254w. mon \sec79f;1b-012997 7-2

     .. -                   _ .           _ - - - . - _ _ .      . - _ - - ~ _ _ . . - -           - - .-      - ..

J 7.13.2 DNB Performance The current DNBR analyses of record for the FNP Units are primarily those which were performed to support the transition of the FNP Units from LOPAR fuel to VANTAGE 5 fuel. All the DNBR ; analyses which were performed for VANTAGE 5 fuel included an uprated core power level of 2775 MWt and are therefore bounding for operation at the current core power level of 2652 MWt. A comparison of the current FSAR thermal-hydraulic parameters, the VANTAGE 5 analysis parameters and the power uprate parameters is show, in Table 7.1-1. To support the operation of FNP Units 1 and 2 at power uprate conditions, a DNBR reanalysis was required to address the complete loss of flow event. A number of additional items were included in the scope of the power uprate program to improve operational margins and enhance operational . flexibility for the FNP Units. The analyses to support the power uprate and the additional programs ! which were performed coincident with the power uprate are addressed below. 7.13.2.1 Revised Overtemperature AT/ Overpower AT (OTAT/OPAT) Trip Setpoints Revised OTAT and OPAT trip setpoints (Reference 5) were determined for FNP to provide improved margins as well as to provide protection for DNB-related events which use OTAT and OPAT as the primary reactor trip. To support the OTAT/OPAT setpoint margin improvement, the core limit lines for FNP were revised from the limits which were developed for Reference 1. The revised core limits were based on VANTAGE 5 as the most limiting fuel design. The F, limit for the VANTAGE 5 fuel remains et 1.70. The VANTAGE 5 safety analysis DNBR limits for this analysis were reduced by , J decreasing the DNBR margin which was retained in the VANTAGE 5 safety analysis DNBR limits for Reference 1. The DNBR margin which was retained for the Reference 1 analyses was necessary to offset the transition core DNBR penalty associated with the first VANTAGE 5 transition cycle. Since !

      - the current Farley core designs are primarily VANTAGE 5 (or all VANTAGE 5), the amount of retained DNBR margin needed to address any limited insertion of LOPAR fuel assemblies was significantly reduced. The reduced VANTAGE 5 safety analysis DNBR limits resulted in less                    ;

restrictive core limits and improved OTAT/OPAT setpoints.

          'Ihe revised core limit lines and OTAT/OPAT setpoints were developed for power uprate conditions but were previously submitted to and approved by the NRC to support their implementation prior to implementation of power uprate.

7.1.3.2.2 Relaxed Axial Offset Control (RAOC) Strategy The DNBR analyses performed in conjunction with the OTAT/OPAT setpoint margin improvement program included the first time implementation of the Relaxed Axial Offset Control (RAOC) strategy for FNP (see Section 7.2). The Condition II axial power distributions from the RAOC analysis were O evaluated relative to the axial power distribution assumption used to generate the DNB core limits (i.e., the 1.55 cosine axial power shape). The limiting Condition II axial power distributions were used to define the f(AI) reset function in the revised OTAT setpoints such that the DNB design m:\3254w.non\sec7.wpf:lt412997 7-3 a

criterion is met for accidents which are terminated by the variable OTAT setpoint. In addition, the normal operation axial power shapes were evaluated relative to the assumed limiting normal operation axial power shape in the analysis of the DNB-limited events which are not terminated by the OTAT reactor trip, e.g., the loss of flow accident. The currently assumed limiting normal operation axial power shape remained bounding for the implementation of RAOC. RAOC was developed for power uprate conditions but was previously submitted to and approved by the NRC to support its implementation prior to implementation of power uprate. 7.13.23 Complete Loss of Flow The DNB analysis of the limiting complete loss of flow event (frequency decay) was performed for the power uprate conditions assuming reactor protection provided by the reactor coolant loop low flow reactor trip function. The impact of the higher ZIRLO fuel temperatures (see Section 7.13.4) was included in the analysis of this event. He minimum DNBRs met the DNB design criterion for this event. 7.13.2.4 Rod Control System Optimization Optimization of the rod control system setpoints was performed for the FNP Units, ne optimization process resulted in RCCA dropped rod analysis condi t ions which were more limiting for DNB. To provide margin for the analysis of the worst RCCA dropped rod conditions, the dropped rod DNB limit lines were revised to incorporate the reduced VANTAGE 5 safety analysis DNBR limits discussed in Section 7.13.2.1 The revised rod control system setpoints were developed for power uprate conditions but were implemented under the provisions of 10 CFR 50.59 prior to implementation of power uprate. 7.13.2.5 LOPAR Fuel The DNBR analyses for the revised coit limits assumed that the uprated core designs are primarily VANTAGE 5 fuel. Only a limited number of LOPAR fuel assemblies may be used in the uprated core as a reload design. Operation with a mixed core of VANTAGE 5 and LOPAR fuel is still addressed using the approved transition core DNB methodology (References 6 through 10). To ensure that the LOPAR fuel is not limiting with respect to DNB, the LOPAR F, limit was reduced to a value of 130. The LOPAR safety analysis DNBR limits are unchanged from the analyses supporting Refereuce 1. The mixed core DNBR effect of the LOPAR fuel on the VANTAGE 5 DNBR analyses will continue to be addressed by the application of DNBR margin on a cycle specific basis. The maximum number of LOPAR fuel assemblies which can be used in a mixed core design is limited by the VANTAGE 5 DNBR margin which is available for the specific cycle to offset the transition core DNBR penalty. m:\3254w.non\sec7.wpf:lt412997 7-4

i p 7.1.3.3 Hydraulic Evaluation b The impact of the power uprate conditions on the fuel hydraulic analyses was evaluated. The increased coolant density associated with the low end of the RCS temperature range does not have a l significant impact on the hydraulic analyses. The fraction of the flow that Ir/ pisses the core through the thimble guide tubes is unchanged from the value in Reference 2. Fuel assembly lift forces were evaluated for the power uprate parameters and shown to be bounded by existing analyses for the VANTAGE 5 and LOPAR fuel. The use of ZIRLO cladding does not affect the VANTAGE 5 l I hydraulic resistance. The VANTAGE 5 and the LOPAR fuel assemblies were shown to be hydraulically compatible in Reference 11. The power uprate conditions do not affect this conclusion. j 7.1.3.4 Fuel Temperatures j The fuel temperatures for the power uprate safety analysis for VANTAGE 5 fuel were based on l ZIRLO cladding. The ZIRLO fuel temperatures are higher than the previous Zircaloy-4 fuel { l temperatures which were used for the Reference 1 analyses. The ZIRLO fuel temperatures were calculated with the approved fuel performance models (Reference 12) for conditions which bound the f I power upn te parameters. The ZIRLO analysis also addressed the use of IFBA (integral fuel burnable absorber). The IFBA product used in the analysis was 1.5X IFBA with 100 psig backfill. The ZIRLO IFBA and non IFB A fuel temperatures were used as initial conditions for LOCA and non-LOCA transients. Also, based on the ZIRLO fuel temperature analysis, the linear power limit which precludes fuel centerline melting was reduced to 22.4 kW/ft (Reference 5) from the current value of 22.5 kW/ft in Reference 2. ZIRLO cladding was implemented prior to implementation of power uprate. 7,1.4 Conclusions C are thermal-hydraulic analyses and evaluations were sformed in suppon of the operation of FNP l Units 1 and 2 at an uprated power level of 2775 MWt psre) over a range of RCS temperatures. The results showed that the core thermal-hydraulic design criteria listed in Reference 2 are satisfied. 7.1.5 References l

l. leuct from Woodward, J. D., (SNC), to USNRC, " Joseph M. Farley Nuclear Plant VANTAGE 5 Fuel Design Amendment," July 15,1991.

2. J. M. Farley Nuclear Plant Updated Final Safety Analysis Repon," Revision 13, as amended through April 1996.

! t 3. WCAP-11397-P-A, " Revised Thermal Design Procedure," A. J. Friedland and S. Ray, f Apdl1989. mM254w.non\sec7.wpf.It412997 7,5

4. WCAP-12771, Rev.1 (Proprietary), " Westinghouse Revised Thennal % sign Procedure Instrument Uncertainty Methodology for Alabama Power Farley Nucica Plant Units i and 2 (Uprating to 2785 MWt NSSS Power)," W. H. Moomau, September 1996.

5. Joseph M. Farley Units 1 & 2 Licensing Report for Technical Specification Changes with Revised Core Limits, Revised OTAT/OPAT Trip Setpoints and inclusion of RAOC Control Strategy, Revision 2," R. J. Morrison, May 1996.

6. WCAP-9500-A, " Reference Core Report - 17 x 17 Optimized Fuel Assembly," S. L. Davidson and J. A. lorii, May 1982.

7. Letter from E. P. Rahe (Westinghouse) to Miller (NRC), dated March 19,1982, NS-EPR-2573, WCAP-9500 and WCAPs-9401/9402, 'NRC SER Mixed Core Compatibility items."

8. Letter from C. O. Thomas (NRC) to E. P. Rahe (Westinghouse), " Supplemental Acceptance No. 2 for Referencing Topical Report WCAP-9500," January 1983.

9. Schueren, P. and McAtee, K. R., " Extension of Methodology for Calculating Transition Core DNBR Penalties," WCAP-Il837-P-A, January 1990.

10. Letter from S. R. Tritch (Westinghouse) to R. C. Jones (NRC), " VANTAGE 5 DNB Transition Core Effects," ET-NRC-91-3618 September 1991.

I 1. Davidson, S. L., and Kramer, W. R., (Ed.), " Reference Core Report VANTAGE 5 Fuel Assembly," WCAP-10444-P-A (Proprietary) and WCAP-10445-NP-A (Non-Proprietary), September 1985. j

12. Weiner, R. A., et al., " Improved Fuel Performance Models for Westinghouse Fuel Rod Design and Safety Evaluations," WCAP-10851 P-A (Proprietary) and WCAP-il873-A (Non-Proprietary), August 1988.

13. "J. M. Farley Nuclear Plant Unit 2, Cycle 12 Reload Safety Evaluation," S. L. Davidson, September 1996.

1 m:\3254w.non\sec7 wpf:It412997 7-6

W ( TABLE 7.1-1 (Sheet 1 of 3) THERMAL HYDRAULIC DESIGN PARAMETERS FOR FARLEY UNITS 1 AND 2 J Current VANTAGE 5 FSAR Analysis Power Parameters Parameten Uprate

Thermal and Hydraulic Design Parameters (Reference 2) (Reference 1) Parameters j Reactor Core Heat Output, MWt 2652 2775 2775 Reactor Core Heat Output,10' BTU /hr 9051 9469 9469 Heat Generated in Fuel, % 97.4 97.4 97.4 Pressurizer Pressure. Nominal, psia 2250 2250 2250 i F , Nuclear Enthalpy Rise Hot Channel Factor

) (LOPAR) 1.55 1.60 1.30 l (V 5) 1.70* 1.70 1.70 Part Power Multiplier for Fa i (LOPAR) [l+0.3(1-P)] [l+0.3(1 P)] [l+0.3(1 P)] (V-5) [1+0.3(l-P)] [1+0.3(l P)] [1+0.3(l-P)] Minimum DNBR at Nominal Conditions (Using RTDP) [ Typical Flow Channel J (LOPAR) 2.36*' 2.36 3.20 (V-5) 2.36*' 2.36 2.36 i nimble (Cold Wall) Flow Channel (LOPAR) 2.26** 2.26 3.02 (V-5) 2.23** 2.23 2.23 Design Limit DNBR Typical Flow Channel . (LOPAR) 1.25 1.25 1.25 (V-5) 1.24 1.24 1.24 j Thimble (Cold Wall) Flow Channel ! (LOPAR) 1.24 1.24 1.24 i (V-5) 1.23 1.23 1.23 DNB Correlation" (LOPAR) WRB-1 WRB-1 WRB-1 (V 5) WRB-2 WRB-2 WRB-2 (a) The current maximum F,in the Unit 2 Technical Specifications is 1.65. (b) ne minimum nominal DNBRs from the VANTAGE 5 analysis (Reference 1) are conservatively listed in the current FSAR. (c) See Chapter 4.4 of Reference 2 for the use of the W-3 DNB correlation. O mt1254w.nonisec7.wpf !b-013097 7-7

TABLE 7.11 (Sheet 2 of 3) TIIERMAI-IIYDRAULIC DESIGN PARAMETERS FOR FARLEY UNITS 1 AND 2 Current VANTAGE 5 FSAR Analysis Power Parameters Parameters Uprate IIFP Nominal Coolant Conditions (Reference 2) (Reference 1) Parameters Vessel Minimum Measured Flow Rate, MMF, (including Bypass) 10' lbm/hr 101.5( 100.l* 101.5-100.1"' gpm 267,880 263,400 263,400* Vessel hermal Design Flow Rate, TDF, (including Bypass) 10' lbm/hr 99.3 98.1 99.4-98.1 Epm 261,600 258,000 258.000 Core Flow Rate (excluding Bypass, based on TDF) 10' Ibm /hr 92.2 91.1 92.3-91.1 gpm 243,030 239,680 239,680 Fuel Assembly Flow Area for Heat Transfer, ft2 (LOPAR) 41.55 41.55 41.55 (V-5)'d) 44.04 44.04 44.04 Core Inlet Mass Velocity (Based on TDF) 10* 1bm/hr-ft2 (LOPAR) 2.22 2.19 2.22-2.19 (V 5) 2.09 2.07 2.10-2.07 (a) Inlet temperature = 543.8'F (b) Inlet temperature = 541.8'F (c) Inlet temperature = 531.3' - 541.8'F (d) Assumes all LOPAR or VANTAGE 5 Core (c) Based on 2.1% flow measurement uncertainty (0.1% feedwater venturi fouling bias included). The minimum measured flow (MMF) rate is the flow used in the reactor core DNBR analyses which were performed with the Revised hermal Design Procedure. He DNBR analyses also bound a MMF of 264,200 gpm which reflects a flow measurement uncertainty of 2.4-percent (0.1% feedwater venturi fouling bias included). 1 i 1 m:\3254w.non\sec7.wpf.1b-012997 7-8

j l l TABLE 7.11 (Sheet 3 of 3) THERMAL INDRAULIC DESIGN PARAMETERS FOR FARLEY UNITS 1 AND 2 Current VANTAGE 5 FSAR Analysis Power Thermal & Hydraulic Design Parameters Parameters Parameters Uprate (Based on TDF) (Reference 2) (Reference 1) Parameters Nominal Vessel / Core inlet Temperature, 'F 543.1 541.1 530.6 - 541.1 Vessel Average Temperature, 'F 577.2 577.2 567.2 - 577.2 Core Average Temperature, "F 581.5 581.8 571.7 - 581.8 Vessel Outlet Temperature, 'F 611.3* 613.3 603.8 - 613.3 Average Temperature Rise in Vessel, 'F 68.2 72.2 73.2 - 72.2 Av: rage Temperature Rise in Core. 'F 72.9 77.0 78.2 - 77.0 Heat Transfer Active Heat Transfer Surface Area, ft2m j (LOPAR) 48,598 48,598 48,598 (V-5) 46,779 46,779 46,779 Average Heat Flux, BTU /hr-ft2m (LOPAR) 181,410 189,820 189,820 (V-5) 188,460 197,200 197,200 Average Linear Power, kw/ft* 5.20 5.45 5.45 Peak Linear Power for Normal Operation, kw/ft" (LOPAR) 12.07 12.63 12.63'd' (V-5) 12.75* 13.34* 13.61* Temperature Limit for Pruention of Centerline Melt, 'F 4,700 4,700 4,700 (a) Not an explicit FSAR value; value obtained from sum of the vessel inlet temperature and the average temperature rise in the vessel. (b) Assumes all LOPAR or VANTAGE 5 core (c) Based on densified active fuellength (d) Based on 2.32 Fo peaking factor for LOPAR (c) Based on 2.45 Fa peaking factor for VANTAGE 5 (f) Based on 2.5 F opeaking factor for VANTAGE 5 l l l O m:\3254w.non\sec7.wpf:Ib-ol2997 7-9

TABLE 7.12 INITIAL CONDITION UNCERTAINTIES USED IN DNBR ANALYSES VAhTAGE5 Current FSAR Value Analysis Value Power Uprate Parameters (Reference 2) (Reference 1) Value Pressurizer Pressure (control) 50.0 psi 50.0 psi 50.0 psi i i Temperature (rod control) 6.0 F 1 60*F 6.0*F* Power Measurement 2.0% RTP 2.0% RTP 2.0% RTP f 1 RCS Flow Measurement 2.4% flow'" 2.1% flow *) 2.1% flow'") i (a) Includes a 0.1% flow uncenainty for feedwater venturi fouhng. l (b) A value of 2.1% was used to set the minimum measured flow for DNBR analyses with RTDP. A bounding value of 2.5% was included in the RTDP DNBR limit. ) (c) A value of 2.1% was used to set the muumum measured flow (MMF) for the RTDP DNBR analyses.

    'Ihe DNBR analyses also bound a MMF of 264,200 gpm which reflects a flow measurement uncertainty of 2.4%'". The R'IDP DNBR limit is applicable for the range of 2.1% to 2.4%.                       1 (d) Includes a cold leg streaming bias of -1.0*F.

l I l I l l l l l l 9 l mA3254w.non\sec7.wpf.It>.012997 7 10

i I i n 7.2 Fuel Core Design U 7.2.1 Introduction and Background The nuclear design analysis performed to support the use of VANTAGE 5 fuel (Reference 1), 4 determined the effects on key safety parameters for the transition to VANTAGE 5 fuel at an uprated core power of 2775 MWt and at a nominal vessel T,,, of 577.2*F. Since the effects of the uprating on ] key safety parameters have been detennined and documented previously, the objective of the nuclear design analyses documented in this report will be to focus on the key safety parameter impacts due to operation at reduced RCS temperatures. Key safety parameters are used as input to the FSAR j Chapter 15 accident analyses. The range of temperature reduction considered in the nuclear design ' l analysis is from 567.2 F to 577.2*F vessel average hot full power (HFP) temperature. , i

7.2.2 Input Parameters and Assumptions i The nuclear design analyses demonstrating the acceptability of operation at a core power level of I 2775 MWt and a vessel T.,, of 577.2 F were performed previously as part of the Farley VANTAGE 5

, program. This evaluation will use the same assumptions as the VANTAGE 5 program except a vessel , T,., as low as 567.2*F is considered. . 7.2.3 Description of Analyses and Evaluations

v

To satisfy the above objective, two VANTAGE 5 core models were constructed based on the same loading pattem. The first model (Model 1) represents the uprated power level at a T,., of 567.2*F.

The second model (i.e., Model 2) represents the uprated power level at a T,,, of 577.2*F. Key safety parameters were then evaluated such that the expected ranges of variation of the parameters were detennined for the anticipated range of operating temperatures. The key parameters referred to here are those described in the standard reload design methodology (Reference 2). Cycle energy values are expected to vary in actual operation, but the conclusions remain valid. In general, reduced RCS , temperatures have two somewhat significant effects on the core: (1) the Beginning of Cycle, Hot Full l Power (BOL-HFP) Moderator Temperature Coefficient (MTC) is about I to 2 pcm/*F more positive; 4 and (2) the BOL-HFP Axial Offset is about 2 percent more positive. Methodology The methods and core models used in the Farley Units I and 2 VANTAGE 5 analyses are described in ] ~ References 2,3, and 4. These licensed methods and models have been used for Farley and other previous Westinghouse reload designs using LOPAR and VANTAGE 5 fuel. No changes to the nuclear design philosophy, methods, or models are necessary due to the uprating. O The reload design philosophy used by Westinghouse includes the evaluation of the reload core key safety parameters which comprise the nuclear design dependent input to the FSAR safety evaluation for each reload cycle. This philosophy is described in References 2 and 3. These key safety m:u254w.nonwc7.wpr. b.ot2997 7-11

parameters will be evaluated for each Farley reload cycle. If one or more of the key parameters fall outside the bounds assumed in the safety analyses, the affected transients will be reevaluated and the results documented in the Reload Safety Evaluation report (RSE) for that cycle. The main objective of the uprating core analyses is to determine, prior to the cycle specific reload design, if the previously used bounds for the key safety parameters remain applicable. The results of these analyses are described below. Design Evaluation - Physics Characteristics and Key Safety Parameters As previously mentioned, a conceptual core loading pattern was constructed to be representative of future Farley cores. Table 7.2-1 compares the safety parameter ranges considered in the Farley VANTAGE 5 analysis, those obtained for the Farley Unit 1 Cycle 14 and Farley Unit 2 Cycle 11 designs, and those for reduced RCS temperature analysis at power uprate conditions. The most significant effect of the temperature reduction is to increase the Beginning of Cycle, Hot Full Power (BOL-HFP) MTC by about I to 2 pcm/*F. Since the Hot Zero Power (HZP) Core Inlet Temperature remains at 547*F during reduced temperature operation, the BOL-HZP MTC is not effected. A comparison between MTC as a function of relative power and the MTC Technical Specifications limit is provided in Figure 7.2-1 for Models 1 and 2. The MTCs in Figure 7.2-1 are calculated without Xenon. Note that in Figure 7.2-1, MTC values are calculated at a cycle bumup of zero MWD /MTL. Since this loading pattern contains a large number of IFBAs, the MTC values become more positive with cycle bumup to about 2000 MWD /MTU. Accordingly, the HZP-MTC at 1000 MWD /MTU is more positive than the HZP-MTC value reported in Figure 7.2-1 at 0 MWD /MTU by approxicately +0.3 pcm/ F. 1 As described above, reduced temperature operation results in a more positive MTC. This results in a smaller addition of reactivity from HFP to HZP when the core trips. Accordingly, implementation of l reduced RCS temperatures will result in slightly more shutdown margin at HZP. l l At BOL-HFP the axial power distribution shifts slightly toward the top of the core under reduced temperature operation. This shift corresponds to the BOL-HFP Axial Offset being about I to 2 percent more positive. This shift does not have significant safety or core operations impacts and is smaller than typical cycle-to-cycle variation. The key safety parameters for power uprate as shown in Table 7.2-1 have been incorporated into the power uprate analysis and are acceptable. l l m u254w.nonssec7.wpr;ib-o 2997 7-12

I J Design Evaluation - Power Distributions and Peaking Factors i l

The Farley VANTAGE 5 analysis addressed the impacts of VANTAGE 5 fuel on core power I distributions and on peaking factors. His section will focus primarily on the impacts of the reduced RCS temperature operation on core power distribution and peaking factors.

j Radial Power Distribution impacts Assembly average power at BOL, MOL and EOL were calculated using Core Models 1 and 2. The l! impact on the radial power distribution due to the T,,, difference at the uprated conditions is quite j small at BOL with the largest percent difference in assembly power of 1.3%. De MOL and EOL i comparisons yield similar results with the trend that powcr distribution differences due to the T,,, i range at the uprated conditions decrease slightly with bumup. Small variations in power occur i depending on the assembly location in the core.

!              The impacts of the above radial power distribution differences on rod worths and on off-nominal condition peaking factors are small and are well within normal cycle-to-cycle variation in these 1

parameters.

l' Axial Power Distribution and RAOC FQ'(z) Impacts 4 l The axial power distribution impacts of reduced RCS temperatures at power uprate conditions show j only a small axial sensitivity to RCS temperatures. { As part of the reload design process, a cycle specific RAOC check is performed which implicitly j includes the axial impacts of the uprating and the reduced RCS temperatures since the Xenon axial j shape parameter library (see Reference 4) is regenerated each cycle at the appropriate T/H conditions. j The cycle specific check will then confirm the continued applicability of the RAOC band (Maximum

of +9 to -12% Axial Flux Difference at HFP). Figure 7.2-2 shows the total peaking factor, FQT (z) x P,,,, versus core height resulting from the RAOC total peaking factor evaluations. Based on the above discussion, it is anticipated that the results shown in this figure would not be significantly impacted by the RCS temperature reductions. De model used to generate Figure 7.2-2 is representative of the mid-range between Model 1 and Model 2. This mid-range model is considered valid for the entire ,

l T,,, range of 567.2*F through 577.2*F and cycle specific checks will confirm the continued applicability of the RAOC band. 7.2.4 Conclusions i In summary, the implementation of a T,,, range at power uprate conditions will not cause changes to l the current nuclear design bases given in the Farley Units 1 and 2 FSAR. The impact of the reduced ; temperatures on peaking factors, rod worths, reactivity coefficients, shutdown margin and kinetics parameters is well within normal cycle-to-cycle variation of these values and will be addressed on a cycle specific basis consistent with Reload Safety Evaluation Methodology. The ranges of key safety mA3254w.non\sec7.wpf Ib 012997 7-13 1

parameters as reported in Table 7.2-1 remain valid and bounding for reduced temperature operating j conditions. 1 No new Technical Specifications or modifications to existing Technical Specifications are anticipated to result due to nuclear design related aspects of the reduced RCS temperatures. 7.2.5 References

1. Letter from Woodward, J. D., (SNC), to USNRC, " Joseph M. Farley Nuclear Plant VANTAGE 5 Fuel Design Amendment," July 15,1991. ;

2. Davidson, S. L. (Ed.), et al., " Westinghouse Reload Safety Evaluation Methodology,"

WCAP-9272-P-A (Proprietary) and WCAP-9273-NP-A (Non-Proprietary), July 1985.

3. Nguyen, T. Q., et al., " Qualification of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores," WCAP-11596-P-A (Proprietary) and WCAP-ll597-A (Non-Proprietary), June 1988.

4. Miller, R. W., et al., " Relaxation of Constant Axial Offset Control-FQ Surveillance Technical Specification," WCAP-10216-P-A, Revision l A (Proprietary) and WCAP-10217-A, Revision I A (Non-Proprietary), February 1994.

O O m:0254w.non\sec7.wpf.It412997 7-l4

i TABLE 7.21 FARLEY 2785 MWt UPRATING PROGRAM KEY SAFETY PARAMETERS Farley Unit 1, Cycle 14 l 5 Farley and Farley Power Safety Parameters VANTAGE 5 Analysis Farley Unit 2, Cycle 11 Uprate 2775 2652 2775 Reactor Core Power (MWt) 577.2 577.2 567.2 to 577.2 Vessel T,,, HFP (*F) RCS Pressure (psia) 2250 2250 2250 Core Average Linear Heat 5.45 5.20 5.45 j l Rate (Kw/ft) Most Positive MTC (pem/*F) 7.0 7.0 7.0 Most Positive MDC (Ak/g/cc) .50 .50 .50 Doppler Temperature .91 to -3.0 .91 to -3.0 .91 to -3.0 ! Coefficient (pcm/*F) i Doppler Only Power 9.55 to -6.05 -9.55 to -6.05 -8.5 to -6.0 ! O Coefficients (pem/% Power) Least Negative

                                            -19.4 to -12.6                -19.4 to -12.6    -19.4 to -12.6

, Doppler Only Power Coefficients (pcm/% Power) Most Negative Beta-Effective .0044 .0072 .0045 . 0072 .0045 .0072 1.77 1.77 1.77 ; Shutdown Margin (%Ap) Nuclear Design F,* 1.550/1.650 1.55/1.65/1.70* I.30/1.70

J S

(1) LOPAR/ VANTAGE 5 (2) LOPAR/V5 - Farley Unit 2/V5 - Farley Unit 1 l (3) Includes 4% uncertainty [ m:\3254w.non\sec7.wpf.lb-012997 7-15

O 8 i IMTC LIMIT MODEL 1 O MODEL 2 s U T t .

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O.0 0.2 0.4 0.6 0.8 1.0 RELATIVE POWER Figure 7.2-1 Moderator Temperature Coemclent versus Power at Beginning of Life O i No Xenon Conditions m:\3254wmoe\sec7.wpf.It>012997 7.]6

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12 2 4 6 8 10 0 CORE ELEVATION (FT) Figure 7.2 2 Maximum Total Peaking FQ'(x) x Pm versus Core Elevation Normal Operation m:\3254w.noe\sec7.wyf:Ib.012997 7 17 .

73 Fuel Rod Design and Performance 73.1 Introduction and Background O' l The purpose of this evaluation was to review the fuel rod design criteria to determine the acceptability of operating the Farley Units 1 and 2 fuel at the uprated power level of 2775 MWt (Core). 73.2 Input Parameters and Assumptions The assumptions used in the fuel rod design criteria evaluation for the Uprating Program are summarized in Table 73-1. 7.33 Description of Analyses, Acceptance Criteria, and Results An evaluation was performed under the Uprating Program of the impact of NSSS performance parameters in Table 73-1 on the ability to satisfy fuel rod design criteria for Farley Units I and 2. De following sections summarize the impact of the proposed core power uprating on key fuel rod design criteria relative to their cor rsponding acceptance limits, and provide an assessment of the resulting impact on anticipated design margin. The key criteria considered include rod internal pressure, clad corrosion, and clad stress and strain. Other fuel rod design criteria are not considered to be significantly impacted by a core power uprating. 7.3.3.1 Rod Internal Pressure Design Basis - The fuel system will not be damaged due to excessive fuel rod internal pressure. Acceptance Limit - The internal pressure of the lead rod in the reactor will be limited to a value below that which could cause the diametral gap to increase due to outward clad creep during steady state operation or for extensive DNB propagation to occur. Design Evaluation - Margin to the rod intemal pressure limit is impacted by changes in the core power rating because higher power levels result in higher fuel operating temperatures and the resulting increase in fission gas release levels. The NRC-approved Westinghouse PAD 3.4 fuel performance model and methodology, References 1,2, and 3, were used to evaluate rod intemal pressure as a function of bumup. Rod intemal pressure will be one of the most limiting considerations for Fuel Rod Design at uprated conditions. The results of this uprate evaluation confirmed that rod intemal pressure limits regarding gap reopening and DNB propagation can be satisfied for the assumed core duty corresponding to a Foi of 1.70 bounding power history at the uprated conditions utilizing cycle-specific fuel features such as annular blankets or product equivalent, IFBA loading (1.0x,1.25x,1.5x, etc.) and supplemental WABA rodlets. m:u254w.nonssec7.wpt:ib-ol2997 7-18

4 1

i l 7.3.3.2 Clad Corrosion 4

Design Basis - De fuel sys:em will not be damaged due to excessive fuel clad oxidation. The fuel , system will be operated to prevent significant degradation of mechanical properties of the clad at low l temperatures, as a result of hydrogen embrittlement caused by the formation of zirconium hydride l platelets.

Acceptance Limit - De calculated clad temperature (metal oxide interface temperature) will be less
than 750*F for Zirc-4 clad fuel and 780*F for ZIRLO clad fuel during steady state operation. For

! Condition II events, the calculated clad temperature will not exceed 800 F for Zirc-4 clad fuel and l 850*F for ZIRLO clad fuel. De hydrogen pickup level in the clad of either ZIRLO or Zirc-4 clad j fuel will be less than or equal to 600 ppm at the end of fuel operation. i Design Evaluation - The uprating conditions result in increased operating temperatures for the clad due , to the increased rod average power rating. Since the corrosion process is a strong function of clad j temperature, the uprating will reduce the margin to the clad corrosion limit. Using NRC-approved models and methodology, References 1,2, and 3, the impact of the core power uprating on corrosion and hydrogen pickup has been evaluated at the uprated conditions. De results of the corrosion evaluation demonstrate that the corrosion limits can be satisfied at the uprated conditions. 7.3.3.3 Clad Stress and Strain Design Basis - De fuel system will not be damaged due to excessive fuel clad stress and stram. Acceptance Limit - De volume average effective stress calculated with the Von Mises equation considering interference due to uniform cylindrical pellet-clad contact, caused by pellet thermal expansion, pellet swelling and uniform clad creep, and pressure differences, is less than the 0.2% offset yield stress with due consideration to temperature and irradiation effects under Condition II l esents. The acceptance limit for fuel rod clad strain during Condition II events is that the total tensile strain due to uniform cylindrical pellet thermal expansion during a transient is less than 1% from the pre-transient value. I Design Evaluation - The NRC-approved models and methodology, References I,2, and 3, were used to evaluate clad stress and strain limits. The local power duty during Condition II events is a key factor in evaluating margin to clad stress and strain limits. The fuel duty at the uprated conditions is ; more limiting, resulting in some reduction in margin to the clad stress and strain limits. The reruits of l this evaluation show that the core power uprating will not impact the fuel's capability to meet clad i stress and strain limits for the uprated power conditions. 7.3.4 Conclusions The fuel rod design criteria most impacted by a change in core power rating have been reviewed with respect to the available margin to support the uprating. Although some design criteria are impacted, as w\3254w.non\sec7.wpf:lb412997 7-19

stated above, the uprated conditions listed in Table 7.3-1 are supported. Finally, as in the past, cycle-specific fuel performance analysis will continue to be performed for each fuel region to confirm that this assessment, and all fuel rod design criteria, are satisfied for the operating conditions specified for each cycle of operation. These evaluations support the Reload Safety Evaluation (RSE) which is performed for each cycle of operation. 7.3.5 References

1. Weiner, R. A., et al., "Irnprovel Fuel Performance Models for Westinghouse Fuel Rod Design and Safety Evaluations", WCAP-10851-P-A (Proprietary) and WCAP-11873-A (Non-Proprietary),

August 1988.

2. Davidson, S. L., and Nuhfer, D. L., " VANTAGE + Fuel Assembly Reference Core Report,"

WCAP-12610 P-A (Proprietary), September 1994.

3. Davidson, S. L., " Westinghouse Fuel Criteria Evaluation Process," WCAP-12488-A, October 1994.

O O; l m:u254 .nonsiec7.wpr: b-o 2*'e7 7-20

TABLE 7.31

SUMMARY

OF FARLEY UPRATING PARAMETERS ANALYZED IN FUEL ROD DESIGN EVALUATION Parameter Current Condition Uprated Condition 1 Core Power (MWt) 2652 2775 Core Inlet Temperature ('F) 543.1 530.6 - 541.1 Mass Flow Rate (x10', Ib/hr-ft') 2.12 2.05 I System Pressure (Psia) 2250 2250 i Cycle Lengths (MWD /MTU) 19,400 21,200 FAH Limit 1.70/1.65 1.70 Fuel Design Considered Zirc-4/ZIRLO; Zirc-4/ZIRLO 3 4 1.0x-1.5x IFBA: 1.0x-1.5x IFBA; j 100 psig backfill

100 psig backfill *

          *IFBA rods only; non-IFBA rods backfill pressure is set at 275 psig.

O b i 1 4 ) a i 4 i i i

I, 1* m:u254w.non\sec7.wpf:1b.ot2997 7-2I

7.4 Heat Generation Rates 7.4.1 Introduction and Background O Gamma ray heat generation rates in the lower core plate were determined for power uprate conditions. Heat generation rates for other significant reactor internals components were obtained through a scaling process. These values were supplied as input for use in the reactor intemals structural evaluations described in Section 5.2. The presence of heat generated in reactor in'emals components, along with the various fluid temperatures, results in thermal gradients within and between components. These thermal gradients result in thermal stresses and thermal growth which must be accounted for in the design and analysis of the various components. The primary design considerations are (1) to ensure that thermal growth is consistent with the functional requirements of components and (2) to ensure that the applicable ASME Code requirements are satisfied. In order to satisfy these requirements, the reactor internals components must be analyzed with respect to fatigue and maximum allowable stress considerations. The reactor intemals components subjected to significant heat generation effects (either directly or indirectly) are the upper and lower core plates, the lower core support; the core baffle plates, the former plates, the core barrel, the neutron pad, the baffle-former bolts and the barrel-former bolts. Note, however, that due to relatively low heat generation rates (generally less than 50 BTU /hr-lbm) the upper core plate, the lower core suppon, and neutron pad experience little, if any, temperature rise over the surrounding reactor coolant. This section provides a description of how the heat generation rates are aetermined for the lower core i plate, and how the component average heating rate values are determined for the significant remaining i reactor internals components. Azimuthal distribution penaining to the Farley core barrel, determined l by means of the pseudo-adjoint method, is also provided.

7.4.2 Reactor Internals Heat Generation Rates - Lower Core Plate 1 1 7.4.2.1 Input Parameters and Assumptions Conservative axial power distributions were assumed in the long-term heat generation rate calculation. For the short-term bottom-peaked calculation, the axial power distribution was taken from the Core Radiation Source Data (CRSD) document as described in WCAP-9620 (Reference 1). Farley specific radial (assembly-by-assembly) loading pattems were also used. 7.4.2.2 Description of Analyses The analysis was performed through the use of the DORT (version 2.8.14) discrete ordinates code. The lower core plate was analyzed in an R-Z (cylindrical) geometry celculation based on the equivalent volume cylindrical core concept. The varying amounts of structure located axially below mu254mnonssec7.wpf.ib-o 2997 7-22

i O the core were approximated as a number of regions each with the appropriate amount of stainless steel, water, and other materials uniformly homogenized throughout the region. The R-Z geometry included the lower three feet of the core and extended axially to one foot below the lower core plate and i radially out to the inner radius of the reactor vessel. l 7.4.23 Results ) The heat generation rates for the lower core plate were provided as input for the reactor internals analysis described in Section 5.2. 7.43 Radial Internals - Core Barrel, Baffle Plates, Neutron Pad 7.43.1 Input Parameters and Assumptions Design basis heat generation rates which are applicable to the Farley radial internals are contained in Apper iices H and I of WCAP-9620 (Reference 1). The core power distributions upon which these calnlations were based were derived from 25 independent fuel cycles in 11 three-loop reactors and rearesented an upper tolerance limit of beginning-of-cycle (BOC) and end-of-cycle (EOC) power in peripheral assemblies, based on a 95 percent probability with 95 percent confidence. Peripheral l assemblies are defined as those with one or two faces or one comer adjacent to the core baffle. Most

p of the 25 fuel cycles were out-in loading patterns which, when combined with the statistical processing I h selected, resulted in a core power distribution which was biased high on the core periphery. This high bias was desired by the reactor intemals analysts to ensure conservative, but not unrealistic, results in the critical baffle-barrel region of the reactor internals. The evaluation of heat generation rates for the radial internals used Farley specific assembly-wise core power distributions for power uprate and CRSD power distributions from Reference 1 (Figure A-3). The core thermal power level associated with each of the determinations (long-term and short-term) was also used. 7.43.2 Description of Analyses An assessment was made of the effect of the core power distributions on the heat generation rates in the core baffle plates and core barrel. The approach taken was to use scaling factors which account for the fact that heat generation rates in the radial internals regions are the result of radiation leakage from the periphery of the core and that, to a close approximation, the heat generation rate in a given region is proportional to the power produced in adjacent fuel regions. These ratio expressions were determined based on discrete ordinates transport theory calculations using various core power distributions. O mms 4w.nonsiec7.wpr.itai2997 7-23

7.4.33 Results The heat generation rates for the radial components were provided as input for the reactor intemals analysis described in Section 5.2. 7.4.4 Core Barrel Azimuthal Heating EMe Distribution 7.4.4.1 Input Parameters and Assumptions The input assumptions and parameters used in developing the core barrel azimuthal heating rates are consistent with the assumptions stated in Section 7.4.3. The analysis used the long-term operation and core relative assembly power values as discussed in Section 7.4.3 and the core thermal power level was 2775 MWt. 7.4.4.2 Description of Analyses The pseudo-adjoint model consists of ten forward coupled neutron-photon DORT discrete ordinates transport theory calculations. The calculations include 500 ppm boron in the water and use the CRSD long-temi pin-by-pin power distributions in the peripheral fuel assemblies and a relative assembly power of 1.0 in the remaining modeled fuel assemblies. DORT results were obtained for each of nine single-assembly calculations and a single calculation including the significant inner assemblies. These results were combined by superposition to create the resulting composite distribution. 7.4.4.3 Results The core barrel azimuthal heat generation rates were provided as input for the reactor internals analysis described in Section 5.2. 7.4.5 References

1. Reactor Internals Heat Generation Rates and Neutron Fluences, WCAP-9620, Revision 1, A. H. l Fero, December,1983. l l

9l mA3254w.non\sec7.wpf:1b-012997 7-24

7.5 Neutron Fluence 7.5.1 Introduction Knowledge of the neutron environment within the reactor pressure vessel and surveillance capsule geometry is an integral part of LWR reactor pressure vessel surveillance programs. To interpret the neutron radiation induced material property changes observed in the test specimens, the neutron environment (energy spectrum, flux, fluence) to which the test specimens were exposed must be known. To relate the changes observed in the test specimens to the present and future condition of the reactor vessel, a relationship must be established between the neutron environment at various positions within the pressure vessel and that experienced by the test specimens. De former requirement is normally met by employing a combination of rigorous analytical techniques and measurements obtained with passive neutron flux monitors contained in each of the surveillance capsules. The latter information is generally derived solely from analysis. WCAP-14687 provides an update of the dosimetry evaluation for Capsules Y, U, X, and W for Farley Unit I withdrawn at the end of Cycles 1,4,7, and 12, respectively. The update includes Capsules U, W, and X for Farley Unit 2 withdrawn at the end of Cycles 1,4, and 6, respectively. This update is based on current state-of-the-art methodology and nuclear data including recently released neutron transport and dosimetry cross-section libraries derived from the ENDF/B-VI data base. WCAP-14687 provides a consistent up-to-date neutron exposure data base for use in evaluating the material O properties of the Farley Units 1 and 2 reactor vessels. 7.5.2 Description of Analysis In performing the fast neutron exposure evaluations for the surveillance capsules and reactor vessel, two distinct sets of transport calculations were carried out. De first, a single computation in the conventional forward mode, was used primarily to obtain relative neutron energy distributions throughout the reactor geometry as well as to establish relative radial distributions of exposure parameters through the vessel wall. De neutron spectral information was required for the interpretation of neutron dosimetry withdrawn from the surveillance capsules as well as for the determination of exposure parameter ratios within the pressure vessel geometry. De relative radial gradient information was required to permit the projection of measured exposure parameters to locations interior to the pressure vessel wall, i.e., the 1/4T and 3/4T locations. The second set of calculations consisted of a series of adjoint analyses relating the fast neutron flux at surveillance capsule positions and at several azimuthal locations on the pressure vessel inner radius to neutron source distributions within the reactor core. De source importance functions generated from these adjoint analyses provided the basis for all absolute exposure calculations and comparison with measurement. These importance functions, when combined with fuel cycle specific neutron source i distributions, yielded absolute predictions of neutron exposure at the locations of interest for each cycle of irradiation. They also established the means to perform similar predictions and dosimetry evaluations for all subsequent fuel cycles. mA3254w.nonWc7.wpf;1tA12997 7-25

The absolute cycle specific data from the adjoint evaluations together with the relative neutron energy spectra and radial distribution information from the reference forward calculation provided the means to:

1. Evaluate neutron dosimetry obtained from surveillance capsules;

2. Relate dosimetry results to key locations at the inner radius and through the thickness of the pressure vessel wall;

3. Enable a direct comparison of r.nalytical prediction with measurement; and

4. Establish a mechanism for projection of pressure vessel exposure as the design of each new fuel cycle evolves.

7.5.3 Results WCAP-14687 provides the results of dosimetry evaluations and the pressure vessel neutron exposure projections. Neutron exposure projections are computed at key locations on the pressure vessel inner radius. Along with the current (13.82 EFPY for Farley Unit i and 11.30 EFPY for Farley Unit 2) exposure, projections are also pmvided for exposure periods of 16,32,36, and 54 EFPY. Projectior.s for future operation were based on the assumption that the average exposure rates (averaged over the Cycles 9 through 13 irradiation period for Farley Unit I and Cycles 7 through 10 irradiation period for Farley Unit 2) would continue to be applicable up to the first cycle of uprated power for each unit. Projections assume that Farley Unit I uprates to 2775 MWt in Cycle 16 at 16.5 EFPY. Projections assume that Farley Unit 2 uprates to 2775 MWt in Cycle 13 at 13.8 EFPY. In the calculation of exposure gradients within the pressure vessel wall for the Farley Units 1 and 2 ! reactor vessels, exposure projections to 16,32,36, and 54 EFPY were also employed. Uprated power l levels were projected as described above. I 7.5.4 References

1. WCAP-14687, Joseph M. Farley Units 1 and 2 Radiation Analysis and Neutron Dosimetry Evaluation, R. L. Bencini, June 1996.

1 i ei. m:\3254w.non\sec7xpf.ib.012997 7-26

_ _ _ _ . _ _ _ _ . _ _ .___ _._.__ _ _ _.. _ ....m . . ._ _ _ . . _ . . . _ . . i: 7.6 Source Terms 3 ( 3 7.6.1 Introduction and Background >

Source terms for several different accident and normal operating conditions were determined for power uprate conditions. The results were used as input to dose and balance of plant analyses. The reanalyzed areas include: core total inventory; reactor coolant system fission products (halogens and
noble gases); and gas decay tank activities. Rese areas are summarized below.
his section describes the methods and results of the core, RCS and gas decay tank imentory calculations performed for the Farley power uprating project.

i Finally, a section is included to address the significance of small changes in the assumed loading partem. The parameters investigated include initial fuel enrichment, inclusion of axial blankets, and bumup assumptions. The effects of changes in these parameters are summarized and discussed. 7.6.2 Total Core Actinide and Fission Product Inventory 7.6.2.1 Input Parameters and Assumptions Tables 7.6-1 and 7.6-2 describe the assumptions and parameters that were used in the determination of d a total core actinide and fission pmduct inventory. 7.6.2.2 Description of Analyses l Fuel burnup and fission product values were modeled via the ORIGEN2 code (References 1 through 5). ORIGEN2 is a versatile point-depletion and radioactive-decay computer code for use in simulating nuclear fuel cycles and calculating the nuclide compositions and characteristics of materials contained therein. His code takes into account the transmutation of all the isotopes in the material. For the relatively high fluxes in the core region, burn-in and burn-out of isotopes can have an ! important effect. His is particularly the case when high burnup cases are being considered. ! 1 For the Farley uprating, a representative equilibrium loading pattem was assumed. The ORIGEN2 analysis models a single assembly in each of the regions. Bumup calculations, i reflecting each of the appropriate power histories, are performed. The total inventory for each region at the end of the equilibrium cycle is then determined by multiplying the assembly value by the ; number of assemblies per region. Finally, the regions are summed to produce a core total inventory, j 7.6.2.3 Results ! The core activities were provided as input to the radiological evaluations (see BOP Licensing Report). mA3254w.nonwec7.wpf.lb-012997 7 27 l

7.63 Reactor Coolant System Activities 7.63.1 Input Parameters and Assumptions O The parameters used in the calculation of the reactor coolant fission product concentrations, including pertinent information conceming the expected coolant cleanup flow rate, demineralizer effectiveness, and volume control tank noble gas stripping behavior, are presented in Tables 7.6-2 and 7.6-3. In these calculations, small cladding defects (equivalent to 1 percent of the fuel rods) are assumed to be present at initial core loading and uniformly distributed throughout the core. Similar defects are assumed to be present in sll reload regions. The fission product escape rate coefficients are, therefore, based on an average fuel temperature. 7.63.2 Description of Analyses The halogen and noble gas fission product activity in the reactor coolant during operation with defects in the cladding of the fuel rods was computed. The calculations are based on the assumption that there is no activity reduction due to pressurizer operation and that the nuclide concentration in the volume control tank can be approximated. In calculating the RCS fission product activities, no credit was taken for removal due to purge of the volume control tank. This represents a conservative treatment for the RCS. 7.6.23 Results of Analyses l I The RCS activitics were provided as input to the radiological evaluations (see BOP Licensing Report). 7.6.4 Gas Decay Tank Activities 7.6.4.1 Input Parameters and Assumptions l Radiological inventories for the gas decay tanks (GDT) are determined in similar fashion to the determination for the reactor coolant system. For conservatism, the entire inventory is assumed to be placed in a single gas decay tank, and the inventory is expressed as a volumetric activity in this tank. Additional input parameters may be found in Tables 7.6-1 through 7.6-3. 7.6.4.2 Description of Analyses Activities are calculated for twelve noble gas nuclides. A continuous volume control tank purge rate of 0.7 standard cubic feet per minute was assumed. In the case of the gas decay tank, this represents a conservative treatment, providing a gas decay tank inventory that remains applicable in high-pressure or periodic purge modes. m:\3254w.non\sec7.wpf;lb-012997 7-28

   .~   .-                - . . -       . . . . . - -             . . . _ . - . .      . . _ -   .-- - -          - . . . . - .

J l\ p 'Ihe resultant inventory represents the design activity distribution with one percent defective fuel and the volume control tank purge system operating. ! 7.6.4.3 Results of Analyses ; 4 The gas decay tank activities were provided as input to the radiological evaluations (see BOP Licensing Report). ! 7.6.5 References ; l 1. CCC-371/ORIGEN2 Version 2.1.

2. RSIC Computer Code Collection: ORIGEN 2.1 - Isotope Generation and Depletion Code, Matrix i Exponential Method. j

3. A User's Manual for the ORIGEN2 Computer Code, ORNUTM-7175, A. G. Croff, July 1980 (packaged with Ref. 3 above). ,

4. ORIGEN2: A Versatile Computer Code for Calculating the Nuclide Compositions and Characteristics of Nuclear Materials, Allen G. Croff, Nuclear Technology Vol. 62, September 1983.

5. Conversion / Configuration / Validation of ORIGEN 2 Code, V 2.1, RSAC-M-813, T. M. Lloyd, October 11,1993.

I l au254..nonsuc72,f:st412997 7-29

TABLE 7.6-1 INPUT PARAMETERS FOR FISSION PRODUCT INVENTORY CALCULATION Parameter Assumed Value Core Thermal Pcwer (MWt) 2775 x 102% Fuel Assembly Type 17 x 17 VANTAGE 5 Uranium Mass (MTU) 66.8 Equilibrium Cycle Length (MWD /MTU) 20,000 Equilibrium Loading Pattem Listed in the Following Table Uranium Enrichment (Active Fuel) 4.4 w/%,44 Assemblies 4.8 w/%*,24 Assemblies Uranium Enrichment (Axial Blanket Fuel) Not modeled in calculation (Addressed through parametric sensitivity study) TABLE 7.6-2 EQUILIBRIUM LOADING PATTERN End of Cycle Burnup Region Number of Assemblies (MWD /MTU) Average Power Feed "A" 44 24251 1.205 Feed "B" 24 26929 1.325 1 x Bumed "A" 44 43631 0.964 1 x Bumed "B" 24 41800 0.759 2 x Bumed "A" 5 54003 0.930 2 x Bumed "B" 16 46030 0.431 ; l

Uranium enrichments up to 5.0% were evaluated through a parametric sensitivity study. The details of this study were provided as input to the radiological evaluations (see BOP Licensing i Report).

O' m:u254w.nonssec7.wpt:ib o 2997 7-30

TABLE 7.6-3 L INPUT PARAMETERS FOR FISSION PRODUCT INVENTORY CALCULATION . I Parameter Assumed Value ' l Total Core Thermal Power 2775 x 102% Fuel Assembly Type 17 x 17 VANTAGE 5 Fuel Enrichment 4.4 w/%,44 Assemblies 4.8 w/%*,24 Assemblies Uranium Mass 66.8 MTU Equilibrium cycle length 20,000 MWD /MTU Initial boron concentration in equilibrium cycle, 1400 ppm lower is conservative. Mixed bed demineralizer resin volume 30 ft' Cation bed demineralizer resin volume 20 ft'

O Assumed Failed Fuel Fraction 1%

Reactor coolant mr.ss 394,637 lbs Purification system flow rate 120 gpm Volume control tank total volume 300 ft' Nominal volume control tank temperature 112*F l 1 Volume control tank vapor purge rate .7 scfm* Gas Decay Tank Volume, single tank 600 ft' (1) Uranium enrichments up to 5.0% were evaluated through a parametric sensitivity study. The details of this study were provided as input to the radiological evaluations (see BOP Licensing Report). (2) For the work transmitted in this report, the cation bed demineralizers were not modeled, having no effect on the halogen and noble gas values reported. Similarly, it was unnecessary to consider a cation demineralizer DF. (3) This purge rate is assumed when purge is in use. In the case of RCS coolant activities, VCT purge is not assumed to be in service, a conservative treatment. O b m:\3254w.non\sec7.wpf.lb-012997 7-31}}

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