Text

Best Estimate LOCA Analysis, Vol 5
	ML20155E759
Person / Time
Site:	Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png
Issue date:	02/28/1986
From:	; NORTHEAST UTILITIES SERVICE CO.
To:	;
Shared Package
ML20155E746	List: ML20155E741; ML20155E759;
References
	NUSCO-150, NUSCO-150-V05, NUSCO-150-V5, NUDOCS 8604180090
	Download: ML20155E759 (288)
	v • d • e

NUSCO 150 CONNECTICUT YANKEE (Haddam Neck Plant)

Best Estimate LOCA Analysis N

J February 1986 Prepared By LOCA Analysis Section/ Safety Analysis Branch NORTHEAST UTILITIES SERVICE COMPANY (O) v 8604180390 860331 PDR ADOCK 05000213 P PDR

t ABSTRACT U

This report presents the transient thermal and hydraulic respouse for Connecticut Yankee (Haddam Neck Plant) for a variety of potential core uncovery events. These events include small to large-break loss of coolant accidents, station AC blackout, total loss of DC power, +' red and bleed cooling, steam generator tube rupture, and other accidents. The calculations were performed in support of the Connecticut Yankee

, Probabilistic Safety Study. The thermal-hydraulic computer code NULAPS was used in this analysis. Best estimate assumptions and input data were l' used, for the most part, in the study.

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TABLE OF CONTENTS (d)

DISCLAIMER TITLE PAGE ABSTRACT TABLE OF CONTENTS

1. INTRODUCTION 1-1

- 1.1 Purpose 1-1 1.2 Base Analytical Models 1-2 1.3 Data and Assumptions 1-3

2. STATION BLACK 0UT ANALYSIS 2-1 2.1 Introduction 2-1 2.2 Analytical Model 2-1 2.3 Discussion of Results 2-2 2.3.1 SBO, 300 GPM/RCP Leak, AFW Unavailable 2-2 2.3.2 SBO, 100 GPM/RCP Leak, AFW Unavailable 2-3 2.3.3 SBO, 50 GPM/RCP Leak, AFW Unavailable 2-4 2.3.4 SBO, 300 GPM/RCP Leak, AFW Available 2-5 2.3.5 SBO, 100 GPM/RCP Leak, AFW Available 2-5 2.3.6 SBO, 50 GPM/RCP Leak, AFW Available 2-6 2.4 Summary 2-6

\s 3. INCORE INSTRUMENT TUBE RUPTURE ANALYSIS 3-1 3.1 Introduction 3-1 3.2 Analytical Model 3-1 3.3 Discussion of Results 3-2 3.3.1 IITR, 1 HPSI Pump Available, RCPs Tripped 3-2 3.3.2 IITR, I HPSI Pump Available, RCPs Not Tripped 3-3 3.3.3 IITR, 1 Charging Pump Available, RCPs Tripped 3-3 3.3.4 IITR, 1 Charging Pump Available, RCPs Not 3-4 j Tripped 3.4 Summa ry 3-4

4. STEAM GENERATOR TUBE RUPTURE 4-1 i

4.1 Introduction 4-1 4.2 Analytical Model 4-1 4.3 Discussion of Results 4-2 4.3.1 SGTR, I HPSI Pump Available, RCPs Tripped 4-2 4.3.2 SGTR, I HPSI-Pump Available, RCPs Not Tripped 4-3 4.3.3 SGTR, 1 Charging Pump Available, RCPs Tripped 4-3 4.3.4 SGTR, 1 Charging Pump Available, RCPs Not 4-4 Tripped 4.3.5 SGTR, No Injection Flov 4-5 i <4.3.6 SGTR, Additional Cases Related to Stuck-Open 4-5 SG Safety Value and Nonisolation of Faulted SG 4.4 Summary 4-6 OJ f

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TABLE OF CONTENTS (Cont'd)

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5. LARGE BREAK LOCA ANALYSIS 5-1 5.1 Introduction 5-1 5.2 ' Analytical Model 5-1 ,

s 5.3 Discussion of Results 5-2 5.3.1 LBLOCA, 1 LPSI Pump Available 5-2 5.3.2 LBLOCA, 60 Percent Flow From One LPSI Pump 5-3 5.4 Summary 5-4

6. SMALL'AND MEDIUM BREAK LOCA ANALYSIS 6-1 6.1 Introduction 6-1 6.2 Analytical Model 6-1 6.3 Discussion of Results for Medium Breaks 6-2 6.4 Discussion of Results for Medium-Saall Breaks 6 6.4.1 0.02 ft2 Break, Charging Flow, No SG Feedwater 6-5 6.4.2 0.02 ft2 Break, Charging Injection at 1,200 6-6 Seconds, No SG Feedwater 6.4. 3 . .03 fta Break, No Safety Injection,100*F/hr 6-6 RCS Cooldown,at 300 Seconds 6.4.4 Summary 6-8 6.5 Discussion of Results for Small Breaks 6-8 6.5.1 0.003 ft Break, 2 HPSI, No SG Feedwater 6-9 6.5.2 0.003 ft2 Break, Charging Injection, No SG 6-9 Feedwater 6.5.3 0.003 ft2 Break, No SG Feedwater, Feed and 6-10 Bleed with Charging Injection and 1 PORV at 2,400 Seconds 6.5.4 0.003 ft2 Break, No Safety Injection Flow, 6-11 75'F/Hr RCS Cooldown at 900 Seconds 6.5.5 Summa ry 6-12 6.6 Discussion of Results for Consequential Stuck Open PORV 6-12 6.6.1 Stuck Open PORV, 5 Percent Main Feedwater, 6-13 No Safety Injection 6.6.2 Stuck Open PORV, No Safety Injection Flow, 6-14 Leak Isolated and 75'F/Hr RCS Cooldown at 3,600 Seconds 6.7 Discussion of Results for Reactor Coolant Pump Seal 6-15 LOCA 6.8 Summary of Small and Medium Break LOCA Analysis 6-16

7. TOTAL LOSS OF FEEDWATER (FEED AND BLEED) ANALYSIS 7-1 7.1 Introduction 7-1 7.2 Analytical Model 7-1 7.3 Discussion of Results 7-2 7.3.1 Feed and Bleed Initiated at 2,400 Seconds, .7-2 One PORV and One Charging Pump 7.3.2 Feed and Bleed Initiated at 2,400 Seconds, 3 Two PORV's and One HPSI Pump 7.4 Summary 7-4 iv

TABLE OF CONTENTS

.(Cont'd) 8-1 D)

(. M. MINIMUM AFW FLOW REQUIREMENTS ANALYSIS 11 - 1 8.1 Introduction 11 - 1 8.2 Analytical Model

8.3 Discussion of Results 8-2 8.4 Sununa ry 8-3

'9 . ANTICIPATED TRANSIENT WITHOUT SCRAM ANALYSIS 9-1 J 9.1 Introduction. 9-1 9.2 Analytical Model 9-1 9.3 Discussion of Results 9-3 9.4 Summary 9-7 10-1 J

10. HIGH PRESSURE R:' CIRCULATION ANALYSIS 1

2 10.1 Introduction 10-1 i

10.2 Analytical Model 10-1 10.3 Discussion of Results 10-2 10-4 10.4 Summary

11. TOTAL LOSS OF DC POWER ANALYSIS 11-1 11.1 Introduction 11-1

} 11.2 Analytical Model 11-2 j 11.3 Discussion of Results 11-2 4 11.4 Susanary 11-4

, 12. FUEL CLADDING TEMPERATURE CALCULATIONS FOR MEDIUM BREAK LOCA 12-1 l.

12-1 12.1 Introduction 12.2 Analytical Model 12-1 12.3 Discussion of Results 12-1 12.4 Summary 12-2

! 13. REFERENCES 13-1 4

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i LIST OF TABLES TABLE NUMBER TITLE PAGE NUMBER-1-5 1.1 Plant Initial Conditions 2-7 l 2.1 Summary of Station Blackout Core Uncovery Times ,

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e--rmee,-,---n- ,w e---w --ww---ve.,w-,-r-v,_weew.~re,e--n-,, ,, nn,mn~-m,-,,,e..+w.wa--.---- -----,wn-,-w,-,,w,,en,wn-a,,--,,,ee,

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LIST OF FIGURES [

FIGURE NUMBER TITLE PAGE NUMBER 1.1 NULAP5 Small and Medium Break Model 1-6 STATION BLACKOUT, 300 GPM/RCP INITIAL l LEAKAGE, AUX. FEEDWATER UNAVAILABLE i 2.1 Collapsed Core Level 2-8 2.2 S.G. Upward Tubes Total Mass 2-9 l 2.3 Loop Seal Total Mass 2-10 STATION BLACKOUT, 100 GPM/RCP INITIAL j LEAKAGE, AUX. FEEDWATER UNAVAILABLE j 2.4 Collapsed Core Level 2-11 i- 2.5 S.G. Upward Tubes Total Mass 2-12 j 2.6 Loop Seal Total Mass 2-13 .

t i STATION BLACKOUT, 50 GPM/RCP INITIAL LEAKAGE, AUX. FEEDWATER UNAVAILABLE 4

2.7 Collapsed Core Level 2-14 2.8 S.G. Upward Tubes Total Mass 2-15 '

2.9 Loop Seal Total Mass 2-16 f

STATION BLACKOUT, 300 GPM/RCP INITIAL .

LEAKAGE, AUX. FEEDWATER AVAILABLE 2.10 Collapsed Core Level 2-17

l. 2.11 S.G. Upward Tubes Total Mass 2-18 j 2.12 Loop Seal Total Mass 2-19 1 STATION BLACKOUT, 100 GPM/RCP INITIAL !

) LEAKAGE, AUX. FEEDWATER AVAILABLE Collapsed Core Level 2.13 .

2-20 2.14 S.G. Upward Tubes Total Mass 2-21 2.15 Loop SeaI Total Mass 2-22 !

1 STATION BLACKOUT, 50 GPM/RCP INITIAL f) LEAKAGE, AUX. FEEDWATER AVAILABLE Collapsed Core Level 2.16 2-23 l ?.17 S.G. Upward Tnhen Total Mann ? 94 !

i INSTRUMENT TUBE RUPTURE, RCP TRIP AT

1715 PSIA, I HPSI PUMP AVAILABLE l 3.1 Pressurizer Pressure 3-5 l 3.2 Rupture and HPSI Flow 3-6

< 3.3 Rupture and HPSI Integrated Flow 3-7 INSTRUMENT TUBE RUPTURE, RCP TRIP AT 1715 PSIA, 1 CHANGING PUMP AVAILABLE (VALVE 110A ONLY) i 3.4 Pressurizer Pressure 3-8 3.5 Rupture and Charging Flow- 3-9

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PAGE_ NUMBER S.G. TUBE RUPTURE, RCP TRIP AT 1715 PSIA, I HPSI PUMP AVAILABLE 4.1 Pressurizer Pressure 4-8 4.2 HPSI and Rupture Integrated Flow 4-9 Safety Valve Integrated Flow for 4-10 4.3 Faulted S.G.

S.G. TUBE RUPTURE, RCP TRIP AT 1715 PSIA, 1 CHARGING PUNP AVAILABLE (VALVE 110A ONLY) 4-11 4.4 Pressurizer Pressure 4-12 4.5 Charging and Rupture Integrated Flow Safety Valve Integrated Flow for 4-13 4.6 Faulted S.G.

S.G. TUBE RUPTURE, RCP TRIP AT 1715 PSIA, HPSI AND CHARGING PUMPS UNAVAILABLE Collapsed Core Level

4-14 4.7 4-15 4.8 Pressurizer Pressure 4 4.9 '

Faulted S.G. Pressure 4-16 DOUBLE ENDED DISCHARGE LEG BREAK, 1 LPSI PUMP ONLY 5.1 Peak Clad Temperature 5-5 5.2 Core Pressure 5-6 O 5.3 Collapsed Core Level 5-7 5-8 V 5.4 Flow Exiting Top of Core DOUBLE ENDED DISCHARGE LEG BREAK, 1 LPSI PUMP ONLY, 1 DELUGE VALVE FAILED CLOSED 5.5 Peak Clad Temperature 5-9 5.6 Double Ended Discharge Leg Break 5-10 j

Normalized Core Power SMALL BREAK ANALYSIS, 0.2 SQ. FT. DISCHARGE LEG BREAK, RCPS OFF

' 6.1 Pressurizer Pressdre 6-18 6.2 Pressurizer Liquid Volume 6-19

! 6.3 Collapsed Core Level 6-20 6.4 Two-Phase Core Level 6-21 6.5 Break and HPSI Flow 6-22 6.6 Hot Leg Temperature 6-23

. 6.1 Steam Generator Pressure 6-24 l

6. ft Steam Generator Mass 6-25 j

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' SMALL BREAK ANALYSIS, 0.2 SQ. FT. DISCHARGE LEG BREAK, HPSI FLOW AT 300 s 6.9 Pressurizer Pressure 6-26 6.10 Pressurizer Liquid Volume 6-27

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6.I1 Collapsed Core Level 6-28 6.12 Two-Phase Core Level 6-29 I

6.13 Break and HPSI Flow '6-30

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PAGE NUMBER 6.14 Hot Leg Temperature 6-31 6.15 Steam Generator Pressure 6-32 6.16 Steam Generator Mass 6-33 SMALL BREAK ANALYSIS, 0.02 SQ. FT. DISCHARGE LEG BREAK, CHARGING INJECTION i

~6.17 Pressurizer Pressure 6-34 6.18 Pressurizer Liquid Level. 6-35 i 6-36 6.19 Reactor Vessel Total Mass 6.20 Collapsed Core Level 6-37 6.21 Two-Phase Core Level 6-38

~6.22 Break and Charging Flow 6-39 6.23 Hot Leg Temperature 6-40

$ 6.24 Steam Generator Pressure 6-41 6.25 Steam Generator Mass 6-42 i

SMALL BREAK ANALYSIS, 0.02 SQ. FT. DISCHARGE 1 LEG BREAK, CHARGING INJECTION AT 1200 SEC l 6.26 Pressurizer Pressure 6-43 6.27 Pressurizer Liquid Level 6-44

6.28 Reactor Vessel Total Mass 6-45

- 6.29 Collapsed Core Level 6-46 6.30 Two-Phase Core Level 6-47 i

6.31 Break and Charging Flow 6-48 l 6-49

! 6.32 Hot Leg Temperature

, 6.33 Steam Generator Pressure 6-50

! 6.34 Steam Generator Mass 6-51 SMALL BREAK ANALYSIS, 0.03 SQ.-FT. DISCHARGE LEG BREAK, S.G. C00LDOWN AT 300 (103 F/HR) 6.35 Pressurizer Pressure 6-52 6.36 Collapsed Core Level 6-53 l

6-54 j 6.37 Break and HPSI Flow 1 6.38 Cold Leg Temperature 6-55 i 6.39 Steam Generator Pressure 6-56 SMALL BREAK ANALYSIS, ' O.003 SQ. IT. DISCHARGE

l. LEG BREAK j

6.40 Pressurizer Pressure 6-57 6.41 Pressurizer Liquid Volume 6-58 6.42 Reactor Vessel Total Mass 6-59 6.43 Collapsed Core Level 6-60 6.44 Two-Phase Core Level 6-61 i

! 6.45 Break and HPS' w 6-62 6.46 Hot Leg Tear . re -

6-63 i 6.47 Steam Generatot .ressure 6-64 6.48 Steam Generator Mass- 6-65

$ SMALL BREAK ANALYSIS, 0.003 SQ. FT DISCHARGE LEG BREAK, CHARGING INJECTION-6-66 6.49 Pressurizer Pressure 6.50 Pressurizer Liquid Volume 6-67 6.51 Reactor Vessel Total Mass 6-68 O%

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T PAGE NUMBER Collapsed Core Level 6-69

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6.52 Two-Phase Core Level 6-70 ,

6.53 Break and Charging Flow 6-71 6.54 6-72 . ,

6.55 PORV Flow 6-73 6.56 Hot Leg Temperature 6-74 6.57 Steam Generator Pressure Steam Generator Mass 6-75 !

6.58 SMALL BREAK ANALYSIS, 0.003 SQ. FT. DISCHARGE LEG BREAK Pressurizer Pressure 6-76 6.59 6-77 6.60 Pressurizer Liquid Volume Reactor Vessel Total Mass 6-78 6.61 6-79 6.62 Collapsed Core Level Two-Phase Core Level 6-80 6.63 6-81 6.64 Break and Charging Flow 6-82 6.65 PORV Flow 6-83 6.66 Hot Leg Temperature Steam Generator Pressure 6-84 6.67 6-85 6.68 Steam Generator Mass SMALL BREAK ANALYSIS, 0.003 SQ. FT. DISCHARGE LEG BREAK, S.G. C00LDOWN AT 900 SEC (75F/HR)

Pressurizer Pressure 6-86 6.69 Pressurizer Liquid Volume 6-87 6.70 6-88

< 6.71 Reactor Vessel Total Mass Collapsed Core Level 6-89 6.72 6-90

~ 6.73 Two-Phase Core Level 6-91 6.74 Break and HPSI Flow 6-92 6.75 Hot Leg Temperature 6-93 6.76 Steam Generator Pressure 6-94 6.77 Steam Generator Mass SMALL BREAK ANALYSIS, STUCK OPEN PORV, NO SAFETY INJECTION Pressurizer Pressure 6-95 6.78 Pressurizer Liquid Volume 6-96 6.79 6-97

. 6.80 Reactor Vessel Total Mass 6-98

! 6.81 Collapsed Core Level 6-99 6.82 Two-Phase Core Level 6-100 i' 6.83 PORV and HPSI Flow 6-101 6.84 Hot Leg Temperature 6-102

- 6.85 Cold Leg Temperature 6-103 4 6.86 Steam Generator Pressure 6-104 6.87 Steam Generator Mass 1

SMALL BREAK ANALYSIS, STUCK OPEN PORV, LEAK ISOLATED AND S.G. COOLING INITI ATED AT 3600 SEC 6-105 1 6.88 Pressurizer Pressure 6-106 I~ 6.89 Pressurizer Liquid Volume 6-107 I 6.90 Reactor Vessel Total Mass 6-108 Collapsed Core Level

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PAGE NUMBllt 6-109 6.92 Two-Phase Core Level 6-110 6.93 PORV and HPSI Flow 6-111 6.94 Hot Leg Temperature 6-112 6.95 Steam Generator Pressure 6-113 6.96 Steam Generator Mass SMAIJ BREAK ANALYSIS, FOUR MAIN C001 ANT PUMP SEAL FAILURES, NO SAFETY INJECTION 6-114 o.97 Pressurizer Pressure 6-115 6.98 Pressurizer Liquid Volume 6 116 6.99 Reactor Vessel Total Mass 6-117 6.100 Collapsed Core Level 6-118 6.101 Two-Phase Core Level 6-119 6.102 Seals and llPSI Flow 6-120 6.103 Hot Leg Temperature 6-121 6.104 Cold Leg Temperature 6-122 6.105 Steam Generator Pressure 6-123 6.106 Steam Generator Mass TOTAL LOSS OF S.G. FEEDWATER, FEED AND BLEED AT 2400 SECONDS WITH I PORV AND 1 CHARGING PUMP 7-6 7.1 Pressurizer Pressure 7-7 7.2 Pressurizer Liquid Volume 7-8 7.3 Reactor Vessel Total Mass 7-9 7.4 Collapsed Core Level 7-10 7.5 Two-Phase Core Level 7-11 7.6 PORV and Charging Flow 7-12 7.7 Hot Leg Temperature 7-13 7.8 Steam Generator Pressure 7-14 7.9 Steam Generator Mass TOTAL LOSS OF S.G. FEEDWATER, FEED AND BLEED AT 2400 SECONDS WITH 2 PORVs AND 1 IIPSI PUMP 7-15 7.10 Pressurizer Pressure 7-16 7.11 Pressurizer Liqui <1 Volume 7-17

/.12 Reactor Vessel Total Mass 7-18 7.Ii Collapsed Core Level 7-19 7.14 Two-Phase Core Level 7-20 7.15 PORVs and ilPSI Flow 7-21 7.16 Hot Lex Temperature 7-22 7.17 Steam Generator Pressure 7-23 7.18 Steam Generator Mass LOSS OF S.G. MAIN FEEDWATER, 1 AUX. FEl:D'4ATER PUMP TO 1 S.G., OFFSITE POWER UNAVAILABLE fl-4 8.' Integrated PORV Flow L-5 8.2 RCS Pressure 8-6 8.3 1 S.G. Collapsed Liquid Level 3 S.G. Collapsed Liquid Level 8-7 8.4 LOSS OF S.G. MAIN FEEDWATER, 1 AUX. FEEDWATER PUMP '10 i S.G. , OFFSITE POWER AVAI LAllLE Integrated PORV Flow 8-8 M.5 8-9 8.0 RCS Pressure xii

_ PAG _ % tLR

, ; 6.92 Two-Phase Core Level 6-109 x_/ 6.93 PORV and HPSI Flow 6-110 6.94 Hot Leg Temperature 6-111 o.95 Steam Generator Pressure 6-112 6.96 Steam Generator Mass 6-113 SMALL BREAK ANALYSIS, FOUR MAIN COOLANT PUMP SEAL FAILURES, NO SAFETY INJECTION o.97 Pressurizer Pressure 6-114 6.98 Pressurizer Liquid Volmu- 6-115 6.99 Reactor Vessel Total Mass 6-116 6.100 Collapsed Core Level 6-117 6.101 Two-Phase Core Level 6-118 6.102 Seals and IIPSI Flow 6-119 6.103 1:ot Leg Temperature 6-120 6.104 Cold Leg Temperature 6-121 6.105 Steam Generator Pressure 6-122 6.106 Steam Generator Mass 6-123 TOTAL LOSS OF S.G. FEEDWATER, FEED AND BLEED AT 2400 SECONDS WITil 1 PORV AND 1 CHARGING PUMP 7.1 Pressurizer Pressure 7-6 7.2 Pressurizer Liquid Volume 7-7 7.3 Reactor Vessel Total Mass 7-8 7.4 Collapsed Core Level 7-9 7.5 Two-Phase Core Level 7-10

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7.6 PORV and Charging Flow 7-11

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7.7 Hot Leg Temperature 7-12 7.8 Steam Generator Pressure 7-13 7.9 Steam Generator Mass 7-14 TOTAL LOSS OF S.G. FEEDWATER, FEED AND BLEED AT 2400 SECONDS WITH 2 PORVs AND 1 HPSI PUMP 7.10 Pressurizer Pressure 7-15 7.11 Pressurizer Liquid Volume 7-16 1.12 Reactor Vessel Total Mass 7-17 1.11 Collapsed Core Level 7-1B 7.14 Two-Phase Core Level 7-19 7.15 PORVs and HPSI Flow 7-20 7.16 Ilo t Leg Temperature 7-21 7.17 Steam Generator Pressure 7-22 7.18 Steam Generator Mass 7-23 LOSS OF S.G. MAIN FEEDWATER, 1 AUX. FEEDWATER PU:!P TO 1 S.G. , OFFSITE POWER UNAVAILABLE 8.1 Integrated PORV Flow 8-4 8.2 RCS Pressure 8-5 8.3 1 S.G. Collapsed Liquid Level 8-6 8.4 3 S.C. Collapsed Liquid Level 8-7 LOSS OF S.G. MAIN FEEDWATER, 1 AUX. FEEDWATLH PUMP TO 1 S.G., OFFSITE POWER AVAILABLE y 8.5 Integrated P0HV Flow 8-8

. } 8.6 RCS Pressure 8-9 xii

PAGL NUMill R

['(')/ LOSS OF S.G. MAIN FEEDWATER WITHOUT SCRAM, TURBINE NEVER TRIPPED, PORV BLOCK VALVE KEPT CLOSED 9.1 Core Power 9-8 9.2 Pressurizer Pressure 9-9 9.3 Pressuri7er Liquid Volume 9-10 9.4 Reactor Vessel Total Mass 9-11 9.5 Pressurizer Safety Valves Flow 9-12 9.6 Average Loop Temperature 9-13 9.7 Steam Generator Mass 9-14 LOSS OF S.G. MAIN FEEDWATER WITHOUT SCRAM, TURBINE NEVER TRIPPED 9.8 Core Power 9-15 9.9 Pressurizer Pressure 9-16 9.10 Pressurizer Liquid Volume 9-17 9.11 Reactor Vessel Total Mass 9-18 9.12 PORV Flow 9-19 9.13 Pressurizer Safety Valves Flow 9-20 9.14 Average Loop Temperature 9-21 9.15 Steam Generator Mass 9-22 LOSS OF S.G. MAIN FEEDWATER WITil0UT SCRAM, TURBINE TRIPPED AT 40 SECONDS 9.16 Core Power 9-23 9.17 Pressurizer Pressure 9-24

(~~g 9.18 Pressurizer Liquid Volume 9-25 t / 9.19 Reactor Vessel Total Mass 9-26

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9.20 PORV Flow 9-27 9.21 Average Loop Temperature 9-28 9.22 Steam Generator Mass 9-29 SMALL BREAK ANALYSIS, HIGH PRESSURE RECIRCULATION,

.045 SQ. FT. LOOP 2 DISCHARGE LEG BREAK 10.1 RCS Pressure 10-5 10.2 Collapsed Core Level 10-6 SMALL BREAK ANALYSIS, lilCH PRESSURE RECIRCULATION,

.02 SQ. FT. LOOP 2 DISCHARGE LEG BREAK 10.3 RCS Pressure 10-7 10.4 Collapsed Core Level 10-8 TOTAL LOSS OF DC 11.1 S.G. Pressure 11-5 11.2 S.G. Level 11-6 11.3 Steam Line Void Fraction 11-7 11.4 Aux. Feed Flow 11-8 11.5 Average Temperature 11-9 11.6 Pressurizer Pressure 11-10 FUEL CLADDING TEMPERATURE CALCULATIONS FOR 0.2 SQ. FT. DISCllARGL LEG BREAK, RCPS OFF, llPSI FLOW m

g AT 300 SEC.

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9 12.1 12.2 12.3 NULAPS Node Diagram Core Pressure Collapsed Core Level 12-3 12-4 12-5 l 12.4 Fuel Cladding Average Temperature 12-6 i !

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(~N 1. INTRODUCTION

)

l.1 Purpose Northeast Utilities Service Company (NUSCO) has performed a Probabilistic Safety Study (PSS) for the Connecticut Yankee Atomic Power Company, Haddam Neck Plant (referred to as Connecticut Yankee). The scope of the PSS involves the investigation into the causes, probabilities, and possible plant damage states involving a wide spectrum of " internally" initiated events. " External" events such as flooding, fire, and seismicity are not considered.

The purpose of this Best hstimate report is to provide the thermal-hydraulic bases for the selection of " success criteria" for mitigating various accidents. The analyses performed in this report are also used in the determination of the loss of coolant accident categories as defined in the PSS. The analyses in this report provide valuable insights into the available time for operator action for some accidents where multiple equipment failures occur. This information can be used as input to the PSS in the performance of the human reliability analysis.

The accidents which are considered in this report include:

o small, medium, and large-break loss of coolant accidents

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(LOCA);

o variations of the above such as incore instrument tube rupture, steam generator tube rupture, catastro} hic reactor coolant pump seal LOCA, and stuck open pressurizer PORV; o total loss of steam generator feedwater leading to feed and bleed cooling; o anticipated transient without scram for the loss of main feedwater event; o total loss of DC power; o station AC blackout.

Calculations are also performed to determine a) minimum auxiliary feedwater flow re juirements for the loss of main feedwater event, and b) minimum charging flow requirements for the recirculation phase of small to medium LOCAs.

liest estimate assumptions and input data are used whenever possible. In some instances, bounding " type" assumptions are made to limit the number of calculations which might otherwise he required.

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1-1

s j-t 1.2 Base Analytical Model C/

The calculations in this study were perf ormed using the NUIAl",

code (Reference 1). NULAPS is a transient thermal hydraulit-system blowdown code which has been developed to analyze the postulated loss-of-coolant accident. As discussed in Reference 1, NULAPS was modified to perform small break LOCA ECCS licensing analyses for the Haddam Neck Plant. However, because the methodology comprising NULAPS are based on physically founded models, the NULAPS code is also suitable for performing best-estimate analyses.

A nodalization diagram of the base NULAPS model is shown in Figure 1.1. The primary system is represented by two loops, each combining two actual loops. In each loop, the hot legs are divided into two single volumes, and the SG into one pipe component and one single volume. The pipe component is divided into nine nodes consisting of one SG inlet plenum node and eight SG tube nodes. The single volume represents the SG outlet plenum. The cold leg pump suction is represented by one pipe component divided into two nodes. The cold leg pump discharge is modeled differently for the intact and the affected loop. As can be seen from Figure 1.1, the pump discharge piping in the left side of the diagram is represented by one single volume. The pump discharge piping in the right side of the diagram is represented by one single volume tN consisting of half the length of the actual piping and the

('

) equivalent of two plant loop diameters. This is followed by two single volumes in parallel, representing the other half of the discharge piping in length and the equivalent of one plant loop in diameter, respectively. Of these, control volume 190 contains the break (when applicable), represented by the simple junction 950 which leads to the containment control volume 960.

The pressurizer, control volume 500, is modeled by a pipe component and is divided into eight nodes. The surge line, also a pipe component, is divided into two nodes.

The reactor vessel is represented by two lower downcomer annulus volumes, one upper downcomer single volume, one lower plenum single volume, three pipe volumes which include the bypass and the core, four upper plenum volumes, and one uppen head single volume.

The secondary side is represented by five SG shell side pipe volumes, one separator volume, and one steam dome single volume. The turbine bypass valves and the safety valves are connected to the steam dome and lead to the condenser and to the atmosphere, respectively. For the cases simulating manual SG cooling, the steam dome control volume also contains the atmospheric dump valve (ADV) combined with other steam relieving paths (i.e., SG vent lines (SGV), auxiliary feed pump i

f- s turbines (AFP), hogging air ejectors, and main condenser single-jet air ejectors (SJAEs)). The main feedwater (MFW) and (v) l l-2

~

/' auxiliary feedwater (AFW) inject into the SG downcomer, modeled

( ,)N as an annulus divided into two nodes.

1.3 Data and Assumptions The following data and assumptions were used throughout the study unless otherwise so stated in the corresponding section for a particular transient.

o To allow for reacter core trip delay and rod drop time, full rod insertion reactor shutdown occurred at an assumed 4.8 seconds after a reactor trip signal is generated.

o In addition to decay heat, core heat from moderator and fuel reactivity feedback is included for the first 200 seconds af ter reactor shutdown. Decay heat is based on ANS-5.1, 1971 (Reference 2).

o The core heat axial shape is assumed to be skewed toward the top to produce highest clad temperatures in what would be the uncovery region.

o Safety pump flow rates are based on best estimate delivery curves (References 3 and 4).

o Best-estimate pump actuation delay times (from time of f-~g safety injection actuation signal) were used for the low-pressure safety injection (LPSI) pumps, high-pressure (A ) safety injection (HPSI) pumps, and charging pumps, o The HPSI pump flow path is equally distributed among the four actual cold legs. Charging flow is entirely to the cold leg of Loop 2 (Reference 5).

o Main steam flow to the turbine is tripped on reactor trip.

Main steam bypass flow is actuated on reactor trip. There are ten turbine bypass valves which can pass a total of 40 percent of the normal full main steam flow. Eight of these valves are open when T is greater than 545*F.

The other two valves are open"Ihen either T is greater than545*Forasnecessarytomaintaina92$"hsiasteam generator pressure (Reference 3).

o Where appropriate, main feedwater (MFW) is tripped on reactor trip. Auxiliary feedwater (AFW) initiates on either low steam generator (SG) level with an assumed 60-second delay or on a MFW trip with an assumed 30-second delay. AFW is throttled to maintain an appropriate SG level (Reference 6). The AFW is initially delivered to the SG's at the MFW temperature. It reduces to the DWST water temperature (90*F) after a total of 66,800 pounds have been swept out of the delivery lines (Reference 3).

O m

1-3

y (n)

\- /

o The Terry Turbines (TTs), which power the AW pumps, wer e modeled. They exhaust steam from SGs to atmospheric pressure at a constant rate corresponding to a 450 psig 1T admission flow. The TT steam admission valves are throttled either automatically or by operator action to maintain the admission pressure (Reference 7).

o Unless otherwise stated, the following nominal values were used to describe equipment operation:

Pressurizer Safety Valves (3)

Valve I lift @ 2575 psia (set + 3 itreent (accumulation))

reseat @ 2475 psia (set - 1 percent)

Valve 2 2626.5 psia lift 2514.5 psia rescat Valve 3 2678 psia lift 2574 psia rescat The valve flow area provides 293,300 lb/hr per valve at 2575 psia (References 8 and 9).

SG Safety Valves (4 per SG, 16 total)

Valve I lift @ 1098.5 psia (set + 10 percent accumulation)

/}

Cf rescat @ 1000 psia (set)

Valve 2 1131.5 psia lift 1030 psia rescat Valve 3 1142.5 psia lift 1040 psia rescat Valve 4 1152.4 psia lift 1049 pasa rescat The valve flow area provides 606,756 lb/hr per valve at 1098.5 psia (Reference 10).

Pressurizer PORVs (2)

Lift @ 2285 psia Rescat @ 2265 psia The valve flow area provides 210,000 lb/hr @ 2415 psia per PORV (Reference 3).

In Table 1.1, typical steady state results of a NULAPS calculation are compared to actual plant conditions. The agreement is found to be very good.

O

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1-4

i A TAbtE 1.I

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Plant Initial Conditions NULAPS Values Plant Values Reactor Power, Mwt 1,825 1,825 Pressurizer Pressurizer (PSIA) 2,012.8 2,015 Pressurizer Level (%) 50 50 Steam Generator Level (% Narrow Range) 25 30 Steam Header Pressure (PSIA) 711 700 S*eam/Feedwater Flow (Total, LBS/HR) 7,864,380 7,804,000

'r . 12 cold 584.4 578 T

hot ( F) 561.4 average ( F)

T 555 Primary Coolant Flow (LBS/HR) 105,156,000 106,715,000 SG Recirculation Ratio 25% 25%

Feedwater Temp. ('F) 432 420

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I h 2. STATION BLACK 0UT ANALYSIS b

2.1 Introduction The Station Blackout (SBO) NULAPS model simulated the total loss of all offsite and onsite a-c power while the plant was operating at normal full power. The reactor tripped as a result of the blackout. The scenarios investigated considered both AFW available and unavailable for three different specified initial RCP seal leak rates. The goal of the analysis was to identify the elapsed time when core uncovery begins for each scenario.

2.2 Analytical Model Initial RCP seal leakage flows of 50, 100 and 300 gpm per RCP were investigated for both an AFW available scenario (AFW pumps are driven by the steam driven Terry Turbines, no a-c is needed) and an AFW unavailable scenario. The RCS breach engendered by a leaking RCP seal was modeled as a trip valve to a time dependent volume at atmospheric pressure. Valve areas were established which would result in the desired flows (50, 100 and 300 gpm) at normal plant operating pressure and temperature. The natural result of this method was that seal leakage rates decreased as the RCS depressurized during the transient.

( ,) The Terry Turbines were assumed to pass steam out of the SGs in the AFV unavailable scenario. This resulted in uncovery times that were sooner, but not significantly so, than when this SG mass loss mechanism was excluded from the model.

The model for SB0s was dif ferent f rom the model for the other transients in that it was a single loop model. That is, all four plant SG loops were combined into one loop for the model.

This became necessary to reduce the computer running time that two loop model exhibited. The two loop model's running time became excessive as not only maximum time steps for the code were reduced to obtain more eliable results but also the lower leakage rates took longer transient times to reach uncovery of the core.

The close similarity in results for a one-loop and two-loop run for the same transient scenario indicated the validity of the one-loop model. This reassurance was sought due to the loop seal behavior having a significant effect on core level and the one- and two-loop models having one- and two-loop seals, respectively.

The basic sequence of events for the SB0 model proceeded as

< follows:

The plant was operating at normal full power. The SB0 was initiated and concurrently:

2-1

o RCP seat leakage initiated,

%,-l o RCPs trip off and begin to coastdown, o SG main steam flow and main feedwater flow are isolated, i

1 o SG steam flow to the Terry Turbines begins, o the control rods are released and within 5 seconds core power reduces from full power to decay heat plus feedback.

Af ter an assumed delay of 5 minutes, AW initiates f or the AFW j available scenarios. This is conservative since it would normally be expected that auto AW would be initiated immediately on main feedwater trip. Subsequent t.o these l

initial events, t.he transient proceeds at its own pace with pressurizer safety valves and SG safety valves lifting and rescating as dictated by system preasures. Specifics on system behavior associated with uncovering will be discussed individually for each scenario.

2.3 Discussion of Results

! The results of each of the SB0 scenarios are discussed I separately as follows:

2.3.1 SBO, 300 GPM Leak, AW Unavailable

" This scenario involved a SB0 with an assumed initial

leak flow rate of 300 gpm from each of the four RCPs, with AW unavailable. The elapsed transient time until inititation of core uncovery is approximately 2,700 seconds as seen in Figure 2.1 (SB0 was initiated at time = 40 seconds). .

Beginning of core uncovery corresponds to a collapacd core level - that is the effective height of water surrounding the core as a traction of core height -

l of 70 percent. Seventy to 60 percent represents the point at which the frothy mixture of bubbling wates surrounding the core has a low enough average liquid proportion to etfectively constitute the onset of j core uncovery with its attendent reduction in core i heat removal ability.

The process that led to the uncovery is basically the i following: Af ter t he SB0 has begun, heat is

! transferred from the RCS primary to the SG secondary.

l The SG lowest lift pressure safety valves open to

! relieve the pressure increases in the SG secondary l rauseen by the heat transfer. At 2,400 neconds, the SGs have bolled dry; the SG saietles have Iiited ion the last time at 2,200 seconds. From 2,200 seconds on, the RCS pressure increases from its plateau at 2-2

/O slightly above the SG safety litt pressure

.V (1,098.5 psia) to slightly below the pressurizer safety lift pressure (2,575 psia).

As this high-pressure develops in the region above the core due to boiloff, a pressure difference develops between the steata region bounded by the core liquid level and the liquid la the upside of the SG tubes, and the steam region bounded by the top of the liquid loop seal and the top of the SG tubes. The higher pressure above the core region forces the core liquid level downward as it seeks to equalize the pressure difference. The result is the decrease in core collapsed level at 2700 to 3000 seconds as seen in Figure 2.1. The level recovers somewhat, first at 3100 seconds due to a major draining of the SG liquid (Figure 2.2) which causes core level to increase to match the pressure difference across the unblocked SG upside tubes. The level recovers a second time at 3300 seconds due to the clearing of the loop seal liquid (Figure 2.3) which allows steam flow to relieve pressure from the core region around the SG to the sect lean.

In sununary, a SBO with initial 300 gpm seal leakage per RCP and AFW unavailable results in core uncovery after 2700 seconds (45 minutes) have elapsed.

2.3.2 SBO, 100 GPM Leak, AFV Unavailable This scenario involved a SB0 with an assumed initial leak flow rate of 100 gpm from each of the four RCPs, with AFW unavailable. The elapsed transient time until initiation of core uncovery is approximately 4500 seconds as seen on Figure 2.4 (SB0 was initiated at time = 40 seconds). As with the 300 gpm scenario, beginning of core uncovery corresponds to a collapsed core level of 70 percent. As seen in Figure 2.4, the level recovers to a value above 70 percent alter 450 seconds of uncovery. The core uncovers permanently at 5700 seconds of elapsed time.

Calculations demonstrated that the initial uncovery results in peak clad temperatures below 1300*F.

The process that led to the uncovery is essentially the same as for the 300 gpm scenario except that this transient involved primary discharge through the pressurizer safety valves. In this transient the SGs have boiled dry at 2300 seconds and the SG safety valves have lifted for the last time at 2l00 seconds.

From 2200 seconds on, the HCS pressure increases irom its plateau at slightly above SG safety valve litt pressure to the pressurizer safety valve lift pressure at 4100 seconds. From that point on, 2-3

i

/i primary mass exits via the lowest lif t preseare

\s_,/ safety valve. The pressurizer safety valve lifts daring this transient due to the 100 gpm leak providing less of a pressure relief mechanism than the 300 rpm transient. In the same manner as the 300 gpa transient, the core liquid level is forced down by the pressure differential created by liquid t in the upside of the SG tubes and in the loop seal.

The level recovery at 5000 seconds (Figure 2.4) is the result of the liquid in the tubes and loop seal clearing (Figures 2.5 and 2.6).

In summary, a SB0 with initial 100 spa seal leakage per RCP and AFW unavailable results in initial core uncovery after 4500 seconds (75 minutes) and a second ,

ultimate core uncovery after $700 seconds !

(95 minutes). The initial uncovery results in a clad temperature also less than 1300*F.

2.3.3 SBO, 50 GPM Leak, AFW Unavailable

.9 This scenario involved a SB0 with an assumed initial leak flow rate of 50 gpa from each of the four RCps, with AFW unavailable. The elapsed transient time ,

until initiation of core uncovery is approximately 6000 seconds as seen on Figure 2.7. (SB0 was ,

initiated at time = 40 seconds). As before, '

beginning of core uncovery corresponds to a collapsed level of 70 percent. As seen in Figure 2.7, the level decreases to 70 percent at 4700 seconds; however, the depth and duration of the uncovery below 70 percent is of a small enough magnitude to be considered as less than a true uncovery; i.e. no attendant noteworthy clad temperature excursion. ,

The process that led *,o the recession in level a.

4600 to 5000 seconds is the result of the pressure differential described in the previous SB0 transients and recovery at 5000 seconds is seen to coincide wit h SG upside tube clearance (Figure 2.8). The SGs boil dry by 2300 seconds, the SG safety valves have lifted j for the last time at 2100 seconds, and from 2l00 seconds on, the RCS pressure rises from slightly "

above SG safety valve lift pressure to the pressurizer safety valve lift pressure at 3800 seconds. As with the 100 gpm transient, the ;

primary mass exits via the safety valve for the duration of the event. As seen in Figure 2.7, some level recovery movements in the 5400 to 5900 second ;

range correspond to liquid expulsion from the loop !

seal region (Figure 2.9). By 6000 seconds, enough !

mass has escaped the primary via the RCP seals and the pressurizer safeties to cause a permanent uncovery. l m

t 2-4

a

()

(_,,I In summary, a SB0 with initial 50 gpm seal Acakage per RCP and AFW unavailable results in core uncovery after 6000 seconds (100 minutes) have elapsed.

2.3.4 SBO, 300 CPM Leak, AFW Available This scenario involved a SB0 with an assumed initial leak flow rate of 300 gpa from each RCP, with AFW available. The elapsed transient time until initiation of core uncovery is approximately 3200 seconds as shown in Figure 2.10 (SB0 was initiated at time = 40 seconds). As before, the beginning of core uncovery corresponds to a collapsed level of 70 percent.

The essential difference between this scenario and l the three previous is the availability of AFW. The effect of the availability of AFW is that the SG is maintained as a heat sink throughout the transient.

Primary system pressure, as a result, remains l

essentially at the SG safety valve lowest lift l

pressure and the seal leak rate is, therefore, lower than that for the corresponding scenario with AFW unavailable. As with the previous transients, uncovery initiates due to the pressure differential set up by the liquid in the loop seal and SG upside l g- g tubes. Level recovery from 5600 to 6100 seconds

(Figure 2.10) can be seen to correspond to clearance g

'- ) of the liquid in the SG tubes between the hot legs and "U-bend" region (Figures 2.11) and loop seal (Figure 2.12).

l in summary, a SB0 with initial 300 gpm seal leakage per RCP and AFW available results in core uncovery after 3200 seconds (53 minutes) have elapsed.

2.3.5 SBO, 100 GPM Leak, AFW Available This scenario involved a SB0 with an assumed initial leak flow rate of 100 gpm from each RCP, with AFV available. The elapsed transient time until initiation of core uncovery is approximately 10,000 seconds as seen in Figure 2.13 (SB0 was initiated at time = 40 seconds). As before, the beginning of core uncovery corresponds to a collapsed level of 70 percent.

l The pattern of this transient is esser.tially the same l

as the previous one. The SG is maintained as a heat l

sink throughout the transient and primary pressure

' remains near the SG safety valves inwest lift pressure. Uncovery initiates due to the pressure differential set up by the liquid in the loop seal O and SG upside tubes. Level recoveries (Figure 2.11) 2-5

i due to the SG upside tubes clearing (Figure 2.14) can

/] be seen at 12800, 15800 and 18700 seconds. By

(_j 18700 seconds, a significant portion of the loop seal has cleared (Figure 2.15).

In summary, a SB0 with initial 100 gpm seal leakage per RCP and AFW available results in core uncovery after 10,000 seconds (167 minutes) have elapsed.

2.3.6 SBO, 50 GPM Leak, AFW Available This scenario involved a SB0 with au assumed initial leak flow rate of 50 gpm from each RCP, with AFW available. The elapsed transient time until initiation of core uncovery is approximately 23,700 seconds as shown in Figure 2.16 (SB0 was initiated at time = 40 seconds). As previously, the beginning of core uncovery corresponds to a collapsed level of 70 percent. Prior to 23700 seconds core uncovery has not been reached and maintained for a time span sufficient to be considered uncovery. Even for the uncovery period shown in Figure 2.16, f rom 23,700 to 28,700 seconds, clad temperature remains below 1000*F. The core level response is due to the SG upside tube liquid drainage as seen in Figure 2.17. Significant clearance of the loop seal f-~g does not occur during this transient (for the time

( ) investigated); however, instances of steam voiding in the loop's lowest pipe section were observed indicating the possibility that some steam escaped around the loop seal during this transient.

In summary, a SB0 with initial 50 gpm seal leakage per RCP and AFW available results in core uncovery af ter 23,700 seconds (395 minutes, 6.58 hours6.712963e-4 days 0.0161 hours 9.589947e-5 weeks 2.2069e-5 months ) have elapsed. Gross fuel damage would not be expected prior to 28,700 seconds (8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months ).

2.4 Summary A summary of the core uncovery times for the six SB0 scenarios is provided in Table 2.1. As shown in Table 2.1 the results are very dependent on the availability of Auxiliary Feedwater as well as the assumed initial RCP seal leak rate.

l l

2-6 l

TABLE 2.I Summary of Sy tion Blackout Core Uncovery Times 300 gpm/RCP 100 spe/RCP 50 gpm/RCP Initial __ _. Initial Initial AFW 45 minutes 75* minutes 100 minutes Unavailable 95 minutes AFW 53 minutes 167 minutes 395 minutes Available (2.8 hrs.) (6.58 hours6.712963e-4 days 0.0161 hours 9.589947e-5 weeks 2.2069e-5 months )

clad temp. remains (1300*F l

i

[

2-7

O FIGURE 2.1 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACK 0U r 300 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER UNAVAILABLE COLLAPSED CORE LEVEL 1.0-0.9i

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i FIGURE 2.2 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT .

300 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER UNAVAILABLE SG UPWARD TUBES TOTAL MASS i

30000-275002 h i l 250002 5 i ,l U 22500i j O D20000j T

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i tO FIGURE 2.3 i

HADDAM NECK- PLANT SMALL BREAK ANALYSIS 4 STATION BLACKOUT 300 GPM/RCP INITIAL LEAKAGE .

4 AUX FEEDWATER UNAVAILABLE LOOP SEAL TOTAL MASS ;

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O FIGURE 2.4 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT

100 GPM/RCP INITIAL LEAKAGE

' AUX FEEDWATER UNAVAILABLE COLLAPSED CORE LEVEL 1

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FIGURE 2.5 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 100 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER UNAVAILABLE SG UPWARD TUBES TOTAL MASS 30000; 27s00i 25000i u 22soci 20000i

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FIGURE 2.6 l HADDAM NECK PLANT SMALL BREAK ANALYSIS :

i STATION BLACKOUT :

i 100 GPM/RCP INITIAL LEAKAGE (

! AUX FEEDWATER UNAVAILABLE !

i LOOP SEAL TOTAL MASS I l i

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O FIGURE 2.7 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 50 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER UNAVAILABLE COLLAPSED CORE LEVEL 1.0; t g d

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O FIGURE 2.8 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 50 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER UNAVAILABLE SG UPWARD TUBES TOTAL MASS 30000-27500i 2tC00i G

U 22500i w

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FIGURE 2.9 j HADDAM NECK PLANT SMALL BREAK ANALYSIS 4 STATION BLACKOUT i

50 GPM/RCP INITIAL LEAKAGE j i AUX FEEDWATER UNAVAILABLE

! LOOP SEAL TOTAL MASS ,

i I l 50000-I j- 47500 c. . l 450002 I

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O FIGURE 2.10 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 300 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER AVAILABLE COLLAPSED CORE LEVEL 1.0-0.9i ,,

,, , j ,

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O FIGURE 2.11 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 300 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER AVAILABLE i SG UPWARD TUBES TOTAL MASS 30000-275002 250005 l 225002 R 200002 7 .

17500-E j 15000}

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i FIGURE 2.12 HADDAM NECK PLANT SMALL BREAK ANALYSIS ,

STATION BLACKOUT 300 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER AVAILABLE LOOP SEAL TOTAL MASS 4

6 il 47500i I

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1 FIGURE 2.13 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 100 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER AVAILABLE COLLAPSED CORE LEVEL 1.0- g_

bi c"

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O 2-20

O FIGURE 2.14 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 100 GPM/RCF INITIAL LEAKAGE AUX FEEDWATER AVAILABLE SG UPWARD TUBES TOTAL MASS 30000 2750Ci 25000 \

3 5 22500 d' U

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1 l

O i FIGURE 2.15 l HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 100 GPM/RCP INITIAL LEAKAGE !

AUX FEEDWATER AVAILABLE j LOOP SEAL TOTAL MASS 48000i I ]

46000;,

U M 44000 l

L 420002 O

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' 0 2000 4000 0000 8000 10000 12000 14000 16000 18000 2C000 TIME (SEC) i 2-22 -

m b

FIGURE 2.16 HADDAM NECK PLANT SMALL BREAK ANALYSIS STATION BLACKOUT 50 GPM/RCP INITIAL LEAKAGE AUX FEEDWATER AVAILABLE COLLAPSED CORE LEVEL 1.00-0.952 i t , It if f R 0.85-A C.eC- '

O ! O.75-I g 0.70g l I

5 0.EE i

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[ ) 3. INCORE INSTRUMENT TURE RUPTURE ANAL.YSIS V

3.1 Int roduction The Incore Instrument Tube Rupture (IITR) NULAPS model simulated the simultaneous rupture of four incore instrument tubes while the plant was operating at normal full power. The IITR transients assumed the failure of four tubes and that offsite power remained available. The scenarios investigated were for one charging pump only available, and for one high-pressure safety injection (llPSI) pump only available.

Both of these scenarios were investigated for a) RCPs tripped after low pressurizer pressure (1715 psia) and b) RCPs running.

The goal of the analysis was to identify the adequacy of the specified equipment to prevent core uncovery.

3.2 An.yl_ytical Model The RCS breach investigated in this analysis consisted of a rupture in the bottom of the reactor vessel (RV) equivalent in size to four incore instrument tubes. Each tube has a maximum inside diameter of 0.375 inches (Reference 11). The break path was modeled as a trip valve to a time dependent valve at atmospheric pressure.

The model for the IITRs consisted of a one/three two loop f'~' model. That is, the model consisted of two loops, one

(",g/ representing one the single loop and the other representing three combined loops. The one/three configuration was used (rather than a symmetrical two/two combination) since that was the model configuration that was needed for the Steam Generator Tube Rupture transient and a separate model for the IITR was unnecessary.

The basic sequence of events for the IITR model proceeded as follows:

o The plant was operating at normal full power and the IITP initiated; o Pressurizer pressure reduced to 1715 psia - the reactor trip signal setpoint and safety injection actuation (SIA) setpoint; o RCPs trip of f and begin to coast down (for RCPs tripped scenarios);

o SG main steam flow is redirected from turbine to bypass -

valves; o Main feedwater flow is isolated; ps o The control rods are released and within 5 seconds core g i power reduces from full power to decay heat plus feedback;

\~s) 3-1

/~~N o F.ither llPSI pump flow (af ter a 20-second delay) or

,h charging pump flow (af ter a 30-second delay) is assumed.

o AFW flow to the SGs and SG steam flow to the Terry Turbines (TTs) begins after a delay of 30 seconds.

For the charging flow scenarios, the charging flow is increased to the delivery associated with valve 110A fully open af ter a delay of 5 minutes. Subsequent to these initial events, the transient proceeds at its own pace with the SG sately valves lifting and reseating as dictated by system pressures. AFW flow and Main Steam flow is controlled as described in Section 1.3. Specifics on system behavior will be discussed individually for each IITR scenario.

3.3 Discussion of Results For each of the four llTR scenarios in which HPSI pamp flow and charging pump flow are individually credited (for the cases with and without RCP trip), no core uncovery occurred throughout the t rans ient . The results of each of the scenanim are discussed separately as follows:

3.3.1 IITR, I HPSI Pump Available, RCPs Tripped This scenario involved an llTR with only one llPSI

,- s pump available and all four RCPs tripped at 1715 psia

( i pressurizer pressure. For the duration of this N- / transient, which was run out to 6000 seconds, no core uncovery occurs. This analysis also indicated that uncovery would not occur at times greater than 6000 seconds. The collapsed core level never decreased below the top of the core.

By 5000 seconds (IITR initiates at time =

50 seconds), RCS pressure has decreased to a plateau slightly above 1300 psia as shown in pressurizer pressure response of Figure 3.1. This plateau represents an equilibrium condition of decay heat removal via the SGs and cold IIPSI flow matching the l break flow. As seen in Figure 3.2, the mass flow into the RCS via llPSI slightly exceeds the break mass flow rate which allows an equilibrium condition or better to be maintained in the RCS. This assures that covery of the core can be maintained thereaf ter.

Figure 3.3 shows the integrated flow rates and further illustrates that the llPSI pumps can accommodate the leak flow during this transient. The primary heat removal vehicles are the SGs which are cooled via AFW and steam flow to the decay heat removal header. The SG safety valves never lift.

Figure 3.3 shows the integrated flow for the llPSI l pump. By 6000 seconds, approximately 51,000 gallons

/7 will have been delivered by the llPSI pump. Thus the

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'O equilibrium condition of a covered core can be maintained for this transient scenario of four ruptured incore instrument tubes wit!t only i IIPSI pump available with steam generator Icedwater and t he RCPs tripped at 1715 psia.

3.3.2 IITR, I HPSI Pump Available, RCPs Not Tripped The preceding scenario was examined for the case where all four RCPs remain running throughout the transient. The results are essentially the same as for the RCPs tripped case. The equilibrium condition of a covered core can be maintained for this transient scenario of four ruptured incore instrument tubes with only one HPSI pump available and the RCPs running.

3.3.3 IITR, 1 Charging Pump Available, RCPs Tripped This scenario involved an IITR with only one charging pump available (and valve 110A open, valve 110 closed) and all four RCPs t ripped at 1715 psia. For the duration of this transient, which was executed to 10,000 seconds, no core uncovery occurs. This analysis also indicated that uncovery would not occur at times greater than 10,000 seconds. The collapsed s

core level never receeded below the top of the core.

F

] By 3000 seconds (IITR initiates at time =

50 seconds), RCS pressure has decreased to a plateau of 1000 to 1100 psia as shown in Figure 2.4. This plateau represents an equilibrium condition of decay heat removal via the SGs and cold charging flow making up the RCS rupture flow. As seen in Figure 2.5, mass flow into the RCS via the charging pump eventually exceeds the break mass flow rate which allows the RCS inventory to be maintained in the RCS. This assures that covery of the core can be maintained at times after 10,000 seconds. The primary heat removal mechanisms are the SGs which are cooled via AFW and steam flow to the decay heat removal header. The SG safety valves never lift. By 10,000 seconds approximately 42,000 gallons will have been delivered by the charging pump. Thus, the equilibrium condition of a covered core can be maintained for this transient scenario of four ruptured incore instrument tubes with only one charging pump available (and valve 110A only), steam generator feedwater and the RCPs tripped at 1715 psia.

A U

3-3

3.3.4 IITR,_i Chargi_ng Pump Available, RCPs Not Tr_ipped (m _

The preceding scenario was examincel f or t he cane where 'all four RCPs remain running throughout the transient. Most of the results are the same as the RCPs tripped case. For this case, the RCS upper head is refilled much sooner (at about 5000 seconds), as would be expected from having RCP flow to the reactor vessel. Thus, the equilibrium condition of a covered core can be snaintained for this transient scenario of four ruptured incore instrument tubes with only one charging pump available (and valve 110A only), steam generator feedwater, and the RCPs running.

3.4 Summary A number of !!TR scenarios were investigated to determine the adeepsary of o se ilPSI pump or one charging pump, with or wit hout RCP trip. The results indicate that core uncovery would not occur for up to four ruptured incore instrument tubes it one llPSI pump or one charging pump is available, steam generator lecilwater is provided, and there is adequate RWST inventory until switchover to recirculation is performed. The results are not affected by RCP operation.

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7 4. STEAM GENERATOR TUBE RUPTURE ANALYSIS i

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w- 4.1 Introduction The Steam Generator Tube Rupture (SGTR) NULAPS model simulated the simultaneous double ended rupture of five SG tubes while the plant was operating at normal full power. The rupture assumed was the equivalent of a 2-inch diameter break and offsite power remained available.

Since the SG tubes have an inside diameter of 0.64 inches (Reference 8), a double-ended guillotine rupture of five tubes corresponds to an area of .002234 ft2 . The scenarios investigated were a) only one charging pump available and b) only one HPSI pump available. Both of these scenarios were investigated for the RCPs tripped after a low pressurizer pressure of 1715 psia while the RCPs remained operating. Also investigated was the scenario of no injection flow to the RCS with the RCPs tripped. For all scenarios, SG cooling is supplied by AFW. The goal of the analysis was to identify the adequacy of the specified equipment to prevent core uncovery.

For the no RCS injection scenario, the goal was to identify the time available to establish feed and bleed cooling and the time available to isolate the faulted SG.

4.2 Analytical Model

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The SG tube rupture investigated in this analysis was the double-ended rupture of five tubes. The rupture was chosen to be on the primary flow discharge end where the tubes connect at the exit of the SG's near the tube sheet. This will typically result in the largest flow rates from primary to secondary due to the greater density of the primary in the coldest region of the tubes. The rupture was modeled as two trip valves, one from the downward tube direction and one from the tube sheet, each connecting to the bottom of the SG *iser section on the secondary side. Each trip valve had an arma of 0.01117 ft.2 which corresponds to five 0.64-inch diameters. The intact tubes where modeled as a piping run parallel to and separate from the piping run representing the tubes which become ruptured.

The RCS model for SGTRs was a one/three two loop model as previously mentioned in the IITR discussion (Section 3). The model consisted of two loops, one representing one actual SG/RCP loop (the faulted SG) and the other representing three combined SG/RCP loops.

The basic sequence of events for the SGTR model proceeded as follows:

e The plant was operating at normal full power and the SGTR initiated;

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\s_f o Pressurizer pressure receeds to 1715 psia, the reactor trip signal setpoint and safety injection actuation signal (SIAS) setpoint; o RCPs are tripped and begin to coast down (for RCPs tripped scenarios);

o SG main steam flow is redirected from turbine to bypass valves; o Main Feedwater flow is isolated; o The control rods are inserted and within 5 secords core power reduces from full power to decay heat plus feedback; o Either HPSI pump flow, af ter a 20-second delay, or charging pump flow, after a 30-second delay, is initiated; o AFW flow to the SGs and SG steam flow to the Terry Turbines (TTs) begins after a delay of 30 seconds.

For the charging flow scenarios, the charging flow is increased to the delivery associated with valve 110A fully open af ter an arbitrary delay of 5 minutes. Subsequent to these initial events, the transient proceeds with the SG safety valves lifting and reseating as dictated by system pressures. AFW g "g flow and Main Steam flow ia controlled as described in g ) Section 1.3. At an assumed delay time of two minutes after the SIAS has been generated (1715 psia pressurizer pressure), flow from the ruptured SG to the turbine steam bypass valves and terry turbines is isolated as required by the Emergency Operating Procedures of Reference 6. The two-minute assumption is reasonable since operators have stated that the faulted generator would be immediately identifiable based on feedwater regulation valve position indication. Specifics on system behavior will be discussed individually for each SGTR scenario.

4.3 Discussion of Results For each of the four SGTR scenarios with injection to the RCS (HPSI pump flow only and charging pump flow only, both with and without RCP trip), and also for the SGTR scenario with no injection, no core uncovery occurs throughout any of the transients. The results of the scenarios are discussed separately below:

4.3.1 SGTR, I HPSI Pump Available, RCPs Tripped This scenario involved a SGTR (5 tubes) with only one HPSI pump available and all four RCPs tripped at 1715 psia pressurizer pressure. For the duration of this transient, which was run out to 3000 seconds, no core uncovery occurs. The collapsed core level never recceded below the top of the core. It was further

(

4-2

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[~'} ' indicated by this analysis that uncovery will not occur at times greater than 3000 seconds. By about 1100 seconds (SGTR initiates at time = 50 seconds),

RCS pressure decreases to a plateau at about 1160 psia (Figure 4.1). This plateau represents an equilibrium condition of decay heat removal via the intact SGs and cold HPSI flow makeup of the hot RCS fluid lost to the faulted SG. The RCS remains filled with liquid except for the pressurizer while the break flow is matched by the injection as shown in Figure 4.2 which presents integrated rupture and IIPSI flows.

The prime heat removal mechanisms are the intact SGs which are cooled via AFW and steam flow to the decay heat removal header. The safety valves on the intact SGs never lift. The faulted SG, in which the main steam line and decay heat removal line have been manually isolated at time = 220 seconds (170 seconds into transient) completely fills at about time =

700 seconds. For the duration of the event, the faulted SG's safety valve with the lowest lift pressure continuously cycles or remains at the partial open position. Figure 4.3 shows the total flow emitted from the valve. At these steady state conditions including an llPSI pump flow of 1230 gpm, the RWST inventory which consists of 250,000 gallons

(-'s as per Reference 8, will be depleted by 200 minutes into the transient.

In summary, a SGTR (5 tubes) with only one HPSI pump available, steam generator feedwater, all RCPs tripped at 1715 psia results in no core uncovery.

4.3.2 SGTR, 1 IIPSI Pump Available, RCPs Not Tripped The preceding scenario was examined for the case where all four RCPs remain running throughout the transient. The results are essentially the same as the RCPs tripped case.

The equilibrium condition of a covered core can be maintained for this transient scenario of five ruptured SG tubes with only one llPSI pump available, steam generator feedwater and the RCPs not tripped.

4.3.3 SGTR, 1 Charging Pump Available, RCPs Tripped This scenario involved a SGTR (5 tubes) with only one charging pump available (and valve 110A open, valve 110 closed) and all four RCPs tripped off at 1715 psia pressurizer pressure. For the duration of this transient, which was run out to 5000 seconds, no core uncovery occurs. The collapsed core level

( )

4-3

[ j essentially never varies from the top of the rose

(/ It was further demonstrated by this analysis that uncovery will not occur at times greater than 5000 seconds.

By about 3000 seconds (SGTR initiates at time =

50 seconds), RCS pressure has stabilized at a plateau at about 1080 psia as shown in Figure 4.4. By 3000 seconds, the upper head has refilled except for the remaining upper 83 ft 3which is separated from the remainder of the vessel by a significant hydraulic resistance. This volume refills however by 4000 seconds. This plateau represents an equilibrium condition of decay heat removal via the intact SGs and cold HPSI flow makeup of hot RCS water lost to the faulted SG. Mass flow out of the primary side of the RCS is essentially matched by the charging flow from 3000 seconds on as can be seen in Figure 4.5 which shows integrated rupture flow versus integrated charging flow.

The primary heat removal mechanisms are the intact SGs which are cooled via AFV and steam flow to the decay heat removal header. The safety valves on the intact SGs never lift. The faulted SG, which has its main steam line and decay heat removal line manually S isolated at time = 220 seconds (170 seconds into the

((

l transient), completely refills with liquid at about 1850 seconds. From the time the RV upper head essentially refills causing a pressure increase, the faulted SG's safety valve with the lowest lift pressure continuously cycles. Figure 4.6 shows the total flow emitted from the valve. At the above quasi-steady state condition including a charging pump flow of 252 gpm, the RWST inventory (with a capacity of 250,000 gal. given in Reference 8) will be depleted by 980 minutes (16.3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months ) into the transient.

In surunary, a SGTR (5 tubes) with only one charging pump available (and valve 110A only), steam generator feedwater, all RCPs tripped at 1715 psia results in no core uncovery.

4.3.4 SGTR, 1 Charging Pump Available, RCPs Not Trippeg The preceding scenario was examined for the case where all four RCPs remain running throughout the transient. The results presented in this section are essentially the same as that for conditions with the RCPs tripped. The RWST will be depleted by 1100 minutes into the transient. The core can be maintained in a covered condition for this transient

[h scenario of five ruptured SG tubes with only one 4-4

( charging pump available (and valve 110A only), steam

\- generator feedwater and the RCPs not tripped.

4.3.5 SGTR, No Injection Flow This scenario was an investigation of a SGTR (5 tubes) with no injection flow to the RCS and all four RCPs tripped at 1715 psia. As a conservatism that was appropriate for this scenario, the low setpoint safety valve for the faulted SG was modeled as lifting to full open at 990.15 psia and rescating at 955.5 psia. These conditions correspond to a litt pressure equal to set pressure minus 1.0 percent and a rescat pressure equal to lift pressure minus 3.5 percent, respectively. For the duration of this transient, which was executed to 5000 seconds, no core uncovery occurs. The collapsed core level never receeds lower than .87 of the total core height (Figure 4.7) and as discussed under the SB0 (Section 2), this constitutes a covered core. It was further indicated by this analysis that uncovery will not occur at times greater than 5000 seconds. By about 1500 seconds (SGTR initiates at time =

50 seconds), RCS pressure has decreased to a plateau below 1000 psia (Figure 4.8). This plateau represents an equilibrium condition wherein decay heat removal via the intact SGs and the leak flow

((},j maintain a stable system temperature and pressure.

This cooling capability is sufficient to maintain pressure (after the RCS pressure plateau has been established) in the faulted SG at a lower level than the lift pressure of the lowest lift pressure safety valve in the faulted SG (Figure 4.9). With this condition and the fact that the faulted SG exit flow paths have been isolated earlier in the transient, the mass in the RCS/ faulted SG remains stable and core covery is maintained.

4.3.6 SGTR, Additional Cases Related to Stuck-Open SG Safety Valve and Nonisolation of Faulted SG Some additional SGTR scenarios were investigated to determine available times for operator action. The results for these scenarios are as follows:

1) 1 Tube Ruptured, SG Safety Valve Sticks Open Upon Initial Lift For this scenario in which injection flow was supplied by one HPSI pump and the RCPs were tripped at 1715 psia, the core does not uncover.

The RWST inventory of 250,000 gal. is depleted f-'St 388 minutes into the transient.

4-5

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2) 5 Tubes Ruptured, SG Safety Valve

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\,, Sticks Open Upon Initial Lift For this scenario in which injection flow was supplied by one HPSI pump and the RCPs were tripped off at 1715 psia, the core does not uncover. The RWST inventory of 250,000 gal, is depleted 120 minutes into the transient.

3) 1 Tube Ruptured, Faulted SG Is Not Isolated e

In this scenario, flow from the ruptured SG to the turbine bypass valves and terry turbines is not isolated. For this scenario in which injection flow was supplied by one HPSI pump and

, the RCPs were tripped off at 1715 psia, the core does not uncover. The RWST inventory of .

250,000 gal. is depleted 580 minutes into the transient.

,. 4) 5 Tubes Ruptured, Faulted SG Is Not Isolated j In this scenario, flow from the ruptured SG to the turbine bypass valves and terry turbines is not isolated. For this scenario in which injection flow was supplied by one HPSI pump and the RCPs were tripped at 1715 psia, the core >

does not uncover. The RWST inventory of 250,000 gal. is depleted 200 minutes into the

transient.

^

5) 5 Tubes Ruptures, Faulted SG Isolation Delayed In this scenario there was no injection flow to the RCS, the manual isolation (hypass valves !

line and terry turbines line) of the faulted SG was delayed until 45 minutes after SIAS generation, and the RCPs were tripped at 1715 psia. For this scenario, the core also does not uncover. Primary heat removal from the RCS via the intact SGs is sufficient to maiutain RCS pressure below 1000 psia after the faulted SG is isolated and therefore t!.e faulted SG (lowest lift pressure) safety valve does not ,

lift throughout the transient.

! 4.4 Summa ry Several of the SGTR scenarios were investigated to determine 3

the adequacy of I HPSI pump or 1 charging pump, with or without 1

RCP trip. The effects of no safety injection, a stuck open SG safety, and nonisolation of faulted SG were also determined.

Core uncovery would not occur for up to five failed tubes if

I HPSI pump or 1 charging pump is available, and there is L

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FIGURE 4.6 HADDAM NECK PLANT SMALL BREAK ANALYSIS SG TUBE RUPTURE RCP TRIP AT 1715 PSIA 1 CHARGING PUMP AVAILABLE (VALVE 110A ONLY)

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O FIGURE 4.7 HADDAM NECK PLANT SMALL BREAK ANALYSIS SG TUBE RUPTURE RCP TRIP AT 1715 PSIA HPSI AND CHARGING PUMPS UNAVAILABLE COLLAPSED CORE LEVEL 1.00-0.992 i

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HADDAM NECK PLANT SMALL BREAK ANALYSIS

' SG TUBE RUPTURE

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5. LARGE BREAK LOCA ANALYSIS 5.1 Introduction

.The Large Break LOCA (LBLOCA) NULAPS model simulated a double ended guillotine rupture of a cold leg discharge pipe while the ,

I plant was operating at normal full power. Of fsite power was 1 assumed to remain available. Two scenarios were investigated:

1) one low-pressure safety injection (LPSI) pump only available, and 2) one LPSI pump at only 60 percent delivery to simulate the failure of one core deluge valve. The goal of the analysis was to identify the adequacy of the LPSI pumps in mitigating the consequences of a LBLOCA.

5.2 Analytical Model The break was modeled as two trip valves, one from each end of the broken pipe, with each trip valve connected to a time dependent volume which modeled an assumed containment pressure of 30 psia. At the time of the break (time r 50 seconds), a

! t rip valve connecting the two ends of the broken pipe was '

closed and the two trip valves to the containacnt were opened

{< thus establishing the break and preventing communication t hetween the broken ends of the pipe.

To simulate the core's reaction to the immediate voiding of the LBLOCA, the reactor trip delay and decay curve used in the other transients was replaced with a normalized core power curve based on the nominal of the ANS 1971 Standard for Decay

, Energy. Normalized core power is shown in Figure 5.6.

The RCS model for LBLOCA was a one/three two loop model as previously mentioned in the IITR discussion (Section 3). The model consisted of two loops, one representing a single loop

! (the broken cold leg) and the other representative of the remaining three combined loops.

. Upper head injection with the LPSI pump was modeled by a time dependent junction representing one LPSI pump delivery curve 3

connected to an upper head volume containing the RV stand pipes.

The basic sequence of events for the LBLOCA model proceeded as follows:

o The plant was operating at normal full power. The LBLOCA is initiated; o Pressurizer pressure decreases to 1715 psia, the safety injection actuation signal (SIAS) setpoint; o SG main steam flow is redirected from the turbine to the bypass valves; I

i j

5-1

(

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

( h o Main Feedwater flow is isolated; o The LPSI pump is activitated after a 5 second delay; o Af ter a 52-second delay, the RCPs are tripped.

Though not a significant factor, AFW flow and Hain Steam flow is controlled as described in Section 1.3. Specifics on system behavior will be discussed individually for each LBLOCA scenario.

5.3 Discussion of Results 5.3.1 LBLOCA, 1 LPSI Pump Available This scenario was an investigation of a LBLOCA with only one LPSI pump available. The peak clad temperature for this transient which was computed to 400 seconds into the event (LBLOCA initiated at time = 50 seconds) was determined to be 1180*F as shown in Figure 5.1. The peak temperature occurred during the 250- to 300-second time period or during the reflood portion of the event.

The transient and its associated clad temperature response (Figure 5.1) proceeded as follows:

/N (j I The break occured at time = 50 seconds and clad temperature quickly increased to 1075*F in response to the immediate RCS pressure drop and core coolant i voiding (Figures 5.2 and 5.3). As the blowdown proceeds, which lasts about 25 seconds, the voiding of the core causes reactor power to drop to less than eight percent in one second causing the clad temperature to reduce to 900'F. At this point, the blowdown has reduced the core iIow suf f scient ly to again initiate clad heatup. This low core flow as illust. rated during the 58 to 85 seconds period shown in Figure 5.4.

At 95 seconds the RV lower plenum empties through the core and out the break. This mass flow briefly cools the core resulting in a clad temperature below 750 F.

Following this mass flow period, there is again relatively little or no flow in or out of the core region and the temperature v.:reases to 1150 F at 165 seconds.

The LPSI pump is actuated to its full flow speed at 59.4 seconds. Then, at 70 seconds, LPSI pump delivery to the RV upper hea i region commences because the RCS pressure has decreased below the I.PS I shut off head of 330 psia. Flow downward to the core region, however, is momentarily held up until 5-2

h V

sufficient water has accumulated in the upper plenum to permit. liquid down flow to the core at 165 serenota (Figure 5.4). This flow persists until the temperature increase in the core is terminated altes 270 seconds. The RV lower plenum is also being refilled during this period.

At later times (325 seconds and greater), the clad temperature continues to decrease as heat is transferred to the injected liquid entering the core region.

In summary, a LBLOCA (1.0 x DEG/PD) with only one LPSI pump available is able to limit peak clad temperature to 1180 F.

This result. is consistent with the peak clad temperature result of 1238*F from the COBRA / TRAC large break LOCA simulation for CY performed by Battelle Northwest Laboratories (Reference 17). This detailed analysis was also performed utilizing Appendix K assumptions as opposed to the best estimate approach contained herein.

It is important to note that the NULAPS has limited capabilities regarding modeling of the thermal and

/"'Sg hydraulic phenomena following the reflood phase of a i

g_,/ large break LOCA. However, regarding the core average clad temperature response and core average or

" global" conditions, the NULAPS code result, overall, displays a consistency with the more detailed COBRA / TRAC methodology. The similarity between the l two results supports the conclusion that there is a significant margin inherent in the LPSI system for

! mitigating the consequences of the large break LOCAs 5.3.2 LBLOCA, 60 Percent Flow From 1 LPSI Pump i

This scenario was an inve .igation of a LBOCA with only 60 percent of one irSI pump available. Sixty percent of the delivery curve of one LPSI pump simulated delivery for one LPSI pump with one of two core deluge valves failed closed. The peak clad temperature for this transient which was run out to 375 seconds (LBLOCA initiated at time = 50 seconds) was 1500 F (Figure 5.5). The peak clad temperature peaked at about 245 seconds into the event.

The behavior of the transient. and its associated clad temperature response (Figure 5.5) essentially followed that of the 1 LPSI pump scenario.

U 5-3

[ -

Because of the lower flow rates for this scenario,

(- LPSI flow penetration to the core region occurred later in this transient in that the injection flow did not enter the core until about 245 seconds, versus 165 seconds for the previous scenario. This delay in liquid penetration is due to the lower LPSI flow rate which resulted in an extended period of time to accumulate suf ficient water in the upper plenum to permit liquid down flow. The delay in LPSI down flow results in the clad temperature increasing to the peak value of 1500*F.

At times later than 250 seconds, the temperature decreases in the same manner as the previous scenario as liquid continues to enter the core region af ter the lower plenum has been refilled, in summary, a LBLOCA (1.0 x DEG/PD) with only one LPSIP available and one core deluge valve failed closed results in a peak clad temperature of 1500*F.

5.4 Summary For both of the LBLOCA scenarios (one LPSI pump only; 60 percent flow from one LPSI pump), significant fuel failure is precluded. The respective peak clad temperatures were

/ calculated to be ll80*F and 1500*F. These calculations

's]e indicate that only one LPSI pump delivering flow to the reactor vessel through only one core deluge valve is adequate to mitigate the consequences of the most limiting large break LOCA's. These calculations are further supported by analyser of this break using the more detailed COBRA / TRAC transient thermal hydraulic blowdown code discussed in Reference 17.

O G

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FIGURE 5.1 t HADDAM NECK PLANT LARGE BREAK ANALYSIS !

DOUBLE ENDED DISCHARGE LEG BREAK 1 LPSI PUMP ONLY '

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FIGURE 5.6 HADDAM NECK PLANT LARGE BREAK ANALYSIS NORMALIZED CORE P0hT.R Time After LOCA Initiated, Seconds Relative Power d

0.0 1.0 0.2 1.0 0.415 0.1666 1.0 0.0731 2.0 0.0682 4.0 0.0632 6.0 0.0613 8.0 0.0592 10.0 0.0580 20.0 0.0530 40.0 0.0475 60.0 0.0444 80.0 0.0425 100.0 0.0410 200.0 0.0353 400.0 0.0311 !

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6. SMALL AND MEDIUM BREAK LOCA ANALYSIS 6.1 Introduction A small and medium break loss of coolant accident (LOCA) study has been conducted to determine the minimum amount of equipment, coupled with other multiple equipment failures, necessary to maintain the core cooled following a LOCA, or to establish core coolability after core uncovery in a timely manner so as to minimize fuel cladding failure. A wide range of break sizes at the cold leg discharge were analyzed, as this break location yields the most limiting conditions in terms of peak clad temperature. The range of break sizes analyzed includes break sizes of 0.2 fta and smaller. For the purpose of the analysis and discussion, this spectrum of breaks is divided into three categories which include:

1. Medium breaks with areas 0.2 fta to 0.02 ftz,

2. Medium-small breaks with areas 0.02 fta to 0.003 ft2

3. Small breaks with areas 0.003 fta and smaller.

In addition to the above described breaks, a consequential PORV LOCA and a Reactor Coolant Pump (RCP) Seal Failure LOCA were analyzed. The use of an operator initiated Steam Generator

(

(SG) cooldown has also been considered at the Emergency Operating Procedures limit of 100*F/ hour in the event of the assumed unavailability of the HPSI and charging pumps. For small break scenarios involving the unavailability of the !! PSI pumps and SG feedwater systems, feed and bleed was modeleo via manually starting one charging pump and opening one pressurizer Power Operated Relief Valve (PORV).

The discussion below presents a description of the analytical model followed by a presentation of the three small break categories, the PORV initiated LOCA, and RCP Seal Failure LOCA.

6.2 Analytical Model The base analytical model described in Section 1.2 was used in this investigation. For those cases where feed and bleed cooling was considered, the two pressurizer PORVs were modeled at the very top of the pressurizer as a trip valve junction with an area of 0.015 f 2t per valve. This area yields a rated flow of 210,000 lb/hr at 2400 psig for each valve when using the Moody critical flow table (Reference 12).

The assumptions common to all cases are briefly described below. Other assumptions characteristic of each particular case are discussed in the results section.

o The break is initiated at t:0.0 seconds at the cold leg pump discharge.

6-1

.O \ o One high pressure safety injection (HPSI) pump is modeled (d to reach f ull speed 26 seconds af ter the low pressurizer pressure signal. The flow is equally split among all four loops.

o For the cases assuming charging flow, one charging pump is modeled to inject emergency coolant into the broken cold leg (control volume 190). Only valve #110A in the charging line is assumed to be open, to minimize delivery rates, o The reactor coolant pumps (RCPs) are assumed to begin coastdown 52 seconds af ter the pressurizer low pressure

! signal, o The main feedwater flow to the steam generators shuts oft at the time of core trip. For the cases simulating manual S.G. cooling the main feedwater flow in assumed to coast down to 5 percent of the initial full power flow.

o The letdown flow of 120 gpm (Reference 3) is not modeled, as this is only a very small fraction of the discharge rates through the break and would not affect the analysis results nor conclusions contained herein.

6.3 Discussion of Results for Medium Breaks i

'^

The medium breaks with break areas 0.2 ft 2 to 0.02 ft: are characterized by a transient scenario in which the associated depressurization is sufficient to reduce the primary pressure below the LPSI actuation pressure. The HPSI flow, initiated following reactor trip, increases as the primary system depressurizes, eventually exceeding the system boil-off rate and matching the break flow for breaks in this category. At this time, system recovery begins. As such, no longterm core uncovery, resulting in fuel temperature excursions and subsequent cladding rupture, occurs for this category of breaks.

The results of the largest cold leg discharge medium break for CY, with an area of 0.2 ft.2, (about 6-inch diameter) is discussed below.

The primary pressure decreases rapidly initially as liquid mass is expelled out of the break, and the reactor trip occurs.

This is shown in Figure 6.1 which presents pressurizer pressure versus time. The initial depressurization slows as the RCS l

' pressure stabilizes at a value near the secondary side safety l

valve setpoint. During this plateau period the RCS pressure has stabilized at a value where core decay and wall heat is i

l balanced by steam generator heat transfer and the leak flow.

Thefprimary pressure then displays a departure from the plateau l

as the liquid flow out of the break transits to steam flow at about 160 seconds. The additional flow from the LPSI at 6-2

[ ') 330 psia was not modeled. The LPSI flow would accellerate the N J- system recovery; however, this injection was not modeled in this analysis in order to determine the adequacy of !! PSI acting alone. Figure 6.2 shows that the pressurizer liquid volume is discharged into the hot leg through the surge line following opening of the break, so that the pressurizer remains empty for the remainder of the transient. Figure 6.3 shows that the core remains covered by saturated liquid during the first 60 seconds, until the pressure in the upper head builds to overcome the liquid head trapped in the loop seals. As shown in Figure 6.3, the pressure required to clear the loop seal region results in a rapid loss of core level at about 150 seconds into the transient. Clearance of the loop seals, which releases steam from the reactor vessel upper plenum, then results in an increasing core level at about 180 seconds, as seen in Figure 6.3. With the relieving of the steam pressure in the upper plenum, the collapsed liquid level in the core increases rapidly as the coolant levels stabtlize between the annulus and inner vessel regions. Figure 6.4, which presents the mixture core level versus time, shows that the core remains l

covered throughout the remainder of the transient, as the HPSI l

flow exceeds the core and the system boiloff in addition to the mass flows out of the break.

Figure 6.5 shows the break discharge and the combined HPSI flow of all four cold legs. The break flow decreases with decreasing pressure and increasing quality after saturation I conditions are reached. At about 150 seconds the steam pressure in the reactor vessel upper plenum and steam generator tubes increases to clear the liquid from the cold legs, causing the quality out the break to decrease, thus increasing the discharge rate. ,Af ter the loop seals clear and the break quality increases, the primary pressure decreases as does the break flow until it is matched by the IIPSI flow at about 400 seconds. The hot legs temperatures, shown in Figure 6.6, also show that saturation conditions exist in the loops during this transient.

The steam generat or secondary pressure response is shown in Figure 6.7. Following turbine trip and closure of the turbine stop valves, the pressure increases to stabilize momentarily at the condenser bypass valves fully open set point of 930 psia.

As the primary continues to cool down, reverne heat t ransfer i:

established across the steam generators, and the secondary pressure begins to decrease as the primary side act as a heat I sink to the steam generators for the duration of the transient.

! The steam generator secondary tube side mass, shown in Figure 6.8, increases following turbine trip, due to the reduction in heat load and accumulation of liquid from the I

steam generator downcomer region. Eventually, the SG secondary I mass stabilizes as a hydrostatic equilibrium is reached between the downcomer and tube side volumes.

6-3 l

i

A parametric study was conducted for the 0.2 f t 2pump discharge

(\d) break to determine the amount of time available to the operator to initiate the HPSI flow to the primary loops following the low pressurizer pressure trip signal for the case with no initial ECC injection included. Results of this analysis show that if the HPSI flow is initiated not later than 300 seconds af ter reactor trip, the core will be maintained in a coolable condition.

The system response for the 0.2 ft 2pump discharge break with a 300 seconds delay in HPSI actuation is very similar to the 0.2 ft2 pump discharge break with the normal HPSI delay time discussed earlier in this section. This is illustrated in Figures 6.9 to 6.16. The delayed llPSI flow delivery results in some core uncovery as shown in Figures 6.11 and 6.12. Ilowever, although the core uncovery occura over a somewhat longer period of time as compared to the previous analysis, this results in a peak cladding core average temperature of 1264*F, which demonstrates the acceptability of delaying the HPSI injection 300 seconds into the event. The cladding temperature calculations are discussed in more detail in Section 12.0 of this report. The Section 12.0 heat-up analysis was performed to determine the maximum core average temperature for this case.

6.4 Discussion of Results for Medium-Small Breaks The medium-small breaks include break sizes 0.02 to 0.003ft2, This range has been determined using the criterion that one charging pump with only valve #110A delivers sufficient flow to the primary system to maintain the core covered during long term.

The transient scenario for a medium-small break is basically identical to the medium break LOCA discussed in Section 6.3 except that the duration of the transient is extended due to the smaller break size. The flow from one HPSI pump is sufficient to maintain the core in a covered condition. As is expected, the consequences of the accident are less limiting than the medium break due to the smaller break size and as such, more time is available before core uncovery would occur.

In terms of available time for operator action and inventory loss the most limiting small break in this category is the 0.02-ft.2 pump discharge break, equivalent to a diameter of 1.9 in. Analysis of this break credited one charging pump with only valve #110A open so as to minimize the injection. While the injection flows f or the charging pump are 20 percent lower than that for the HPSI flow injection rates, the charging flows I

are still sufficient to cool the core during the long term.

l Core uncovery does occur momentarily early in the transient due to the clearing of the loop seals; however, long term

! coolability is assumed for this break.

6-4

In addition to minimizing the injection, by crediting charging fN instead of IIPSI flows, the 0.02 ft 2 break was also analy/ed to assess the impacts of utilizing alternate meann, in the event of multiplq equipment failures, which can be successf ully employed to achieve adequate core cooling. These analyses incbade 1) one charging pump available with loss of feedwater,

2) delay in charging flow with loss of feedwater, and 3) an 2 additional analysis of a slightly larger break, the 0.03 ft break, with no charging or HPSI flow with steam generator cooldown to initiate the LPSI. This larger break was chosen 2

for analysis since the 0.03 ft break clearly bounds the behaviors for breaks in this category. It should be mentioned that the results of case 3 demonstrate that the LPSI system is actuated too late (about one hour into the event) to prevent an inadequate core cooling condition.

The results are discussed in the following sections.

6.4.1 0.02-Ft.2 Break, Charging Flow, No SG Feedwater Following initiation of the break in the RCP discharge leg, the low pressurizer pressure trip set point is reached at 25.4 seconds (Figure 6.17), after which the core power decreases to the decay heat levels plus moderator and fuel reactivity feedback as described in Section 1.2. The pressurizer, as indicated in Figure 6.18, voids initially and remains O, filled with steam throughout the remainder of the transient. Figure 6.19 presents the reactor vessel total mass versus time and shows that the reactor vessel loses its inventory early in the event due to liquid mass lost out of the break and the increare in steam pressure in the upper plenum of the vessel, which is required to clear the loop seal region of the primary loops. Following clearance of the loop seals the vessel fluid stabilizes and the core inventory shows an increase in liquid mass. After 4500 seconds the core mass slowly starts to increase due to the accumulation of the liquid injected by the charging pump.

Figures 6.20 and 6.21 indicate that the core experiences partial uncovery at about 1,000 seconds into the event. Ilowever, the core average temperature remains well below 2200'F. The charging flow, corresponding to only valve #110A open to minimize the injection, is actuated 30 seconds after the low pressurizer pressure signal. At about 5100 seconds the safety injection flow begins to exrced the break flow (see Figure 6.22). Core uncovery is precluded earlier in the event and after the loop seal clearing time, the injection exceeds the core and system boil off.

! 6-5

/T The hot leg temperature is shown in Figure 6.23 to

(,,) basically follow the saturation temperature after saturation conditions are reached early in the event.

At about 200 seconds, the Tavg becomes greater than 545'F, at which time the eight temperature-controlled secondary bypass valves open in addition to the two temperature / pressure controlled bypass valves, which are oscillating to maintain the SG pressure at 930 psia, to remove the additional energy. This is represented as a downward trend in the SG pressure presented in Figure 6.24. This trend occurs again at about 1500 seconds during the core recovery period.

At about 2400 seconds reverse heat transfer is established. The SG pressure then begins to decrease following the primary pressure and as a consequence the bypass flow to the condenser ceases.

The steam generator secondary mass is shown in Figure 6.25.

6.4.2 0.02 - FT2 Break, Clarging injection at 1200 Seconis, No SG Feedwater This case is identical to the one presented in Section 6.4.1, except that the charging injection is actuated with a delay of 1200 seconds after reactor

()

es trip. The delayed injection has a small effect on the results of the analysis when comparing Figures 6.26 to 6.34 to the previous result in Section 6.4.1. The only major difference is that the discharge rate out of the break is lower prior to the initiation of the charging flow (Figure 6.31). This is due to the higher quality experienced at the break owing to the lack of colder charging water since the break is assumed to be located downstream of the charging injection point.

6.4.3 0.03 - FT2 Break, No Safety injection, 100*F/hr RCS Couldown at 300 Seconds A .03 fL2 break at the cold leg discharge location har. been analyzed assuming no HpSI or charging flow and operator action at 300 seconds to initiate RCS couldown via the steam dump to the condenser at a rate of 100'F/hr. This action is taken to obtain safety injection to the core by depressurizing the primary system to the LPSI actuation pressure of 330 psia (Ref. 4). The break size analyzed herein was chosen to be slightly greater than the most limiting medium small break of 0.02 ft.2 for conservitism. The transient results are presented in Figures 6.35 to 6.40.

O-6-6

(}

(,,/

Figure 6.35 shows the pressurizer pressure vs. time Initially there is a rapid depressurization due to the opening of the break combined with the subsequent cooldown following reactor trip. Once the primary reaches saturation conditions, the pressure momentarily stabilizes. At 300 seconds, the operator is assumed to begin RCS cooldown via the steam dump to the condenser at the Emergency Operating Procedures limit of 100*F/hr. As a result, the pressurizer and primary pressures begin also to decrease due to the additional heat removal capability of the steam generators.

Figure 6.36 presents the collapsed core level behavior. The core level displays a decrease at 150 seconds, due to achievement of saturated conditions which initiates boiling in the core. The core, however, remains covered with a bubbly mixture until ;

650 seconds. At this time, the steam pressure in the upper plenum, from bailing and flashing in the core, increases sufficiently to expell fluid from the core into the downcomer because of the liquid trapped in the loop seals. The core quickly voids and remains uncovered until the loop seals are cleared at about 1400 seconds. Some liquid mass reenters from the downcomer, but due to the lack of safety injection, f- g there is not sufficient inventory in the system to f fully recover the core level. As a consequence, the

\j core is almost completely voided by 2300 seconds and remains uncovered for the duration of this event.

The break flow response, presented in Figure 6.37, shows that the mass flow quickly decreases at about 900 seconds since the loops have drained and the break node has become filled with steam. It increases momentarily, however, as liquid is being discharged during the loop seal's clearance. After clearing of the loop seals, the break flow decreases again as steam flow out of the break in again inititated.

The cold legs temperature and SGs pressure are shown in Figures 6.38 and 6.39.

Itaned on the results presented above one can conclnde that, for this break size, the LPS! Ilow should begin no later than 900 seconds, llowever for I. PSI flow to be injected, the primary temperature would have to l decrease at a rate far in excess to the Emergency

! Operating Procedures limit of 100*F/hr. As such, 11

this 100*F/hr limit is followed, there is l Insufficient time to initiate LPSI flow for the larger breaks in this category. Ilowever, this option

! should prove beneficial when performing such

\

i l

l 6-7

(q

\- /

i cooldowns in conjunction with establishing either the charging or HPSI flow, as the lower pressures resulting from the RCS cooldown will yield higher flows once the charging or llPSI pumps have initiated.

This action would lead to earlier and more rapid mitigation of the accident conditions.

6.4.4 Summary The medium-se all break sizes discussed herein correspond t an area less than .02 ft.2 (1.9-in.

diameter) and greater than .003 ft.2 (3/4-in.

diameter). The analysis of the 0.02 ft.2 break demonstrates that the flow from one charging pump with only valve #110A open is sufficient to keep the core cooled in the event failure of the llPSI pumps to start is assumed at the low pressurizer pressure signal.

In the event both the charging and the IIPSI flow are ,

not available initially, analysis of the break has also demonstrated that the operator has at least 1200 seconds af ter the low pressurizer pressure signal is reached to initiate either the charging or the HPSI flow to prevent core uncovery. Since the 1 0.02 fta cold leg discharge break is the limiting break in this category, using this delay is conservative for the smaller break in this category s,

as they require a longer time to uncover the core.

6.5 Discussion of Results for Small Breaks The "small" break category represents that range of breaks with a leak rate too small to maintain the RCS pressure sufficiently low to ensure adequate core cooling in the event steam generator heat removal is lost. As a consequence, SG heat removal capability is required to assure core coolability for breaks in this range.

The largest break in this range is the 0.003 ft.2 (.742 in, diameter) pump discharge break. Although analysis of this break demonstrated that the llPSI flow coupled with the leak flow discharge rate provided core cooling (without SG heat l

removal capability), this break was chosen as the upper limit I for analyses for this break category to minimize the available operator action times. Analyses of the 0.003 ft.2 with various

! equipment failures were assessed and include:

l 1. .003 ft.2 discharge leg break with IIPSI, and total loss of I SG feedwater.

2. .003 ft.2 discharge leg break with charging injection, and g-') total loss of SG feedwater.

I U l

1 6-8 l

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

/N 3. .003 ft.2 discharge leg break with total loss of Icedwater, and feed and bleed utilizing charging injectson and one PORV opened at 2400 seconds.

4. .003 ft.2 discharge leg break with 5 percent main feedwater and 75 *F/ hour RCS cooldown initiated at 900 seconds.

Results from all of the above cases are discussed below.

6.5.1 .003 Ft.2 Break,IIPSI, No SG Feedwater The results from this analysis are shown in Figures 6.40 to 6.48.

Following initiation of the break in the cold leg pump discharge, the primary system begins to depressurize (Figure 6.40) until the low pressurizer pressure signal set point is reached at 263 seconis.

At this time the core power rapidly decreases. As coolant is expelled through the break, the primary system inventory decreases until actuation of the HPSI flow at 289 seconds initiates refill of the system and eventually causes some repressurization.

The early oscillations in pressure in Figure 6.40 which occur up to 1,000 seconds are due to the changes in heat removal capability by the SGs. The eight temperature-controlled steam bypass valves open

\~- in addition to the two temperature / pressure-controlled valves, which lifted following the turbine stop valves closure at trip.

These valves maintain the primary Taverage below 545'F. At about 2,600 seconds the RCS experiences a large depressurization. This corresponds to the time the primary liquid, which has been increasing due to the continued itPSI flow, refills the RCS and reenters the pressurizer (Figure 6.41). The insurge of colder water condenses the pressurizer steam, causing the RCS to depressurize, increasing the llPSI flow and the flow into the surge line. Finally, the system repressurizes and stabilizes at a pressure of 1,360 psia, which corresponds to the pressure at which the !! PSI flow matches the break flow (see Figure 6.45). Since the RCS maintained subcooled conditions throughout the event, core cooling is assumed for this break size.

6.5.2 .003 FT2 Break, Charging injection, No S.G. Feedwater The results of this analysis are presented in Figures 6.49 to 6.58. Initially the transient behavior is A.:entical to the .003 ft2 discharge leg break with I h Si pump and total loss of S.G.

feedwater discu..cd in Section 6.5.1, until

\

6-9

O)

(

's /

initiation of the safety injection at 289 seconds, which in this case corresponds to the flow from one charging pump with only valve #110A open. The primary system pressure (see Figure 6.49) continues to depressurize after initiation of the charging flow at 289 seconds since the injection flow is much less than the break flow, as shown in Figure 6.54. At about 2,900 seconds the RCS pressure starts to increase as the steam generator heat removal capability is lost due to tFa loss of SG feedwater and subsequent depletion of the secondary liquid inventory. The pressure continues to increase until the PORVs opening setpoint of 2285 psia is reached at about 5200 seconds. The RCS pressure remains at these conditions for the duration of the transient.

The reactor vessel total mass, collapsed core level and swelled core level respanses are shown in Figures 6.51 to 6.53, respectively. Figure 6.52 shows that the core liquid becomes saturated at 5900 seconds. Figure 6.53 shows that the core remains covered with a bubbly mixture until approximately 7500 seconds, at which time core uncovery is initiated.

Core uncovery is initiated since the charging flow is unable to match the break and PORV losses. As such

\, operator action would, therefore, be required prior to 7500 seconds to initiate feedwater to the SGs and increase the injection flows by opening valve #110 of charging line to increase charging flow or start one llPSI pump. This action is required to prevent RCS pressurization and the subsequent opening of the pressurizer PORVs.

6.5.3 .003 FT2 Break, No SG Feedwater, Feed and Bleed with Charging Injection and 1 PORV at 2400 Seconds As can be seen in Figures 6.59 to 6.68, this transient behaves, initially, in the same manner as the .003 ft2 discharge leg break with one llPSI pump and total loss of SG feedwater presented in Section 6.52 above. Ilowever, this analysis demonstrates that the primary system pressure continues to decrease after 289 seconds which corresponds to the llPSI actuation time in the preceding case. This occurs because, in this case, the primary inventory continues to deplete since no safety injection is credited for the first 2400 seconds. After 2200 seconds the SGs secondary inventory is depleted and the loss of the S0 heat sink causes the primary pressure to increase. Feed and bleed is initiated at 2400 seconds with one PORV and one charging pump with only valve #110A open to 6-10

(].

\_,/

assist in controlling the heat up process. The pressurizer pressure reaches a maximum of about 1560 psia at about 3700 seconds. By the time suf ficient liquid inventory has been discharged through the PORV to initiate steam flow out of the system, the RCS experiences a depressurization at about 4500 seconds into the event (see Figure 6.59).

Figure 6.64 shows that the charging flow exceeds the break flow plus the PORV flow for the remainder of the transient. The core will, therefore, remain covered for the duratioe of the event.

Figures 6.62 and 6.63, which show collapsed and swelled core levels respectively, indicate that the core remains covered with a bubbly mixture throughout this event. Figures 6.66 to 6.68 present the hot leg temperature, SG pressure, and SG secondary mass responses, respectively. Once saturation conditions are reached in the primary during the first 400 seconds, the hot leg temperature follows the primary saturation conditions for the remainder of the transient.

6.5.4 .003-Ft.2 Break, No Safety injection Flow, 75'F/ilour RCS Cooldown at 900 Seconds rs The system pressure for this case (Figure 6.69)

(' I displays a continuous decrease throughout the

analysis due to the combined effects of inventory loss out of the break, the initial decrease in core power following trip, and the 75'F/ hour RCS cooldown via the steam dump to condenser assumed to be initiated by the operator at 900 seconds. Because there is no injection credited, the pressurizer is quickly depleted of liquid inventory as seen in

+ Figure 6.70.

The core remains subrooled until about 1,800 secondo at. which time this region saturates and remains suturated for the duration of the event.

The break flow is shown in Figure 6.74. There is no llPSI flow throughout the transient, llowever, with the cooldown rate of 75'F/hr the I. PSI system can be activated, thereby precluding the potential of core uncovery.

The hot leg temperature (Figure 6.75) displays an oscillatory behavior prior to 900 seconds into the event. This is the result of the temperature-cont rolled bypass valves attempt ing to maintain the Taverage below 545'F. Af ter thin period of time, the hu t. leg temperatures begin to decreanc due to the initisted cooldown rate of 75"F/ hour. The SG x_

6-11

I (m

pressure and SG secondary mass behavior are shown in Figures 6.76 and 6.77. In the latter it can he seen that 5 percent of the full power main feedwater flow is sufficient to match the steam flow in the SG during the 75*F/ hour cool down.

6.5.5 Summary Based on the analyses discussed ibove, the following conclusions can be presented.

The "small" break category include breaks with an area of 0.003 ft 2 and smaller. For these breaks, the leak rate is insufficient to accommodate core decay and primary wall metal heat so as to maintain RCS pressure sufficiently low to assume core cooling. As such, the secondary inventory must be maintained to ensure SG heat removal capability for breaks in this category. In the event the small break is concurrent with a total loss of feedwater to the SGs, feed and bleed with one charging pump and one PORV can be initiated at 2400 seconds without resulting in core uncovery. If the IIPSI or the charging flows are not available to make up for the inventory lost through the break, RCS cooldown (via secondary steam relief) can be initiated as late as 900 seconds to depressurize the primary system to the LPSI actuation 4 pressure in time to prevent core uncovery.

6.6 Discussion of Results for Consequential Stuck Open PORV The Haddam Neck plant has two PORVs, each rated at 210,000 lbs/ hour at 2,400 psig. One stuck open PORV corresponds to a break area of .0115 ft.2 when calculated using the Moody model for critical steam flow at the above specified pressure. This results in classifying this transient as a medium small break LOCA.

As discussed earlier, a medium-small break has been defined as a LOCA shich can be mitigated successfully with the charging flow providing the safety injection. The analysis discussed herein assumed a pressurizer PORV (and block isolation valve) to fail open in response to a plant transient at t:0. Two cases were considered:

1. Stuck open PORV with 5 percent main feedwater flow and no safety injection credited to calculate the time of core uncovery.

2. Stuck open PORV with no safety injection, the leak isolated, and a 75'F/ hour RCS cooldown rate initiated .it 3,600 seconds to determine the feasibility of depressurizing the system to below the LPSI shutoff pressure (330 paia).

Q( ,

6-12

l Results of Case 1 above show that core uncovery begins at about

[9 i.j 5,000 seconds when no injection is credited and the operator takes no action during this period. When the operator begins a 75*F/ hour RCS cooldown at 3,600 seconds, in Case 2, the primary system reaches a pressure of about 370 psia by 10,000 seconds and the core remains covered throughout the event. It is important to note that the CY Emergency Operating Procedures l allow a maximum of 100*F/ hour RCS cooling rate,'/ud the result >.

contained herein, threfore, represent a conservative or ,

" bounding type" estimate. The results of these two cases are l discussed below.

6.6.1 Stuck Open PORV, 5 Percent Main Feedwater, No Safety Injection A stuck open PORV LOCA is less limiting than a medium-small cold leg pump discharge break of the same size. The most important reason is that a break at the cold leg would discharge more liquid inventory since the break is located at a lower elevation in ,

the RCS and, as such, conditions at the break l location would be initially subcooled liquid, while I conditions at the PORV are initially saturated liquid or steam. It is estimated that, as documented in Reference 13, a cold leg discharge break equivalent ,

in area to one PORV, (i.e., a 0.01 ftz break) would also not display the characteristic core uncovery as n,V a result of the loop seal clearing and would not !

result in core uncovery when lipSI flow is credited.

The results of a stuck open PORV with 5 percent main feedwater and no safety injection are shown in Figures 6.78 to 6.87.

Following the opening of a PORV at t = 0,0 seconds, )

the primary system depressurizes (Figure 6.78) reaching the low pressurizer pressure set point at 43.5 seconds. At this time the core power decreaset.

rapidly, followed by the system pressure stabilizing at about 950 psia. With no injection credited, core uncovery is initiated at about 5,000 seconds, into the event, as shown in Figures 6.81 and 6.82.

The pressurizer liquid response is shown in Figure 6.79. The liquid inventory is seen to decrease initis.lly due to local flashing caused by the opening of the PORV. But as the primary system depressurizes, approaching saturation, the expanding fluid fills the pressurizer with saturated liquid.

Continued liquid discharge out of the p0RV eventually causes the pressurizer liquid level to decrease at about 700 seconds. At about 3,500 seconds the pressurizer liquid level displays a marked increase O in level. This increase in pressurizer liquid V

6-13

[]

V inventory is due to drainage of the liquid trapped in the SG. Because the hot leg steam flow has decrease a suf ficiently, the liquid in the " upside" t ube regiou of the SGs above the hog leg elevation drains au the hot leg. During this SG drainage period, the pressurizer refills momentarily with saturated

!< liquid. However the continued discharge through the l

PORV causes the system inventory to continue to deplete. As indicated in Figures 6.80, 6.81 and I 6.82, presenting reactor vessel mass, collapsed core liquid level and two-phase core level versus tise, ,

respectively, core uncovery can be seen to begin at I l 5,200 seconds. Total uncovery is achieved at about t 6,800 seconds.

Figure 6.83 shows PORV and HPSI flow versus time.

The IIPSI flows, as mentioned earlier, is not credited j throughout this event. The pressurizer liquid level i transient is shown in Figure 6.79.

The hot leg and cold leg temperature responses are shown in Figures 6.84 and 6.85. Once saturation is reached very early in the transient, the temperature follows the same trend as the primary pressure response (Figure 6.78). During core uncovery, the hot leg temperature is seen to increase at about 5900 p)

(

\#

seconds while the cold leg temperature continues to decrease. This combined behavior is caused by the temperature-controlled condenser bypass valves which open when the Taverage is above 545*F.

Based on the results of this event, core uncovery would not occur for 5200 seconds.

6.6.2 Stuck Open PORV, No Safety injection Flow, Leak Isolated and 75'F/HR RCS Cooldown Initiated at 3,600 Seconds The results of this case is similar to the one described in Section 6.6.1 with the exception that operator action is assumed, at 3,600 seconds, to isolate the PORV by closing the block valve and initiating a 75*F/ hour RCS cooldown to allow the primary system to depressurize to the Li>SI actu.stion setpoint. Figures 6.88 to 6.96 present the major system parameter responses.

Following reactor trip, the primary pressure stabilizes at the secondary temperature until the operator begins RCS cooldown at 3,600 seconds by using the SG steam relief paths as described in Section 1.2. The pressurizer pressure, shown in Figure 6.88, finally reaches 373 psia at

[sT 10,000 seconds. This value corresponds to 43 psi c) 6-14

I

)

above the LPSI shutoit pressure of 330 psia j, (Reference 8), indicating the LPSI could be act iv.it e.I shortly thereafter.

Throughout the time analyzed of 10,000 seconds, the core remains covered with a bubbly mixture (Figures 6.91 and 6.92) and the cladding temperature remains very near the saturation temperature.

Figure 6.96, which presents SG secondary mass versus time, indicates that 5 percent of the full power main feedwater flow is sufficient to maintain the level in the SG during the cooldown process.

Based on the results of this analysis, the operator has at least 3,600 seconds to isolate a stuck open PORV, assuming failure of both the HPSI and the charging pumps to preclude core uncovery.

6.7 Discussion of Results for Reactor Coolant Pump Seal LOCA The purpose of this analysis is to determine the time of core uncovery following a reactor coolant pump seal f ailure combined with a complete loss of primary safety injection (HPSI and charging flow). This provides an estimate of the time available to the operator to take action in the form of isolating the leak by using the loop isolation valves and/or initiating safety injection.

l )

In this analysis, a pump seal leakage rate of 300 gpm is assumed, although this is far in excess of the maximum leakage of 50 gpm that is associated with the failure of a seal as described in Reference 14. Using the llenry/Fausky discharge correlation for subcooled flow, a 300 gpm leak rate is equivalent to an area of 0.00142 ft2, To identify the earliest time for operator action, all four pump seals have been assumed to fail, resulting in a total leak area of 0.00567 ft2 which places this break in the lower end of the medium-small break category discussed in Section 6.4. This is a conservative assumption as it will result in a faster rate of inventory depletion.

Results have indicated that with 5 percent of the full power SG main feedwater flow the core will not begin to uncover until about 5,200 seconds into the event (see Figure 6.100). This initial uncovery occurs prior to the clearing of loop seals due to the increase in steam pressure in the upper plenum, which depresses the level into the core. As shown in Figure 6.100, in this condition, the core remains uncovered for about 1,700 seconds. Once the loop seals are cleared, the core will recover with uncovery occurring again at about 7,000 seconds.

The cort will remain uncovered throughout this time due to insufficient liquid inventory in the system. Therefore, the

( }

operator must isolate the leak in the pump seal before 5200 L.,'

6-15

In addition, f,'--/) ' seconds into the event to prevent core uncovery.

the operator should start safety injection : sing ilPSI or charging systems in order to refill the RCS.

Figures 6.97 to 6.106 present the response f or the major syn t em parameters calculated for this event.

The low pressurizer pressure signal is reached at 134 seconds at which time reactor trip is initiated. The primary system pressure, shown in Figures 6.94, quickly decreases to a pressure of about 960 psia after 1,200 seconds, and remains at this value throughout the transient. The pressurizer empties following reactor trip and remains empty throughout the transient, as shown in Figure 6.98.

The reactor vessel total mass, the collapsed core level, and the swelled core level responses are shown in Figures 6.99 to 6.101, respectively. They indicate that the core liquid becomes saturated at about 750 seconds, but that uncovery doer.

not occur until about 5,200 seconds. This uncovery occurs prior to the clearing 'of the loop seals due to the increase in steam pressure in the upper plenum which depresses the level well below the top of the core. Upon clearing of the loop seals, the fluid levels in the vessel stabilize, resulting in an increase in core level at about 7000 seconds. Ilowever, sufficient inventory continues to be lost and the core experiences uncovery again after 7000 seconds into the event.

['-'N

( ,) The discharge break flow out of the pump seals, shown in Figure 6.102, decreases initially following the initial depressurization. The break flow then stabilizes at approximately 44 lbs/sec until about 4,500 seconds, at which time the flow transits between steam and liquid causing marked changes in leak flow for the remainder of the event.

Results of this evaluation demonstrate that the operator has about 5200 seconds within which to take action to prevent. core uncovery.

6.8 Summary of Small and Medium Break LOCA Analysis Results of the above analysis are discussed in terms of the four defined break categories along with identification of the appropriate equipment or actions to preclude core uncovery.

These include:

Large breaks (A>.2 ft 2) require only one LPSI pump for mitigation.

Medium breaks (.2 ft2 2A>.02 ft 2) require only one HPSI pump for mitigation.

Medium-Small breaks (.02 2ft Al .003 ft2) require one

-- charging pump or one HPSI pump for mitigation.

/s b) 6-16

/} Small breaks (A <.003 ft )2 require S.G. heat removal

(,,/ capability in addition to either one llPSI or one charging pump for mi t igation.

Large breaks were considered in Section 5.

The medium breaks are sufficiently large to depressurize the RCS to pressures below the llPSI pump shutoff pressure very rapidly. For these breaks, initiation of one llPSI pump can be delayed a maximum of 300 seconds without impairing coolability of the core.

The medium-small breaks respond similarly to the medium breaks with the advantage that, if HPSI cannot be established, core coolability can also be attained by the initiation of charging flow from one pump. Operator initiated steam generator cooling to the LPSI actuation is not an effective mitigating procedures in the event of IIPSI unavailability as the LPSI initiation pressure is reached only after prolonged core uncovery.

Ilowever, the charging flow can be delayed up to 20 minutes after reactor trip without impairing coolability of the core For break sizes in the "small" break category, the primary pressure remains above the secondary pressure for a long period of time because the energy discharged from the system through the break is insufficient to accommodate the core decay heat and wall heat sources. As a consequence, the primary system temperature is maintained above the steam generators (SGs)

Cs) secondary temperature. The SGs play an important role in removing the excess heat, and the main feedwater or the auxiliary feedwater is necessary to maintain this heat removal capability for breaks in this "small" break range. In the event the IIPSI or the charging flows are not available to make up the inventory lost through the break in the primary side, RCS cooldown (via secondary steam relief) can be initiated at 900 seconds to depressurize the system to the LPSI initiation pressure in time to prevent core uncovery. In the event the small break LOCA is concurrent with a total loss of feedwater to the SGs, feed and bleed with one charging pump and one PORY can be initiated at 2,400 seconds without resulting in core uncovery.

The sequential PORV LOCA and the RCP seal LOCA behave very similarly to the cold leg discharge breaks discussed herein.

As such, due to the size and behavior of these events, the associated required equipment and operator action times for these LOCA's are the same as that for the medium-small break category.

'N t

6-17

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i. FIGURE 6.1 i

HADDAM NECK PLANT SMALL BREAK ANALYSIS i

0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF 1

PRESSURIZER PRESSURE f l

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FIGURE 6.2 .

HADDAM NECK PLANT SMALL BREAK ANALYSIS l 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF ,

I PRESSURIZER LIQUID VOLUME

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400i 375i 350i

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1 FIGURE 6.7 !

HADDAM NECK PLANT SMALL BREAK ANALYSIS l 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF t

STEAM GENERATOR PRESSURE i

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TIME (SEC)

AFFECTED LOOP --- UNAFFEC TED LOOP 6-25 ,,

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FIGURE 6.9 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF J.

HPSI FLOW AT 300 S t

PRESSURIZER PRESSURE 2200; 2000i i 7

i 1800i 16C0i O .

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t FIGURE 6.10 hADDAM NECK PLANT SMALL BREAK ANALYSIS i

0.2 S0.FT. DISCHARGE LEG BREAK,RCPS OFF

HPSI FLOW AT 300 S !

! PRESSURIZER LIQUID VOLUME 650-600-1 5502 j 500-t 450-L

.O t,,0:

e .

U 300-E 250-3 200-t 150-100-50-b ~

^

^ ' '^

- - - - - - ^ ^^

02 b 2bo ub0 Sh0 8b0 lobo j TIME ISEC) i O ,

6-27

a * -w FIGURE 6.11 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF HPSI FLOW AT 300 S COLLAPSED CORE LEVEL 100--

90- I 80i 70i '

n O ; Q \/ 4[>I i ee i

%0f 30s 3

- t b

Y

)

b 2b0 4b0 6b0 8bo lof 0 TIME (SEC)

O 6-28

1 O

FIGURE 6.12 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF r HPSI FLOW AT 300 S TWO-PHASE CORE LEVEL 100-80-1

~

i O 60-E E

e X

40-

)

i 20-f d

0.. .. . .. .. . . ..

700 000 900 1000 200 300 400 500 600 O 100 TIME (SEC) 6-29

l FIGURE 6.13 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF

HPSI FLOW AT 300 S BREAK AND HPSI FLOW

< 3900-35002 3300-3000i 27002

, b)

V F 24002 li 2I002 18002 1500-C 12002 4

900f 600- }

3005 0

2l~--------~~-~----------/ , , ,

1000 0 200 400 600 800 TIME (SEC1 LEGENO: CURVE BREAK FLOW .--- -- H P S I F L OW O

6-30

i:

1

O ;

i FIGURE 6.14 l

HADDAM NECK PLANT SMALL BREAK ANALYSIS O.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF ;

HPSI FLOW AT 300 S :

. HOT LEG TEMPERATURE ,

1 575i .

550i 4

5252 3

500i O 475i i I

450i 4

E 425i F 400i f 375i 350i 325i ,

1 300i b 2b0 Mb0 6b0 8b0 1000 TIME ISEC) 6-31 e_,_,_ , , ,. - . . - . _ _....-_.-_..,..__..,..,-._-_--.,_.,,.,_...-,--,.,~._--,_,,,.r._ _ _ - _ , , . _ , - . _ _ , , . - _ ...,m- , .__ _ , ,. _, .

o '

i j

FIGURE 6.15 L HADDAM NECK PLANT SMALL BREAK ANALYSIS l 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF HPSI FLOW AT 300 S STEAM GENERATOR PRESSURE l

1000-l J 900i I '*,

'N.,

. g 800i N,,

I i s '

l \.,'

j. .

~ .N j 700- s, p '.'., >

A

! E 6002 '

j S .

5 l U

A

l j E 500. . .. ,s

. s *%,*

P 400i

?

' A . '. . ,

300i 's-i 200i

[

100' '

l l

l 02 ,

0 200 400 600 000 1000 TIME (SEC)

I AFFECT E D LOOP - -- UNAFFEC TED LOOP 1

i O 1

l l 6-32

i O l O '

1 i

FIGURE 6.16 :

HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF HPSI FLOW AT 300 S STEAM GENERATOR MASS i

57500i 55000i 3

p 5 i ;~

, . . . ' . ~~- A y

52500i '!y / . ,,,,, . .. ..

'/'/ ' ** i j ,Iwy j

F a 1..,

j * ,.... ... .. . :

500002

[ ,

I

~

47500i M

A 5 450002 '

l 5 l l

42500i L

8 M

40000i 37500i l

35000i 32500i 300002 O 200 400 600 800 1000 i

O AFFECTED LOOP TIME I5EC1

UNAFFEC TED LOOP 6-33

i

! FIGURE 6.17

! HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION PRESSURIZER PRESSURE 1

2100-J l ,

2000-

~

1900-t800-I 17002 4

, 1600-~

15002 R

14002 S

R E 1300-P i 5 .

1200-

~

1100-10002 3002

$ 8002 7002 i

i 6002 3000 4000 5000 6000 7000 8000 900G 10000 ,

0 1000 2000 TIME ISEC)

I i

6-34

h l

lO I

FIGURE 6.18 HADDAM NECK PLANT SMALL BREAK ANALYSIS 4

0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF I CHARGING INJECTION

! PRESSURIZER LIQUID VOLUME 650-600-r I l

3 550-g 500-4502 L

Q 4005

' D 350-Y s g L

'I U 300-M E

ll 250-F i T 3 200-1 150-100-50-i _,,,

O,Z ,' '-] C , , , , , _,_

8000 9000 10000 0 1000 2000 3000 4000 5000 6000 7000 TIME 15ECl i O 6-35 I

i-1 1 i

FIGURE 6.19

HADDAM NECK PLANT SMALL BREAK ANALYSIS O.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF i LHARGING INJECTION REACTOR VESSEL TOTAL MASS 160000-I

i 150000i 140000-1 130000i 120000i M

R 110000i 5

100000i 4 g M

90000i 80000i 70000i i

60000i

\

l

't i

500002 10 0 20h0 30hD 40hD SC 0 60 0 70b0 80b0 90b0 1000h TIME (SECl O

6-36 3

O FIGURE 6.20 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SO.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION COLLAPSED CORE LEVEL 120-100-l..

60-

%etNY 4 0 --

20-l o,

O 0 1000 2000 3000 4000 5000 TIME ISEC) 6000 7000 0000 9000 10000 6-37

O FIGURE 6.21 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION TWO-PHASE CORE LEVEL 100-l 80-O 60-i E

L 40-20-0- i- 1-

.- .- i-i- i- r 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SECl O

6-38

O FIGURE 6.22 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION BREAK AND CHARGING FLOW 450f 1400f i

350h O :

'i 2504 2C0 s

150; l00f

'4

_. .. . . ... . . r .'i o m --* #u.4!104da C 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC)

LEGENDS CURVE BREAM FLOW -.... - CHARCING FLOW 6-39

O FIGURE 6.23 HADDAM 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF NECK PLANT SMALL BREAK ANALYSI CHARGING INJECTION HOT LEG TEMPERATURE 590; I

580i 570i 560i 550i E 5402 ~

5 R 530i l

520i 510i 500i 490i

r-10000 0000 9000 7000 4802,. 6000 5000 4000 j

1000 2000 3000 O

! TIME ISEC) l 6-40 1

v. _ _ _ _ _ _ _ . _ _ . . _ _ _ _ _ . _ . - _ _ . _ _ _ _ _ - _ - _ _ _ . _ . _ _ . _ . _ _ _

i

O l 1

FIGURE 6.24

HADDAM NECK PLANT SMALL BREAK ANALYSIS

! 0.02 S0.FT. DISCHARGE LEG BREAK,RCPS OFF j CHARGING INJECTION STEAM GENERATOR PRESSURE 950-925<

, 900-I .

j e7s-l . i 850- '

!O E

~

\\

s 8c0- T.

1 s .

i W E 775-

\*

\

750- 't

,P \

~

j i

0 725-

i' j .

7c0- \.,

f ,

i' s

'. I i s7% s. ,

650-I 625-6

! ~. . .- . . -

0 1000 2000 3000 4000 5000 6000 7000 0000 9000 10000 TIME (SECl AFFECTED LOOP -- - ~ UNAFFECTE D LOOP l 6-41

O FIGURE 6.25 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 S0.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION STEAM GENERATOR MASS 70000--

67500-65000 l

6250J-i 6000C-O ,, .

55G00- ,

S S S250 %

50000-8 M 4750 %

450;l-4250%

1 40CUS <

J !' ll ll l l 3 l',no 3500 4 ; . .

O

~

, i i , , , , , , , -m 0 1000 2000 3000 4000 5000 6000 70C0 8000 9000 10000 TIME (SECl 6-42

O FIGURE 6.26 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE' LEG BREAK,RCPS OFF I

CHARGING INJECTION AT 1200 SEC PRESSURIZER PRESSURE 2100-2000-190t!-

1800-17005 1600-15002 R

I1400-b Ei300:

ia00- {

f 1100-I .

1009-L 900-800-700-10 0 20b0 3b0 14bb0 50b0 6bb0 70b0 80b0 9hb0 100 0 TIME (SEC1 6-43

O FIGURE 6.27 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION AT 1200 SEC PRESSURIZER LIQUID VOLUME 650--

6002 550-500-450 4001 l

i .:

1 e .

U 300-E 250-3 200-1502 100-50 01 4

^

0 1000 2000 3000 4000 5000 6000 7000 0000 9000 10000 TIME ISEC)

O 6-44

l O

! FIGURE 6.28 HADDAM NECK PLANT SMALL BREAK ANALYSIS l 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION AT 1200 SEC

! REACTOR VESSEL TOTAL MASS 16000n--

1

f5nn09

140000i 130000i I

1200G0i b

1100002 1000nci i ll 900002 80000i 700002 60000i

)

500002 10b0 20b0 30b0 40b0 50b0 60b0 70b0 Bobo 90b0 10000 3

TIME (SEC1 O

6-45 4

A V

FIGURE 6.29 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING FLOW AT 1200 SEC COLLAPSED CORE LEVEL 10t)-

90f o - .

60i E

!L so: ~

(4 0-Of l

20f 10; O ,,,,,,,, ,,,,-++++ +- - r -

-- - + r- ++-- r TIME (SECl 6-46

kh

! eD FIGURE 6.30 HADDAM NECK PLANT SMALL BREAK ANALYSIS j 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF I

CHARGING INJECTION AT 1200 SEC TWO-PHASE CORE LEVEL 100-J

! 80-l

i. 60-L

. t

! x I 40-i l

l 20-i

.i r

U ,. , ... ... ,. ... .,. .,. , .,. .,

i 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC) e 6-47 l

O i

FIGURE 6.31 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING FLOW AT 1200 SEC BREAK AND CHARGING FLOW 450-400]

i 4

350f i

300i F

0 W250i I

N j200j

/

is04 g 7

100f 54

.. . .... . h.b t + - u ,,.,tt w m W(

i 0 , --------- ! , , , , , , , , _,

1000 2000 3000 4000 5000 6000 7000 0000 9000 10000 0

TIME (SEC)

LEGEND: CURVE BREAK FLOW -- --- CHARGING F LOW 6-48

O

a. FIGURE 6.32 HADDAM NECK PLANT SMALL BREAK ANALYSIS i

0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION AT 1200 SEC HOT LEG TEMPERATURE a

I 590-4 fl i 580i L

570i 560i 550i

[

E 5402 '

530; 520i 510i 500i 490-)

7"- , , , , . ,- , , . ,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME ISEC1 O :

1 6-49

FIGURE 6.33 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION AT 1200 SEC STEAM GENERATOR PRESSURE 950; 925i 900i 875i 850i g i

\ >

g825i \

B \

800i

\

S (

i i

750i \

\

7252 \,

\

700i 'g

\. .

675i \, ,

O ~i ,a 2a ,a a .a .a TIME ISECl 7a .a ,a ,a.

AFFECTED LOOP ---- UNAFFECTED LOOP 6-50

O f

FIGURE 6.34 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.02 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION AT 1200 SEC STEAM GENERATOR MASS 70000-67500-650002 -

62500-I 60000-575002 550002

!5 52500-50000-B M 47500- ,

45000-425002 40000-

- 'I ' '

f,Y{;Y ' $'El 32500-O --

, . - --r 0 1000 2000 3000 4000 5000 6000 7000 0000 9000 10000 TIME ISECl AFFECTED LOOP ---- UNAFFECTED LOOP 6-51

t O

i i FIGURE 6.35 i- HADDAM NECK PLANT SMALL BREAK ANALYSIS i-0.03 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF 1 SG COOLDOWN AT 300 SEC (100 F/HR)

PRESSURIZER PRESSURE

2100; 2000l l 1900f J

! 1800f 1700f

, 1600i ,-

1500f J

1400f j P ,

t R 1300--

1 S I S 12002 ' ,

' U <

a R E!100f j P 1; $1000f I

f ,

, 900f ,

8002 700-]

} 600-)

500f 400f i

l 300f 2002 b Sb0 10b0 15b0 20b0 25bo 3bbb 35b0 TIME ISEC) l 6-52

O FIGURE 6.36 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.03 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG C00LDOWN AT 300 SEC (100 F/HR)

COLLAPSED CORE LEVEL 100- q O

60-l i f \

X 140-I 20-kh h6,m .

O 3

e . . . . _

f!ME ISEC1 6-53

O FIGURE 637 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.03 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 300 SEC (100 F/HR)

BREAK AND HPSI FLOW 700-

~

650-6002 550-500-O 450-F L .

0 400-3502 L

B I M 300-.

t

/

s C 2002 2002 1502 i

1002 502

'I d_ _,t,,g,- } p= A a,

w 0: p . = ........ ..............................................................................

0 500 1000 1500 2000 2500 3000 3500 I TIME (SEC)

L E Gf p60s CUHVE BRERK FLOW ....... HPSI FLOW 6-54

i i

O 1

4 FIGURE 6.38 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.03 S0.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 300 SEC (100 F/HR)

COLD LEG TEMPERATURE ss ,

sw.

I I s, J

Si.

O T s

f te c ; -

l

[

e f-e -}

I l'

f 4/

, w.

I to '.

4. -

4 f i 4 ., -

)l ys, i, i i i 4 ' i, . . , .,,... . ,, .... . . , ,. - ,.

(s t

. I ll e<y j ', f > ' i *I lf)

. ,8 f 'l t li i 6' ' i nm .u,

) 6-55 s

i

- - - - - - _ ..v. . - - . - - - . - _ .

1 l

O ,

4 i L

FIGURE 6.39 HADDAM NECK PLANT SMALL BREAK ANALYSIS l

0.03 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 300 SEC (100 F/HR)

STEAM GENERATOR PRESSURE 950-I 9002 .

I I .

j esol j 800-a 750-I 7c0T

) {

P

~

7 R 650-E 'l

! s ,

S .

f U 600- gf (

R E

! 550-~ !

l l

P ,

S 500-h

%,jh 3

4502 .

400-i 350-.

3005 250-l

+,. _,. ,

i , .,. , .. ,

0 500 1000 1500 2000 2500 3000 3500 l

i r!ME (SEC)

AFFECTED LOOP ---- UNAFFEC TED LOOP 6-56

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

t l'

i O l r ;

i

! FIGURE 6.40 i

' HADDAM NECK PLANT SMALL BREAK ANALYSIS !

O.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF i

! PRESSURIZER PRESSURE i

5 ~

i 2000-

'1950-1900-I 18502 l l

1 !

i l 1800-i '

l . I j 17s0-

!- P 17002 R

E 5

$ 1650-U l R i E ,

2600-- i 9 (

S '

I f l n 1550- ,

1 ;

i l 1500-i i sus 0- l 14002 f f f

(-

1350- Y

(~Y l 1 !

l 13002 !

t W

{

l 12502

{ b 10bo 20bo 30bo 40bo 50b0 sobo 70bo 80E0 90b0 100b0 TIME ISECl l 6-57 ,

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

)

i O -

i i

1 FIGURE 6.41 i HADDAM NECK PLANT SMALL BREAK ANALYSIS

{: 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF PRESSURIZER LIQUID VOLUME i

l 650- ,

~

i l 600-l' i

sso- !

i .

1 .

j 500- l I

1 450- '

! L 1 I l 0 400-U 1' 1 1 D .

4 350-I V 1 e

! L .

4 U 300-l E i

250- T F

T .

3 200-150-6

, 100E ,

j S0-j 02 b 10b0 20bo 30bo 40b0 50b0 60b0 70b0 80b0 90b0 10h00 j TIME 15EC) i h

O 6-58

j-L FIGURE 6.42 HADDAM NECK FLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF j

l REACTOR VESSEL TOTAL MASS

^

162000-i 151500- {

i 161000-l 160500-160000-I 159500-M 1590002 4 A S

a 5 150500-I L .

B 158000- ,

157500-

[ 157000-i i 156500-156000-1555002 I

155000-10b0 20b0 30b0 40b0 50b0 60b0 70b0 00b0 90b0 1000b TIME ISEC)

!O 6-59

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

i.

1- 1

j. i i !

I FIGURE 6.43 HADDAM' NECK PLANT SMALL BREAK ANALYSIS l

)

0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF i I

{ COLLAPSED CORE LEVEL j- :

1 i

l i i

e t

I

,{ i jl l j' L I

L E

l- V 100-

. E L

I r

f l .

! l f

l

! i l

f b 10b0 20b0 3bb0 140b0 Sbbb 6bbb 7bbb ebbb 90bo 10b00 TIME ISEC)

(

! 6-60 t

~ _ _ _ - _ - .-

1 i l 1 t

i.

+

b ,

1 1 1

i FIGURE 6.44 l

! HADDAM NECK PLANT SMALL BREAK ANALYSIS

} 0.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF I

TWO-PHASE CORE LEVEL 1 l

l. '100- i

)

i.

i 1

80-l 1

i I

1

(

! 60-f I. L j E

v i E i L i

a 40- ,

l I f a l I

l I

}

20-t i

I 0- --

-t i h 10b0 20 0 30 0 40bo 5000 60 0 1000 00b0 90b0 10000

TIME (SECl

[

I l 6-61 I

f~s l

\

FIGURE 6.45 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF BREAK AND HPSI FLOW l

Ilui (j I

1002 g j:'

e :

90 . :: :

60 . .

j'. ::

r t 7 0,.

o w -

. : : :a 60i l l .

g :{ g' i

a

- l! .:E.

ii.

i n

/ 50 i i

li r A: 'd :: ,,

'i --

s :\

^ ' ' :. ...

i . -..--

--1 ! ] \, *, '- ' .'**.-

S j : f ..*

C - ;: .' :

C g

j; ; g *t s: ;!

40f

.f !! ! !:

k;

-i : :

30.: : .

1 i ; :if 1 : .: 1 ::

20 "

3 : l' *!

4

se *::

1 :

10i j 02 -!

b 10b0 20b0 30b0 40b0 50bo 60b0 70 0 00b0 90b0 ObOO IIME ISEC1 LEGEND: C Uf1V E BREAM FLOW ......- HPS I F L O W 6-62

i i

i

! i 4 .

O !

t t

i FIGURE 6.46 '

i HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF a

HOT LEG TEMPERATURE i

t-585-f _ !

! 580-i 575- '

i 4

f 570-t I

i

565- ,

l 1 i .

E 550-M e

O P E

R 555-R I

f ,

U .

R 550-E '

i 545-4 i F

Suc_

k 0 1

t 535-4 l

530--

I j tas-4 0~, , , , , , , i e v Y

! O 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME ISEC) i i

f i

t i

i O

1 6-63 f

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

1 i

O FIGURE 6.47 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF STEAM GENERATOR PRESSURE I 1

950-T

^

925- f I

900-f 875-850- .*

4 i

825-i O P A 800--

E

' 5

! 5 i 1 U 775-i H

[

} 750-1 1 P

! S 725-

i A :-

)

i 700-675-4 I G50-i ii2'.o j fiOO.-

' O ' y me r m . . . . . . , ; , , , , , , , me O 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 O 11ME ISEC) f i

]

6-64 f

4

- . - - , - . - . - , _ - , , , - - - _ . . - , ._ .-- - ,,-..-- -- .- - -,..- , ...- --- ,...,-,,,_ _ .-. .n

O FIGURE 6.48 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF STEAM GENERATOR MASS

v. u n , --

51000-4 tit:O O -

450003 ,

42000-.

39000

~

%000j E k 04 E

13n00 300002 L

B M 2 7000-

/40002 210002 t ttCON

/t t 3 0 0 0 y.mmer , y - -..,+re - ~ t**-- , , --+---+--1 ++v - - *

r 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10r00 fIME ISE Cl AFFECTED LOOP -- - - UNAFF EC TE D LOOP 6-65

FIGURE 6.49 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION PRESSURIZER PRESSURE

300f _ , _

$ '3' i

2/06 ]

}

ilrm 1

3 rqur, j 1

i O 19ue j 1

)

18001 N 3 i it

,>04, c

e i s 1t:

30 }

l t yic -

l l i. n.,: .

im 1200-'

?

iib 3,, m .-n .3 ,,,- . ,,-.- .-~.,r-,,r+-+~+++t*~m"'-~'**v"'~++t"+~~t Ox 0 1G00 2000 2000 4000 sono 6000 1000 8000 900r)

T [ Mt. I S f (. I

(> - f> 6

i i

ir i

! I i

4 O !;

i ;

i FIGURE 6.50

! HADDAM NECK PLANT SMALL BREAK ANALYSIS

t. 0.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF

! CHARGING INJECTION i

PRESSURIZER LIQUID VOLUME 900-1

(

. 1 i son I

i 700 *

'l .

l t

} S09.. '

t t. .

{ C i f U i f 0 5002 I I

V i

! o

t U

l M 4C0- '

i

} l' l 1 1 l f 3 3004 i i

?cn- ,

I i i I i 100-F t

0,__,- . . . . . . - -

0 1000 2000 3000 4000 5000 6000 1000 0000 9000 l

j fine. ist u !

t i O

6-6/ [

t t _ . . . . ._. .__ . _ _ -- - .'

i ;

i, !

4 i

h ;

i

! r 1

4 I

i FIGURE 6.51 HADDAM NECK PLANT SMALL BREAK ANALYSIS j 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF i CHARGING INJECTION REACTOR VESSEL TOTAL MASS

} i f>UGOO -

l 7 It,h000 I

i i 140000i

'130000-. .

1 120000i M

l A 1100002

s

+ 5

) 100000L I L r i M

?

j 90000--'

f:000 i

,- 70900i l l :

1 I

I .

60f2002 l

1 l

! s m oo b . .. . _ .., _ _ , ... . .,. ,

0 1000 2000 3000 4000 $000 6000 7000 0000 9000 j !

1 11ME Ist Cl 1

i i

6-68

O FIGURE 6.52 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION COLLAPSED CORE LEVEL 120--

100- --

80-t lc0_

7 40-20-0 0- r*-** ~ r*++++++ m ++ ~ + ,

0 1000 7000 1000

--r 4000

++-+ +r - + r-+ +-r :

TIPE (SEC1 5000 6000 1000 0000

,+ +++++++r 9000 6-69

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

O FIGURE 6.53 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION TWO-PHASE CORE LEVEL 100-60-O 60-E l !

L X

11 0 -

p 20-TIME (SECl O

6-70

O FIGURE 6.54 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION BREAK AND CHARGING FLOW ,

1 70-< l l

65-60-5,5-50 &

452 f

L 0 t40-W l 3% , p ,.. ~ "**"* % ,,

l L l'~ 'N '

302 \.

{~

5 E .

i N

C 25- \,

1 I '.'.

! : s l

20 i \.,

g Ao , m. q 15- :

i 10- :

I S- !

O d ,_, ,, _ _ , _ , ,,_ .,_ , , , .,

0 1000 2000 3000 4000 5000 6000 7000 0000 9000 TIME ISEC) 0 LEGENO: CURVE BREAK FLOW ....- CHARGING FLOW 6-71

O FIGURE 6.55 HADDAM NECK PLANT SMAL'. BREAK ANALYSIS 0.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION PORV FLOW

$50-325-300 1

215:

250) 225:

200 I75--

8 150-

,25:

~

100-25-5 0 ---

25-

~

0 1000 2000 3000 4000 5000 6000 7000 0000 9000 TIME (SEC) 6-72

i FIGURE 6.56 .

1 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF l CHARGING INJECTION i HOT LEG TEMPERATURE d

710-1 200f 1 I 690i 680f i 6702 b'

660i i

650f 6409 6302 l :

e20, T

610f 600-i 590i 500 [

570f 560f k

ssai

su0f 530f 520 ,, ,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 TIME (SECl [

l AFFECTED LOOP --- - UN AFFECTED LOOP 6-73

4 O

FIGURE 6.57 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION STEAM GENERATOR PRESSURE 1000-900f fff I ,,t, t8

1 800f

~

700 P

R 600f S

S R

E 500f P

S 400f R

300-200f 100f I i, E....---.=___ ................_ ._

9000 1 s 4000 5000 6000 7000 8000 0 1000 2000 3000 TIME ISEC)

AFFECTED LOOP - -- - UNAFFECTED LOOP 6-74

FIGURE 6.58 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF CHARGING INJECTION STEAM GENERATOR MASS 55000-1 50000-]

45000f 40000j 35C00m 30000i 25000i 0

2o000' 1500Ui 10000i 5000i %

b lobo 20b0 30b0 40b0 50b0 60b0 70b0 00b0 90b0 TIME (SEC)

AFFECTED LOOP ---- UNAFFECTED LOOP 6-75

1 O

i FIGURE 6.59 t

HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS l WITH 1 PORV AND 1 CHARGING PUMP ,

PRESSURIZER PRESSURE 200d--

19005 i 18002 1700-~

o ,_2 15002 14002 11002

( .

P I?OD 11002 10002

~

4 900-B00-700-600-l -, .- . . . . . . . .

3000 4000 5000 6000 7000 8000 9C 00 10000

! O 1000 2000 TIME ISEC) 1 6-76

i s

FIGURE 6.60 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH-1 PORV AND 1 CHARGING PUMP PRESSURIZER LIQUID VOLUME 1200-1100-~

10002 9002 O !~;700-e 600 W

E 500-F 400-3 300-2002 100-0

^

b 10b0 20b0 30b0 40b0 50bo 60b0 70b0 80b0 90h0 100b0 TIME (SEC)

I O

6-77 4

-,<e--r_- . ~ . - --,,--y,-,,__-.1,__.-.4m,4 - - , -

-__-_m,. ,r,,,_--,.,.,,m._,,--c, _,-.._,,___-.,r,.,--.-.y,_ -

O FIGURE 6.61 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP REACTOR VESSEL TOTAL MASS 160000-L 1

150000i j

140000i i

130000i 120000:

1100002 5

100000i 90000i 80000i l

70000i 60000i i

50000; r

30b0 t&Obo 50b0 60b0 70b0 8bbo 90b0 1000b 10b0 2bb0 TIME ISEC) 6-78

a O

FIGURE 6.62 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 S0.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP COLLAPSED CORE LEVEL 120-100-Nolj o 00:

sn-X 40-20-80b0 70b0 80hD 90b0 10 BOO 10b0 20b0 30b0 40b0 50b0 n n us w Q

6-79

O .

FIGURE 6.63 ,

HADDAM NECK PLANT SMALL BREAK ANALYSIS 2

0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS l WITH 1 PORV AND 1 CHARGING PUMP TWO-PHASE CORE LEVEL 100-j 80- 6 O

~

60-E l

L 40-l f

20-e i

4 0,. ,,_ .,. ,,. .,. _,. .,_ .,. .,, .,. _,

1000 2000 3000 4000 5000 6000 7000 0000 9000 10000 O

O TIME (SEC) 6-80

x

'xN FIGURE 6.64 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP BREAK AND CHARGING FLOW 70-65 60 1

. I 55-~

l 4

45g 40-

- I - . .

35- f I\ -

'**~~..

305 .-

/

C 25 -

b

. i 20-l 15- I l

4 %%t s: ;

J 0,~--~- , , , _,_ , , , , _,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

, TIME (SEC)

LEGEND: CURVE BREAK FLOW ------- C H A RG I N G F L O W 6-81

O FIGURE 6.65 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP PORV FLOW 100; 90i 80i 70i O F 60i 50i B

s u0,l C

30i 20-]

10i 02 , , , , , , , , , , ,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC)

O t

6-82

O FIGURE 6.66 4

HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP

. HOT LEG TEMPERATURE 610--

600-) ;

593i 5%

5802 ~

O 570-!

560i

11 l I 6 i f

[

g550i I I

,SuGi 530 !

5202.

510-!

l 5002 , , , _,. , .,_ , , .,. _,. ,,

4000 5000 6000 7000 8000 9000 10000 l 0 1000 2000 3000 TIME (SECl 6-83

. --_-.-_.-....-__-._.-.......-._..-__--_-_._.-__...._----_..-.~D _

i FIGURE 6.67 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP STEAM GENERATOR PRESSURE 1000; 900i 800

~

700i E 600i B

E 500i 400i A

300-)

200' 100i b IOb0 20b0 30b0 40b0 50b0 60b0 70b0 80b0 90b0 100b0 TIME ISEC)

O 6-84

FIGURE 6.68 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP STEAM GENERATOR MASS 55000--

50000g 45000i 40000i h-35000 S 30000i 25000--: h g k 20000i 15000i 10000i

\

5000) 5, b 10b0 20b0 30b0 40b0 50 0 60 0 'Ob0 80b0 90h0 100b0 TIME !$EC)

AFFECTED LOOP - - - - UNAFFEC TED LOOP 6-85

^

4 FIGURE 6.69 HADDAM NECK PLANT SMALL BREAK ANALYSIS

! 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF

SG COOLDOWN AT 900 SEC. (75 F/HR)

PRESSURIZER PRESSURE 2100,

2000f 1900f i

1800f

, 1700f l 1600i 15002

, 1400f

! P R1300i 5

1200i

R EIl00f P

S 1000i n

900i 800f 700i 600f 500i

! 400- ,

l !

j 300i 2001 i , , ,

! O 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 TIME ISEC) !

l 6-86

}

'.... . _ _ . . . ~ . . _ . _ _ _ . _ _ . _ _ , _ , _ _ _ _ . . _ _ . . _ . _ _ . _ _ _ _ _ _ _ _ _ _ _ . _ , . , _ _ . , _ _ _ , . _ _ , .__ _. ,_...-_ _ _ _ - __.

3 4

J o :

J FIGURE 6.70 HADDAM NECK PLANT SMALL BREAK ANALYSIS .

0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG C00LDOWN AT'900-SEC. (75 F/HR) 4 PRESSURIZER LIQUID VOLUME 650-1 600-I 5502 ,

500-usa:

400A I

D .

350-V O

L U 300-M E

250 F

T .

3 200-i 1502 i

100-50-1 9' ,. k__

n .

1

i 0 L.U U 1200 1800 2400 3000 JGuo 4200 4800 ?,400 tnoo I

TIME ISECI

~

i i

O .

I 6-87 i

- , , - - -nn,.n.,. - - _ _ , - , , , , , _ , , ,

k O

FIGURE 6.71 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 900 SEC. (75 F/HR)

REACTOR VESSEL TOTAL MASS 160000--

155000-150000-f-

d 1450002 1400001 135000-130000-5 4

125000-

)

4 B 120000-M '

115000--

1100001 105000-

)

10n000 I u

95000-900002 , , , , , , , , , , , I 0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 j

TIME (SECl

!O 4

j 6-88

.. ~_u .y. __4_ _ . a..._e.....A__ ..- a.. e. 4 am a a A. *---_-.m-- . _ a a O

FIGURE 6.72 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 900 SEC. (75 F/HR)

COLLAPSED CORE LEVEL 100-l 99f i

^

97-96-'

95i O ,,4 ,

92f E 91 --'

90

x e,4 88 874 h l 83-I e2..

I el , , , , , , , , , , ., j 0 600 3200 1800 2400 3000 3600 4200 4800 5400 6000 TIME ISEC) 6-89

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

III ~ j i-O 4

FIGURE 6.73

! HADDAM NECK PLANT SMALL BREAK ANALYSIS !

0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF '

SG COOLDOWN AT 900 SEC(75 F/HR)

TWO-PHASE CORE LEVEL i

100-4 80-4 i

3 I

O 60-E V

E L

X i 40-4 4

5 i 20-1 l

h *', , , , , , , , , ,

6000 1800 2403 3000 3600 4200 4800 5400 0 600 1200

' TIME (SEC) 6-90 J

FIGURE 6.74 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 900 SEC. (75 F/HR)

BREAK AND HPSI FLOW 70-652 ;

602 55-1 502 45-F L ,

0 40-3sl a

M 30-

!C 25-202 15- r

^~-

102 52 0_ . .. .. . .. . . .. . . . .. ... . .. ...... ... . ...... .. .

0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 ;

TIME (SEC)

O LEGEND: CURVE BREAK FLOW ....... HPSI FLOW l

6-91

I i

4 FIGURE 6.75 HADDAM NECK PLANT SMALL BREAK ANALYSIS 1 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF

. SG COOLDOWN AT 900 SEC. (75 F/HR) i HOT LEG TEMPERATURE 590-

.e

! 586-

.I 570-a j

56d-5502 5402 . ,,

E 5302 i

E .

g520-T 5102 500- i 1

F 490-l 480-4702 4602 f 450-1 4402 , , , , , , , ,. , , ,

0 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 TIME (SECl AFFECTED LOOP - -- ' UNAFFECTED LOOP i

6-92

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

O FIGURE 6.76 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 900 SEC. (75 F/HR)

STEAM GENERATOR PRESSURE 950--

900i 850i 800f \

750i *j 'J ., ,

N 1

E 700i

. 3 650i l P 600i 5

550i 500i

E 3 3

400i O 350i.r - . . . . -

! O 600 1200 1800 2400 3000 3600 4200 4800 5400 6000 TIME ISEC)

AFFECTED LOOP - - - - U N AFF ECT E D LOOP 6-93

(J FIGURE 6.77 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.003 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF SG COOLDOWN AT 900 SEC. (75 F/HR)

STEAM GENERATOR MASS 95000-900002 '

j a

850002 J j ,{(WId f Y , k 80000-75000-f%

70000-650002 5

!cc0002 55000-8 .

M 50000-450002 40000-35000 300002 25000-b Sb0 12b0 18b0 24b0 30b0 36b0 42b0 48b0 54b0 60b0 TIME ISECl AFFECTED LOOP --- - UN AFFECTED LOOP 6-94

1 O

FIGURE 6.78 HADDAM NECK PLANT SMALL BREAK ANALYSIS

STUCK OPEN PORV,RCPS OFF

- NO SAFETY INJECTION

,' PRESSURIZER PRESSURE

! 2100-2000f I

1 1900f l

1800f 1700f f

1600f 1500f 14002 P

R1300f s

1200f a

' E 11002

{ 1000-

, 900i 800f 700f i

600f

i. 500f 3

i 400f 300f i

2": . ... ... . . . . . . ... ..

0 1000 2000 3000 4000 5000 6000 7000 0000 9000 10000 TIME (SEC) i l 6-95 i

l-

- Mg 'p {. , , 'L.s g-i.

1

- FIGURE 6.79 '

HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF ,

I NO SAFETY INJECTION '

PRESSURlZER LIQUID VOLUME ,

1300-1200i

I 4

1100i 1000i

O

0

_4 8005 0

I L

700i

sa

3 ,

! F 500i t

400i l 300; l

i

,- . , , i

. . , i 10000 3000 4000 5000 6000 7000 8000 9000 0 1000 2000 TIME (SEC1 O

i

- 6-96 l

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

1 O

1 FIGURE 6.80 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF NO SAFETY INJECTION REACTOR VESSEL TOTAL MASS j 160000-

J l

1500001 4

1400001 l

{

1300001 i

a 1200002

!!00002 1000002 l

A .

t 90000-i 80000I g

700002 60000-1 50000-40000-

, 30000-l 200005 ,y 100002 _,,

O 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 i TIME (SEC) 6-97 i . _ _ _ - _ _ _ _ _ - - _

O FIGURE 6.81 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF NO SAFETY INJECTION COLLAPSED CORE LEVEL 100-90i 80i 704 60i E

50-7.

40f 30i 2i l o .>

.. .. m TIME (SEC1

.. .. .. .. =_

6-98

O FIGURE 6.82 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF NO SAFETY INJECTION TWO-PHASE CORE LEVEL 100-80-i O 60-L 40-20-0 ,_ ,

_y,,

0 1000 CO *: ) 4000 5000 6000 7000 0000 9000 10000 TIME (SEC) 6-99

FIGURE 6.83 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF NO SAFETY INJECTION PORV AND HPSI FLOW 70-i 4 ss-

p. !:

^

... !1 60-

ji v\ :

!i j

i i. :i B

is i \:

55 ' 5 i !: ,

,:. i :! :

g: :! i 50-3i V j i i

ii i- !

-=: :

uslii 11 , i. i:

-- i. : i : n

) I : it g F '.D I

L : : l .l}

O 40- :a!. .. 3 II : .

'a

y * *1 w :* ,

1 I

I i j i*

35-: : a

,::l l

' I e :i is M 30-: ( .

/ -: :

S ;; '

E .?

C 25-;

20 i 'f.

Is-l

%M

~ 't .,,

i 10 ! ~

S h

, y ,

0- ', ,

5000 6000 7000 8000 9000 10000 0 1000 2000 3000 4000 TIME (SEC)

LEGEN0s CURVE HPSI FLOW -- - PORV FLOW 6-100

O FIGURE 6.84 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF NO SAFETY INJECTION HOT LEG TEMPERATURE 840-8102 :

I 780f ,

750-7202 6902 660-- '

S . :

630- ,

R E .

600-- ,,

F 570 !

540f -

510-4802 l l

4%-

, , , , i , 1 i i i- 1 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC) l l

6-101 l

n O

FIGURE 6.85 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF NO SAFETY INJECTION l COLD LEG TEMPERATURE 550; Oi .

530i 520i 510i O -

500 e

4 a

490i w

480i 470i 460i h 450i /

quoi g 4302 , , , , , , , , , , .,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC) 6-102

s.-

c s

1 FIGURE 6.86 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF NO SAFETY INJECTION STEAM GENERATOR PRESSURE 950-

^

"[

i -T" 'r

, 900i 850i 800i O > 04 E 700i 8

, 650i I

{600i A f 550i 3

500i 250i ,

4

/

I i 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 f

f!ME (SEC1 l

6-103 j

l .-. . . - . . . - . - - - . _ , _ . - , . _ _ . - - . . _ . - . . . . . . - - , - _ - _ - - - _ . . . - . . - - - - .

(

FIGURE 6.87 i

HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF

' NO SAFETY INJECTION STEAM GENERATOR MASS 105000-1000002 950005 ,

f f

900002 850002 800002 750002 5

S 700002 65000-B -

M 60000-55000 50000-450002 400002 35000 30000-O 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC1 I

6-104

t E

O i

FIGURE 6.88 l HADDAM NECK PLANT SMALL BREAK- ANALYSIS STUCK OPEN PORV,RCPS OFF LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC PRESSURIZER PRESSURE .

2100; I

20001 l

1900k

1800k

^

1700h i 1600f 1500f f I

1400f

. P 4

R 13002 -

. E i S .

5 1200- ~

.. E 11002 R ,

4 900-800f i

, 700f 1

j. 600-}

! 500i 400f 3092 2002 0 2000 4000 6000 0000 1%$0

.i TIME ISEC) 4 5

d

> 6-105

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

4 .

!!1 a.

i

O i

FIGURE 6.89

. HADDAM NECK PLANT SMALL BREAK ANALYSIS

!- STUCK OPEN PORV,RCPS OFF 4

LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC PRESSURIZER LIQUID VOLUME 1300-I 5 1200:

'! j 11002 t 10002

! ~

900-

[

800-i D .

700-

~

E :t 600-E 5002

$ ~j .

j 3 400-300-200 i

1002 l

0 10b0 20b0 30b0 40b0 50b0 60b0 70b0 80b0 90b0 100b0 TIME (SECl i

O 4

6-106 7-+ - - -e > , , ,- , ,w-v,-, ,,wwc-,e,--g--,,,n w ., ,,-- -w,-,,--w,,.--,.,,-. ..,w-,- ,. ,---w,----- - - - - - - , . ---.w.--

l l

O FIGURE 6.90 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF

LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC REACTOR VESSEL TOTAL MASS i 160000; jJ 150000i 140000i l 130000' 120000i t

!100002 100000i 900002 '

'y

r naash . . .

v 'q u T F g 80000i 700002 50000i 4 s=~, , , . , _,

0 2000 4000 6000 8000 10900 i TIME (SE C) lO i

! 6-107

v]

r FIGURE 6.91 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC COLLAPSED CORE LEVEL 100-90 os l- '

l ' Tj ', . j' x_, .

, ,,_u w ),

I 'M I 80] '

i i

70y

, O 60$

E 53f 40i 30f i

PQ l

10 0, -_7 0

0 2000 4000 6000 8000 10ZO TIME (SEC) 6-108

i-

!O i

- 1 FIGURE 6.92 HADDAM NECK PLANT SMALL BREAK ANALYSIS -

i STUCK OPEN PORV,RCPS OFF i

! . LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC l TWO-PHASE CORE LEVEL i

. 100-3 s

! t

! [

80-I

!O I

60-L E

{.

i V E

L i 40- l L

I l

20- ,

i i

i 0,. ,,. .,. ,,, .,. , ,,_ ,t ,

f , .,. .,.

4000 5000 6000 7000 8000 9000 10000 0 1000 2000 3000 j TIME (SECl i

i i 6-109 4

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

t ;

N l

{d l I

I FIGURE 6.93 i HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF ;

LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC PORV AND HPSI FLOW I

70-4 652 ,.

s,i .n.A .

60- !:{

;: ; t i :

! \ l N: .::!!

.i l ;

50$f Y : !

I 1

45-.U i',h,f 'O r i

-E.

l It r . o i i 0 40- l N I ! I i

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11 i i

! 352 !

p,}

1 L

B

if, t

M 30-.;: 1: I

/ 'l

'4 l 5 '

? E C 25--;

.i l

1 202 .

I j 15- ,

g 4

10l j L- I j 02 , , . , , , , , , , _ , _ , , . . , _

0 2000 4000 6000 8000 10000 l

I TIME (SEC)

LEGENO: CURVE HPSI FLOW ....... PORY FLOW

[ .

i i

} i 6-110

p t

A l

FIGURE 6.94

HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF J LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC

. HOT LEG TEMPERATURE l 590-580f i

5702 1

l 560f 1

550-540f - _

l 530i 520f E

M 5102 E .

g500- 7 i T U 490i E

400; 2

470-460f 450{

440--

430f s o)--

410f

2 .. . ... , , ... , , , , _.7 O 1000 2000 3000 4000 5000 6000 7000 800C 9000 10000 .

TIME (SEC) 1 6-111 i

i f FIGURE 6.95 i- HADDAM NECK PLANT SMALL BREAK ANALYSIS j STUCK OPEN PORV,RCPS OFF LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC ;

l i

STEAM GENERATOR PRESSURE i ~

' 950-T

~

1[ e

] 900i i

i

! B50i i

800i 750s I

P <

R

, E 7002 '

$ 6 S

U R

4 E 650i I

i

! P 6002~

S R

550i I

}

f 500i j i

Wai i

i uus :

l l

3502 , , , . -r 2000 14000 6000 8000 10000 f 0

l i TIME ISECl I

AFFECTED LOOP ---- UNAFFECTED LOOP l

! 6-112 l'

4-FIGURE 6.96 HADDAM NECK PLANT SMALL BREAK ANALYSIS STUCK OPEN PORV,RCPS OFF LEAK ISOLATED AND SG COOLING INITIATED AT 3600 SEC STEAM GENERATOR MASS 100000-0

8 950002 90000- ,

ESC 002 )h iv 80C00-O 75000-A 700002 5

05000- j E0000-M 550002 500002 4500%

y fjf)f # rj-3500ri .;f

>=o, ,

6000 8000 10av) 0 2000 4000 TIME ISEC1 AFFEC TED LOOP - -- - U N AF F EC T E D LOOP 6-113

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

lI s

'4 Y,

LO i

L FIGURE 6.97 HADDAM NECK PLANT SMALL BREAK ANALYSIS 2

FOUR MAIN COOLANT PUMP SEAL FAILURES NO SAFETY INJECTION ;

PRESSURIZER PRESSURE l 2100-i l 2000i 1 l

)

! 1900i

+

i j 1800i l

17004 I P 1600i -

1 R E

l .

i 5 !

$ l 1

u 15002 '

t R E

P I i $ 14002 '

I A

f i 1300i 4

i I

I i 120Gi l

1 l.

i

! 10ood w m __ - .;- - ._,_

9002 ,, _ , _,. , , .,_ , , , .,. ,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 l TIME ISEC) i 6-114 i j

) ,

I

i O -

i 1

FIGURE 6.98 i

HADDAM NECK PLANT SMALL BREAK ANALYSIS

FOUR MAIN COOLANT PUMP SEAL FAILURES 4

NO SAFETY INJECTION l PRESSURIZER LIQUID VOLUME 4

650-i 4

600-i 550-500-l 450-L 4001 l

D 350-

< V

+ 0 t L 4

0 300-M E

250-

F I

T

) 3 200-6 1 150- ,

f 4

1002 i

50-g , _ f.v - u- - - u- ' .8p 4 d v ;"_

, ,. -m , , .,. , ... ,- .,. ,.., - ,y 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10009 TIME ISEcl I

lO 4

s 4

6-115

}

r ,

4 !

.i :

4 iO 1

i i

FIGURE 6.99 i .

! HADDAM NECK PLANT- SMALL BREAK ANALYSIS

FOUR MAIN COOLANT PUMP SEAL FAILURES

]

NO SAFETY INJECTION

! REACTOR VESSEL TOTAL MASS l i r l 160000-

~.

t !

s

{

150000-i

l, i' 1400002 !

I 130000 '

i !

! 1200002 1

1100002 f 3 M 1000002 I

l S

u_ i _ __

j 90000-.

?

i L

4 0 80000--

j M 700002 l

i ;

i G00002 '

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50000-

{ .

! 1 4000'J-I .

j 30000-

}

\ .

j 20000 ,. ;,, ,,. _,. ,,. , , , _,_ ,

1000 2000 3000 4000 $000 6000 7000 8000 9000 10000 ,

0

[ TIME 15EC1 I

i 6-116 i L

s4-- c --v, W m e . , - - . .e

O FIGURE 6.100 HADDAM NECK PLANT SMALL BREAK ANALYSIS FOUR MAIN COOLANT PUMP SEAL FAILURES NO SAFETY INJECTION COLLAPSED CORE LEVEL 100 905 I

80i 10:

O 60-E 50f x l 40f i

30f 1

20i I h b l YY 10-02 O . Icc, ,ccc >ce. ..c. ,cc.

TIME ISEC1 cc. >c.e es.c .c.c l<cm.

6-117

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

1:. .,

ii O

f i

FIGURE 6.101

} HADDAM NECK PLANT SMALL BREAK ANALYSIS FOUR MAIN COOLANT PUMP SEAL FAILURES NO SAFETY INJECTION TWO-PHASE CORE LEVEL 300- 1 9

80-l O 60-i L

E

v

! [

t x 40-i 4

i i

20--

{

i l

... ,- ,- -r i 0,. ,. .,. , .,. .,. ,

5000 6000 7000 8000 9000 10000 i O 1000 2000 3000 4000 i TIME ISECl i

I i

i 6-118 4

FIGURE 6.102 HADDAM NECK PLANT SMALL BREAK ANALYSIS FOUR MAIN COOLANT PUMP SEAL FAILURES NO SAFETY INJECTION SEALS AND HPSI FLOW 130-120-)

l!

110 k I!

100-'

lI 90I h

ii F 80 .,

e .

n, 70-' ,

}II L

00}!

8 i i')

50 g I-

C

j *.',,,,,,,,,p,y_.,.4 q 40- j ,

i i pj h, 10-l a

0 ... ... ,. - - r - ~ ~ r-e- .-+--+re---r-~+-m---,

,- +--r-0 1000 2000 3000 4000 5000 6000 7000 0000 9000 tm"n TIME (SEC)

LEGEND: CURVE HPSI FLOW - - . SE ALS FL OW O

6-119

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

t O :

I FIGURE 6.103 HADDAM NECK PLANT SMALL BREAK ANALYSIS FOUR MAIN COOLANT PUMP SEAL FAILURES l t

NO SAFETY INJECTION HOT LEG TEMPERATURE 585-

} !A 4

580f l

575i 570f v

1 T

565f "r

3

T 560 R

E '

l 555f r !

l $

, 550i i

i 545k 1

540f f

! 5352 .,. , , , , ,

'I O 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC1 6-120

U FIGURE 6.104 HADDAM NECK PLANT SMALL BREAK ANALYSIS FOUR MAIN COOLANT PUMP SEAL FAILURES NO SAFETY INJECTION COLD LEG TEMPERATURE 545.0-542.52 540.0 y h, 537.5- .

1 535.02 l

532.52 1

P 530.0- l 527.5-W

$25.02 F 522.52 520.01 517.52 515.01 512.5-510,02 .,_ .,_ .,_ _y 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME ISEC)

AFFECTE D LOOP - - - UNAFFEC T E D LOO P 6-121

l O

FIGURE 6.105 HADDAM NECK PLANT SMALL BREAK ANALYSIS FOUR MAIN COOLANT PUMP SEAL FAILURES NO SAFETY INJECTION STEAM GENERATOR PRESSURE 990-t a-

. - - ,. __,, , -- .... . . - ,, ,r 920; ll t

900! I i

880i 860i g890i a i I

820i P 800i A

j 780; 760 720i i -

7002 , .,. _,_ , _,_ , .,.

O- 0 1000 2000 3000 4000 5000 TIME (SEC) 6000 7000 6000 9000 10000 j 6-122

4 5

FIGURE 6.106 HADDAM NECK PLANT SMALL BREAK ANALYSIS FOUR MAIN COOLANT PUMP SEAL FAILURES l NO SAFETY INJECTION 4 STEAM GENERATOR MASS

< 100000- -

\

I '

950002 ,

! 8.n/o I 900001

. /

i j 85000-

/

i /

1 . e l 80000- j i s 750002 j l

M . /

A 70000-S /

/

i 5

/

l 65000-L 600002 B

550002 t

500002 l

45000-1400002 l

j 3%nn hf 30000- _ _ ,,, _,- ,, ,. ..

d 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SECl i

1 O AFF EC T E D LOOP --- UNAFFEC TED LOOP i

l 6-123 1

't-+-4.eww---e:,ww#...--e.- e.,-.-._,_ ----mime ,- m -e--- _evy-,-w,r-e--r----

(T 7. TOTAL LOSS OF FEEDWATER (FEED AND BLEED) ANALYSIS (v) 1.1 I nt roduct, ion The total loss of steam generator (S.G.) feedwater transient has been analyzed to determine the time available to establish feed and bleed cooling. Feed and bleed would be accomplished by using the pressurizer power operated relief valves (PORVs) in addition to the high pressure safety injection (HPSI) or the charging injection system.

Feed and bleed has always been regarded as a last resort method of decay heat removal to be used in the unlikely event of a complete loss of all feedwater to the steam generators. Fo r a complete loss of feedwater, results of this analysis demonstrate that feed and bleed can be initiated directly following the first lifting of the pressurizer PORVs at 2,285 psia without resulting in core uncovery conditions. This analysis has determined that the latest time to initiate feed and bleed is 2,400 seconds. If one chirging pump is available, activation of one PORV held in the open position is adequate in maintaining core cooling. If only one HPSI pump is available, both PORVs are required. One PORV does not relieve sufficient energy, after the HPSI is initiated, to maintain the primary pressure below the HPSI shutoff pressure of 1,400 psig, so that total core uncovery results at 6,000 seconds.

(s) t 7.2 Analytical Model U'

The total loss of S.G. feedwater transient was performed using the NULAPS code. A nodalization diagram of the NULAPS model is shown in Figure 1.1 and is very similar to the one used to perform the medium and small break LOCA calculations (see Section 6.2).

Additional assumptions made are briefly described below:

o The main feedwater flow ceases to enter all four S.G. at t = 0.1 seconds. The auxiliary feedwater flow fails to initiate.

o The reactor core is tripped 2.3 seconds after a low S.G.

level reactor protection signal of 10 percent narrow range (Reference 3).

o The reactor coolant pumps (RCPs) are assumed to begin coastdown 52 seconds after reactor trip. Under normal conditions, the loop 2 and 4 pumps remain running, powered by offsite power, while the RCPs in loops 1 and 3 trip 52 seconds af ter a scram (Reference 3). However, the outcome of the transient is not greatly affected by the number of RCPs in operation.

\ /

7-1

o Normal operation of the pressurizer heaters, both control

\s,,< and backup hanks, is assumed (Reference 3).

o The two pressurizer PORVs are assumed to lif t at 2,285 psia with a rated flow for each valve of 210,000 lb/hr at 2,400 psig (Reference 3).

o The charging flow delivers into the loop containing the pressurizer. In actuality, the charging flow injects in the loop 2 cold leg while the pressurizer is located in loop 4. Only valve #110A of the charging line is assumed to be open, which results in the lowest delivery flow.

7.3 Discussion of Results 7.3.1 Feed and Bleed Initiated at 2400 Seconds, One PORV and_ One Charging Pipmp The t ot al 'oss of S.G. feedwater analysis was performed assuming that the main feedwater flow to all four steam generators is lost instantaneously at 0.1 seconds. The low S.G. level signal setpoint of 10 percent narrow range (NR) is reached at 4.7 seconds. The control rods begin to drop in the tore at 7.0 seconds.

f- g Figures 7.1 to 7.9 show the major system response

( f parameters, q)

Following the initial RCS cooldown, the primary system begins to heatup as the S.G. heat transfer capability decreases due to the loss of feedwater flow and subsequent secondary inventory depletion.

Pressure oscillations can be seen to occur,at this time as shown in Figure 7.1. These oscillations are due to the periodic opening of the eight temperature controlled bypass valves to the condenser which are designed to maintain the Taverage below 545*F. At about 2400 seconds, the pressurizer pressure reaches 2285 psia, the PORVs opening setpoint. At this time the operator is assumed to begin feed and bleed by isolating one PORV, locking open the other, initiating safety injection with one charging pump, and assuring full flow from only valve #110A in the charging line. The primary pressure rapidly decreases due to the venting of steam and saturated liquid f rom the top of the pressurizer. A pressurization is initiated at about 2500 seconds, as shown in Figure 7.1, af ter the discharge through the PORV transists to liquid. PORV energy removal from the primary system is insufficient to accommodate the core decay heat generation until about 4300 seconds.

,_s At this time the PORV flow quality increases and the

! \

8 k

%J 7-2

(~'; RCS depressurizes. At 10,000 seconds the primary

( ,) pressure has been reduced to approximately 670 psia.

The pressurizer liquid volume, shown in Figure 7.2, decreases initially due to the system shrinkage at reactor trip. At about 2000 seconds the primary system fluid undergoes a heat up and expansion due to decreasing S.G. inventory and reduction in heat removal capability. The primary inventory expansion causes liquid to reenter the pressurizer. The pressurizer then contains a saturated bubbly mixture for the remainder of the event.

Figures 7.3 to 7.4 indicate that the reactor vessel mass begins to decrease at about 2000 seconds as the primary system saturates and liquid is lost through the pressurizer. The vessel inventory, shown in Figure 7.3, continues to decrease until about 5700 seconds, when the charging injection begins to accumulate in the RCS. The initiation of the reactor vessel refill at about 5800 seconds is consistent with Figure 7.6 which shows that the charging flow becomes greater than the PORV flow after about 6000 seconds.

Figure 7.7 presents the hot leg temperatures which 7-ss follow the RCS pressure after saturation conditions

( l are reached in the primary loops at about 2,000 seconds.

Figure 7.8 shows the steam generator pressure response. Following an initial increase due to the isolation of the main steam line at trip, the pressure is prevented from increasing above 930 psia by the two temperature / pressure-controlled bypass valves to the condenser. The sudden depressurizations are due to the opening of the eight additional temperature controlled bypass valves whirh are designed to maintain primary Taverage below 545 F.

The S.G. secondary mass is seen from Figure 7.9 to be completely depleted at about 1900 seconds. As indicated in Figure 7.5, no core uncovery is predicted for this event.

7.1.2 Feed and_Hiced Initiated at 2400 Seconds, Two PORVs and One ilPSI Pump This case is identical to the total loss of S.G.

feedwater presented above in Section 7.3.1 except that at 2400 seconds the operator is assumed to initiate feed and bleed procedures with two PORVs and O)

\

x_-

l l

7-3

,m

( one llPSI pump. The major system response parameteen

( are shown in Figures 7.10 to 7.18.

The pressurizer pressure, shown in Figure 7.10, decrease rapidly, upon the opening of the PORVs at 2400 seconds, to a pressure below the HPSI shutoff pressure of 1400 psig due to the rapid discharge of fluid from the top of the pressurizer. The injection l ceases, however, af ter a few minutes, as the primary loops pressurize again because the energy released through the 2 PORVs cannot accommodate the core decay heat. The system continues to void with a subsequent depressurization of the RCS. The llPSI shutoff pressure is reached at about 4000 seconds. Prima ry steam condensation by the injection of cold water into the cold legs f rom the llPSI pump causes further depressurization, increasing the HPS! flow.

Eventually, equilibrium is reached at 6200 seconds when a pressure of about 800 psia is attained wherein the PORV flow equals the liPSI flow, as shown in Figure 7.10.

The pressurizer liquid voluee is presented in Figure 7.11. The pressurizer becomes filled with liquid and is subcooled at about 5600 seconds.

Figures 7.12, 7.13 and 7.14 present reactor vessel

(~')s

( '

total mass, collapsed core level, and two phase core level versus time, respectively, and indicate that the core becomes saturated following the opening of the two pressurizer PORVs. After init.iation of the IIPSI flow at 4000 seconds, the reactor vessel refills and the core liquid returns to its subcooled state at 4700 seconds. During this interval, the core remains covered with a two-phase mixture.

The hot leg temperature, shown in Figure 7.16, follows the primary saturation temperature which is reached early in the transient. At about 5300 seconds, the primary loops, including the upper head, become completely subcooled due to the

continued injection of the cold llPSI water. Since

( the flow is greater in the loop containing the I

pressurizer due to the discharge out of the PORV, NULAPS shows that the hot leg containing the surge line cools at a somewhat faster rate.

As shown in Figure 7.14, no core uncovery results during this transient.

7.4 Summary, s The calculations presented in this section have determined the time available to establish feed and bleed following a

(

7-4

[] simulated total loss of S.G. feedwater transient at the Haddam V Neck plant.

Reference 15, the Haddam Neck Feed and Bleed Report , has concluded that the preferred way to perform feed and bleed at Haddam Neck is to lock open one of the PORVs before the hot side (Th temperature exceeds 575'F and to inject make-up water wtEk)one of the charging pumps and/or one of the high pressure safety injection pumps.

The analysis performed herein is even more constraining in that the operators are not assumed to take any action until the PORVs lift automatically following S.G. dryout. . This . is calculated to occur at about 2400 seconds. Feed and bleed would then be performed with one PORV and one charging pump or two PORVs and one HPSI pump. Both cases result in more system voiding than that for the cases analyzed in Reference 15.

However, even under the assumptions used herein, the core is predicted to remain covered with subcooled or saturated liquid throughout the transient.

7-5

O FIGURE 7.1 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS :

WITH 1 PORV AND 1 CHARGING PUMP !

PRESSURIZER PRESSURE 2300-2200:

2100-2000f

1900f /

1 1800f 1700f 1600J p

1500J '/

i 1400; 1300J S .

1200-

i. I1007 1000--

.I

'400 ,

800-;

700f 600i

~

s*2 ,. ... , , , , .,. ... ... ... .,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME ISEC) 7-6

O i

FIGURE .7.2 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS i TOTAL LOSS OF SG FEEDWATER i FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP !

PRESSURIZER LIQUID VOLUME

.- 1300; 12002

& Jt r

! l 1100i j l

1000i i L I 900' i

h 800i e

7002 F 000i 3

500i 1400i 1

300i 200iv - ---,. ,. , , , ,. . ,- , -r

!- 0 1000 2000 3000 84000 5000 6000 7000 8000 9000 10000 TIME ISEC1 I

7-7

O FIGURE 7.3 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER i

i. FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP REACTOR VESSEL TOTAL MASS 160000i 1$0000:

140000i 130000i 120000i S Il0000i 100000i 90000i 80000i 70000i l

60000i 500001 10 0 20bo 30b0 40b0 50b0 60b0 70b0 80h0 90b0 1000 TIME ISEC1 7-8

O FIGURE 7.4 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP COLLAPSED CORE LEVEL 100--

9'3 ) f 96-97-96f 95f ll O ~4 r

d 92- l E 91f

., 90) i esq l

88; l

83-0 1000 2000 3000 14000 5000 6000 7000 0000 9000 10000 TIME (SEC) 7-9

O -

FIGURE 7.5 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP TWO-PHASE CORE LEVEL 100-80-4 O 60-E iL 40--

20-

)

l i

i I

o_

h 10 0 2 3 40ba 50 0 60 0 to 0 DO JO 9000 10000

O m- ,m 7-10

g - -.u ---s -- -a _. - - a I

i a

l FIGURE 7.6 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP PORV AND CHARGING FLOW 120-110A J

If: ft a1

/

90A l} ; } 1

./ \ i i 80A $ EY $

I 5i 0 70- l : f1 W : : :s l k so-L i

{ ),

e .*

! 50-~ ,

/

5 $ !.I i ee. ;

-( _

l

>=

N .

. 44 '

10-'

~, , , , , , , , , ... ,

2000 3000 4000 5000 6000 7000 8000 9000 10000 0 1000 TIME (SEC)

! LEGENO: CURVE CHARGING FLOW ------ P OR Y F L O W

O 7-11

i l FIGURE 7.7 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS

WITH 1 PORV AND 1 CHARGING PUMP HOT LEG TEMPERATURE l 640-630-4 G20-l 610-h 600-i-

5902 '

a N5802

. N 5701

W i 560

? !

. l' 550-

. l i- 5'4 D -

,. 530-520-j 510-Soo . . . . . ..- . . .

> 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC)

I i

7-12 l

e.-..---._-.--.-_.- .. .. - _ ---..-....._-_- . . . , . - . . - , - . . . - . - . . - . . . . - . . .. .-

a _ ,__a ,

O FIGURE 7.8 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS WITH 1 PORV AND 1 CHARGING PUMP STEAM GENERATOR PRESSURE 1000-900i 800i 700i O :

E 600i 500i 400j A

300 ]

200i 100i 02 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME ISEC1 O

7-13

O FIGURE 7.9 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS i

WITH 1 PORV AND 1 CHARGING PUMP STEAM GENERATOR MASS 55000-.

50000i 45000i

, 400002

O 350004 i

E S 30000i 25000i I

k i 20000i 15000i 10000' 5 !

5000i

^

02

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME ISEC) i 7-14

.---._,,,.,,o m,.-, __.m-y ~ . . . _ , , , _ _ . . - , _ _ ,_,,,,,._.___om_.. -..,,__.m., , . , , _ _ _ . . _ , . , , . _ , ,, , - . - . . . - + , _ . - , , _ _ . _ ~ , . .

L O

I FIGURE 7.10 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER

. FEED AND BLEED AT 2400 SECONDS

. WITH 2 PORVS AND 1 HPSI PUMP PRESSURIZER PRESSURE 7200: ,

A 2000i I

1800i

, 1600i p

1400Y ii,00: . 1 E-

, 10o0-[

-: \

801-j 600i 400i l 2004 02 . ,- ~n

, -r-+- , , , , ,- ,

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 l

TIME (SEC) s l 7-15

FIGURE 7.11 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS WITH 2 PORVS AND 1 HPSI PUMP PRESSURIZER LIQUID VOLUME 1300 I

A 1200i k

1100i 2000i /

O 9002 ~

Q 800i .

t

/002 F E002 3

500i 400i i 300i i

e i i e : -M t'm *' ' r ' - e r i 3000 4000 5000 6000 7000 0000 9000 10000 0 1000 2000 TIME (SEC) 7-16

FIGURE 7.12 l HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS'0F SG FEEDWATER FEED AND BLEED AT 2400 SECONDS l WITH 2 PORVS AND 1 HPSI PUMP REACTOR VESSEL TOTAL MASS 200000-4 F

190000--

100000-

"{

l 170000-i 1600001 '

. O 150000-M 1400001 I

5 130000-( l 120000-110000-100000-90000-80000-70000-0 1050 20b0 30b0 4bbb 5bbb 60b0 7bbb Bbbb 90b0 100bb O -

7-17

1 4

l FIGURE 7.13 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS i TOTAL LOSS OF SG FEEDWATER !

! FEED AND BLEED AT 2400 SECONDS I WITH 2 PORVS AND 1 HPSI PUMP

! COLLAPSED' CORE LEVEL 100- ,

1 1 00-

O 60-L t

t V e f. ,

. L i %

40-l 20- '

l l

0- , _ ,,,_ .,_ ,,._ _,_ ,,,,_ , _ _ ,,,. , _.. _,. _,,,7 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 r TIME ISEtt l

l 7-18 1

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

l FIGURE 7.14 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER 1 FEED AND BLEED AT 2400 SECONDS WITH 2 PORVS AND 1 HPSI PUMP TWO-PHASE CORE LEVEL 100-i 80-O 4 60-E E :

L I 40-20-l 1000 2000 3000 4000 50b0 60 0 70 0 80 0 90 0 10 00 0

0 - tem 7-19

d FIGURE 7.15 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEWATER FEED AND BLEED AT 2400 SECONDS WITH 2 PORVS AND 1 HPSI PUMP PORVS AND HPSI FLOW 390; 360f ,<

1 i 3302 f 3002 [

l [

^

270f I

F 2402 L

l :

210i l l

p, !

L180-}

e -: i

'3 150-l i i i .

: $ t C ! ! / !

120f '

'< : l

i y

9% j 602 l I 4 : ,h,:

l oi d!

o. . . , '. ... . ... . . ,

0 1000 2000 3000 4000 5000 60C0 7000 0000 9000 10000 TIME (SEC)

LEGENDS CUHVE CHAHGING FLCai ....... PORVS FLOW V

7-20 i

FIGURE 7.16 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER ,

FEED AND BLEED AT 2400 SECONDS

- WITH 2 PORVS AND 1 HPSI PUMP HOT LEG TEMPERATURE 600-4 570i 540,2 5102 4802 T

450f ,I N . I

{420- .

T 393-. {(-

l 350 l l ***. ..........--..-----------

i 300-210:

1 240 2102 180-h 10b0 20b0 30b0 40b0 50b0 60bo 70b0 80b0 90b0 10 BOO 2 TIME (SEC1 LOOP WITH PRESSURIZER - - - LOO P W/O PRESSURIZER f

7-21

k O

FIGURE 7.17 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS i WITH 2 PORVS AND 1 HPSI PUMP STEAM GENERATOR PRESSURE 1000; 900i 6

800i 700i 600 -

E 500i

'40 0 ]

A 3001 200i i

10Oi

$ $ $ $ $ S & l l l O 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME (SEC) i f

! 7-22

O ,

t FIGURE 7.18 .

HADDAM NECK PLANT BEST ESTIMATE ANALYSIS TOTAL LOSS OF SG FEEDWATER FEED AND BLEED AT 2400 SECONDS WITH 2 PORVS AND 1 HPSI PUMP L STEAM GENERATOR MASS 55000-4 50000i f 45000i 1

i 40000i

!O 4

35G00]

R

30000 4

t 25000i

! L i M i 20000i 15000i t

f 10000i 5000i 02 g- ,- g- .,. .,. .,. ,

I 5- r , ,

' O 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 TIME ISEC) i i

7 -23

n. 8. MINIMUM AUXILIARY FEEDWATER FLOW REQUIREMENTS ANALYSIS

( \

\~ l 8.1 Introduction The Minimum Auxiliary Feedwater (MAFW) NULAPS model was used to analyze the condition of only one (out of two) AFW pump providing flow to only one (out of four) steam generator (SG) following normal full power plant operation. The purpose was to determine if a pressurizer power operated relief valve (PORV) would lift.

The scenarios investigated were a) all reactor coolant pumps (RCPs) continue to run (offsite power is available) and b) offsite power is lost resulting in the tripping of all RCPs and eventual loss of the secondary side steam condenser.

8.2 Analytical Model The scenarios investigated in this analysis were initiated with a total loss of main feedwater flow. For the loss of offsite power scenario, offsite power was lost simultaneously with the loss of main feedwater flow.

The RCS model for MAFW was a one/three two loop model as previously discussed for the IITR in Section 3. The model consisted of two loops, one representing a single loop (the SG which continues to receive AFW) and the other representing three combined loops.

O)

(,, The pressurizer heaters were included in the pressurizer model for this scenario.

As a conservatism that was appropriate for this scenario, the low l_ setpoint safety valve for each SG was modeled as lifting to full open at 990.15 psia and reseating at 955.5 psia corresponding to a lift pressure equal to set pressure minus 1.0 pcreent and a reseat l pressure equal to lift pressure minus 3.5 percent.

! The basic sequeuce of events for the MAFW model proceeded as

! follows:

o The plant was operating at normal full power. MFW flow to the SGs is terminated.

o For the loss of offsite power scenario, the RCPs trip and coast down.

o SG level decreased to less than ten percent Narrow Range which SCRAMS the reactor and reduces core power to decay heat plus feedback within five seconds.

o SG main steam flow to the turbine is isolated; the bypass valve flow is available.

) o AFW flow to one SG (from one AFW pump) and SG steam flow to one Terry Turbine begins after a delay of 30 seconds.

8-1

o Pressurizer heaters continue their operation as normal.

O(~ o Condenser vacuum is lost af ter ten minutes for the loss of power scenario; steam cooling to the condenser is then unavailable.

Safety injection actuation on a low pressurizer pressure or pressurizer low level activation of charging pump flow, although modeled in these analyses did not occur for this analysis. AFW flow to the one SG and Main Steam flow is controlled as described in Section 1.3. The system behavior subsequent to these initial events will be discussed individually for the cases with and without offsite power described in the following sections.

8.3 Discussion of Results For both the MAFW scenarios in which offsite power is available and lost, the PORVs are lifted. The results of the scenarios are discussed separately as follows:

8.3.1 Offsite Power Lost l

l i This scenario investigated the effects of having only one AFW pump available which provides flow to only one SG. Offsite power is also lost causing the RCPs to trip while condenser cooling, for the steam from the one SG, remains available for only ten minutes.

[\'-~\ For this scenario, a PORV ultimately lifts as can be seen in the PORV integrated mass flow in Figure 8.1.

The RCS pressure transient is depicted in Figure 8.2.

Until 650 seconds (the transient is initiated at 50 seconds) condenser cooling relieves RCS pressure. A gradual pressure increase until 650 seconds is caused by steadily decreasing SG (the 3 steam generators not receiving AFW) inventory through the secondary safety valves. On loss of condenser cooling at 650 seconds, RCS pressure is increased until 950 seconds at whic'n time RCS pressure is decreased by the SG receiving AFW since level has been partially recovered and alno the hot main feedline water has been swept out by the AFW. At about 2,100 seconds, the SG level in the single loop has fully recovered and AFW flow is thereafter added to this SG only as needed to maintain level and is shown.in Figure 8.3. At 2,500 seconds, the single loop SG safety valve begins to pass steam thus relieving pressure. At 3,200 seconds, the pressure rises quickly (Figure 8.2) due to the liquid level in the combined SG loop having been reduced to near zero Wide Range (WR) as shown in Figure 8.4 by steam flow out the safety valves.

Although the single loop SG continues to remove heat through the safety valve relief flow, RCS pressure increases to the PORV lift pressure at 3,500 seconds shown in Figure 8.1.

[ )

8-2

f ) 8.3.2 Offsite Power Available L._)

This scenario investigated the effects of having only one AFW pump available which provides flow to only one SG. Offsite power continues to remain available and, therefore, the RCPs continue running and the condenser for the one SG remains available. For this scenario, a PORV ultime.tely lifts as can be seen in the PORV integrated mass flow in Figure 8.5. The RCS pressure transient is shown in Figure 8.6. At 2,050 seconds, the combined loop SG safety valves have lifted for the last time and level has been reduced to 30 percent WR. Steam flow from the single loop SG to the condenser due to high SG pressure continues throughout the transient. By 4,400 seconds, the SG level has fully recovered. Although the single loop SG continues to remove heat, RCS pressure increases to the PORV lift pressure at 5,900 seconds as shown in Figure 8.5.

8.4 Summary In summary, providing feedwater flow from only one AFW pump to only one steam generator will result in the lifting of a pressurizer PORV. Without Offsite Power, activation of the PORVs would occur at 3500 seconds while with Offsite Power, f' 's PORVs activation occurs at 5900 seconds.

(v I

'~~

\

(O 8-3

l i

i

?

1 FIGURE 8.1 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS !

' LOSS OF SG MAIN FEEDWATER 1 AUX FEEDWATER PUMP TO 1 SG OFFSITE POWER UNAVAILABLE INTEGRATED PORV FLOW i

<- 800-7001 1

~

j 600-'

~

O- R 500-T i E D

P ,

0 400-

! 4

!. F ;

i 0 W 300--

! L l .

200--

l i 100-5 I

! O 500 1000 1500 2000 2500 3000 3500 4000

, TIME (SEC) i O

i l

8-4

,-..,.-.,,.,,.,,--n-,,,,,,.___n, _ _ _ _ _ . . . + _ , _ . . . , _ _ , _ _ , . , _ , , , , . _ , , _ . , . . . _ , . , . , - _ _ _ __,.--,,._.n---- - - - - . . _ ,,_ , .-

O FIGURE 8.2 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS LOSS OF SG MAIN FEEDWATER 1 AUX FEEDWATER PUMP TO I SG OFFSITE POWER UNAVAILABLE RCS PRESSURE 2300-2250-~

2200f 21502 oi~

R 2100-'~

i U

R E 2050-

ie 2000-1950f 1900f ;

b Sb0 lb0 15b0 2bbb 25b0 3bbb 35 0 4000 TIME (SECl O

8-5

O FIGURE 8.3 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS LOSS OF SG MAIN FEEDWATER 1 AUX FEEDWATER PUMP TO 1 SG OFFSITE POWER UNAVAILABLE '

1 SG COLLAPSED LIQUID LEVEL O.9-F 0.8 L

, h !

0.6f L

R

, S 0.52 -

L Q 0.4f L

i /

0.3i o 2, (

0.lf I

= i- , ,- , .,. .,. , ,

O S00 1000 1500 2000 2500 3000 3500 4000 TIME (SEC)

O 8-6

O FIGURE 8.4 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS LOSS OF SG MAIN FEEDWATER 1 AUX FEEDWATER PUMP TO 1 SG OFFSITE POWER UNAVAILABLE 3 SG COLLAPSED LIQUID LEVEL

0. 9 ;

D.8i l

0. 7-S G

0. t.

0.5 l

l i ,

i ('

.I Q 0.4f '

L f

0.3 Y l n ,

f

0. ?- .

t

0. I -

Q f w

0.0 , .,, , ,, , ,,, . .,, , , , ,

0 500 1000 1500 2000 2500 3000 3500 4000 TIME ISEC)

~

O .

8-7

9

! t i !

}

l !

! i t.

i j

FIGURE 8.5 l i

Q HADDAM NECK PLANT BEST ESTIMATE ANALYSIS j- LOSS OF SG MAIN FEEDWATER 1 1 AUX FEEDWATER PUMP TO 1 SG OFFSITE POWER AVAILABLE '

! INTEGRATED PORV FLOW 5504* - i I

5001 1

4 450j I

- t

400;

I 's t N LO

).

1 i >,-

A i

1 i L

D 300i l

i' P O

fl V 2502 _

s L

0 W 200i f L r D 150-M 100 :

50 r -T- , w-w m n. .,. , . ww . , . .,. ,,,

0 1000 2000 3000 4000 5000 6000 7000 0000 TIME IS[Cl O

8-8

O FIGURE 8.6 HADDAM NECK PLANT BEST ESTIMATE ANALYSIS LOSS OF SG MAIN FEEDWATER 1 AUX FEEDWATER PUMP TO 1 SG OFFSITE POWER AVAILABLE RCS PRESSURE 2310-

///N/LA 22502 22202 21902 21602 S 2130-R 2100f 3 _

R 2070-20402 2010 1980--

1950:

19202 18902 b lbbb 20bb 30b0 4bb 50b0 60b0 70b0 8b0 ilME (SEC1 8-9

) 9. A._NTI.C.il,5A.._T.ED_T. RA.NS..I E.NT WITHOUT SCHA_M ANALYSIS

- . - - . ~

)

9.1 Introduction An anticipated transient without scram (ATWS) analysis has been performed for the Haddam Neck Plant assuming a total loss of Steam Generator (SG) main feedwater as the initiating event.

This event has been analyzed assuming normal operating initial conditions and best-estimate plant parameters, combined with a nonmechanistic common mode failure preventing the control rods from dropping into the core and the turbine from tripping following a reactor protection system signal.

A particolar concern during a postulated ATWS is the reactor coolant system (RCS) peak pressure. Reference 16 has calculated that the loss of S.G. feedwater without reactor trip results in the highest RCS pressures.

The loss of main feedwater produces a large imbalance in the energy exchange between the primary side and steam generator secondary side. When feedwater flow to the steam generators is terminated, the secondary system can no longer remove all of the heat that is generated in the reactor core. This heat buildup in the primary system is indicated by rising Reactor Coolant System (RCS) temperature and pressure, and by increasing pressurizer water level, which is due to the insurge

,r N, of expanding reactor coolant. Water level in the steam

( ) generators decrease as the remaining water in the secondary system, unreplenished by main feedwater flow, is boiled off.

When the steam generator water level decreases to the point where the steam generator tubes are exposed and primary-to-secondary system heat transfer is reduced, the reactor coolant temperature and pressure begin to increase at a greater rate. This greater rate of primary system temperature and pressure increase is maintained as the pressurizer fills and releases liquid through the safety and relief valves. It should be noted that the safety and relief valves have a smaller volumetric relief capacity for water than for steam.

Reactivity feedback, due to the high primary system temperature, reduces core power. The system pressure eventually begins to decrease and a steam space is again formed in the pressurizer.

The peak pressure achieved in the primary system depends upon the ability of the pressurizer relief and safety valves to release the reactor coolant volumetric insurge to the pressurizer. These are designed at CY to lift and discharge steam from the top of the pressurizer at pressures above 2,285 psia and 2,500 psia (nominal), respectively. The probability of these valves failing open increases each time they are challenged. As such, there is a small probability that an ATWS could degrade into a Loss of Coolant Accident (1,0CA), with a potential for core uncovery.

/'_s3

\ i V

9-1

f's The purpose of this analysis is to identify the minimum number I

^ 'I of PORVs and safety valves which would be able to accomodate the reactor coolant expansion and maintain the RCS peak pressure within reasonable limits. in addition, this analysis is also intended to determine if operator intervention to trip the turbine is necessary to prevent the pressurizer safety valves from opening, in addition to the two PORVs.

The analysis presented herein basically consists of three cases. The most limiting case assumes that the PORV block valves, which are normally kept closed at CY, remain closed throughout the transient and that the operator never trips the turbine. For this case, the maximum pressurizer pressure was calculated to be 2,665 psia at 110 seconds, since two of the three pressurizer safety valves open to mitigate the RCS pressurization. The second case assumes that the turbine is never tripped and the PORVs are not isolated. Here, the first safety valve opens in addition to the two PORVs from about 95 seconds to 110 seconds at the pressurizer pressure of 2,575 psia, its opening pressure. The third case is similar to the second, but assumes that the operator trips the turbine by 40 seconds. This prevents the pressurizer safety valves from opening and results in a peak pressurizer pressure of 2,530 psia at 120 seconds.

9.2 Analytical Model

['h s/

The NULAPS model is the same as the one used to perform the Total Loss of Feedwater or Feed and Bleed analysis shown in Section 7.0 of this report except that, in addition to the two PORVs, the three safety valves have been modeled at the very top of the pressurizer as three trip valve junction with an area of 0.01132 ft2 each. This area yields a rated flow of 240,000 lb/hr at 2,500 psia (Ref. 3) when using the Moody discharge correlation of Reference 12.

The following assumptions have been used in this analysis in addition to those specified in Sortion 1.3:

o The main feedwater flow ceases to enter all four S.G. at t = 0.1 seconds. The auxiliary feedwater begins to enter all S.G.s 30 seconds later.

o The two auxiliary feedwater (AFW) pumps are assumed to be operable and to deliver best-estimate flow as a function of S.G. pressure (Ref. 3).

o No credit is taken for automatic reactor trip and for automatic control rod insertion as reactor coolant temperature rises. i o The turbine does not trip, except for those cases simulating operator intervention at the times specified in the results portion of this section.

9-2

[]

\ ,/

o The density moderator coefficient (MTC) and fuel lemperature coefficient (FTC) corresponding to beginning, of cycle at I rods out (BOC ARO) conditions have been chosen. These correspond to best-estimate least-negative reactivity coefficients which cause the core power to decrease at a slower rate, as compared to end of cycle (EOC) conditions, following moderator and fuel temperature increase during an ATWS. Hence, the results are bounding for all times in the refueling cycle, o The reactor coolant pumps continue to operate during the t: ansient.

o The turbine governor valve is assumed to operate on impulse pressure control. This is modeled by maintaining the S.G. pressure constant during the transient, even if in actuality it may decrease as the S.G. empties. This should not affect the S.G. heat removal as the enthalpy of steam does not change appreciably over the pressure range of 900 psia to 200 psia.

o When operator-initiated turbine trip is modeled, the bypass valves to the condenser are credited to function normally and to actuate when the Tavg in the primary loops is above 545*F and the S.G. pressure is above 930 psia.

fs o The PORV block valves are assumed to be initially closed

( ) and to have an opening / closing setpoint of

# 2,285/2,265 psia with a 17-second linear ramp.

o The three pressurizer safety valves have nominal setpoints of 2,500 psia, 2,550 psia and 2,600 psia, respectively.

Each safety valve has a rated flow of 240,000 lb/hr at 2,500 psia and opens at 3 percent above the setpoint (Ref. 3) (i.e., 2575 psia, 2626 psia, 2678 psia),

respectively.

9.3 Discussion of Results 9.3.1 Loss of S.G. Main Feedwater Without Scram, Turbine Never Tripped, PORV Block Valve Kept Closed The loss of S.G. main feedwater ATWS has been performed assuming that the main feedwater flows to all four steam generators is lost by 0.1 seconds. No credit is taken for automatic reactor trip. The turbine governor is operating on impulse pressure control, resulting in a reduction of the S.G. steam mass flow to the turbine. The auxiliary feedwater (AFW) is modeled to enter the S.G. at 30 seconds.

The plant response is shown in Figures 9.1 to 9.7.

Ih t /

U 9-3

There is very little change in system conditions fos (t'"')s the first 40 seconds of this event. The loss of S.G.

main feedwater flow causes the S.G. downromer mass t o saturate and expand so that enough inventory enters the S.G. shell to match the reduced S.G. steam flow to the turbine. In addition, the voiding in the S.G.

shell sides increases keeping the S.G. tubes covered, so that, basically, a constant heat transfer area is maintained. However, the auxiliary feedwater flow is not able to replenish the liquid inventory which is boiling off, and by 40 seconds, the S.G. water level decreases to the point where the steam generator tubes are exposed and primary-to-secondary system heat transfer is reduced. The temperature in the primary side starts to increase rapidly at that time, as is seen in Figure 9.5. This adds negative reactivity to the core due to the negative moderator density coefficient and, to a smaller degree, to the fuel temperature coefficient, causing the core power to decrease as shown in Figure 9.1. The heat-up also causes the primary coolant to expand. Water begins to enter the pressurizer, compressing the pressurizer steam space. The pressurizer pressure, shown in Figure 9.2, increases to the pressurizer PORVs setpoint of 2,285 psia by 43 seconds. These are assumed not to open, and the pressure continues to

.-s

, increase, reaching the first pressurizer safety valve

('/ ) opening pressure of 2,575 psia at 56 seconds. This safety valve is capable of removing the excess core heat which cannot be removed by the incapacitated steam generators. The primary pressure and temperatures begin to stabilize. But, at about 82 seconds, the pressurizer becomes practically solid, as implied by Figure 9.3, which shows the pressurizer liquid volume response. The volumetric relief capacity of the safety valves is smaller for water than it is for steam and the pressurizer saf ety valve can no longer keep up with the primary coolant expansion. The loop temperature, seen in Figure 9.6, begins to rise once more at a faster rate and the system quickly pressurizes to the opening pressure of the second safety valve. A peak pressure of 2,665 psia is reached in the pressurizer at 110 seconds.

The additional liquid released by the second pressurizer safety valve is sufficient to finally match the system volumetric expansion. Also, the core power decreases at a greater rate due to this second temperature increase. This results in more negative reactivity being applied to the core. The primary pressure decreases and the second pressurizer safety valve completely closes at 126 seconds. By

[}

v this time the core power has decreased sufficiently 9-4

() to be within the heat removal capability of the four V steam generators plus the first pressurizer safety valve, and the system pressure stabilizes at its opening pressure.

The reactor vessel total mass is shown in Figure 9.4.

By 200 seconds, the end of the analysis, the reactor vessel remains in a subcooled condition.

The pressurizer safety valves response can be seen in Figure 9.5. The first safety valve opens at 56 seconds and oscillates until 83 seconds to discharge, f rom the primary system, the excess volume created by the expansion of the primary mass. At that time, the pressurizer becomes filled with water and the volumetric relief capacity of the safety valve decreases. The system pressurizes to the opening of the second safety valve and this remains open until 126 seconds. For the rest of the transient the first safety valve fluctuates maintaining the pressurizer pressure at 2,575 psia.

The steam generator mass, presented in Figure 9.7, indicates that, as explained earlier in this discussion, there is a small initial increase in S.G.

secondary mass. This is caused by the influx of f-~s water from the S.G. downcomer as the water saturates and expands following the loss of subcooled main

(' ) feedwater flow. The auxiliary feedwater flow, which enters the S.G. with a 30-second delay, is not sufficient to match the S.G. boil-off and the mass starts to decrease. The mass and energy removed by the pressurizer safety valves after 80 seconds, combined with the continued reduction in core power, places less load on the steam generators at that time. Eventually, the S.G. boiling has been reduced so that the secondary mass, replenished by the auxiliary feedwater flow, begins to stabilize.

9.3.2 Loss of S.G. Main Feedwater Without Scram, Turbine Never Tripped This transient is identical to the one discussed in 9.3.1 except that the pressurizer power operated relief valves (PORVs) are allowed to lift when their setpoint of 2,285 psia is reached. The plant responses can be seen in Figures 9.8 to 9.15.

The transient scenario is identical to the case discussed in 9.3.1 until 56 seconds time when the PORVs (and PORV block valves) opening setpoint is reached. At this time the PORV block valves begin to ramp open, as shown in Figure 9.12, and the

/ 'T pressurizer pressure, shown in Figure 9.3.9, starts N. .)

9-5

(4 to decrease. At 62 seconds, the pressurizer pressure

)

(_ / reaches the PORV block valves closing setpoint. The valves begin to ramp close, fully closing at 78 seconds.

Once the PORVs are closed, there is no outlet for the system expansion, and the primary system starts to rapidly repressurize, reaching the PORVs setpoint again at about 87 seconds. The block valves begin to ramp open, but the discharge out of the PORVs is not sufficient to accomodate the system expansion. The opening pressure of the first pressurizer safety valve is reached and the valve oscillates from 95 to 100 seconds, as shown in Figure 9.13. Meanwhile, the pressurizer continues to fill and the PORVs begin to discharge saturated liquid, thus decreasing the volumetric Icak rate. The opening pressure of the first pressurizer safety valve is reached again at 107 seconds. By that time the core power has decreased sufficiently to be within the removal capability of the SG auxiliary feedwater flow and the pressurizer PORVs flow. The safety valve completely closes at 110 seconds and the primary pressure decreases, oscillating, for the remainder of the analysis, between the opening / closing pressure of the PORV block valves.

r\

Figure 9.8 shows core power versus time. The core

('~ ') power response of this case differs from the core power response presented in 9.3.1 only from 56 seconds to 80 seconds. The difference arises from the fact that the first case predicts the pressurizer safety valve to remain open during that time interval, while this case predicts the PORVs to open, resulting in lower pressures and slightly lower temperatures. For the higher range of pressures and temperatures this equates to a slightly smaller density. This yields lower core power at that time due to the negative MTC used in this analysis.

9.3.3 Loss of S.G. Main Feedwater Without Scram, Turbine Tripped at 40 Seconds The t ransient is very similar to the one discussed in 9.3.2 except that the turbine is assumed to be manually tripped at 40 seconds. The transient rerponse is presented in Figures 9.16 to 9.22. As can be seen from these figures, tripping the turbine at 40 seconds, followed by the opening of the S.G.

bypass valves, reduces the energy removed by the steam generators, resulting in higher primary temperatures and pressures. The pressurizer PORVs

,~~s open the first time at 48 seconds, instead of 56 seconds as in the previous case and remain open (v )

9-6

(' '\, longer, closing at 82 seconds. The initial higher

(,_,/ primary temperatures shown Figure 9.21 result in a .

lower core heat generation during that interval due to the negative MTC. This yields lowe r t empe ra t u i ce.

after the PORVs close at 82 seconds and a slower second pressurization, as seen in Figure 9.17. The peak is calculated to be 2,530 psia, demonstrating that, for this case, only the pressurizer PORVs lift.

The pressurizer safety valves are never actuated, as compared to the case presented in 9.3.2. For the remainder of the transient, the system response closely resembles the previous case.

9.4 Summary This section has discussed a L ss of Steam Generator Main Feedwater without Scram event which wa - also shown in Reference 16 to yield in the highest h

~~1300-4 4~~

~~12505 1200-11502 11002 v~~

~~L 10502 b -~~

~~1000-o 950-~~~

u E 900-j F 850-3 l 800-i 750-7005 s 6%D-h* '3' W I T T I I I 'F' 'I 0 20 40 60 80 100 120 140 160 180 700 i TIME ISECl 9-10 i

~~-.,n.~-.. .,-n-._,--,_--___---_,.,...--,-. .,..-,.n,.,. ....,.,n- ., . , - - - - . . - . . - , , -.-.-n-. .., -~~

~~O l~~

~~FIGURE 9.4 '~~

HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED PORV BLOCK VALVE KEPT CLOSED REACTOR VESSEL TOTAL MASS 156000-155000-1540002 153000-1520005 151000-150000-i-

~~149Juc-i 148000-147000-146000-1 145000-1440001 1430002 142000- -,- ,- ,- ,- -r t- , , , , , ,~~

~~0 20 40 60 80 100 120 140 160 180 200 l!ME (SECl I 9-11 l l~~

1

~~a -4 __~~

~~O FIGURE 9.5 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED PORV BLOCK VALVE KEPT CLOSED PRESSURIZER SAFETY VALVES FLOW 900-600-700f l~~

~~600i L .~~

~~l 0 500 ,-~~

~~! 200 :~~

(

~~300-~~

=

~~O n u istc>~~

~~9-12~~

~~4 Iv FIGURE 9.6 i~~

~~HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM i TURBINE NEVER TRIPPED PORV BLOCK VALVE KEPT CLOSED~~

~~! AVERAGE LOOP TEMPERATURE~~

!- 640; -_

~~630i~~

^

i +

~~l ~~~

~~620-i~~

?

~~610i i~~

~~E E 600- '~~

~~3 T E5905~~

)

~~F 580-l 570- ,~~

~~i i~~

~~560f 5502 ,,. , , , ,~~

~~IL40 160 180 200 40 60 80 100 120 0 20 TIME ISEcl l~~

}

~~9-13 i~~

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

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

~~l l~~

~~O l~~

FIGURE 9.7 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED PORV BLOCK VALVE KEPT CLOSED STEAM GENERATOR MASS 39000-360002 33000-30000-O 27000f 240002

\*

~~R >~~

~~S .~~

~~S 21000-180002 .,~~

~~t. .~~
B .
M 15000- \
120002 '\ ,
\
90002 \,
\
j .
6000- .
i*
30002 . .. .. ,
i a
W iy- y g- p 'y' q I E y 3 20 40 60 80 100 120 140 160 180 200 D
TIME (SEC)
LOOP WITH PRESSURIZER --- LOOP W/O PRESSURIZER I
9-14
._ . .-. . _ - -.. ~ . .
i i
O
+
FIGURE 9.8 l HADDAM NECK PLANT ATWS ANALYSIS J
LOSS OF SG. MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED CORE POWER i
110- r i l 1 f i
1002 i
I 90i L
i 60i 70i 1
P 602
~~i 0 I W j E i ft~~
~~50i l~~
~~40i i~~
~~30-l l -~~
l 20i i
I -
) lui j .__
02 ,, , , , , .__, , , , ,,. ,
1 0 ?O 40 60 00 100 120 140 160 ISO 200 l T!ME istci
!O i
i 9-15 i
4 O
! FIGURE 9.9 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED l PRESSURIZER PRESSURE l
, 2u00 - l 3 .
F 2550-T k ?%DU l
I 24502 !
l 24002 f
. O -,0:
P R 2300-u 2250-
.! E P 2200-i S A
2150--
l 2100-I l 20502 I
20002
{
19502 i
19002 , ,
0 20 40 60 80 100 120 140 160 180 200 l
I TIME (SEC) i e
r a
9-16 I
. . - - - - _ _ - _ . - . , . - . - - _ . _ ~ . - _ . . _ - - - . . - _ . . _ - . - . - . - .
4 .m2. 4 .-.u
~~5 4 - .--4am,a=._#. .s...~a.,s. w.-6-.m.-sa . .44, - ..ma .. . . . . - .s.. - . - , * = .-..-2,.m.u.._, .__s,.u 1~~
i O l FIGURE 9.10 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED PRESSURIZER LIQUID VOLUME 1300-1250-1200-1150-1800-1050 10002 0 950-b E 9002 F 6502 3
800-750-700-650-
~
1 . ,- , , ,
0 20 40 60 80 100 120 140 160 180 200 TIME ISECl 9-17
t l-iO 1
i l-FIGURE 9.11 l HADDAM NECK PLANT ATWS ANALYSIS
~
LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM
~~TURBINE NEVER TRIPPED l REACTOR VESSEL TOTAL MASS~~
~~j. 150000- ,~~
t 155000-i 154000-I i
i y
153000-i 152000-l !
151000-r L
~~150000-I M~~
\ R i 5 149000-S s
148000-
!. L i 8 M
147000- ,
146000-4 f
~~145000- ,~~
1440002 i
j 143000-1 14?0002 i ,m 000- p ,,,, ,,,t , , ,
l. 120 140 160 180 /00 20 40 60 80 100 1 0 l
TIME (SEC) l i
9-18 I
i
. - + . - - ~
O FIGURE 9.12 i HADDAM NECK PLANT ATWS ANALYSIS l
! LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED PORV FLOW 215-I 1
P50:
1 225i i i j 2004 1752, L
150i L
l M 125J '
{
100i N
75i 4
i 502 25J; 02 I i U L.
! 0 20 4h Sb 8b th0 120 150 th0 th0 200 TIME ISEC) 4 O
1 j
9-19
l O
FIGURE 9.13 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED PRESSURIZER SAFETY VALVES FLOW 3?5-1n0..
275-0 250-225A 200-e , ,, :
8 150-125-100-75-50-25-0- p_m_, _ _ _ _ _ , , , , , , , , . , ,,,
0 20 40 60 80 100 120 140 ISO 180 200 TIME (SEC1 O
9-20
O FIGURE 9.14 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE NEVER TRIPPED AVERAGE LOOP TEMPERATURE 635-l 630-6252 620-615-6102 E 6052 E
j600:
ys5S:
590-F 585-5602 575-570-565-60-O , , ,- , , ,- , , . -r 0 20 40 60 00 100 120 140 160 180 200 TIME ISEC) 9-21
4 i
4
.s 4
1 i
l FIGURE 9.15 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM i TURBINE NEVER TRIPPED i STEAM GENERATOR MASS
~~39000-1 1~~
30000 ~
i n 4 330002 I j 30000f !
270002
~~1 .~~
240002 ',
s R i S ,
S 21000- '
l i
) 100002 .,
i e .
~~8 H 15f100-~~
\.,,
i
\
! 12000- '
g 1
\., .
90002 .
\
. 6000-~ .,
30002 '**********- . . .,,,,,,,,,,,,,,,
I 2
l 0 ,.. , , .., ,,. , , , , ,,. .,
0 20 40 60 80 100 120 140 160 180 200
{
l TIME ISEci LOO P WITH PRESSURIZER - -- LOOP W/O PRESSURIZER i O ,
j 9-22
d F
t e
4 k
i L FIGURE 9.16 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE TRIPPED AT 40 SECONDS CORE POWER 110; I
I 100i 90i i~
eoi l 70i E0i u
.I E
R
$0-j %
l 1 40i >
i j 30i 4
20i ,
4 10i f
g- g y p' I' 3 I 80 103 120 140 160 180 200 l 0 20 40 60
~~l. TIME ISEC1~~
!O
{
j 9-23 4
O FIGURE 9.17 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE TRIPPED AT 40 SECONDS PRESSURIZER PRESSURE 2550-2500i 2450-2400i 2350i f
2300i i
b22502 ~
E S ??00 i
2150i 2100i 2060^
2000J 19502 O ,
0 20 40 60 80 100 TIME (SECl 120 140 160 180 200 9-24
4 O
i-FIGURE 9.18 i HADDAM NECK PLANT ATWS ANALYSIS 1:, LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE TRIPPED AT 40 SECONDS PRESSURIZER LIQUID VOLUME 1300-i 3
1250-1200{
1150-1 1100-I l L 1050-'
e Q i U
! 1000-t V
0 950--
I L U
M
! E :100L ,
t t
i r es0 -
t 3
t i
0001
~~150~~
[
l
\ 1001 650-4 600-- , ,- ,- ,,.
, i- , , , , , ,
j 0 20 40 60 80 100 120 140 160 180 200 TIME ISEcl l 9-25 e-~+~oww+--m- wwv, w,w,,--w~ w,v gg---w wwwm mm y-g-w. _ enn -,-- ~ -w , u o w w s+v-w -
,,-e,,nm-m, . , - . - . _ mw- -
O s
a FIGURE 9.19 HADDAM NECK PLANT ATWS ANALYSIS r LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM 1 TURBINE TRIPPED AT 40 SECONDS i
REACTOR VESSEL TOTAL MASS 156000--
t.
1550002 I
154000-
} 153000-'
i 152000i 1510002' i
iS0000f j
' M ,
4 A 149000- -
S 5 .
148000-i-
L 147000- '
l 8
~~M i 146000, 145000-144000~,~~
~~143000f 142000f l 141000f~~
~~2 i . , , , , , , ,~~
0 20 40 60 80 100 120 140 160 100 200 TIME ISECl
!O i
1
! 9-26 m m , + w .+-e m y -vw
O i FIGURE 9.20
~~HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE TRIPPED AT 40 SECONDS PORY FLOW i~~
300-j 1
275i i
250i l 225f 200i 5
~~F 1752 '~~
4 L
O i W 1502 '
L 8
! M i /
i S 1252 '
j E C
100i f
75-i
! i S0i l
t 25i j
02 ,. ,
L u .,
' ' ' i .- , .
1 0 20 '80 60 60 100 120 140 160 180 200 j
TIME (SCCI f
! 9-27 i
,,-,,,..--.----n-.-- , , , _ - . , , - . , , , , , , - - , , . . ---- - ,-...- ._ ~,-- .-. ,,.- - - ,.-
A O
FIGURE 9.21 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE TRIPPED AT 40 SECONDS AVERAGE LOOP TEMPERATURE 640-630-620-[
610i O E 600-
?
W .
E 590-I 580;
$ #0-]
560-j
, , .- . n i- , , , , , --T 0 20 40 60 80 100 120 140 160 180 200 TIME (SEC)
O 9-28
O FIGURE 9.2 2 HADDAM NECK PLANT ATWS ANALYSIS LOSS OF SG MAIN FEEDWATER WITHOUT SCRAM TURBINE TRIPPED AT 40 SECONDS STEAM GENERATOR MASS 39000-36000-330002 l
300002 l
27000-240002
~~A i~~
S ,
! $ 21000- '
ISC002
~~li M 15000-~~
\. .
N.
12003 2 \.,
N 90002 '
\.
60002 ',
\.,
3000- 's
'N o: \ ~.... - . - ..- ..... ....
D 20 40 60 80 100 120 140 160 100 i'00 TIME ISEC)
LOOP WITH PRESSURIZER --- LOOP W/O PRESS!!R12ER O
9-29
10. 111G11 PRESSURE RECIRCULATION ANALYSIS 10.1 p3troduction The liigh Pressure Recirculation (HPR) NULAPS model was used to investigate the medium and small break LOCA during the long term or recirculation mode of the event. Recirculation occurs when 100,000 gallons have been depleted from the Refueling Water Storage Tank (RWST). Upon a recirculation activation the charging pump suction is aligned to the discharge of the Residual Heat Removal (RNR) pumps. The HPSI pumps are stopped at this time. The analysis was performed to assess the ability of charging flow to prevent significant core uncovery during the recirculation mode. The availability of conditions to allow an alternate to recirculation charging flow for core uncovery mitigation was also investigated. This alternate involves recirculation flow to the RV upper head deluge lines via the residual heat removel (RHR) pumps which can be utilized if RCS pressure is decreased to 165 psia (i.e., Low Pressure Recirculation) as identified in the Emergency Operation Procedure (EOP).
10.2 Analytical Model The scenarios investigated in this analysis are initiated with a medium or small LOCA located in the cold leg discharge (CLD)
s for the RCS loop 2. This is the limiting break location for high pressure recirculation since in the recirculation mode only charging pump flow to the RCS is available and, exclusive l of operator action, the sole delivery point is to the loop 2
~~cold leg. Clearly, for breaks in the other three loops, delivery to the core is sufficient to match hoiloff and maintain the core in a covered condition during the recirculation phase of a LOCA.~~
The RCS model for this event was a one/three two loop model as previously discussed for the Incore Instrument Tube Rupture
. analysis in Section 3. The model consisted of two loopn, one l representing a single loop (loop 2) and the other representing three combined loops (loops 1, 3, 4). The pressurizer was connected to the combined three-loop modeled hot leg.
l l The basic sequence of events for the high pressure recirculation pipe break scenarios proceeded as follows:
o The plant is operating at normal full power. A LOCA is initiated in the loop 2 cold leg.
o Pressurizer level decreases and charging flow initiates to maintain (recover) level.
o Pressurizer pressure decreases to the safety injection
,s actuation signal (SIAS) setpoint of 1715 psia.
10-1
6:
~~o. The reactor trips and core power reduces"to decay heat 3 plus feedback within 5 seconds.~~
(d o SG main steam flow to the turbine is isolated. Bypass valve flow (steam dump to condenser) is available.
o Main feedwater flow is isolated and after a delay of 30 seconds AFW flow to the SGs and SG steam flow to the Terry Turbines initiates.
o Af ter a 52 second delay, the RCPs are assumed to trip and begin to coastdown.
o Two HPSI pumps and two LPSI pumps are sequenced on and the charging pump flow suction is realigned to the RWST.
AFW flow and Main Steam flow is controlled as described in Section 1.3. System behavior subsequent to these initial events will be discussed individually for each scenario.
10.3 Discussion of Results An investigation of a spectrum of break sizes established the
.045 ft2 and .02 ft2 loop 2 cold leg breaks in the pump ,
discharge as cases where potential core uncovery ig possible.
For loop 2 breaks greater than or equal to .045 ft (equivalent p
diameter = 2.9 in.), the RCS, with all accident mitigation pumps activated in the injection mode, will depressurize to 165 psia, the shutoff head of the RHR pumps, and below prior to initiation of core uncovery and also prior to the depletion of 100,000 gallons of RWST inventory'. Therefore, high pressure recirculation using using only the charging system is not required for break sizes 0.045 ft2 aad
- larger.
For loop 2 cold leg breaks less than or equal to .02'f$
(equivalent diameter = 1.9 in.), one charging pump with only valve 110A available is sufficient in the recirculation mode to prevent core uncov'ery. In this scenario, recirculation was also preceeded with all pumps activated during the injection 2 phase. Breaks in the loop 2 cold leg between .02 and .045 ft however, with only one charging pump available for recirculation (even with valve 110 available) resulted in eventual core uncovery. Results for breaks located in the charginglinealsoresultedinsignjficantcoreuncovery. The injection line flow area is 0.05 ft s that for all break sizes down to and including .01 ft.2 significant core uncovery was predicted.
Additional actions including a 75*F/hr cooldown via SG cooling and RCS cooldown using the PORVs were also examined and demonstrated to be beneficial for these events. None of these actions, however, were demonstrated to totally mitigate the O
V consequences of all possible loop 2 cold leg breaks in the pump discharge.
10-2
~ [) 10.3.; liPR .045 FT2 CLD BREAK 2
This scenario was an investigation of a .045 ft break in the loop 2 cold leg. As seen in Figure 10.1, RCS pressure decreases to 165 psia (150 psig) by 970 seconds (transient initiates at 50 seconds). With all injection pumps act.ivated f or the injection phase, 100,000 RWST gallons are used by 1,130 seconds. As seen in Figure 10.2, there is not significant core uncovery before the RCS decreases to 165 psia. The collapsed liquid level, shown in Figure 10.2, in the 450-650 second time frame, is a loop seal effect that is characteristic for this range of break sizes. It should be mentiongd that a similar scenario investigated for a 0.04 f t break resulted in RCS pressure remaining above 300 psia untilsigni{icantroreuncoveryhadcommenced. Thus.
the .045 ft ie the smallest break size for which depressurization is sufficient and timely enough to permit using the core deluge lines to prevent core uncovery during the long-term.
10.3.2 HPR .02 FT2 CLD BREAK This ang' lysis represents an investigation of a
.02 ft. break in the loop 2 CLD. As seen in (y Figure 10.3, the RCS depressurizes to a pressure slightly above 400 psia by 4,000 seconds (the
('") transient is initiated at 50 seconds). By this time, the recirculation mode had been initiated with total RCS makeup flows consisting of a minimum of one charging pump with suction via the RIIR pump from the sump and discharge through valve 110A only. As seen in Figure 10.4, this is sufficient to maintain adequate core coverage. The collapsed core liquid level is slightly above the 80 percent level and a two phase mixture covers the top of the core.
Referring again to Figure 10.3, the RCS can be seen refilling at about 1,200 seconds. At 1,950 seconds, llPSI and charging injection flow to the RCS is terminated due to 100,000 gallons having been used from the RWST. All injection pumps had been initiated for the injection phase. For this scenario, a 10 minute delay was included between the end of the injection mode and the start of one charging pump for the subsequent recirculation flow.
Recirculation thus commenced at about 2,550 seconds.
A similar scenario investigated for a .03 ft break resulted in significant core uncovery beginning at about 2,000 seconds af ter the initiation of
,_s recirculation. Additionally, the .03 ft2 case was
/ run with the less conservative conditions of valve V) 10-3
( 110 open and no delay between injection and
\ _-)
s recirculation. Thus, the .02 ft" is the largest break size for which one charging pump, during the recirculation phases, is sufficient to prevent core uncovery.
10.4 Summary The resulta of this investigation indicate that, with the exception of a small range of break sizes in the loop 2 cold leg, medium and small LOCAs during the recirculation phase can be satisfactorily mitigated by the high and low pressure safety injection systems. Cold leg breaks in loop 2 in the 0.02 to 0.045 ft2 range result in insufficient safety injection flow in the high pressure recirculation mode to prevent core uncovery.
Breaks smaller than or equal to .02 ft2 demonstrate core coolability because of the lower break flow rates and the injection is sufficient to maintain the core in a covered a
condition. Breaks larger than or equal to .045 f t 2 depressurize rapidly enough so that Low Pressure Recirculation can be activated thereby assuring adequate core cooling.
Breaks ' located directly in the charging line for sizes 0.045 ft2 and smaller also produce results analogous to the loop 2 cold leg breaks discussed above since for these breaks the RCS pressure also remains above the shutoff head of the HilR pumps while the charging flow provides insufficient flow to g))
( prevent core uncovery.
All breaks located in loops 1, 3, or 4, or in the loop 2 hot leg however demonstrate acceptable ECCS performance since the charging flow (injected into the loop 2 cold leg) is able to maintain the core in a coolable condition.
Alternate actions such as increased RCS depressurization through SG secondary cooldown or injecting charging flow through available alternate lines to the cold legs present the operators with additional options to assist in precluding core uncovery for bteaks in loop 2 for this category of break sizes.
O f I
'V 10-4
. . . _ _ _ . _ _-_ . _ _ . _ _ _ _ _ _ _ _ ~ ____ . . _ ._- _ -_. _ _ ._
I r I L
LO, h j i
FIGURE 10.1 HADDAM NECK PLANT SMALL BREAK ANALYSIS :
! HIGH PRESSURE RECIRCULATION l
. .045 SQ.FT. LOOP 2 DISCHARGE LEG BREAK 2 RCS PRESSURE i
! i j 2200; ,
)
1 I
p r.09 4
i 160C-; ;
e i
It cn L~
1 lO l
i p
R E 1200~- ~
S i S i U l R E 1000i f.
P S 80 %
', I J
A ,
i I 600-
) I 400 ;
l i
I l ?00{
W I
b -r+** i im .,,, w ..,, . , ...,
' r -e--r~ ~ -r-- i -,- ,
0 100 200 300 400 500 600 700 800 900 1000 1100 2200 13u e !
TIME ISEC1 f
I f
1 k
i 10-5 1
-,... -. - ~ _ - - ---.- -..- . . . . , . - . . _ - - _ _ -, _ ..... - - . - - - . . . - . - _ . .- - - _ -.
F FIGURE 10.2 HADDAM NECK PLANT SMALL BREAK ANALYSIS ;
HIGH PRESSURE RECIRCULATION
.045 SQ.FT. LOOP 2 DIC AH RGE LEG BREAK COLLAPSED CORE LEVEL
~~1. 0-f - ,~~
}
b 0.9f .,
V O.e: [
0h L 0.62 ~
j P
i ? h I
~~0.s: 3 b .~~
l {
g 0.4i lL
~~0. 3-j 0.2f fa. Ii~~
(' , . . , , , , _ , , ,
h U " t. -,.,-.. . . m.m. m y . , , , , , , _ . , ,
_ [. 0 100 200 300 400 500 000 700 800 000 1000 1100 1200 1.
TIME ISECs i
~
10-6 i
- l O ,
1 i
FIGURE 10.3 l
HADDAM NECK PLANT SMALL BREAK ANALYSIS HIGH PRESSURE RECIRCULATION
.02 SQ.FT. LOOP 2 DISCHARGE LEG BR AEK
~~RCS PRESSURE 210Tt~~
~
2003 1
. 19302 I !
180$-- ,
1700-'
16032 ISOC-
! R
! C 144002 0,
P 133d-a 1
S 1270 S
u I
j .
(,(
i R 1100, l i E
! 1000:
P i 5 900 i !
A
' (
BODI .
730- -
e 00C-500-]
~-
is 0Gl l 30'. -
k' PU2 .,,r.., .-~r-~,. ..--,--,,w-,,,. .,
.,. 7 0 1000 2000 3000 t1000 5000 6000 7000 eagn
!O -
i 10-7 I. . _ __ _ _ . _ _ _
a ~
O >
FIGURE 10.4 HADDAM NECK PLANT SMALL BREAK ANALYSIS HIGH PRESSURE RECIRCULATION
.02 S0.FT. LOOP 2 DISCHARGE LEG BREAK COLLAPSED CORE LEVEL
~~i. e . _ _ . . _ .~~
3 m "/ a ' o ov'"Y ' 8 v' *- ,.o C. MS-
'l
~~c. w.~~
o
~~0. 9. 5 c..~~
' O r.
. l
> i
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~~, ,4 i~~
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o- J l .
4 i i
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c a.- i j o.,
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j r
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T- +--i - . . - - , . , - - - - ,
31)l j f ' $(ilif t (;Jipe j .l g- 1
( Ili E l l' ' ' QIJ OQ 11ML tL(i 10-8
n
( ) 11. TOTAL LOSS OF DIRECT CURRENT POWER ANALYSIS V
11.1 Int roduction The purpose of this study is to determine whether core uncovery will occur following the total loss of direct current (d.c.)
power. If core uncovery is determined to occur, then the time of oncovery is an important parameter in estimating the probability of operator actions to mitigate the event. The results of this study demonstrate that the core remains covered in the first four hours of the event and will remain covered for several additional hours. This should provide sufficient time for the operators to mitigate the consequences of the event.
D.C. power at Connecticut Yankee is supplied from two battery busses. The symptoms and results of the loss of either bus are described in Reference 6. Each bus supplies the control power and breaker indication for one half of the 4160V and 480V breakers. If the d.c. bus is lost, these breakers will fail "as-is". The loss of the "A" bus deenergizes the solenoids shutting the main steam stop valves. Also, a reactor trip will occur with a loss of primary side annunciation. The "A" and "B" vital inverters will be disabled, and the breaker indicating lights and control power for all breakers on busses 1-1A, 1-2, 4, 5, and 8 will be lost.
n
('-I The loss of the "B" battery bus deenergizes the solenoids preventing the operation of the HP steam dump system. Also, the reactor and turbine will trip with no secondary side i annunciators. The loss of the "B" bus results in the loss of the "C" and "D" vital inverters as well as the loss of breaker indicating lights and control power for all breakers on busses 1-1B, 1-3, 6, 7, and 9.
If a total loss of d.c. power occurs, the following automatic actions would result.
The reactor and turbine will trip. The main steam stop valves will close. The charging flow control valves 110 and 110A will l open fully, and the one operating charging pump will align with the RWST. The Terry Turbines will draw steam and provide power to the auxiliary feed pumps which will start and supply all steam generators. The main feed regulating valves will close and the feedwater bypass valves will open. All the reactor coolant pumps will coast down. All level control and indications on the steam generators and the pressurizer will fail. The pressurizer pressure signal which actuates the P0HVs also will lose power. The Terry Turbines are assumed to trip, terminating the auxiliary feed, if the steam line fills with liquid.
The operators are assumed to take the following actions during g} the event.
11-1
['i_/} o The main feed pumps are manually tripped off ofter 2 minutes.
o The letdoen flow is not isolated.
o The charging flow and auxiliary feed flow are allowed to continue at full flow throughout the event.
The response of the Connecticut Yankee Reactor Coolant System to the scenario is sin ulated by NULAPS. A discussion of the analytic model used in the analysis along with a description of the results is presented below.
11.2 Analytical Model The single loop representation of Connecticut Yankee is used for the total loss of d.c. power analysis. This model is similar to the one used in the station blackout analysis presented in Section 2. Additional modeling of the steam lines to the Terry Turbines, the letdown lines, and pressurizer safety valves have been added for the loss of d.c. analysis.
The model was initialized with thermal-hydraulic conditions representative of best estimate conditions provided in Reference 3.
11.3 Discussion of Results
(' ') The total loss of d.c. event starts with the main steam stop valves closing. Simultaneously all level control is lost as well as the steam bypass control. The auxiliary feedwater pumps and their Terry Turbines start and the feedwater bypass line valves open fully. Reactor trip and turbine trip occur.
The closure of the main steam stop valves with no steam bypass causes the pressure in the steam generators to rise to the safety relief valve setpoint. The safety relief valves open at 240 seconds to limit the steam pressure to 1000 psia.
Figure 11.1 presents the steam generator pressure during the event. The pressure remains at the safety valve lift setpoint until 1290 seconds. The decrease in steam pressure is caused by the auxiliary feedwater which is 90*F reaching the steam generators and condensing the steam. The auxiliary feedwater is started at 60 seconds. However, the feedwater lines are filled with hotter 420 F feedwater. At approximately 900 4
seconds, two of the feedwater lines are swept out while the remaining two feedwater lines are swept out at 1000 seconds.
The auxiliary feedwater slowly fills the steam generator while cooling the primary system. Figure 11.2 shows ti.e collapsed liquid level in the downcomer. At 2850 seconds the steam generators are essentially filled with subcooled and saturated liquid. The steam lines begin to fill at this time. At approximately 8900 seconds, the void fraction in the steam lines decreases below 0.5 indicating that liquid would be fsj entering the Terry Turbines. The Terry Turbines and the v
11-2
[] auxiliary feed pumps are assumed to t rip at this time. The
() steam Iine void f raction is shown in Figure i1.3.
For the duration of the event no feedwater is provided to the steam generators and the steam flow to the Terry Turbines remains off. The auxiliary feed flow during the transient is given in Figure 11.4. The pressure and temperature of the steam generators slowly increase towards the safety valve setpoint. Four hours after the initiation of the loss of d.c. ,
however, the safety valve setpoint has not been reached. The level in the steam generator downcomer slowly decreases but continues to indicate that after four hours the steam generators are essentially filled with liquid.
l On the primary side, the conditions are dominated by the heat transfer to the steam generators and the continuous charging and letdown flow. The average temperature of the primary loop during the transient is shown in Figure 11.5. After the reactor trip, the temperature rises as the steam generator pressure increases to the safety valve setpoints. The Tavg follows the cycling of the steam generator safety valves unt il the steam generator pressure decreases following the decrease in auxiliary feedwater temperature. Tavg continues to follow the decrease in secondary side temperature and pressure to 8900 seconds when the auxiliary feedwater is tripped. Tavg then increases with the increase in steam generator temperature and f- pressure.
V The pressurizer pressure during the transient is shown in Figure 11.6. The pressure follows the average temperature changes until about 4000 seconds. At this point, the effect of the charging pump adding liquid to the RCS in excess of the letdown flow is realized. The overfilling of the RCS continues to increase the pressure and level in the pressurizer until the l auxiliary feedwater stops and the average temperature I
increases. This causes a large increase in the pressurizer level and pressure. The pressure approaches the safety valve lift setpoint. Ilowever, the setpoint is not reached in this simulation because the letdown flow exceeds the charging flow i at these high pressures. The increase in the letdown flow l relieves the pressure increase of the RCS. At four hours into i
the event, the pressurizer safety valve has not lifted. The l loss of coolant from the RCS due to the letdown flow exceeding l
the charging flow is small, approximately 5 to 7 lbm/sec. At this loss rate, the core would not uncover for several more hours. If the safety valve were to lift, this would reduce the pressure. At the reduced pressure, the charging flow would increase and the letdown flow would be decreased thus limiting the coolant loss until the pressure increases to the setpoint again. At this point, the transient simulation was stopped.
Clearly the time to core uncovery for this event, if it were to occur, is estimated to be well beyond four hours into the event.
f%)\
11-3
l I
~~11. 4 Summa ry The total loss of d.c. power analysis demonstrates that in the~~
. first four hours the core will not be uncovered. The l conditions after four hours indicate that core uncovery would j not occur for several more hours, thus giving the operating j staf f more than suf ficient time to take action to restore d.c.
1 power.
T I
n
(
~~h j~~
a 1
I t I
i i
J I
I '
F 1
s 1
1 I
i a
i 1
.\
4 11-4
_ _..-m.._ . . _ _ - . . , _ _ . . . . _ _ _ . . . _ . . . . _ _ _ _ _ _ . _ . _ _ _ _ . . . . _ . _ _ . . _ . . _ _ _ _ _ _ . _ _ . . - _ . _ . . . . _ . . _ . _ _ _ . _ .
I O
FIGURE 11.1 HADDAM NECK PLANT TOTAL LOSS OF DC S. G. PRESSURE 1100; 1000i 900i 800i t
g - E 6002 '
5 S
.S 500 h 9
u00i 300J, 200i 100 o' . . . . .
0 2000 4000 6000 8000 10000 12000 14000 TIME (SECl 6
11-5
~ ~ - _ . _ . - . _ _ . . _ _ _ _ _ . _ _
1 i
'j .
, %)
l-5; .
i FIGURE 11.2 ;
i HADDAM NECK PLANT TOTAL LOSS OF DC S. G. LEVEL 1.00f ,,p,,,,,___.
0.95i 0.90-l a
C.85: ~
O '
0.80f f S
G 0.75-L L i E v a. }
E :
0.7G c.ss-]
2 1 I 4
l
) ,1 4
C.60d
' ; l
!. 4 l U.5E]
1 2 4
c.504 0 2 ado 40$o sobo - 8050 10b00 12500 14E00 TIME ISEC1 s
l 11-6
___.-__-.......__m.____.-.__._,.,_,--_- _ _ _ . . . _ - . _ . - _ _ , _ _ _ _ . - _ _ . - - _ .
_s FIGURE 11.3 HADDAM NECK PLANT TOTAL LOSS OF DC
~
STEAM LINE VolD FRACTION 1.03 - , nw y#, 4, 1
~~0. 92, c.ei 1~~
3 C.7 1
3 J 0.6]
2 v a e
0.sg e 3 3
2 0.%
l 3 1 -
t j
c.:q l
I I
~~2j ,~~
j
! I -
~~c.1a 3~~
3 C.G-6000 80b0 10b00 12000 1'4000 0 2000 L1000 TIP'E ISEC) 11-7 1
r ;
E i
L@
l i
~~j. FIGURE 11.4~~
.. HADDAM NECK PLANT i TOTAL LOSS OF DC
! AUX FEED FLOW i i
~~i. 120],~~
110i i
10Ch !
! 3 4 e i sui I
e' BCi L
F L
70i i' h r
( 602 ir L 3, S
M
/
i 5 503 3 I' 3 4 . i
~~4 t.a-i k~~
3 30 ,
s
~~t. !~~
Y 2
3 I
~~t.3 1~~
I ;
? e
! 3 -
i r
IUi f 2 e i 3 j 1 l CL r b 20b0 4000 50b0 80bb 20000 12 BOO 14000 t
l. I I' TIME (SECl
' f j .'
k I 11-8 i i
4
.1 bh i FIGURE 11.5 ,
i HADDAM NECK PLANT i TOTAL LOSS OF DC
~~AVERAGE TEMPERATURE f~~
}
570j f 560f 4 .
1 550--
l s40) s304 )
1- 520,2 t 510 ,
500-'
i : '
I E 490- -
t g P ,
480-I '4 F
3 470, h- .
46C-I .
i uso-- ,
1 .
~~44t2 5 43cq}~~
3
~~4201 410 1~~
4 N00 ,
j 14000 !
C 2000 4000 5000 8000 10000 12000 l '
TIME ISEC) i i
i l i
E i
i f
1 11-9
,v+- v r-- r-- , .ww-_ m------ -w--,c,-- . + - - , , _ , - - _ _ _ . _ _ _ - _.e..,--, r----m.-_-+,-,-.me,.~ m.--.
p <
l t
4 t
FIGURE 11.6 i
~~HADDAM NECK PLANT TOTAL LOSS OF DC o~~
PRZ. PRESSURE :
2550f j 2500i I
1 2450i i
l- <
, 2400i ,
i 1 i
j 2350b j i 2 1
4 P 23004
~~i R A l- E 3 i' 5 1~~
' 0 5
?' t2250-3 d f
, ! 3
~~R A l ) 220G4 3~~
3 l 3 e c 50d j
! 3 ,
l d i 3 210G-3 ,
?
i A i t a
! 1 I 2:504 i 3 r 4 l 1 3
1 2000-]
l
^
t 3
~~195Cg v- , , , .~~
O 2000 4000 6000 8000 10000 12000 14000 TIME (SEC1 ,
e l-
~~11-10 I-~~
~wr,-,,--,-, .n..-v.,-r,~a,-_-a,...,_e_n--,---,..n n,,-.-,-.,,,--.---,n.,, .~,. ,- ,--.-- .. s-,,. - , ,- - _ , ,- ,-, - .. .i,-,...,._,,--.-
[~) 12. FUEL CLADDING TEMPERATURE CALCULATIONS FOR MEDIUM BREAK LOCA
\ _)
s g 12.1 Introduction The purpose of this section is to detecmine the maximum fuel clad average temperature achieved for the 0.2 ft 2 break in the pump discharge leg as discussed in Section 6.0. As mentioned in Section 6.0, analysis of the 0.2 ft2 break was performed-assuming a 300 second delay in HPSI actuation and, as such, the partial core uncovery for this event was extended compared to the core with no delay in HPSI actuation. Due to the nature of the transient, a separate heat up model was constructed to determine the maximum core average clad temperature for this event. . Also, because there is the potential for liquid drainage, from the hot legs and steam generators, to de-superheat the steam during periods of core uncovery when using the NULAPS model discussed in Section 1.2, this separate heat up analysis was performed to remove the cooling effect from the clad temperature calculation. The model is discussed below.
12.2 Analytical Model The model consists of a NULAPS representation of the core region with a time dependent inlet flow junction at the inlet to the core and an outlet time dependent control volume at the core exit. The model is illustrated in Figure 12.1. The inlet r'~x
() junction was used to supply liquid to the core region to simulate the liquid and two phase levels consistent with that computed for the 0.2 f t2 break discussed in Section 6.0. The outlet time dependent volume was utilized to impose the 0.2 ft:
pressure transient on the heat-up calculation. The core was represented with twelve (12) axial regions with appropriate core average heat slabs included to perform the heat-up analysis. The results of this evaluation are discussed in the following section.
12.3 Discussion of Results As discussed above, the pressure transient for the Section 6.0 0.2 ft2 break was imposed on the heat-up calculation while the time dependent inlet flow junction was used to supply liquid to the core region to reproduce the transient liquid and two phase levels. As shown in Figure 12.3, the core region was allowed to uncover af ter which liquid was supplied to reproduce the
- liquid level transient. As shown in Figure 12.3, the result itig liquid level used to perform the heat-up was maintained at a lower level than that for the 0.2 ft 2 break results of Section 6.0 to further maximize the clad temperature. The pressure transient is given in Figure 12.2.
/
k
. s_
12-1
4 1
i- j i
a With these inputs, the clad temperature response w.is completed with the levels presented in Figure 12.4. As shown in
. Figure ,12.4, the peak clad core average temperature was computed to be 1264*F occurring at 134 seconds into the event.
12.4 Summary i i j
l The . fuel clad average temperature calculations for the 0.2 f t.2 i break discussed in Section 6.0 demonstrate that core is I
! adequately cooled throughout the transient with a peak clad i core average tengerature of 1264*F.
l' L
iw .
2
),
i f> ,
4 1
s 1
i l
e
! i f
i-i l
l i
i i ,
! 12-2 r
5 s--,. ,m-.--.....-.-.._ .,-..-ryw. .
.,,. - - ,--.,,m, -,v,, --vw,,,---, ._-.y.,w.,-e,-,,.v w 4 e -_- % je.v m
a -
i 3
4
N.
400
%,h .
[
j h 350 O . [1 s
e l' s.1 je 3 }vl h(it 2 $
1 ;
900 800 FIGURE 12.1. HADDAM NECK PLANT FUEL CLADDING TEMPERATURE CALCULATIONS NODE DIAGRAM
~~O 12-3~~
i
~~O I~~
FIGURE 12.2' HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF HPSI FLOW AT 300 S CORE PRESSURE i
2200-l 2000i
~~5 1800i {~~
t 1600i i 1
1400i P .
}
R i 4 E :
S 1200i Y \
E p 1000i S
b '.
800i e
i 600i 400i 200i
. 02 .,_ , .,. , .,. , .,
100 200 300 400 500 600 700 800 0
TIME (SEC1 4
LEGEND: CURVE LARGE M00EL -- -- MINI MODEL t
12-4
O FIGURE 12.3 HADDAM NECK PLANT SMALL BREAK ANALYSIS 0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF HPSI FLOW AT 300 S COLLAPSED CORE LEVEL 100-
'l 20-h o -
~~nyS J E~~
i l
ai j 4 L
x i
90- j i
Nwe+.L sgswn .
i ./q a- i t f i
i
!\.
~~t .-~~
/
l" b-1 l
\. r' 0_ \. /
b Ibo 2bb 3bo 4bo Sho 6bo 7bb ebo TIME ISEC)
LEGEN0: CURVE LARGE MODEL ------ M I N I MODEL 12-5
d 1
I J
O FIGURE 12.4
! HADDAM NECK PLANT SMALL BREAK ANALYSIS <
0.2 SQ.FT. DISCHARGE LEG BREAK,RCPS OFF r
HPSI FLOW AT 300 S FUEL CLADDING AVERAGE TEMPERATURE 13007 I
1200' f
1100-iO
~~1000-~~
! T
! I l P
500:
~~r r N h N~~
F 800f 7002 600-500-'
' = i . . . . , , , , , , , . . -r 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 000 TIME 15EC1 12-6
~~13. REFERENCES _~~
~~1. NUSCO Topical Report "NULAP5, A FORTRAN IV Digital Computer Program for Nuclear Steam Supply System Blowdown and Fuel Rod Heat Up Analysis"; Load Module: BE084CG.N14LOADE. LOAD.~~
~~2. ANS-5.1 " Proposed ANS Standard - Decay Energy Release Rates Following Shutdown of Uranium Fueled Thermal Reactors",~~
~~October, 1971 and Revised October, 1973.~~
~~3. NUSCO 132 "Best Estimate Transient Analysis for the Connecticut Yankee Nuclear Power Plant", May, 1983.~~
~~4. NUSCO 126 " Evaluation of Westinghouse Topical Report WCAP 9600 to Determine Applicability to the Connecticut Yankee Reactor",~~
~~September, 1979.~~
~~5. NUSCO Drawing 16103-26007, Rev. 3.~~
~~6. Connecticut Yankee Emergency Operating Procedures.~~
~~7. PDCR Control No. B-284, PDCR No. 401, " Safety Grade Auto Ini tiation Auxilia ry Feedwater."~~
~~. 8. "CYT, Plant Information Book, Primary Systems" Rev. 10/83.~~
~~9. Crosby Letter from Calc. C2-517-557-RE, Rev. O.~~
~~10. "CYT, Plant Information Book, Secondary Systems" Rev. 10/82.~~
~~11. NUSCO Drawing 16103-29067, Sheets 20, Rev. 7 and 31, Rev. 2.~~
~~12. F. J. Moody, " Maximum Discharge Date of Liquid Vapor Mixtures from Vessels," Nonequilibrium Two-Phase Flows, ASME Hymp. Vol.,~~
~~American Society of Mechanical Engineers (1975).~~
~~13. NUSCO Topical Report " Calculative Methods for the Northeast Utilities Small Break LOCA ECCS Evaluation Model," July 1984.~~
~~14 Connecticut Yankee Atomic Power Company, facilities Description and Safety Analysis, Docket No. 50-213.~~
~~15. Letter from J. F. Opeka (CYAPCO) to C. I. Grimes (NRC) "Haddam Neck Plant Environmental Qualification of Equipment Outside Containment,", December 13, 1985.~~
~~16. Letter D. C. Switzer from CY Atomic Power to A. Giambusso, U. S. Nuclear Regulatory Commission, Docket No. 50-213, February 28, 1975.~~
~~17. COBRA / TRAC Simulation of a Large-Break LOCA in the CY Haddam Neck Pressurized Water Reactor Loaded with Tyirconium Clad p Fuel, Numerial Applications, Inc., December 26, 1984.~~
'[ )
13-1 L

ML20155E759

Text

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