ML20214D503

Response of B&W Plant to Steam Generator Tube Ruptures

ML20214D503
Person / Time
Site:	Three Mile Island
Issue date:	09/30/1986
From:	Jensen R, Santee G, Jason White INTERMOUNTAIN TECHNOLOGIES, INC.
To:
Shared Package
ML20214D448	List: ML20214D446 ML20214D465 ML20214D503
References
NSAC-101, NUDOCS 8611240118
Download: ML20214D503 (402)

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NSAC 01 ~ _ . _  ;

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I ResponseofaB&WPlant i to Steam Generator

.l Tube Ruptures I Prepared by Intermountain Technologies, Inc.

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ll ihe elec r c u lYi indust lec ic rResearc Institute I

g PA'" a naa g e

I I Response of a B&W Plant to Steam Generator Tube Ruptures g

NSAC-101 Fina! Report. September 1986 I

I Prepared by INTERMOUNTAIN TECHNOLOGIES. INC-1400 Benton Avenue Idano Falls Idaho 83401 Poncipa' !nvestigatoat I

I ORDERING !NFORMATION 4

Ccptes of this report may be ordered from Research Reports Center (RRC), Box 50490.

Palo A!!o. CA 94303. (415) 965-4081. There is no charge to NSAC member utihties and 3 certain other nonprofit organizabons.

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%ac as Steam gererator U r cVe C%e tnroagn steam generator ' P ant t'a s.erts FELAPS l

EPRis pec-g ams recewe feceraf f.ranc:a' ass < stance by vdA of soonsc'sto of !"e lost.tu*e t, federaq c*^ea ut ut es and tweer beneMs a e a.a'ase to a" ebg b;e persons regar3ess of race cuor raronal or g n haac cao of age Eiec*r.c Puer Pesea cm les?'tute and EPRt we reg.sfered sovee mee 1 E'ec*nc P acr Resea-ch laaue Mc Cce,rgnt 1986 N4 ear Sa'e9 AnaWs Center A2 rghts rese'ved i

NOTICE in s report was precarM by tre organeation(s) ramec below as an account of work sponsorca ty the Nuc' ear

( Sa'ery Araws Center (NSAC) operated ty the Eiectnc Power Research Inst.tute inc (EPR!) Netrer NSAC i

me+bers of NSAC the organear on(s) named teien nor any person act.ng on be na't of any of them (a) ma6es l any wa<<a,t, e= press or ephed *+tn respect to tv use of a~y informat on acca a'us me mo d or process a secsea in in<s repec or inat sucn use may not intnnge cre.areN ownec 'g ts or m assm a , taco t es l a in respect to t*e use of or 'or ca+ ages resst:ng ' rom the use cd a,y .n'or+av acca a:a +ethod or p acess o.svesed in :n-s report P epa ed ty i

' Irtemua n Tecnrotag-es Inc laaho Fass Idano 1

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NSAC PERSPECTIVE PROJECT DESCRIPTION The reactor coolant system in a pressurized water reactor includes thousands of steam generator tubes. In some plants, corrosion, wear, or fatigue of steam I generator tubes has resulted in leaks from the reactor coolant system to the secondary steam producing system. In a few cases, the leaks have led to ruptures of a tube. The design basis steam generator tube rupture is an instantaneous, complete rupture of one tube. In this effort, cases far in excess of the design basis were analyzed.

This work entailed an evaluation of the effect of steam generator tube ruptures in a Babcock & Wilcox (B&W) designed plant having a lower loop configuration and 177 fuel assemblies. The evaluation was performed using the RELAP5 code to calculate thermal hydraulic response of the plant to the rupture of single or multiple tubes I in ene or both once-through steam generators (OTSGs). The RELAPS code provides best-estimate predictive capability for use in a wide spectrum of system thermal-hydraulic analysis applications.

PROJECT OBJECTIVES The main objectives of this project were:

I 1. to determine the system response of a B&W lower loop plant to the rupture of one or more steam generator tubes,

2. to examine the effect of various operating strategies and equipment failures on these strategies.

3. to develop and document the analytical techniques necessary to perform these analysis.

PROJECT RESULTS Ruptures of up to ten tubes in one or both OTSGs were evaluated. For the cases evaluated, the core remained satisfactorily cooled. In no case did a fuel rod cladding temperature excursion occur.

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I In all cases, a controlled shutdo'.vn was achieved, with primary pressure below the lowest secondary safety valve opening set point and continuing to decrease. Hot leg subcooling margins were greater than 20F' (11.1C').

In cases where operation of reactor coolant pumps was continued during the g transient following the steam generator tube rupture (s), both forced circulation 5 and pressurizer spray were available. With pumps running, the plant recovery was determined to be steadier and more easily controlled than in cases where the pumps were tripped early in the transient.

In cases where the reactor coolant pumps were tripped, natural circulation or feed and bleed were sufficient to cool the plant.

I James F. Lang V.K. (Bindi) Chexal NSAC Project Managers I

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ABSTRACT I This report describes an evaluation of the system response of a lower loop Babcock

& Wilcox 177 fuel assembly plant to the rupture of single or multiple tubes in one or both once-through steam generators with the RELAPS code. Comparisons are made between the results of RELAPS, RETRAN and B&W MINITRAP code for a single steam I generator tube rupture. The modeling approach used for these analyses, along with a system description of the major features of the plant are included.

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I CONTENTS Section Pge 1 INTRODUCTION 1-1 I 1.1 General 1.2 Mitigation Strategy 1.3 Cases Analyzed 1-1 1-1 1-3 2 FINDINGS AND CONCLUSIONS 2-1 I 3 SYSTEM DESCRIPTION AND CODE MODEL 3.1 The System 3.2 RELAPS Code Description 3-1 3-1

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3-1 3.3 RELAPS Hydrodynamic Input Model 3-10 3.4 Steady-State Initialization 3-13 3.5 Deck Validation 3-14 4 BENCHMARK ANALYSIS 4-1 4.1 RELAPS Input Model Description for Benchmark Calculation 4-1 4.2 Results of Benchmark Calculation 4-2 4.3 Conclusions from Benchmark Analyses 4-18 5 SINGLE TUBE RUPTURE CASES 5-1 5.1 General 5-1 5.2 Single Tube Rupture Case 2 5-3 5.3 Single Tube Rupture Case 3 5-33 5.4 Single Tube Rupture Case 12 5-63 5.5 Single Tube Rupture Case 10 5-89 5.6 Single Tube Rupture Case 11 5-115 6 TEN TUBE RUPTURE CASES 6-1 6.1 General 6-1 I 6.2 Ten Tube Rupture Case 4 6.3 Ten Tube Rupture Case 5 6-3 6-34 6.4 Ten Tube Rupture Case 6 6-60 I .ii I

I Section Page 6.5 Ten Tube Rupture Case 8 6-86 6.6 Ten Tube Rupture Case 9 6-111 7 FIVE TUBE RUPTURES IN EACH OTSG, CASE 7 7-1 8 REFERENCES 8-1 APPENDIX A TRIPS AND CONTROL A-1 APPENDIX B FUEL CLADDING SURFACE TEMPERATURE B-1 I

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ILLUSTRATIONS Figure Page 3-1 Primary Coolant System 3-2 I 3-2 3-3 3-4 Steam Pressure Control System Main and Emergency Feedwater Systems Control of Main Feedwater 3-3 3-4 3-5 3-5 Control of Emergency Feedwater 3-6 3-6 HPI and MU Systems 3-7 Azimuthal Cross-Section of the Reactor Vessel. Showing I 3-7 3-8 8 Reactor Vent Valves RELAPS Nodalization Diagram 3-8 3-11 4-1 Comparison of RELAPS, RETRAN, and MINITRAP Calculated 0TSG A Pressure 4-4 4-2 Comparison of RELAP5, RETRAN, and MINITRAP 4-5 I 4-3 Calculated 0TSG B Pressure Comparison of RELAP5, RETRAN, and MINITRAP Calculated Loop A TOSG Indicated Liquid Level 4-6 4-4 Comparison of RELAP5, RETRA?,, and MINITRAP Calculated Loop B OTSG Indicated Liquid Level 4_7 4-5 Comparison of RELAP5, RETRAN and MINITRAP Calculated Loop A Cold Leg Fluid Temperature 4-9 I 4-6 Comparison of RELAP5, RETRAN, and MINITRAP Calculated Loop B Cold Leg Fluid Temperature 4-10 .

I 4-7 4-8 Comparison of RELAPS, RETRAN, and MINITRAP Calculated Loop A Flow Comparison of RELAPS, RETRAN, and MINITRAP 4-11 l

t I 4-9 Calculated Loop A Hot Leg Fluid Temperature Comparison of RELAP5, RETRAN, and MINITRAP Calculated Loop B Hot Leg Fluid Temperature 4-12 4-13 E 4-10 Commparison of RELAP5, RETRAN, and MINITRAP 5 Calculated Upper Break Flow 4-14 4-11 Comparison of RELAP5, RETRAN, and MINITRAP Calculated Lower Break Flow 4-15 I

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I Figure P_agj; 4-12 Comparison of RELAPS, RETRAN, and MINITRAP Calculated Total HPI Flow 4-16 4-13 Comparison of RELAP5, RETRAN, and MINITRAP Calculated Pressurizer Indicated Level 4-17 4-14 Comparison of RELAPS, RETRAN, and MINITRAP Calculated Core Outlet Pressure 4-19 4-15 Comparison of RELAPS, RETRAN, and MINITRAP Calculated Hot Leg Subcooling Margin 4-20 5-2.1 Break Flow 5-9 5-2.2 Pressurizer Indicated Level 5-10 5-2.3 Core Outlet Pressure 5-11 5-2.4 Reactor Power 5-12 5-2.5 Loop A and B Hot leg Mass Flow Rate 5-13 5-2.6 Total HPI Flow Into RCS 5-14 5-2.7 PORV Flow Out of RCS 5-15 5-2.8 Net Flow Rate Out of RCS 5-16 5-2.9 Integrated Flows Into and Out of RCS 5-17 5-2.10 Loop A Fluid Temperatures 5-18 5-2.11 Loop B Fluid Temperatures 5-19 5-2.12 Hot Leg Subcooling Margin 5-20 5-2.13 Upper Head Average Liquid Fraction 5-21 5-2.14 OTSGA Break Flow 5-22 5-2.15 OTSGA EFW Flow 5-23 5-2.16 OTSGA Safety Valve Flow 5-24 5-2.17 OTSGA MADV Flow 5-25 5-2.18 OTSGA TBV Flow 5-26 5-2.19 OTSGB EFW Flow 5-27 5-2.20 OTSGB Safety Valve Flow 5-28 5-2.21 OTSGB MADV Flow 5-29 5-2.22 OTSGB TBV Flow 5-30 5-2.23 OTSG Downcomer Indicated Level 5-31 5-2.24 Steam Generator Pressure 5-32 5-3.1 Break Flow 5-38 5-3.2 Pressurizer Indicated Level 5-39 5-3.3 Core Outlet Pressure 5-40 5-3.4 Reactor Power 5-41 5-3.5 Loop A and B Hot Leg Mass Flow Rate 5-42 5-3.6 Net Flow Into RCS 5-43 5-3.7 Total Break Flow 5-44 X

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I I Fiqure 5-3.8 Total HPI Flow Page 5-45 5-3.9 I

PORV Flow 5-46 5-3.10 Integrated Flows Into RCS 5-47 5-3.11 Loop A Fluid Temperatures 5-48 5-3.12 Loop B Fluid Temperatures 5-49 5-3.13 Core Outlet Subcooling Margin 5-50 5-3.14 Upper Head Average Liquid Fraction 5-51 5-3.15 OTSGA Break Flow 5-52 5-3.16 OTSGA EFW Flow 5-53 5-3.17 OTSGA Safety Valve Flow 5-54 5-3.18 OTSGA MADV Flow 5-55 5-3.19 I 5-3.20 5-3.21 OTSGA TBV Flow OTSGB EFW Flow OTSGB Safety Valve Flow 5-56 5-57 5-58 5-3.22 OTSGB MADV Flow 5-59 5-3.23 OTSGB TBV Flow 5-60 5-3.24 I 5-3.25 5-4.1 OTSG Downcomer Indicated Level Steam Generator Pressure Break Flow 5-61 5-62 5-67 5-4.2 Pressurizer Indicated Level 5-68 5-4.3 Core Outlet Pressure 5-69 5-4.4 Reactor Power I 5-4.5 5-4.6 Loop A and B Hot Leg Mass Flow Rate Flows Into RCS 5-70 5-71 5-72 5-4.7 Integrated Flows Into and Out of RCS 5-73 5-4.8 Loop A Fluid Temperatures 5-74 5-4.9 I 5-4.10 5-4.11 Loop B Fluid Temperatures Hot Leg Subcooling Margin Upper Head Average Liquid Fraction 5-75 5-76 5-77 l

5-4.12 OTSGA Break Flow 5-78 5-4.13 OTSGA EFW Flow 5-79 5-4. 4 TSGA Safety valve Flow lE 5 80 5 5-4.15 OTSGA MADV Flow 5-81 5-4.16 OTSGA TBV Flow 5-82

5-4.17 OTSGB EFW Flow 5-83 l 5-4.18 OTSGB Safety Valve Flow 5-84 5-4.19 OTSGB MADV Flow 5-85 I x4 I

I Fiqure Page 5-4.20 OTSGB TBV Flow 5-86 5-4.21 OTSG Downcomer Indicated Level 5-87 5-4.22 Steam Generator Pressure 5-88 5-5.1 Break Flow 5-93 g

5-5.2 Pressurizer Indicated Level 5-94 3 5-5.3 Core Outlet Pressure 5-95 5-5.4 Reactor Power 5-96 5-5.5 Loop A and B Hot Leg Mass Flow Rate 5-97 5-5.6 Flow Into RCS 5-98 5-5.7 Integrated Flows Into RCS 5-99 E

3 5-5.8 Loop A Fluid Temperatures .

5-100 5-5.9 Loop B Fluid Temperatures 5-101 5-5.10 Core Outlet Subcooling Margin 5-102 5-5.11 Upper Head Average Liquid Fraction 5-103 g 5-5.12 OTSGA Break Flow 5-104 5 5-5.13 OTSGA EFW Flow 5-105 5-5.14 OTSGA Safety Valve Flow 5-106 5-5.15 OTSGA MADV Flow 5-107 5-5.16 OTSGA TBV Flow 5-108 g 5-5.17 OTSGB EFW Flow 5-109 3 5-5.18 OTSGB Safety Valve Flow 5-110 5-5.19 OTSGB MADV Flow 5-111 5-5.20 OTSGB TBV Flow 5-112 5-5.21 OTSG Downcomer Indicated Level 5-113 E

5-5.22 Steam Generator Pressure 5-114 3 5-6.1 Break Flow 5-120 5-6.2 Pressurizer Indicated Level 5-121 5-6.3 Core Outlet Pressure 5-122 5-6.4 Reactor Power 5-123 g 5-6.5 Loop A and B Hot leg Mass Flow Rate 5-124 5 5-6.6 Flows Into RCS 5-125 5-6.7 Integrated Flows Into RCS 5-126 5-6.8 Loop A Fluid Temperatures 5-127 5-6.9 Loop B Fluid Temperatures 5-128 g 5-6.10 Core Outlet Subcooling Margin 5-129 3 5-6.11 Upper Head Average Liquid Fraction 5-130 5-6.12 OTSGA Break Flow 5-131 xii i

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Fiqure Page 5-6.13 OTSGA EFW Flow 5-132 OTSGA Safety Valve Flow 5-133

, I 5-6.14 5-6.15 5-6.16 OTSGA MADV Flow OTSGA TBV Flow 5-134 5-135 5-6.17 OTSGB EFW Flow 5-136 5-6.18 OTSGB Safety Valve Flow 5-137 5-6.19 5-138 I 5-6.20 5-6.21 OTSGB MADV Flow OTSGB TBV Flow OTSG Downcomer Indicated Level 5-139 5-140 l 5-6.22 Steam Generator Pressure 5-141 6-2.1 Break Flow 6-8 6-2.2 Pressurizer Indicated Level 6-9 6-2.3 Core Outlet Pressure 6-10 6-2.4 Reactor Power 6-11 6-2.5 Loop A and B Hot leg Mass Flow Rate 6-12 6-2.6 Flows Into RCS 6-13 6-2.7 Integrated Flows Into RCS 6-14 6-2.8 Loop A Fluid Temperatures 6-15 6-2.9 Loop B Fluid Temperatures 6-16 6-2.10 Hot leg Subcooling Margin 6-17 6-2.11 Upper Head Average Liquid Fraction 6-18 6-19 I 6-2.12 6-2.13 6-2.14 OTSGA Break Floa OTSGA EFW Flow OTSGA Safety Valve Flow 6-20 6-21 6-2.15 OTSGA MADV Flow 6-22 6-2.16 OTSGA TBV Flow 6-23 6-2.17 OTSGB EFW Flow 6-24 6-2.18 OTSGB Safety Valve Flow 6-25 6-2.19 OTSGB MADV Flow 6-26 6-2.20 OTSGV TBV Flow 6-27 6-2.21 OTSG Downcomer Indicated Level 6-28 6-2.22 Steam Generator Pressure 6-29 6-2.23 Liquid Temperature Distribution at T = 14.00 Minutes 6-30 6-2.24 Void Fraction (%) Distribution at T = 14.00 Minutes 6-31 6-2.25 Liquid Temperature Distribution at T = 44.75 Minutes 6-32 6-2.26 Void Fraction (%) Distribution at T = 44.75 Minutes 6-33 6-3.1 Break Flow 6-38 xiii I

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Fiqure Page 6-3.2 Pressurizer Indicated Level 6-39 6-3.3 Core Outlet Pressure 6-43 6-3.4 Reactor Power 6-41 6-3.5 Loop A and B Hot Leg Mass Flow Rate 6-42 6-3.6 Flows Into RCS 6-43 6-3.7 Integrated Flows Into and Out of RCS 6-44 6-3.8 Loop A Fluid Temperatures 4 6-45 6-3.9 Loop B Fluid Temperatures 6-46 6-3.10 Hot Leg Subcooling Margin 6-47 6-3.11 Upper Head Average Liquid Fraction 6-48 ,

6-3.12 OTSGA Break Flow 6-49 6-3.13 OTSGA EFW Flow 6-50 6-3.14 OTSGA Safety Valve Flow 6-51 6-3.15 OTSGA MADV Flow 6-52 6-3.16 OTSGA TBV Flow 6-53 6-3.17 OTSGB EFW Flow 6-54 6-3.18 OTSGB Safety Valve Flow 6-55 6-3.19 OTSGB MADV Flow 6-56 6-3.20 OTSGB TBV Flow 6-57 6-3.21 OTSG Downcomer Indicated Level 6-58 6-3.22 Steam Generator Pressure 6-59 6-4.1 Break Flow 6-64 6-4.2 Pressurizer Indicated Level 6-65 6-4.3 Core Outlet Pressure 6-66 6-4.4 Reactor Power 6-67 6-4.5 Loop A and B Hot leg Mass Flow Rate 6-68 6-4.6 Flows Into RCS 6-69 6-4.7 Integrated Flows Into RCS 6-70 6-4.8 Loop A Fluid Temperatures 6-71 6-4.9 Loop B Fluid Temperatures 6-72 6-4.10 Core Outlet Subcooling Margin 6-73 6-4.11 Upper Head Average Liquid Fraction 6-74 6-4.12 OTSGA Break Flow 6-75 6-4.13 OTSGA EFW Flow 6-76 6-4.14 OTSGA Saety Valve Flow 6-77 6-4.15 OTSGA MADV Flow 6-78 I

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Fiqure Page 6-4.16 OTSGA TBV Flow 6-79 6-4.17 OTSGB EFW Flow 6-80 6-4.18 OTSGB Safety Valve Flow 6-81 6-4.19 OTSGB MADV Flow 6-82 I 6-4.20 OTSGB TBV Flow 6-4.21 OTSG Oowncomer Indicated Level 6-83 6-84 6-4.22 Steam Generator Pressure 6-85 6-5.1 Break Flow 6-89 6-5.2 Pressurizer Indicated Level 6-90 I 6-5.3 6-5.4 Core Outlet Pressure Reactor Power 6-91 6-92 6-5.5 Loop A and B Hot Leg Mass Flow Rate 6-93 6-5.6 Flows Into RCS 6-94 6-5.7 Integrated Flows Into RCS 6-95 6-5.8 Loop A Fluid Temperatures 6-96 6-5.9 Loop B Fluid Temperatures 6-97 6-5.10 Core Outlet Subcooling Margin 6-98

, 6-5.11 Upper Head Average Liquid Fraction 6-99 6-5.12 OTSGA Break Flow 6-100 I 6-5.13 OTSGA EFW Flow 6-5.14 OTSGB Safety Valve Flow 6-101 6-102 6-5.15 OTSGB MADV Flow 6-103 6-5.16 OTSGA TBV Flow 6-104 6-5.17 OTSGB EFW Flow 6-105 6-5.18 OTSGB Safety Valve Flow 6-106 6-5.19 OTSGB MADV Flow 6-107

/ 6-5.20 OTSGB T8V Flow 6-108 6-5.21 OTSG Downcomer Indicated Level 6-109 6-5.22 Steam Generator Pressure 6-110 6-6.1 Break Flow 6-115 6-6.2 Pressurizer Indicated Level 6-116 6-6.3 Core Outlet Pressure 6-117 6-6.4 Reactor Power 6-118 6-6.5 Loop A and B Hot Leg Mass Flow Rate 6-119 6-6.6 Flows Into RCS 6-120 7, 6-6.7 Integrated Flows Into RCS 6-121 6-6.8 Loop A Fluid Temperatures I 6-122 xv I

I Figure Page 6-6.9 Loop B Fluid Temperatures 6-123 6-6.10 Core Outlet Subcooling Margin 6-124 6-6.11 Upper Head Average Liquid Fraction 6-125 6-6.12 OTSGA Break Flow 6-126 6-6.13 OTSGA EFW Flow 6-127 6-6.14 OTSGA Safety Valve Flow 6-128 6-6.15 OTSGA MADV Flow 6-129 6-6.16 OTSGA T8V Flow 6-130 6-6.17 OTSGB EFW Flow 6-131 6-6.18 OTSGB Safety Valve Flow 6-132 6-6.19 OTSGB MADV Flow 6-133 6-6.20 OTSGB TBV Flow 6-134 6-6.21 OTSG Downcomer Indicated Level 6-135 6-6.22 Steam Generator Pressure 6-136 7.1 Break Flow 7-5 7.2 Break Flow 7-6 7.3 Pressurizer Indicated Level 7-7 7.4 Core Outlet Pressure 7-8 7.5 Reactor Power' 7-9 g 7.6 Loop A and B Hot Leg Mass Flow Rate 7-10 5 7.7 Flows Into RCS 7-11 7.8 Integrated Flows Into RCS 7-12 7.9 Loop A Fluid Temperatures 7-13 7.10 Loop B Fluid Temperatures 7-14 E

7.11 Core Outlet Subcooling Margin 7-15 5 7.12 Upper Head Average Liquid Fraction 7-16 7.13 OTSGA Break Flow 7-17 7.14 OTSGA EFW Flow 7-18 7.15 OTSGA Safety Valve Flow 7-19 7.16 OTSGA MADV Flow 7-20 7.17 OTSGA TBV Flow 7-21 7.18 OTSGB Break Flow 7-22 7.19 OTSGB EFW Flow 7-23 7.20 OTSGB Safety Valve Flow 7-24 7.21 OTSGB MADV Flow 7-25 7.22 OTSGB TBV Flow 7-26 7.23 OTSG Downcomer Indicated Level 7-27 xvi I

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7.24 Steam Generator Pressure 7-28 A-1 Control Block Diagram of the Affected 0TSG MADV System A-16 A-2 Control Block Diagram of the Unaffected OTSG MADV A-17 A-3 Control Block Diagram for EFW System B A-18 A-4 Pressurizer Heaters Control Block Diagram A-19 A-5 HP1 Control Block Diagram A-20 A-6 RELAPS Model of a Long Section of Ruptured Tube A-21 A-7 Vent Valve Control Block Diagram A-22 B-1 Single Tube Rupture Case 1 B-2 B-2 Single Tube Rupture Case 2 B-3 B-3 Single Case Rupture Case 3 B-4 B-4 Ten Tube Rupture Case 4 B-5 B-5 Ten Tube Rupture Case 5 B-6 B-6 Ten Tube Rupture Case 6 B-7 B-7 Five - Five Tube Rupture Case 7 B-8 B-8 Ten Tube Rupture Case 8 B-9 B-9 Ten Tube Rupture Case 9 B-10 B-10 Single Tube Rupture Case 10 B-11 B-11 Single Tube Rupture Case 11 B-12 B-12 Single Tube Rupture Case 12 B-13 I

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TABLES Table Page 1-1 Analysis Description 1-4 Conditions at Time of Tube Rupture I 3-1 4-1 5-1.1 Sequence of Events for Benchmark Calculation Single Tube Cases 3-14 4-3 5-2 5-2.1 Sequence of Events for Single Tube Rupture Case 2 5-4 5-3.1 Sequence of Events for Single Tube Rupture Case 3 5-34 5-4.1 Sequence of Events for Single Tube Rupture Case 12 5-63 5-5.1 Sequence of Events for Single Tube Rupture Case 10 5-90 5-6.1 Sequence of Events for Single Tube Rupture Case 11 5-116 6-1.1 Ten Tube Rupture Cases 6-2 6-2.1 Sequence of Events for Ten Tube Rupture Case 4 6-4 6-3.1 Sequence of Events for Ten Tube Rupture Case 5 I 6-4.1 6-5.1 Sequence of Events for Ten Tube Rupture Case 6 Sequence of Events for Ten Tube Rupture Case 8 6-35 6-60 6-86 6-6.1 Sequence of Events for Ten Tube Rupture Case 9 6-111 7-1 Sequence of Events for Five Tube Ruptures in Each OTSG Case 7 7-2

'I A-1 A-2 A-3 Desired 0TSG Pressure as a Function of Time after Scram OTSG Safety Valve Characteristics Turbine Bypass Normalized Valve Position as a Function of A-2 A-4 Steam Line Pressure Before Scram A-5 A-4 MADV Stem Position as a function of Steam Generator Pressure A-6 A-5 MADV Valve Position as a Function of Difference Between I Fluid Temperature in OTSG and Fluid Temperature in Upper Plenum A-6 A-6 MADV Valve Position as a function of Difference Between OTSG Pressure and Desired 0TSG Pressure A-6 A-7 Fraction of Full EFW Flow as a Function of Pressure Above Desired Pressure A-7 A-8 Pressurizer Heater Characteristics A-8 A-9 Pressurizer Heater Power Versus Subcooling Margin A-8 A-10 Hakeup Flew Versus Indicated Pressurizer Level A-10 A-11 HPI Flow as a Function of RCS Pressure A-10 I xix I

Table Page A-12 1.0 Minus HPI Flow as a Function of Hot Leg Subcooling Margin A-ll A-13 Vent Valve Loss Coefficient Versus Valve Opening Angle A-14 A-14 Vent Valve Opening Angle as a Function of the Valve Differential Pressure A-15 l

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Section 1 INTRODUCTION 1.1 GENERAL This effort assesses plant responses to the rupture of up to 10 tubes in one or both steam generators of a generic Babcock & Wilcox (B&W) lower loop reactor plant.

Steam generators in pressurized water reactor plants are heat exchangers that transfer heat from the reactor coolant system to a secondary, steam producing coolant system. Heat transfer area in the steam generator is provided by thousands of tubes that also provide the physical barrier between the two coolant

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systems. Reactor water is on the inside of the tubes and secondary water is on the outside. The heat transferred in the steam generator converts the secondary water to steam that drives a turbine generator to produce electricity.

Thousands of steam generator tubes comprise part of the reactor coolant system pressure boundary in a pressurized water reactor. In some plants, corrosion, wear, or fatigue of steam generator tubes has caused primary-to-secondary leaks.

In a few cases the leaks have led to ruptures of a tube. Research is underway to improve steam generator reliability. Primary-to-secondary leaks, and especially tube ruptures, h6ve raised questions regarding plant response to the potential rupture of one or more tubes in one or more steam generators.

This report describes an evaluation of the effect of steam generator tube ruptures in a Babcock & Wilcox (B&W) plant having a lower loop configuration and 177 fuel assemblies. The evaluation used the RELAPS code to calculate thermal hydraulic L response of the plant to the rupture of single or multiple tubes in one or both once-through steam generators (OTSGs). The effort considered coincident equipment malfunctions and various recovery actions.

1.2 MITIGATION STRATEGY A steam generator tube rupture is a loss of coolant accident that allows primary coolant to flow into one or more steam generators. This type of accident is of

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concern because of the potential for disrupting core cooling and of releasing radioactivity from the primary into the secondary system.

Since the leak from a failed tube cannot be isolated, reactor water will flow into ,

the secondary system as long as there is a higher pressure in the primary system than in the secondary system. In general, this implies that primary coolant will continue to be lost until the primary loop is cooled, depressurized, and drained.

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The mitigation procedure for this event has to balance two somewhat contradictory requirements.

a. Subcooling margin must be minimized to limit the primary-to-secondary pressure difference and leakage.

b. Delays in cooldown and depressurization must be minimized to l W

minimize primary-to-secondary leakage.

The sequence of operator actions to mitigate a steam generator tube rupture in a typical B&W design plant are:

a. Diagnose that a steam generator tube rupture has occurred and determine which steam generator is leaking. This is done by monitoring the radioactivity levels in the condenser and the steam lines. The tube rupture can also be confirmed by monitoring the primary system make-up flow, the pressurizer level, and the reactor coolant system pressure. For the cases considered in this report, a scram is assumed to occur automatically on low reactor coolant system pressure (less than 1900 psia) or the reactor is tripped manually one minute after the high make-up alarm is sounded.

b. Perform a rapid cooldown and depressurization of the plant l while maintaining an adequate subcooling margin to keep the 3 reactor coolant pumps running. This is done to minimize the primary to secondary leakage and to minimize the amount of radioactive steam lost through the steam line safety valves.

If the reactor coolant pumps are not running, action should be taken to ensure natural convection. This cooldown/depressuri-zation period should last until the primary conditions are g about 1000 psia and 500*F. At this time, the primary pressure g is below the set-point of the secondary safety valves. This rapid cooldown rate should be about 100F'/hr.

c. Isolate the affected steam generator when the primary system temperature approaches 500*F. This is done by limiting the emergency feedwater to maintain the level at the low limit, and by steaming to maintain the level below 95% on the operator range. Steaming may also be required to maintain natural

( convection in the primary loop and to ensure that a steam blockage does not form at the top of the hot leg (i.e., the candy cane).

1-2 I

L IL

d. Cooldown and depressurize the plant until a cold shutdown condition is reached.

1.3 CASES ANALYZED p Twelve analyses were perforr ed covering a range of parameters. Table 1-1 lists L

the cases in chronological order. For convenience the chronological case numbers are retained throughout this report.

L There are three sets of cases shown in this table, namely:

L -

single tube - 6 cases ten tube in one generator - 5 cases

( -

five tubes in each generator - I case In reviewing these analyses, it is helpful to know why the various cases were selected.

( Of the six single tube cases, case I was run to compare the present model with previously run cases. This case is discussed in Section 4 The remaining single tube ruptures are discussed in Section 5. These cases include: a baseline for comparison (case 2), an alternate mitigation procedure

( (case 3), and an alternate pump trip criterion (case 12). Also, included in Section 5 are two cases representing additional system failures. These are: a stuck open power operated relief valve (PORV) on the pressurizer (case 11), and a stuck open steam safety valve on the secondary system (case 12).

c

[ The results of the ten tube ruptures in one steam generator are discussed in Section 6. These include: a baseline (case 4), an alternate pump trip criterion p (case 5), and an alternate mitigation strategy (case 6). A different break location (case 8), and the impact of failure of the level indication and control of the affected steam generator (case 9), were also considered.

Additionally, one case was run which had a simultaneous rupture of five tubes in each of the two steam generators (case 7). This case is discussed in Section 7.

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1-3

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Table 1-1 ANALYSIS DESCRIPTION Humber Case of Pump Trip Other No. Tubes Criterion Assumptions Remarks I l-0TSGA At rupture Loss of offsite power at rupture Benchmark analysis to compare RELAPS with RETRAN and B&W MINITRAP analyses 2 1-0TSGA At scram Baseline tube rupture 3 1-0TSGA At scram Continue steaming OTSGA Alternate SGTR procedure 4 10-0TSGA 20F* subcooling Effect of larger number of ruptures 5 10-0TSGA 0F* subcooling Effect of less restrictive pump trip criterion 7

6 10-0TSGA 20F* subcooling Continue steaming OTSGA Compare two SGTR procedures (isolation versus steaming) 7 5-0TSGA 20F* subcooling Effect of leaks in both steam generators 5-0TSGB 8 10-0TSGA 20F* subcooling Ruptures at bottom of 0TSG Effect of different rupture location 9 10-0TSGA 20F* subcooling Failure of water level indica- Effect of overfilling the OTSG tion and control 10 1-0TSGA 20F* subcooling Second4ry safety valve sticks Effect of secondary system breach open on first challenge 11 1-0TSGA At scram PORV sticks open on first use Feed and bleed cooling 12 1-0TSGA 20F* subcooling Effect of delayed pump trip on baseline SGTR for all cases except case number 8, tube ruptures are modeled as occurring at the top of the OTSG(s).

M M M M M M M

Section 2 FINDINGS AND CONCLUSIONS I

Ruptures of up to a total of ten tubes in one or both Once Through Steam Gen-I 1.

erators were evaluated. For these cases, the core remained satisfactorily cooled. In no case did a fuel rod cladding temperature excursion occur. The maximum fuel rod cladding temperature during the transients evaluated never exceeded the normal operating temperature.

I 2. In all cases, a controlled shutdown was achieved, with primary pressure below the lowest secondary safety valve opening set point and continuing to decrease.

Hot leg subcooling margins were greater than 20F' (11.lC').

In cases where operation of reactor coolant pumps was continued following the I 3.

steam generator tube rupture (s), pressurizer spray was available and the plant recovery was calculated to be steadier than in cases where the pumps were tripped early in the transient.

Comparing cases 2 and 12 for the rupture of a single tube, it can be seen I a.

that continued operation of reactor coolant pumps and use of pressurizer spray caused no more of a rapid plant cooldown than occurred when pumps were tripped. However, maintaining forced circulation did minimize fluctuations in cooldown rate, pressurizer level and subcooling margin.

Moreover, maintaining forced circulation in the affected loop caused the g

" affected steam generator to cool at the same rate as the rest of the plant. This is in contrast to the cases where the pumps were tripped. In these cases it was necessary, late in the transient, to steam the affected l

steam generator to restore natural circulation and to cool down the affected loop.

b. Comparing cases 4 and 5 for the rupture of ten tubes in one steam gener-ator, continued operation of reactor coolant pumps and use of pressurizer spray prevented the loss of subcooling and provided a more rapid plant l

I cooldown than occurred when the pumps were tripped. Moreover, maintaining

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forced circulation provided a symmetric cooldown cf both loops and limited voiding to the pressurizer and the upper head of the reactor vessel.

4. In cases where the reactor coolant pumps are tripped, natural circulation or feed and bleed are sufficient to cool the plant.

a. For the rupture of a single tube (case 2) natural circulation is main-tained in the unaffected loop through steaming of the unaffected steam generator. Flow in the affected loop stagnates when the affected steam g

3 generator is isolated but is restored once steaming is resumed.

b. For the rupture of a single tube where both steam generators are steamed (case 3), natural circulation is maintained in both loops throughout the transient.

c. For the rupture of ten tubes in one steam generator (case 4), primary flow appears to be driven by the primary-to-secondary leak ar.d high pressure injection flow rather than by the thermal head between the core and the unaffected steam generator. Thus the flow in the affected loop remains g

3 higher than the flow in the unaffected loop through most of the transient. Plant cooldown, therefore, is through feed and bleed to the affected steam generator until late in the transient when steaming of the unaffected steam generator is initiated to achieve the desired cooldown rate.

g 3

d. For the rupture of ten tubes in one generator where both steam generators are steamed (case 6), the results are similar to the results of case 4 in that the cooling is by feed and bleed. In this case, hcwever, steaming g

the unaffected generator causes a more rapid cool-down of the primary 5 system,

e. For the rupture of five tubes in each of the two steam generators (case 7), flow in both loops is driven by the primary-to-secondary leak and high g

pressure injection flow through most of the transient. Plant cooldown is 5 through feed and bleed to the steam generators until late in the transient when steaming of the unaffected steam generator converts it from a heat source into a heat sink, and natural circulation in the uraffected loop is initiated.

2-2 I

5. Calculations showed steaming of the affected steam generator to be effective in preventing overfill of the affected steam generator in all cases during which emergency feedaater was assumed to operate correctly. When water level indication and control were assumed to fail in such a way that there was full emergency feed water flow to the affected steam generator (case 9), the steam generator was calculated to overfill early in the transient. Overfill of the affected steam generator had little effect on the plant cooldown.

6. Comparing cases 4 and 8 shows that changing the location of the ten tube rup-tures from the top of the steam generator to the bottom of the steam generator had little effect on the plant response.

7. Comparison of cases 2 and 11 show that for a single ruptured tube, a stuck open PORV causes a more rapid initial depressurization and cooldoon rate and a temporary loss of subcooling. However, over the course of the transient, the stuck open PORV had little effect on the average recovery rate. It simply increased the primary system losses that had to be made up with high pressure injection flow.

8. Comparison of cases 10 and 12 shows that a stuck open safety valve for the affected steam generator causes the affected steam generator to boil dry, but has little effect on plant recovery. This is because the forced circulation cooldown is being effected by steaming the unaffected steam generator in both cases and the heat input from the affected steam generator is small in both cases.

I I

2-3 lI

I Section 3 SYSTEM DESCRIPTION AND CODE MODEL 3.1 THE SYSTEM The general arrangement of the Babcock and Wilcox lower loop reactor coolant system is shown in Figure 3-1. The Reactor Coolant System consists of the reactor vessel, two vertical once-through steam generators, four shaft-sealed reactor coolant pumps, an electrically heated pressurizer and interconnecting piping. The system is arranged in two heat transport loops A and B, each with two reactor coolant pumps and one steam generator. The pressurizer is located on loop A. The reactor coolant is provided to the reactor through four lines, each containing a reactor coolant pump. The coolant is transported from the reactor vessel to the steam generators and flows downward through the steam generator tubes transferring heat to the steam and water on the shell side of the steam generator.

Plant control at various power levels is achieved by the Integrated Control System (ICS) which produces control signals for control of the reactor, steam generator, feedwater system, turbine and steam bypass under all operating conditions. This control is achieved by providing commands to the control rod drive system, feedwater regulating valves and feed pumps, turbine control and bypass valves.

The key features of these controllers for typical B&W plants are provided on figures 3-2 through 3-7. The integrated Control System mair.tains a constant average reactor coolant temperature over the load range between 15% and 100% rated reactor p]wer and constant steam pressure at all power levels.

3.2 RELAPS CODE DESCRIPTION The RELAPS light water reactor transient analysis code (1) developed at the Idaho National Engineering Laboratory (INEL) for the Nuclear Regulatory Commission (NRC), provides an advanced best-estimate predictive capability for use in a wide spectrum of system thermal-hydraulic analysis applications. The RELAP5 code is I based on a nonhomogeneous and nonequilibrium model for the two-phase system that is solved by a fast, semi-implicit numerical scheme to permit calculaticn of system transients. The code includes many generic component models from which general systems can be modeled. The component models include pumps, valves, 3-1 I

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Main Feedwater Valve Sequencing For most B&W plants FW valves open and close automatica!!y as follows:

1. At- 0% power only S/U valve is open

2. Up to ~ 15% power only S/U valve is opened.

3. At ~ 20% power S/U valve is 100% open. (One RV

[ pump still at low speed)

4. Above 15% power main RV block valve is opened and r main control valve starts to open L 5. Up to 100% power both main RV contro! valve position and RV pump speed are increased

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1. At 100% power main control valve is ~ 70% open and RY pump speed is - 75% of maximum speed.

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I pipes, heat structures, reactor point kinetics, electric heaters, accumulators, and control system components. In addition, special process models are included for effects such as form losses, flow at abrupt area changes, branches, critical flow, boron tracking, and noncondensable gases.

The system mathematical models are coupled into an efficient code structure. The code includes extensive input checking capability to help the user discover input errors and inconsistencies. Also included, are free format input, internal plot capability, restart, renodalization, and variable output edit features.

The code version used for this analysis was an updated version of RELAPS/ MOD 1, Cycle 18. The update to Cycle 18 reformats the output listing in a more efficient manner without affecting the calculated results.

RELAPS is a five equation code, i.e., equations are solved for the liquid and vapor mass, liquid and vapor momentum, and the mixture energy. Solving a single energy equation can lead to mass errors since it is assumed that the least massive phase is at saturation.

The RELAPS mass error is a measure of the consistency of the numerical scheme. In order to solve the coupled hydraulic equations, the state equation is linearized, i.e., density is assumed to be a linear function of pressure and internal energy. After the field equations are solved, the resulting internal energy and pressure are used to determine a new density using the actual state function instead of a linear approximation. The difference between this new density and the density obtained by assuming a linear state function is called the mass error.

1 Mass error can be expected to accumulate whenever fluid volumes are near phase boundaries and whenever any fluid volume crosses the 50% quality line. For this latter case, significant mass errors can accumulate regardless of time-step size due to redefinition of the temperature of the liquid and the vapor.

The code has been used extensively. Applications have included analytical support for the LOFT and Semiscale experimental programs; support of the EPRI safety / relief valve testing program; and simulation of design basis loss-of-coolant accidents, anticipated transients without scram, and operational transients in LWR systems for use in regulatory investigations.

3-9 l

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I 3.3 RELAPS HYDRODYNAMIC INPUT MODEL The hydrodynamic description of the plant used for this analysis was developed from a RETRAN-02/M002 deck of THI-2. The RETRAN deck had been validated against several transients (2, 3, 4). Where possible, the deck was converted so that a one-to-one correspondence would exist between the RETRAN and RELAP5 control volumes and junctions. This was not possible in all cases. RELAP5 requires that a junction either be connected to the inlet or the outlet of a control volume, whereas, RETRAN has no such restriction. Therefore, it was necessary to break some RETRAN volumes into two or more RELAPS control volumes to preserve the elevation pressure drop from corresponding RETRAN junctions. Examples of where g this was necessary include the reactor vessel downcomer, lower plenum, and upper W l plenum. Additional modeling detail was also added to the RELAPS model to better follow phase discontinuities. Examples include the hot legs, the cold legs, the upper-upper head region, and the pressurizer. In the RETRAN deck, the high-pressure injection (HPI) flows from the four HPI injection lines connected to four cold legs were lumped into one RETRAN junction on one cold leg. For the RELAP5 l model, the four HPI injection locations were explicitly modeled.

Figure 3-8 shows the RELAPS nodalization diagram used for this analysis. There I

are several features which are not shown on this diagram, including: the ruptured I

tube, which consisted of junctions connected from the once-through steam generator 5 (OTSG) inlet plenum and outlet plenum to the steam generator secondary; the four HPI injection junctions that are connected to the control volume downstream of the primary coolant pumps; the pressurizer spray line and associated junctions, which run from the control volume downstream of the primary coolant pumps to the top of ,

the pressurizer; and the time-dependent volumes that are used as boundary conditions to the safety valves, the steam control valves, the turbine bypass valves, the modulating atmospheric dump valves (MADVs), the power operated relief valve (PORV), the feedwater system, emergency feedsater (EFW) system, and the HPI system. The base case model for Case 1 (discussed in Section 4) consisted of a total of 151 control volumes, 173 junctions, 24 heat structures with a total of 132 heat conduction mesh points, 122 trips, and 130 control variables. The trips and controls used to simulate automatic and manual operator recovery actions are provided in Appendix A.

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I As described in Appendix A, several controllers required common trips. These included: scram, recovery, and loss-of-natural-circulation trips.

Scram was assumed to occur when the hot leg pressure dropped below 1900 psia or 1 minute after the makeup flow reached 170 gpm, whichever occurred first (the 1-minute delay is an assumed operator response time).

+

The recovery trip enabled several control actions which simulated the manual operator control actions. Recovery was assumed to begin 5 minutes after scram (the 5-minute delay is the assumed time required for the operator to diagnose the accident and to begin the procedures required to bring the plant to cold shutdown).

Based on typical plant procedures, loss of natural circulation was assumed to have occurred if any of the following conditions existed:

(a) the cold leg temperature in the loop was greater than the fluid tempetature in the OTSG downcomer by more than 35'F, (b) the hot leg fluid temperature in the loop was greater than the cold leg fluid temperature in the loop by more than 50*F, (c) the hot leg temperature in the loop was not within plus or minus 10*F of the fluid temperature in the upper plenum.

It was postulated that the tube rupture occurred just below the upper tube sheet, a location where leaks have occurred in operating OTSGs. Hence, it was necessary to model the ruptured tube in two parts; the short section of the ruptured tube, which extended from the steam generator inlet plenum through the top tube sheet to the steam generator secondary side, and the much longer section of the ruptured tube, which extended from the steam generator outlet plenum through the bottom E 3

steam generator tube sheet to the top of the steam generator secondary side.

Modeling each section of the ruptured tube involved separate modeling difficulties.

The flow through the ruptured tube (or tubes) was initially modeled explicity.

However, the resulting computer running time and mass error was unacceptable. A control system model was then developed to correctly represent the flows through both the short and long sections of ruptured tube. Appendix A.2.11 presents a discussion of this model.

The modeling of the emergency feedwater (EFW) was also not straightforward.

Initial computer runs revealed that there was a tendency for all of the EFW to be 3-12 I

carried out of the OTSG into the steam line. This was viewed as non-physical and also contradicted the results of experiments performed by B&W. In order to match the experimental data, the EFW was introduced into the OTSGs with a spatial distribution. Ten percent of the EFW flow was introduced into each of the top 12 volumes in the OTSG, and the remaining 10% was divided equally among the lowest I three volumes. This scheme resulted into a distribution pattern which matched the experimental data.

During the modeling of the OTSGs, it was found that RELAP5 does not predict the same overall heat transfer coefficient that has been experimentally determined.

I This resulted in incorrect heat transfer to the steam generator. Since the heat transfer rate is equal to the product of the area, the temperature difference, and the heat transfer coefficient, any one of the three could be adjusted to yield the correct amount of heat transfer. It was decided to adjust the area rather than change the temperatures in the system or to modify the computer program. A 52.4%

I area increase was necessary to match the amount of heat transferred.

Another difficult modeling area was the treatment of the upper head area of the reactor vessel (see Figure 3-8). The flow between this region and the rest of the system are not well known. It was decided to model this area as a dead-end region I connected to the upper plenum area through a limited flow area. Consequently, the upper plenum did not respond to the system transient as rapidly as other areas, the temperature calculated for this area remained high, and voiding was often calculated to occur. This was felt to be a conservative respresentation of this area.

I The alternative to this modeling approach would be to force a part of the hot leg flow through this region. But, in the absence of non-proprietary data concerning the flows, and flow resistances in the upper head region, this approach would not necessarily yield conservative results.

3.4 STEADY-STATE INITIALIZATION I RELAPS has no provision for an automatic steady-state initialization. It is up to the code user to provide an exact steady-state input description of the plant, or to run a null transient and allow the code to reach a quasi-steady initial condition. The latter approach was used for the analyses described in this report. A close approximation of the steady-state fluid temperatures was input as I

j 3-13

Il initial conditions, and the calculation was allowed to run for 3 minutes of a null-transient simulation. Table 3-1 shows the steady-state initial conditions used for the calculations.

Table 3-1 CONDITIONS AT TIME OF TUBE RUPTURE Reactor Power 2547.24 MWT Temperature Downstream of Primary Coolant Pumps 556.5'F Temperature in Hot Legs 601.0*F Hot Leg Mass Flow Rate 19945.5 lbm/s E OTSG Secondary Side Pressure 992.2 psia 5 Pressurizer Pressure 2189.4 psia RCS pump speed 1185. rpm Feedwater Flow 1537.4 lbm/s OTSG Inlet Feedwater Temperature 462.7'F Steam Line Temperature (Superheated) 577.8'F I

3.5 DECK VALIDATION Several steps were taken to assure that the RELAPS input deck was free of errors. These steps included the following:

(1) an independent card--by-card cross-check was performed to assure that the RELAP5 hydrodynamic input was correctly converted from the RETRAN deck; (2) the RETRAN deck was cross-checked against two other decks of B&W plants, and the discrepancies were successfully resolved; (3) a zero-power, zero-flow, uniform temperature calculation was run for approximately 3000 seconds of transient simulation to assure that no unbalanced elevation changes existed in the RELAPS input model; (4) a preliminary benchmark calculation was run on a steam generator tube rupture transient for which there existed E comparable B&W and RETRAN calculations (5, 6). The results of 5 these calculations are discussed in the next section.

Considering the code differences and the differences between the plants which were modeled, the results calculated by l RELAP5 appeared to be reasonable; (5) preliminary results of calculations which are presented in g this report were reviewed by NSAC and General Public Utilities 5 (GPU) staff members. Errors or omissions in the control system description were noted and corrected.

I 3-14 I

I Section 4 BENCHMARK ANALYSIS The transient chosen for the benchmark calculation was a tube rupture in OTSG A I with a coincident loss of offsite power. This transient was originally calculated by the Babcock and Wilcox company using the MINITRAP code (6) and later by GPU using RETRAN-02 (7). This section describes the modeling techniques for and the results from the RELAPS Benchmark analysis. Conclusions drawn from comparison with previous analyses of this transient are also presented.

I 4.1 RELAP5 INPUT MODEL DESCRIPTION FOR BENCHMARK CALCULATION The nodalization scheme used for the benchmark calculation was similar to the scheme used for the other calculations documented in this report. To maintain consistency between the PELAPS model and the RETRAN model, the following nodali-zation modifications were made:

I 1. The five safety valve junctions for each OTSG secondary were combined into a single junction.

2. The EFW flow was injected into the OTSG downcomers.

The RELAPS benchmark model also differs from the model for other calculations documented in this report in the treatment of control actions and boundary condi-tions. The objective of modifying the model was to elimina'e most differences between the RETRAN and RELAPS results caused by control actions or the treatment of boundary conditions. A summary of the unique controls and boundary conditions imposed for the RELAPS benchmark analysis is as follows:

1. The flows for the MADVs, the PORV and the EFW systems that were calculated by RETRAN were input into the RELAPS model in the form of fill tables.

2. The HPI trip was specified so that HPI initiation would occur at the same time as in the RETRAN calculation, and the HP1 con-trol logic which simulated the throttling action of the opera-tor was disabled.

3. The reactor kinetics model was disabled, and the reactor power history from the RETRAN listing was input into RELAPS in tabu-lar form.

4-1

I

4. The trips and controls for the pressurizer heaters were dis-abled, and the power history from the RETRAN listing was input into RELAP5 in tabular form.

5. The pump speeds calculated by RETRAN were input into the RELAPS model in the form of a table.

6. The vent valve between the reactor vessel downcomer and upper plenum was disabled.

7. The turbine bypass valves were' disabled.

8. The pressurizer spray system was disabled.

These changes were made so that the differences between calculations of the three codes would be due principally to the codes themselves and nodalizations. There are differences in ccmplexity among the three codes and nodalization differs in both magnitude and detail. For example, the RELAPS model contains heat structures for the reactor vessei walls and loop piping while the RETRAN model does not. As g

a result, comparisons of absolute results are not as instructive as comparisons of g trends calculated by the three codes.

In summary, the purpose of this analysis was not to compare the three codes, but rather to ensure that the RELAPS model developed would accurately describe the plant's performance. E 3

4.2 RESULTS OF BENCHMARK CALCULATION In this subsection, the results of the RELAP5 benchmark, the B&W MINITRAP and GPU RETRAN calculations are presented.

Table 4-1 shows a comparison of the sequence of events among the three calcula-tions. Since the RETRAN calculation was based on the accident and operator action assumptions used in the MINITRAP calculation, and since the RETRAN calculation was used for the RELAPS boundary condition assumptions, most of the event times are in close agreement.

Figures 4-1 through 4-4 show the comparisons between the OTSG secondary pressure and level response. At transient initiation, the feedwater and steam flows cease.

The secondary pressure quickly rises to the safety valve setpoint, then slowly decreases as the EFW flow reduces the secondary fluid temperature as it increases the secondary liquid inventory. The responses of these parameters calculated by the three codes are similar.

4-2 I

I l

Table 4-1 SEQUENCE OF EVENTS FOR BENCHMARK CALCULATION Time After Rupture (Minutes)

Event RELAPS RETRAN MINITRAP Single Tube Ruptures 0.00 0.00 0.00 Loss of OffSite Power 0.00 0.00 0.00 Reactor Scram 0.01 0.01 0.01 RCPs Trip 0.01 0.01 0.01 MWFPs Trip 0.01 0.01 0.01 Turbine Trip 0.01 0.01 0.01 MADVs and MSSVs Lift 0.02 0.02 0.07 Pressurizer Heaters on 0.43 0.43 0.43 EFW flow begins 0.43 0.43 0.43 I Operator Initiates Manual RCS Cooldown 1.50 1.50 1.50 Operator Reduces MADV Flow 6.00 6.00 6.00 Operator Opens PORV to Reduce 10.00 10.00 9.50 RCS Pressure Operator Closes MADVs on Both 10.50 10.50 10.50 OTSGs to Reduce Cooldown Rate Loop A EFW Flow Terminated 11.17 11.17 10.50

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RELAPS CALCULATION E RETRAN CALCULATION 3

---

MINITRAP CALCULATION O

a - _

I I

I o 1 I I I I I i 1

-2 0 2 4 6 8 10 12 14 16 TIME AFTER RUPTURE (MINUTES)

Figure 4-1. Comparison of RELAPS, RETRAN, and MINITRAP Calculated 0TSG A Pressure 4-4 I

b g N i CASE i

1i - RELAPS i BENCHMARK i i i b

i 8 -

l \

l l \ -

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w8 r4 p O L RELAPS CALCULATION RETRAN CALCULATION MINITRAP CALCULATION 8 -

m -

[

~

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-2 0 2 4 6 8 10 12 14 16 TIME AFTER RUPTURE (MINUTES)

[ Figure 4-2. Comparison of RELAPS, RETRAN, and MINITRAP Calculated 0TSG B Pressure

[

4-5

[

r I

g CASE 1 - RELAPS BENCHMARK M i I I i i i i i 8

m W

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RELAPS CALCULATION RETRAN CALCULATION s -----

MINITRAP CALCULATION

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-2 0 2 4 6 8 10 12 14 16 g TIME AFTER RUPTURE (MINUTES) u Figure 4-3. Comparison of RELAP5, RETRAN, and MINITRAP R Calculated Loop A OTSG Indicated Liquid Level 3 4-6 I

r L

E o CASE 1 - RELAPS i BENCHMARK i i 3

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w -

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i 8 10 12 14 16

-2 0 2 TIME AFTER RUPTURE (MINUTES)

{

Figure 4-4. Comparison of RELAP5, RETRAN, and MINITRAP Calculated Loop B OTSG Indicated Liquid Level 4-7

[

I Figures 4-5 and 4-6 show the comparisons of primary system cold leg fluid tempera-tures. The cold leg temperature in each loop tends to follow closely the corre-spending OTSG secondary fluid temperature. Therefore, the cold leg temperature exhibits the same trend as the secondary pressure and is similar for all three codes.

Figure 4-7 shows the comparisons of Loop A hot leg flow. The comparisons for the I

Loop B flow are similar. Loop flow rates calculated by RELAP5 and RETRAN are in good agreement. Figures 4-8 and 4-9 show the comparisons of hot leg fluid temperatures. The differential fluid temperatures between the hot and cold legs are a function of the loop flow rates and the amount of power added to the cool-ant. The core power is identical in the RELAPS and RETRAN calculation since the core power decay calculated by RETRAN was used as a boundary condition for RELAPS.

As seen earlier, the loop flow rates are also in good agreement between the RELAPS and RETRAN calculations. The higher hot leg temperature calculated by RELAPS is consistent with the presence in RELAP5 and absence in RETRAN of heat structures for the reactor vessel walls and hot and cold leg piping.

Figures 4-10 and 4-11 show the comparisons of the break flows from the upper and lower ends of the ruptured tube. As discussed earlier, the mass flow rates calcu-lated by RETRAN were used as boundary conditions in RELAP5. Figure 4-12 shows the comparison of total HPI flow. HPI flows agree until the PORV is opened 10 minutes into the transient. In the RELAPS calculation, HPI flow increases as reactor coolant system pressure decreases, modeling the automatic response of the HPI sys-tem. In the RETRAN calculation, however, it was assumed that the operator inter-vened to limit HPI flow to the value calculated by the B&W code.

Figure 4-13 shows the comparison of the indicated pressurizer liquid level. The pressurizer level reflects the changes in the reactor coolant system liquid vol- I

=

ume, which is in turn controlled by the flow rates into and out of the reactor coolant system, as well as net changes of reactor coolant temperature. As seen in earlier comparisons, the flow rates into and out of the reactor coolant system are relatively close, as are the cold leg temperatures. Since the RELAPS hot leg tem- g perature is somewhat higher than the RETRAN hot leg temperature, the net change in W average reactor coolant temperature is somewhat less in the RELAPS calculation.

The smaller net change in average reactor coolant temperature in the RELAPS calcu-lation is consistent with a smaller decrease in pressurizer indicated liquid level during the first 10 minutes of the transient. When the PORV is opened 10 minutes into the transient, all codes calculate an insurge into the pressurizer.

4-8 I

[ g CASE 1 - RELAPS BENCHMARK e i i i i i i i i

[

n ll- oo _

[ O

= RELAPS CALCULATION RETRAN CALCULATION MINITRAP CALCULATION

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id CE

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( -2 0 2 4 6 8 10 12 14 TIME AFTER RUPTURE (MINUTES)

Figure 4-5. Comparison of RELAPS, RETRAN, and MINITRAP Calculated Loop A Cold Leg Fluid Temperature

(:

4-9

[

l,,ii i -

g CASE 1 - RELAPS BENCHMARK a o I I I i i i i I g I

n ll-O _ -

O RELAP5 CALCULATION w - - - - - - - - - - -

RETRAN CALCULATION o

v MINITRAP CALCULATION W i T

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G i i 1 I I I I I

-2 0 2 4 6 0 10 12 14 16 TIME AFTER RUPTURE (MINUTES)

Figure 4-6. Comparison of RELAPS, RETRAN, and MINITRAP l Calculated Loop B Cold leg Fluid Temperature E l

4-10 l

l l

8 CASE 1 - RELAPS BENCHMARK v) l I i i i i i i N

PUMP TRIP h

8 g _. _

N l RELAPS CALCULATION RETRAN CALCULATION

---

MINITRAP CALCULATION 8

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-2 0 2 4 6 8 10 12 14 16 TIME AFTER RUPTURE (MINUTES)

Figure 4-7. Comparison of RELAP5, RETRAN, and MINITRAP l Calculated Loop A Flow 4s11

g CASE 1 - RELAPS BENCHMARK c I I I I I I I I no LL g -

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MINITRAP CALCULATION o

ag -

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Q i t i i I I i 1

-2 0 2 4 6 8 10 12 14 16 g TIME AFTER RUPTURE (MINUTES) u Figure 4-8. Comparison of RELAPS, RETRAN, and MINITRAP l Calculated Loop A Hot Leg Fluid Temperature u 4-12

I g CASE 1 - RELAPS BENCHMARK I c I I I I I I I I

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MINITRAP CALCULATION O o O_ E l 0 t

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I O l l 1 1 I I I

-2 0 2 4 6 8 10 12 14 16 TIME AFTER RUPTURE (MINUTES)

Figure 4-9. Comparison of RELAP5, RETRAN, and MINITRAP Calculated Loop B Hot Leg Fluid Temperature l

I 4-13

(

l

m CASE 1 - RELAPS BENCHMARK m I I I I I i 1 l

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RCS PRESSURE REDUCED 03 T

W Q- RELAPS CALCULATION QO -

- - - - - - - - - - - RETRAN CALCULATION -

]~ ----- MINITRAP CALCULATION I

l I

tn - _

l 1

I o I I I I I I I

-2 0 2 4 6 8 10 12 14 16 TIME AFTER RUPTURE (MINUTES)

Figure 4-10. Comparison of RELAPS, RETRAN, and MINITRAP Calculated Upper Break Flow 4-14 I

I

I , CASE 1 - RELAPS BENCHMARK

- 1 I I I i 1 I i

\ b

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RETRAN CALCULATION

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MINITRAP CALCUL ATION N -

o i I I I i  ! I

-2 0 2 4 6 8 10 12 14 16 g TIME AFTER RUPTURE (MINUTES)

Figure 4-11. Comparison of RELAPS, RETRAN, and MINITRAP Calculated Lower Break Flow l

4-15

" ~

r

@ CASE 1 - RELAPS BENCHMARK ra I I i i i l i i O -

RELAPS CALCULATION RETRAN CALCULATION

---

MINITRAP CALCULATION O

m

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E Q- o Oo- PORV CPENED, -

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l o i I I I I I I I

-2 0  ? 4 6 8 10 12 14 16 TIME AFTER RUPTURE (MINUTES) l Figure 4-12. Comparison of RELAPS, RETRAN, and MINITRAP Calculated Total HPI Flow l 4-16 I

l

a CASE 1 - RELAPS BENCHMARK G  : l I

1 1 I I

^ l RELAPS CALCULATION Wo I o O

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---

MINITRAP CALCULATION RETRAN CALCULATION ~

Z s

v

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i B HPI INITIATED 's_____ '\

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-2 0 2 4 6 8 10 12 14 16 I TIME AFTER RUPTURE (MINUTES) 3 Figure 4-13. Comparison of RELAP5, RETRAN, and MINITRAP g Calculated Pressurizer Indicated Level l

l 4-17 I

Figure 4-14 shows the comparison of core outlet pressure. The responses calcu-lated by RELAP5 and RETRAN are similar. The slower response of pressure to open-ing the PORV as calculated by MINITRAP was found to be due to incorrect modeling of the pressurizer in the MINITRAP code.

Figure 4-15 shows the comparison of hot leg subcooling margin. The agreement between RELAP5 and RETRAN calculations reflects the agreement between hot leg temperatures and pressures calculated by the two codes.

4.3 CONCLUSION

S FROM BENCHMARK ANALYSES The RELAPS calculation displayed behavior similar to that observed in the other analyses. The differer.ces between the RELAPS calculation and the other calcula-tions are consistent with differences in code complexity and plant modeling details such as the use of piping heat structures in RELAP5. This comparison pro-vides confidence in similar RELAPS calculations discussed in other sections of this report.

I I

I 4-18

I o CASE 1 - RELAPS BENCHMARK O

N i i i i i i i O -

Ifk -

10 PORV OPENED i

I e 0 -

i -=: x *-% -__- - -

~

~~~' ---

k HPI INITIATED N

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m i

\i

%'s N 0 -

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S i w r T

D

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m \

W Woe -

\

s -

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I bO a-O Jo I w h RELAPS CALCULATION Uo - - - - - - - - - - - RETRAN CALCULATION O - ----- MINITRAP CALCULATION -

o O~ ~

I o S I 1 1 4

I 6

I I i 1

-2 0 2 8 10 12 14 16 TIME AFTER RUPTURE (MINUTES)

Figure 4-14. Compariscn of RELAP5, RETRAN, and MINITRAP Calculated Core Outlet Pressure 4-19

I o CASE 1 - RELAPS BENCHMARK a

- i I i i i i i 1

E o

3 -

3

/i

,/ _

^ / i W / s f8 -

j I

T l

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f? ~

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s-- D i / \,

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< ' f Eo to -

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i f_s i O  !

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O O

D CD @- -

W 0

W o - -

_J cu F-O Z[ o~

RELAPS CALCULATION -

- - - - - - - - - - - RETRAN CALCULATION

---

MINITRAP CALCULATION o - -

o Y I I I I I i i 1

-2 0 2 4 6 8 10 12 14 18 g TIME AFTER RUPTURE (MINUTES) u Figure 4-15. Comparison of RELAP5, RETRAN, and MINITRAP Calculated Hot Leg Subcooling Margin 4-20 I

Section 5 SINGLE TUBE RUPTURE CASES 5.1 GENERAL This section describes the results of the five single tube rupture cases (see Table 5-1.1). The nodalization scheme used for these cases is identical to the benchmark model described in Section 4.

I For each case, the results for var' Oles that the operator could monitor during the course of the transient are provided. In addition, the tube rupture break flow, net flow into the primary coolant system, and upper head liquid fraction are provided. These additional variables play an important role in determining the pressure and subcooling behavior during the later part of the transient.

The calculation was run to the point where all of the following conditions were met: (a) primary system pressure less than lowest secondary safety valve opening setpoint, (b) the hot leg subcooling margin greater than 20'F, and (c) primary system pressure decreasing with time. This assured safe shutdown of the plant.

Appendix B presents a fuel clad temperature versus time plot for each of the single tube cases.

I

I I

I I

5-1 l

Table 5-1.1 SINGLE TUBE CASES Number Case of Pump Trip Other No. Tubes Criterion Assumptions Remarks 2 1-0TSGA At scram Baseline single tube rupture; natural circulation 3 1-0TSGA At scram Continue steaming OTSGA Alternate SGTR procedure l

12 1-0TSGA 20F* subcooling Effect of delayed pump trip on baseline SGTR 10 1-0TSGA 20F* subcooling Secondary safety valve sticks Effect of a secondary system breach

• open on first challenge 4

11 1-0TSGA At scram PORV sticks open on first use Feed and bleed cooling Note: For all the cases shown the tube rupture is modeled as occurring at the top of the OTSG.

M M M M M M m m e

5.2. SINGLE TUBE RUPTURE CASE 2 This case represents a baseline rupture of a single tube in OTSG-A. The primary coolant pumps were tripped at scram so that the behavior of the plant under I natural circulation cooldown conditions could be investigated. The affected 0TSG is isolated when the reactor coolant temperature falls below 540*F.

Table 5-2.1 shows the sequence of events for this case. Figure 5-2.1 shows the flow rate through the two ends of the ruptured tube. Since the tube rupture was postulated to occur at the bottom of the upper tube sheet, the flow resistance of the upper end of the ruptured tube was less than the lower end, which resulted in more flow through the upper end of the ruptured tube. The flow thrcugh both ends of the tube was relatively constant up until scram, which occurred at 2.19 minutes after rupture. After scram, the break flow reflected the changes in the primary I pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop.

I Figures 5-2.2 and 5-2.3 show the pressurizer indicated level and core outlet pressure, respectively. As a result of the break, the operator had an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result of the decreasing primary system pressure, the pressurizer heaters were energized.

However, they could not keep up with the effects of the break, and the pressure I continued to decline. Because of the decreasing pressurizer level, the makeup pump increased its flow. However, one makeup pump, at full capacity, could not replace all of the water being lost from the primary, so the level continued to decline. The operator would have received a high makeup flow alarm at 1.19 minute after rupture. It was postulated that the operator scrammed the plant and initiated full HPI flow 1 minute after the high makeup flow alarm was received.

After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp drop in average primary system temperature. The long-term j pressurizer level and primary system pressure response reflect changes in the primary system inventory brought about by operator recovery actions that were postulated to have begun 5 minutes after scraa.

I

{

l 5-3 1

i

Table 5-2.1 SEQUENCE OF EVENTS FOR SINGLE TUBE RUPTURE CASE 2 I

Time After Rupture Event (Minutes)

Single Tube Ruptures 0.00 High Makeup Flow Alarm 1.19 Reactor Manual Scram (1 Minute After High Makeup Flow) 2.19 Turbine and Main Feedwater Pumps Tripped 2.19 Operator Initiates Full HPI Flow. Trips RCPs 2.19 MADVs and MSSVs Lift 2.24 EFW Flow Begins 2.43 Operator Initiates Manu'al RCS Cooldown 7.19 Operator Opens PORV to Reduce RCS Pressure 7.19 Operator Closes PORV to Maintain Subcooling Margin 9.25 OTSG A Level Reaches 50% Operating Range, 12.76 EFW Flow Begins Cycling to Maintain Level OTSG B Level Reaches 50% Operating Range, 14.33 EFW Flow Begins Cycling to Maintain Level Operator Opens PORV to Reduce RCS Pressure 15.00 OTSG B Pressure Exceeds Target Pressure, TBVs Opened 15.71 Operator Closes PORV to Maintain Subcooling Margin 16.25 Operator Opens PORV to Reduce RCS Pressure 26.61 Operator Closes PORV to Maintain Subcooling Margin 27.48 Operator Opens PORV to Reduce RCS Pressure 30.88 Operator Notes Loss of Natural Circulation in 49.20 Loop A, Opens MADVs Analysis Termination Criteria Reached 53.63 I

1 1

5-4 I'

l

---____ -1

Figures 5-2.4 and 5-2.5 show the reactor power and hot leg flow rates for each loop. Prior to scram, the break had little influence on the reactor power since the net mass that left the system was small. The primary coolant pumps were tripped at scram. After pump trip, the flow rates in the individual loops quickly approached stable single-phase natural circulation flow rates. EFW flow to the affected OTSG was terminated when the level reached the 50% operating range level setpoint at 12.8 minutes after rupture. This was done to isolate the affected OTSG from the secondary system. After feedwater flow terminated, the temperature and pressure in the affected 0TSG increased. This caused the primary-to-secondary temperature difference across the affected OTSG to decrease, and the driving head for natural circulation in the affected loop slowly decreased. This caused a slow decrease in the flow rates through this loop. At 49.2 minutes after rupture, the affected loop hot leg temperature exceeded the core outlet temperature by 10*F, one indication of loss of natural circulation discussed in Section 3.3. After the loss of natural circulation was detected in the affected loop (Loop A), it was postulated that the operator would begin to take corrective actions to restore the natural circulation flow rate in that loop by opening the MADVs.

Since the unaffected loop was being cooled by the combined effects of the EFW injection into the OTSG and steam flow out the TBVs, the driving head caused by the primary fluid temperature drop across this OTSG was not decreased, and the flow through this loop remained relatively constant.

Figures 5-2.6 through 5-2.9 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. At scram, it was postulated that i

I the operator manually initiated full HPI. For the next 5 minutes, HPI flow reflected changes in the primary system pressure. Recovery was assumed to begin at 7.19 minutes, 5 minutes after scram. It was postulated that the operator then throttled HPI and controlled the HPI flow based on the subcooling margin. It was postulated that the operator would also use the PORV to control subcooling margin l and to aid in the depressurization of the plant since reactor coolant pumps were

! tripped at scram for this transient and high-head auxiliary pressurizer spray was not available for the plant modeled. After recovery began, the PORV was opened whenever the subcooling margin reached 50F* and reclosed if the subcooling margin er pped t 25F . rigure 5-2.8 shows that for most of the transient HPI flow into

!E3 the primary coolant system exceeded the combined flow out of the system through j the PORV and ruptured tube.

l l 5-5

Figure 5-2.9 shows the integrated flow rates into and out of the primary coolant system. Except for a brief period prior to full HPI initiation, the primary coolant system inventory constantly increased.

figures 5-2.10 and 5-2.11 show the Loop A and B fluid temperatures in the hot and I

cold legs as well as the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged and then diverged as the RCS pumps tripped and coasted down. The fluid temperatures in the cold legs upstream of the primary coolant pumps are typically within a few degrees of the OTSG saturation temperatures under natural circulation conditions. The cold leg fluid temperature downstream of the primary coolant pumps is colder than the fluid g upstream of the pumps due to the addition of lower temperature HPI fluid. The E Loop A cold leg temperature downstream of the pumps is reduced to about 350'F due to a combination of low loop flow and the low temperature of the HPI.

At 12.76 minutes into the transient, the EFW in the affected OTSG (Loop A) was terminated. This caused the fluid temperature in the affected 0TSG to rise to the hot leg fluid temperature. As the OTSG and hot leg fluid temperatures crossed at approximately 28 minutes after rupture, the affected 0TSG became an additional heat source instead of a heat sink, and the affected 0TSG was slowly cooled by the decreasing primary coolant system flow in the affected loop. This caused the E

gradual loss of natural circulation driving head discussed earlier in relation to E Figure 5-2.5. The cold leg temperature upstream of tne pumps in the affected loop followed the OTSG temperature.

The Loop B cold leg fluid temperature decreased in response to operator action to decrease OTSG pressure to cool down the plant at 100*F/hr. This action caused in the Loop B OTSG temperature to decrease. No loss of natural circulation occurred in this loop.

Figure 5-2.12 shows the hot leg subcooling margin in the unaffected loop. The g subcooling margin reflected changes in the primary system pressure and hot leg 5 temperature. The subcooling was controlled by the operator recovery actions. The minimum subcooling margin observed in this transient was approximately 25'F. No ,

voiding resulted in the RCS in this transient except in the pressurizer and upper head.

l Figure 5-2.13 shows the liquid fraction (1.0 - void fraction) of the upper head I region. Since the upper head region was modeled as a dead-end region connected to 5-6

g the upper plenum of the reactor vessel, the fluid temperature in this region of g the reactor vessel did not respond to changes in upper plenum fluid temperature.

This resulted in the fluid in this region remaining at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in this region. This occurred at approximately 15 minutes Ifter transient initiation. A steam bubble in the upper head acts like another pressurizer. The I abrupt changes in upper head liquid fraction occur at the same time as abrupt changes in the pressurizer indicated level, as seen in Figure 5-2.2 and were dut to the opening and closing of the PORV.

Figures 5-2.14 through 5-2.22 show the calculated flows into and out of the Loop A and Loop B secondary systems. Figure 5-2.23 shows the OTSG A and B indicated secondary levels. Figure 5-2.24 shows the pressure behavior in the two OTSGs.

These figures are discussed as a group. Immediately after scram, the feedaater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and water level decrease in the OTSGs. The increased pressure caused the safety valves, the modulating atmospheric dump valves (MADVs),

and turbine bypass valves (TBVs) to cycle. The early pressure response in the secondary was in turn controlled by these valve actions. Fourteen seconds after scram, the emergency feedaater system (EFW) was actuated. This system was effective in reducing secondary pressure, as it consisted of water at approximately 90*F which was sprayed into the OTSG, The EFW system also helped increase the level in each of the two OTSGs. Because of the presence of the break in the Loop A OTSG, the level increase rate was somewhat higher in this OTSG and reached the 50% operating range level setpoint at 12.76 minutes, whereas the level setpoint was reached at 14.33 minutes in Loop B. The EFW flow was terminated when the level exceeded 50% operating range and was restarted when the level dropped j below the 50% setpoint.

l After the continuous EFW flow was terminated, the temperature and pressure in the I OTSGs increased. In the affected 0TSG, the pressure increased to the MADV and turbine bypass valve opening setpoints, and the valves cycled briefly. In the B OTSG, as the pressure crossed the target pressure, the TBV opened while the EFW system cycled to maintain level at the desired level. The result of these actions was a cooldown of the unaffected 0TSG which closely approximates the desired cool-down. At 49.2 minutes after rupture, the operator opened the Loop A MADVs to restore natural circulation conditions.

i l

l l

5-7 l

The analysis was terminated at 53.63 minutes after rupture with the primary system pressure below the secondary relief pressure setpoint and with the plant in a stable operating mode. At the end of the simulation, adequate subcooling margin was available, and the plant was being brought to cold shutdown in a controlled I

3 manner. At no time during the simulation did a fuel rod cladding heatup occur.

I

. I I

I I

I I

s.e I' I'

I SINGLE TUBE RUPTURE CASE 2 I c m i I iiiI i i i i i I - - - - -

LOWER END OF RUPTURED TUBE FLCW UPPER END OF RUPTURED TUBE FLOW I $ -

~

NOTE - SUDDEN CHANGES IN FLOW RATES FREQUENTLY CORRESPCND TO OPENING 8 CLOSING OF THE PORV I o* \ ~

g $ H I L_

2 O

m r -

_J k /

x h3 -

~

$ , ' /\

< s\

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Ww -

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s

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g -5 0 5 10 15 20 25 30 35 40 45 50 55 3 TIME AFTER RUPTURE (MINUTES) l Figure 5-2.1. Break Flow I

5-9 l 5,

g m i I SINGLE TUBE RUPTURE CASE 2 I I I I I I I I i l l INDICATED PRESSURIZER LIOUID LEVEL l l

8 LB I8 om Z

C o

8

._]

NOTE -

LD SUDDEN CHANGES IN PRESSURIZER

> INDICATED LEVEL FREQUENTLY Ld I CORRESPOND TO OPENING

-Jo SCRAM & CLOSING OF THE PORV

_ f _

a" LD g

o Ha - -

a Z

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o _.

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I y I I I i i  ! I I I I I

-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.2. Pressurizer Indicated Level 5-10 I

I g SINGLE' TUBE RUPTURE CASE 2 g i i i i i i i i i , i l----- CORE OUTLET PRESSURE l n

~

A -

sl /1 NOTE - SUDDEN CHANGES IN CORE o g//l

\ \

OUTLET PRESSURE FREQUENTLY CORRESPOND TO OPENING g -

J & CLOSING OF THE PORV -

I ~

(

n o \

c <R

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w A

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e; f} j __ 1

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-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES) .

Figure 5-2.3. Core Outlet Pressure i

5-11 I -

r o

o 8 SINGLE TUBE RUPTURE CASE 2 i i i i 8 i i i i i i i l SCRAM 1 I l REACTOR POWER _

l I

i -

I n8 U) o b

I 12J 1- a Oo

<8

~

~

I 8

I I

I 1

o 1 L I I I I I I i l i 1 l

20 25 30 35 40 45 50 55

-5 0 5 10 15 TIME IN MINUTES l Figure 5-2.4. Reactor Power 5-12 1

I

I 8 SINGLE TUBE RUPTURE CASE 2 I @

N i i i i i i i i -l i TRP

---

LOOP B HOT LEG MASS FL0n' RATE LOOP A HOT LEG MASS FLOW RATE 8

I g u

I I 8 g

~

I C to W

N I E ma v8 _. -

e I x O

)

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=~ = ~~~ ~

t FLOW REDUCTION IN AFFECTED LOOP I 8 0 i i i i I i I i i I I

-5 0 5 10 15 20 25 30 35 40 45 50 55 l TIME AFTER RUPTURE (MINUTES)

Figure 5-2.5. Loop A and B Hot Leg Mass Flow Rate 5-13

I g SINGLE TUBE RUPTURE CASE 2

- 1 I I I I I I i i I i I

~ -

% I I

O -

a m

I I

v bo I

e s

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F F--

I-

? - _

I!

I

@ l TOTAL HPI FLOW l 7 i i i i i i I i

-5 0 5 10 15 20 25 30 35 40 45 50 ss E

TIME AFTER RUPTURE (MINUTES) u Figure 5-2.6. Total HPI Flow Into RCS 5-14 I'

I g SINGLE TUBE RUPTURE CASE 2

- 1 I I I I i i i i i 1 O -

I 0 Lij (D

( N \

N E

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l_

I I ERV FLOW i i I i i l

I i I i

! -5 0 5 10 15 20 ES 30 35 40 45 50 55 1 g TIME AFTER RUPTURE (MINUTES)

Figure 5-2.7. PORV Flow Out of RCS 1

5-15

I g SINGLE TUBE RUPTURE CASE i 2 i i

- 1 I i i i i i i I

o I w

g d

l3 L1-O a ~

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_J LL H

L1J Z g I

NET FLOW OUT OF RCS l

@ l i i I i i i 7 I I i I i 55 15 20 25 30 35 40 45 50

-5 0 5 10 TIME AFTER RUPTURE (MINUTES) l Figure 5-2.8. Het Flow Rate Out of RCS I

5-16 I

l

[ 8 SINGLE TUBE RUPTURE CASE 2 o I i i i i i i i i i i m

[ n E

ED

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INTEGRATED NET FLOW INTO RCS 'N N o ------

INTEGRATED PORV FLOW

[ 8 - - - - - - - - - - -

INTEGRATED TOTAL HPI FLOW g INTEGRATED TOTAL BREAK FLOW y i I I I I I I I I I I

[ -5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

[ Figure 5-2.9. Integrated Flows Into and Out of RCS

[

5-17

[

g SINGLE TUBE RUPTURE CASE 2 5 I I I I I I I i i i  !

LOOP A OTSG SATURATION TEMPERATURE

- - - - - - - - - - LOOP A COLD LEG DOWNSTREAM OF PUMPS O LOOP A COLD LEG UPSTREAM OF PUMPS -

$~ ------ LOOP A HOT LEG gg _ _ ,

o I w OTSG A BECOMES o

v

('N'v.  %

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-5 0 5 10 15 20 25 30 35 40 45 50 55 g TIME AFTER RUPTURE (MINUTES) u Figure 5-2.10. Loop A Fluid Temperatures I

s.1e i Ii

o SINGLE TUBE RUPTURE CASE 2 I R i l l I I I I I I I I I 8 e

I I ci -

0 I W a

v g _ _ _ _ _

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LOOP B OTSG SATURATION TEMPERATURE LOOP B COLD LEG DOWNSTREAM OF PUMPS LOOP B COLD LEG UPSTREAM OF PUMPS I g

@ l 0

i I LOOP B HOT LEG I I I I I I I I

-5 5 10 15 20 25 30 35 40 45 50 55 ll TIME AFTER RUPTURE (MINUTES)

Figure 5-2.11. Loop B Fluid Temperatures iI l

l 5-19 I

g SINGLE TUBE RUPTURE CASE 2 I

- 1 I i i i i i i i i i S

NOTE - SUODEN CHANGES IN SUBC00 LING MARGIN FREQUENTLY CORRESPOND -

8 -

TO OPENING & CLOSING 0F THE PORV n

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l HOT LEG SUBCOOLING MARGIN l o

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-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES) l Figure 5-2.12. Hot Leg Subccoling Margin Il 5-20 I

g SINGLE TUBE RUPTURE CASE 2

. I I I I I I I I I I i l UPPER HEAD AVERAGE LIQUID FRACT. l RCS PRESSU E REACHES SATURATICN PRESSURE O -_

l Y

Z O

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5 I

10 I

15 I

20 25 I I 30 I

35 I

40 I

45 l lA 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.13. Upper Head Average Liquid Fraction 5-21 I

I g SINGLE TUBE RUPTURE i CASE i i 2 i i in i i i i i O_ -

8 4

I:

8 m

bo Wo _ -

M W

N l I 3 CD o -

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3:

LL

<o _ m wS -

l x

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s -

I m- + +

o _

Oi _

l g l OTSGA BREAK FLOW l i i i i i I l 7 i i i i i

-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.14. OTSGA Break Flow 5-22 I

I g SINGLE TUBE RUPTURE CASE 2 in i i i i e i i i i i 1 I s _ _

I S m

n o U

gS ['

I C a3 8" i _ ~

l d 3: o og - _

I _J LL

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d .. e _

o y - _

g l OTSGA EFW FLOW l 7  : i I i  ! I i I l 1 1

-5 10 20 25 30 35 40 45 50 55 I 0 5 15 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.15. OTSGA EFW Flow I e.a I

I g SINGLE TUBE RUPTURE CASE 2 m i I i i l i I i i i I

,8r _ -

b w

W E N

E 8 _ - E on d

28 am

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@ l OTSGA MADV FLOW l 7 I I I I I I i t i i i

-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.17. OTSGA MADV Flow 5-25 l

I

!I

g SINGLE TUBE RUPTURE CASE 2 to I i i i i i i i I i I 8, _ _

8, _ _

o g _ _

n o Uo - _

Lu, U m h

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mm _ _

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g l OTSGA TSV FLOW l

• i' i i t i I i i i i i 1 0 5 10 15 20 25 30 35 40 45 50 55 l

-5 TIME AFTER RUPTURE (MINUTES) l Figure 5-2.18. OTSGA TBV Flow 5-26 I

l - - . . - - . -

I g m

SINGLE TUBE RUPTURE CASE 2 I i i i i i i i i I

a 8

I 8

I I N -

I 9R en N

8 -

d" I sg

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a. C -

u; I CD 0

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l l

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o - 6._ - _ L  :

} dL:jaj. J ._

l  ?- -

g l OTSGB ErW FLOW l 7 i t i i i i 1 I i I

-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.19. OTSGB EFW Flow g 5-2,

I

g SINGLE TUBE RUPTURE CASE 2 n I I I I I & I I I I I S -

8 -

^R Um W

(D N

TO co m

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o J

LL WO - ..

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F-L1J

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l g l OTSGB SAFETY VALVE FLOW l l 7 I I I I I I I I I I t

-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.20. OTSGB Safety Valve Flow l

t l S-28 l

(

L r g SINGLE TUBE RUPTURE CASE 2 L m i i i i i i i i i i F o L 0 - -

E o

- g - _

I r

Oo - -

LLJ S m m E

m8

_i m 3:

~ ~

n LL

>c Og - _

g Z

CD o F oS m

W o - _

l o _

m ,

l 8i _ -

l g l OTSGB MADV FLOW l 7 i i i i I I i i i 1

-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.21. OTSGB MADV Flow l

)

5-29 l

I g SINGLE TUBE RUPTURE CASE 2 m i i i i i i i i i i h -

bOcn o -

]O I.

0 0 d I I

~

m l ,

hy "

[h b~

0 -

g l OTSGB TBV FLOW l i i i i 7 I i i i i i 1 0 5 10 15 20 25 30 35 40 45 50 55 l

-5 TIME AFTER RUPTURE (MINUTES) r w re s-2.22. orsce Tsv riu s.se I I-

g ,

SINGLE TUBE RUPTURE CASE 2 I

I - -

o g - _

I I _

E -

)Ihhjhhih;f,I;f,jj-l -

/

ao /

fS ^ ~

I $

I ?e -

/

5 I s /

b$ - -

I 8 o _ h -

I o _

- -~~--

t88; 8?!8 ti?!L -

1 i i t i t i 1 1 i TIME AFTER RUPTURE (MINUTES)

Figure 5-2.23. OTSG Downcomer Indicated Level I

I '-'t I

I g SINGLE TUBE RUPTURE CASE 2 '

m i i i i i i i . 1 i i s

s 8

N

'N s -

- s, 8 -  %

N

-- s s

\

s s

< \

N f H o TURBINE BYPASS W ~

VALVES OPENE0 -

Q-@ i TO RESTORE EFW FLOW TERMINATED NATURAL ya IN LOOP A CIRCULATION Tw Wo E y "o - -

T

\

s@

F-N- N To -

LLJ@

Z LtJ C o 7 0

~ ~

Lij F- o W@

RCS CORE DUTLET PRESSURE o ------- OTSG TARGET PRESSURE -

O

---

LOOP B OTSG PRESSURE LOOP A OTSG PRESSURE o

o - _

o 1 I I I I I 1 I I I I

-5 0 5 10 15 20 25 30 35 40 45 50 55 TIME AFTER RUPTURE (MINUTES)

Figure 5-2.24. Steam Generator Pressure 5-32 I

5.3 SINGLE TUBE RUPTURE CASE 3 This case is the same as Case 2 except for the OTSGA steaming controls. Case 3, unlike Case 2, continues steaming OTSGA rather than isolating the generator. This case shows the effects of using an alternate operating procedure in response to a steam generator tube rupture.

Table 5-3.1 shows the sequence of events for this calculation. Figure 5-3.1 shows tne flow rate through the two ends of the ruptured tube. As before, there was more flow through the upper end of the ruptured tube. The break flow reflected the changes in the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop.

Figures 5-3.2 and 5-3.3 show the pressurizer indicated level and core outlet pressure, respectively. As a result of the break, the operator had an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result of the decreasing primary system pressure, the pressurizer heaters were energized.

Because of the decreasing pressurizer level, the makeup pumps increased their flow. The operator would have received a high makeup flow alarm at 1.19 minutes after rupture. Manual scram occurred 1 minute after the high makeup flow alarm.

After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp drop in average primary system temperature. The long-term pressurizer level and primary system pressure response reflect changes in the primary system inventory brought about by operator recovery actions that were pos'oulated to begin 5 minutes af ter scram. The sharp drop in the pressure at about 40 minutes appears to have been caused by the mass error phenonena described in Section 3.2. At this time the upper head volume is going from all steam to all water, and the pressure drop occurs as the quality is going through 50% thus suggesting a mass error.

I 5-33

Table 5-3.1 SEQUENCE OF EVENTS FOR SINGLE TUBE RUPTURE CASE 3 Event Time After Rupture (Minutes)

Single Tube Rupture 0.00 High Makeup Flow Alarm 1.19 Reactor Maiual Scram (1 Minute after High Makeup Flow) 2.19 E

Turbine and Main Feedwater Pumps Tripped 2.19 E Operator Initiates Full HPI Flow 2.19 MADVs and MSSVs Lift 2.24 EFW Flow Begins 2.43 Operator Initiates Manual RCS Cooldown 7.19 Operator Throttles HPI to Reduce RCS Pressure 7.19 Operator Opens PORV to Reduce RCS Pressure 7.19 Operator Closes PORV to Maintain Subcooling Margin 9.?5 OTSGB Level Reaches 50% Operating Range 12.8 EFW Flow Begins Cycling to Maintain Level OTSGA Pressure Exceeds Target Pressure, TBVs Opened 13.8 OTSGB Level Reaches 50% Operating Range, 14.3 EFW Flow Begins Cycling to Maintain Level OTSGB Pressure Exceeds Target Pressure, TBVs Opened 15.7 Operator Opens PORV to Reduce RCS Pressure 17.5 Operator Closes PORV to Maintain Subcooling Margin 18.8 Operator Opens PORV to Reduce RCS Pressure 22.8 Operator Closes PORV to Maintain Subcooling Margin 23.7 Operator Opens PORV to Reduce RCS Pressure 29.8 Analysis Termination Criteria Reached 40.36 Figures 5-3.4 and 5-3.5 show the reactor power and hot leg flow rates for each loop. Prior to scram, the break had little influence on the reactor power since the net mass that left the system was small. The primary coolant pumps were tripped at scram so that the behavior of the plant under natural circulation cooldown conditions with a single tube rupture could be investigated. After pump trip, the flow rates in the individual loops quickly approached stable single-phase natural circulation flow rates. Since both locps were being cooled by the combined effects of EFW injection into the OTSG and steam flow out of the TBVs, 5-34

L r

L the driving head caused by the primary fluid temperature drop across the OTSGs was not decreased, and the flow through both loops remained relatively constant.

L Figures 5-3.6 through 5-3.10 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. At scram it was postulated that the operator manually initiated full HPI, and the flow reflected changes in the primary system pressure. Recovery was assumed to begin at 7.19 minutes, 5 minutes after scram. It was postulated that the operator then throttled HPI and controlled the HPI flow based on the subcooling margin. It was postulated that the operator would also use the PORV to control subcooling margin and to aid in the depressurization of the piant since reactor coolant pumps were tripped at scram for this transient, and high-head auxiliary pressurizer spray was not available for the plant modeled. After recovery began, the PORV was opened whenever the subcooling margin reached 50f* and closed whenever the subcooling margin dropped to 25F'. Figure 5-3.8 shows that for most of the transient, HPI flow into the primary coolant system exceeded the combined flow out of the system through the PORV and ruptured tube. Figure 5-3.10 shows the integrated flow rates into and out of the primary coolant system. Except for a brief period prior to full HPI initiation, the primary coolant system inventory constantly increased.

Figures 5-3.11 and 5-3.12 show the loop A and B fluid temperatures in the hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged and then diverged as the RCS pumps tripped and coasted doen. The fluid temperatures in the cold legs upstreat of the primary coolant pumps are typically within a few degrees of the OTSG saturation temperatures under natural circulation conditions. The cold leg fluid temperature downstream of the primary coolant pumps is usually colder than the fluid upstream of the pumps due to the addition of lower temperature HPI fluid.

~

When the level in the steam generators reached the 50% operating range setpoint (at 12.8 minutes in OTSGA and at 14.3 minutes in OTSGB), EFW was terminated. This caused the fluid temperature and pressure in the affected 0TSG to rise. When the

[ OTSG pressure reached the target pressure, the EFW and TBVs began cycling to maintain the desired cooldown rate. Both the Loop A and the Loop B cold leg fluid

~

terperature decreased in response to decreases in the OTSGA and OTSGB temperature. No loss of natural circulation occurred in either loop.

Figure 5-3.13 shows the core outlet subcooling margin. The subcooling margin reflected changes in the primary system pressure and hot leg temperature. The m

5-35 w

I subcooling was controlled by the operator recovery actions. The minimum subcooling margin observed in this transient was approximately 25'F. No voiding resulted in the RCS in this transient except in the pressurizer and upper head.

Figure 5-3.14 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before the fluid in this region remained at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in this region. This occurred at approximately 9 minutes after transient initiation.

Figures 5-3.15 through 5-3.23 show the calculated flows into and out of the Loop A and loop B secondary systems. Figure 5-3.24 shows the OTSG A and B indicated secondary levels. Figure 5-3.25 shows the pressure behavior in the two OTSGs.

These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure caused the safety valves, the modulating atmospheric dump vahes (MADVs), and turbine bypass valves (TBVs) to cycle. The early pressure response in the secondary was in turn controlled by these valve actions. Fourteen seconds after g scram, the emergency feedwater system (EFW) was actuated. This system was effective in reducing secondary pressure, as it consisted of water at approximately 90'F which was sprayed into the OTSG. The EFW system also helped increase the level in each of the two OTSGs. Because of the presence of the break in the Loop A OTSG, the level increase rate was somewhat higher in this OTSG and reached 50% operating range level setpoint at 12.8 minutes, whereas the level setpoint was reached at 14.3 minutes in Loop B. The EFW flow was terminated when the level exceeded 50% operating range and was restarted when the level dropped below the 50% setpoint.

After the continuous EFW flow was terminated, the temperature and pressure in the OTSGs increased, in both OTSGs as the pressure crossed the target pressure, the TBVs opened while the EFW system cycled to maintain level at the desired level.

The result of these a*tions was a cooldown of both OTSGs which closely approximates the desirec cooldown.

5-36 I

r k, The analysis was terminated at 40.36 minutes after rupture with the primary system pressure below the secondary relief pressure setpoint and with the plant in a stable operating mode. At the end of the simulation, adequate subcooling margin was available, and the plant was being brought to a cold shutdown in a controlled manner. At no time during the simulation did a fuel rod cladding heatup occur.

\

v L

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L

[

[

[

m E

[

[

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5-37 i iii i i i

I o SINGLE TUBE RUPTURE CASE 3 m i I I i i i i t I LOWER END OF RUPTURED TUBE FLOW UPPER END OF RUPTURED TUBE FLOW N -

l I

gR w

l w

km

{

I d,

g

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~

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a '~ % _ _]

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l i

e , , , , , , , , ,

-s o s to 15 TIME AFTER RUPTURE (MINUTES) 20 es 30 as ao es l

Figure 5-3.1. Break Flow 5 3e I I

g SINGLE TUBE RUPTURE CASE 3 m I I I #  : i i

(. .

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l INDICATED PRESSURIZER LIQUID LEVEL l F

L 8

r + -

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[ Figure 5-3.2. Pressurizer Indicated Level

[

5-39 i

g SINGLE TUBE RUPTURE CASE 3 I

i i i i i i i i i g

8 /l _

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-5 0 5 10 15 20 25 30 35 40 45 l TIME AFTER RUPTURE OviINUTES) l l Figure 5-3.3. Core Outlet Pressure I

l l

5-40 I

g SINGLE TUBE RUPTURE CASE 3 o 1 I I 1 i i i i I l REACTOR POWER l 8 _ _

I I

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-5 0 5 10 15 PO F5 30 35 40 45 TIME IN MINUTES g

Figure 5-3.4. Reactor Power 5-41 l3

K g i SINGLE TUBE RUPTURE CASE 3 i i i i i i 1 I

- - - - - RCS FLOW RATE CLOOP B LOOP)

RCS FLOW RATE CLOOP A LOOP) 0 - - _

g _ _

~

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-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES) g Figure 5-3.5. Loop A and B Hot leg Mass Flow Rate 5-42 I

L r g SINGLE TUBE RUPTURE CASE 3 L m i i i i i i i i i g _ _

[

E CE - -

[ $

1 m

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+ v j

r L

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-s

[ a s to is 20 TIME AFTER RUPTURE (MINUTES) 25 so 35 40 as Figure 5-3.6. Net Flow Into RCS

- 5-43

m. _.- _ a

g SINGLE TUBE RUPTURE CASE 3 .

N I I I I I I I I I g

I I

n o o - -

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l l

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g l TOTAL BREAK FLOW ]

7 I I I I I I i i i

-5 0 5 10 15 20 25 30 35 40 15 g TIME AFTER RUPTURE (MINUTES) E Figure 5-3.7. Total Break Flow 5.o I

l 1

I g N I SINGLE TUBE RUPTURE CASE 3 I I I I I I 1 &

I 8

I

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g l TOTAL HPI FLOW l l 7 I I I I I I I i  !

-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES) l I Figure 5-3.8. Total HPI Flow I

I s-d

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-5 0 5 10 15 70 P5 30 35 20 45

TIME AFTER RUPTURE (MINUTES)

Figure 5-3.14. Upper Head Average Liquid Fraction g

, E i

5-51

!I 1

g SINGLE TUBE RUPTURE CASE 3 3 m I I l l l l l l O,e- -

l l

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g l OTSGA BREAK FLOW' l 7 I I I I I I I I I

-5 0 5 10 15 20 P5 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

Figure 5-3.15. 0"GA Break Flow 5-52

g SINGLE TUBE RUPTURE CASE 3 to I i i i l I i i i I o y - _

I o o - _

o g _ _

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g l OTSGA EFW FLOW l 7 I I I I i 1 I I I

, -5 0 5 to 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES) g Figure 5-3.16. OTSGA EFW Flow l

5-53 I

o SINGLE TUBE RUPTURE CASE 3 I

i i i I I i I

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-5 0 5 13 15 20 TIME AFTER RUPTURE (MINUTES) l

,,,.e53.u. 01s s.<e,v.,. ,,-

l 5-54

g SINGLE TUBE RUPTURE CASE 3 in i i i i i e i i i

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h o l OTSGA MADV FLOW l 7 I I I I I I I I

-5 0 5 10 15 20 25 30 35 40 45

[ TIME AFTER RUPTURE (MINUTES)

~

Figure 5-3.18. OTSGA MADV Flow

[

5-55

[

g SINGLE TUBE RUPTURE CASE 3 to i I I I i i i 'l 1 0

4 0

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w .

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l g l OTSGA TSV FLOW l

! 7 I I I i 1 1 I I g

-5 0 5 10 15 20 P5 30 35 40 45 TIME AFTER RUPTURE 04INUTES)

Figure 5-3.19. OTSGA TBV Flow l

5-56 I

o SINGLE TUBE RUPTURE CASE 3 0 i i i i i i i i i I s -

I o g - -

o I ^o 00 ._ -

Lij "

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0 OTSGS EFW FLOW l l 7 I I I i 1 I I I I

-5 0 5 10 15 20 P5 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

I Figure 5-3.20. OTSGB EFW Flow I 5-57

g SINGLE TUBE RUPTURE CASE 3 I

tn i I I I i I I i  !

E I

s I GR -

I

=

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om

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8 l OTSGB MADV FLOW l

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-5 0 5 10 15 20 25 30 35 40 45 l TIME AFTER RUPTURE (MINUTES)

Figure 5-3.22. OTSGB MADV Flow I

5-59 I

o SINGLE TUBE RUPTURE CASE i 3 i i

@ i i i i i i I

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I 9-I l

08 wm l

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10 15 20 25 30 35 40 45

-5 0 5 TIME AFTER RUPTURE (MINUTES) g Figure 5-3.23. OTSGB TBV Flow I

5-60 I

l g SINGLE TUBE RUPTURE CASE 3 I

~ -

m o

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h Iiiikh h !! l I Jj v /, I I m /

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-5 0 5 10 15 20 P5 30 35 40 45 TIME AFTER RUPTURE (MINUTES) g Figure 5 3.24. OTSG Downcomer Indicated Level 5-61 I

I g SINGLE TUBE RUPTURE CASE 3 m m I I I I I

ji 7, I i g i

k 8 _

\ _

a' g

N \%

o N um o -

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---

(1) RCS CORE OUTLET' W ESSURE o ------- (2) OTSG TARGET PRESSURE ~

- - - - - (3) LOOP B OTSG PRESSURE (4) LOOP A OTSG PRESSU_RE o

o _

o i I I I I .L 1 __ I I

-5 0 5 10 15 20 PS *10 35 40 45 TIME AFTER RUPTURE ntINUTES)

Figure 5-3.25. Steam Generator Pressure I

5-62 l I

5.4 SINGLE TUBE RUPTURE CASE 12 This case represents a rupture of a single tube of the OTSG-A steam generator, with pump trip postulated to occur when the hot leg subccoling margin decreased to below 20F* instead of following a decrease in primary pressure below 1600 psia.

Case 12 was run to show the effect of using a less restrictive pump trip citerion than was used in Case 2.

Table o-4.1 shows the sequence of events for this calculation. Figure 5-4.1 shows the flow rate through the two ends of the ruptured tube. As before, there was more flow at the upper end of the ru;,tured tube. The flow through both ends of I the tube was relatively constant up until scram, which occurred at 2.19 minutes after rupture. After scram, the break flow reflected the changes in the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop.

Table 5-4.1 SEQUENCE OF EVENTS FOR SINGLE TUBE RUPTURE CASE 12 I Event Time After Rupture (Minutes)

Single Tube Rupture in OTSG-A 0.00 High Makeup Flow Alarm 1.19 l

I Reactor Manual Scram (1 Minute After High Makeup Flow)

Turbine and Main Feedwater Pumps Tripped 2.19 2.19 Operator Initiates Full HPI Flow 2.19

, MADVs and MSSVs Lift 2.24 EFW Flow Begins 2.43 l Operator Initiates Manual RCS Cooldown 7.19 Operator Throttles HPI to Reduce RCS Pressure 7.19 Analysis Termination Criteria Reached 55.15 I Figures 5-4.2 and 5-4.3 show the pressurizer indicated level and core outlet pres-sure, respectively. The operator had an almost immediate indication of an upset

,I l

5-63 l

'I

Ii condition due to the decline in pressurizer level and primary system pressure caused by the break. In the case of a tube rupture, the operator would also receive signals from air ejector radiation monitors. As a result of the decreas-ing primary system pressure, the pressurizer heaters were energized however, they could not keep up with the effects of the break, and the pressure continued to decline. Because of the decreasing pressurizer level, the makeup pump increased its flow however, one makeup pump, at full capacity, could not replace all of the water being lost from the primary, so the level continued to decline. The operator received a high makeup flow alarm at 1.19 minute after rupture. It was postulated that the operator scrammed the plant and initiated full HPI flow 1 min- g ute after the high makeup flow alarm was received. After scram occurred, tnere g was an abrupt drop in pressurizer level and pressure because of the sharp drop in average primary system temperature. The long-term pressurizer level and primary system pressure response reflect changes in primary system inventory brought about by the operator recovery actions that were postulated to have begun 5 minutes after scram.

Figures 5-4.4 and 5-4.5 show the reactor power and hot leg flow rates for each loop. Prior to scram, the break had little influence on the reactor power since the net mass that left the system was small. For this transient, it was g postulated that the operator would trip the primary coolant pumps when the g subcooling margin reached 20F*. This condition was never reached during this transient, so the reactor coolant pumps were never tripped.

Figures 5-4.6 and 5-4.7 show the flow rates into and out of the primary coolant I

g system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. At scram, it was postulated that the operator manually initiated full HPI, and the flow reflected changes in the primary system pressure. After recovery began at 7.19 minutes, 5 minutes after scram, it was postulated that the operator throttled HPI and controlled the HPI E flow based on the subcooling margin. It was assumed that after initiation of g recovery the pressurizer spray system would be used in preference to the PORV if the reactor coolant pumps were running. Pressurizer spray was initiated whenever the subcooling margin exceeded 50*F and was terminated if the subcooling margin dropped to 25F*. Figure 5-4.6 shows that for most of the transient, HPI flow into g the primary coolant system exceeded the flow out of the system through the g ruptured tube.

I 5-64 I

I

Figure 5-4.7 shows the integrated flow rates into and out of the primary coolant system. Except for a brief period prior to full HPI initiation, the net inflow was positive, indicating that more water was being put into the primary coolant system than was lost from the primary coolant system.

I figures 5-4.8 and 5-4.9 show the Loop A and B fluid temperatures in the hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged as the power removal requirements di-inished.

I Figure 5-4.10 shows the hot leg subcooling margin in the effected loop. The sub-cooling margin reflected changes in the primary system pressure and hot leg temperature. The subcooling was controlled by the operator recovery actions. The minimum subcooling margin observed in this transient was approximately 43*F, which occurred prior to scram. No voiding occurred in the RCS in this transient except I in the pressurizer and upper head.

Figure 5-4.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remained at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the I fluid in this region. This occurred at approximately 24 minutes after transient initiation. At this time a substantial amount of voiding occurred. It is felt that the dead-head model over-predicts the amount of voiding in this region. This treatment is felt to be conservative in modeling the system bebavior.

I Figures 5-4.12 through 5-4.20 show a sumrary of the calculated flows into and out of the Loop A and Loop B secondary systems. Figure 5-4.21 shows the OTSG A and B indicated secondary levels. Figure 5-4.22 shcws the pressure behavior in the two OTSGs. These figures are discussed as a group. Immediately after screm, the feedwater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure caused the safety valves, the modulating atmospheric dump valves (MADVs),

and turbine bypass valves (TBVs) to cycle. The early pressure response in the secondary was, in turn, controlled by these valve actions. Fourteen seconds after scram, the emergency feedwater (EFW) was initiated. When the reactor coolant I pumps are running, the OTSG level setpoint is at 30 inches. When the OTSG 1evel dropped below this setpoint, the EFW flow began and was terminated when the level exceeded the 30-inch level setpoint. The level in the affected generator increased due to leak flow. The level increase would be limited to 95% of 5-65 I

operating range by opening the MADVs, but in the course of this analysis the MADVs were not opened to control the level. In the B OTSG, the TBVs were opened as the pressure crossed the target pressure, while the EFW system cycled to maintain level at the desired level. The result of these actions was a cooldown of the unaffected 0TSG, which closely approximates the desired cooldown.

The analysis was terminated at 55.15 minutes after rupture, with the primary sys-tem pressure below the secondary relief pressure setpoint and with the plant in a g stable operating mode. At the end of the simulation, adequate subcooling margin '

M was available, and the plant was being brought to cold shutdown in a controlled manner. At no time during the simulaticn did a fuel rod cladding heatup occur.

This case highlights the advantages of using low hot leg subcooling margin (in this case 20F') instead of low pressure as the primary system purrp trip 3 criteria. In this case, subcooling never dropped below 20*F; therefore, reactor coolant pumps were riever tripped and pressurizer spray remained available for the duration of the transient. Availability of reactor coolant pumps (and pressurizer spray) assures core cooling, eases operator actions, and avoids the complications such as pressurizer level fluctuations associated with using PORVs for primary depressurization.

I I

I I

I I

I 5-66

SINGLE TUBE RUPTURE CASE 12

[ o m I i i i i I i i I i i 1 LOWER END OF RUPTURED TUBE FLOW UPPER END OF RUPTURED TUBE FLOW l N

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[ -5 0 5 10 15 20 TIME AFTER RUPTURE (MINUTES) 25 30 35 40 45 50 55 60 Figure 5-4.1. Break Flow

[.

5-67

g SINGLE TUBE RUPTURE CASE 12 I

m I I I I I I I I I I I I

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5-68 I

I g SINGLE TUBE RUPTURE CASE 12 g i i i i i i i i i i i i I l----- CORE OUTLET PRESSURE l 8

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5 10 15 20 25 30 35 40 45 50 55 60 l TIME AFTER RUPTURE (MINUTES) l l

l Figure 5-4.3. Core Outlet Pressure I

5-69 I

8 8 SINGLE TUBE RUPTURE CASE 12 I

8 i iiiiiiiiiii 8 SCRAM I

l REACTOR POWER l I

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-5 0 5 10 15 20 25 30 35 40 45 50 55 60 TIME IN MINUTES g Figure 5-4.4. Reactor Power I 5-70 I

I $ SINGLE TUBE RUPTURE CASE 12 g - i i i i i i i i i i i I

I g ,--

~

l

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LOOP B HOT LEG MASS FLOW RATE LOOP A HOT LEG MASS FLOW RATE 8

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20 25 I

30 I I 35 I

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45 50

[ ]

55 60 TIME AFTER RUPTURE (MINUTES)

I Figure 5-4.5. Loop A and B Hot Leg Mass Flow Rate 5-71 I

g SINGLE TUBE RUPTURE CASE 12i i

- i i i i 6 i i

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(1) NET FLOW INTO RCS

- - - - - - - - - - (2) TOTAL HPI FLOW g (3) TOTAL BREAK FLOW i i i i i i i 7 i i i i i 15 20 25 30 35 40 45 50 55 60

-5 0 5 10 TIME AFTER RUPTURE (MINUTES)

I Figure 5-4.6. Flows into RCS 5-72

l 8 o

o e i SINGLEi i TUBE i RUPTURE CnSE 12 i i I i i i i N

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INTEGRATED NET FLOW INTO RCS E o ------

INTEGRATED PORV FLO4 5 8 g

INTEGRATED TOTAL HP] FLOW INTEGRATED TOTAL BREAK FLOW 7 I I i i t i I i 1 i I 1

-5 0 5 10 15 20 25 30 35 40 45 50 55 SO TIME AFTER RUPTURE (MINUTES)

! Figure 5-4.7. Integrated Flows Into and Out of RCS

!I g 5 73 l

I

o SINGLE TUBE RUPTUREi CASE 12 I

R i i i i i i i i l i I LOOP A OTSG SATURATION TEMPERATURE

- - - - - - - - - - - LOOP A COLO LEG DOWNSTREAM OF PUMPS l 3

0 LOOP A COLO LEG UPSTREAM OF PUMPS -

---

LOOP A HOT LEG I

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,4,e,e 5 4.e. <ee,A ,,e,e rem,e,ete,es y

5-74 I

I g SINGLE TUBE RUPTURE CASE 12 s i i i i i i i i i i i i I

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i LOOP B OTSG SATURATION TEMPERATURE LOOP B COLD LEG DOWNSTREAM OF PUMPS LOOP B COLD LEG UPSTREAM OF PUMPS

! g LOCP B HOT LEG 8 i i i i i I I I I I I I

-5 0 5 10 15 20 25 30 35 40 45 50 55 60 l TIME AFTER RUPTURE (MINUTES)

, Figure 5-4.9. Loop B Fluid Temperatures lI 5-75 l

I l _ _ _ _ . _ . . _ . . _ _ _ . _ _ _ _ _ ._ . . _ . ._. _ _ _ . . _ _ . _ _ _ , _ . . _ . _ _ . _ _ _ . _

g SINGLE TUBE RUPTURE CASE 12 I

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7 I  ! l l l I I l I I I 1 TI E A TER RUPTU E MI UTES) g figure 5-4.10. Hot Leg Subcooling Margin 5-76 I

o SINGLE TUBE RUPTURE CASE 12

. I I I I i l i i I i i i

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I l UPPER HEAD AVERAGE LIQUID FRACT. l

, RCS PRESSURE REACH S SATURATION PRESSURE O _ _

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d i I I I f I I I I I f f M -5 0 5 10 15 20 25 30 35 40 45 50 55 60 i TIME AFTER RUPTURE (MINUTES)

I Figure 5-4.11. Upper Head Average Liquid Fraction ll i

s-77

I

g SINGLE TUBE RUPTURE CASE 12 I

m 6 I i l i i i l i l i I 5 -

g 8 -

3 I

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@ l OTSGA BREAK FLOW l g 7 1 i i i I i I i i i i 1 5

-5 0 5 10 15 20 25 30 35 40 45 50 55 60 l TIME AFTER RUPTURE (MINUTES) l, ripre s-4. u. ors a area r w g

5-78 Il

I g m I i SINGLE i i TUBEI RUPTURE CASE 12 I i i i i i i I o sn i

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g l OTS3A EFW FLOW l T i i i i i i i i i e i I

'I -5 0 5 10 15 20 25 30 35 40 45 50 55 60 TIME AFTER RUPTURE (MINUTES) i Figure 5-4.13. OTSGA EFW Flow 5-79 I

I' g SINGLE TUBE RUPTURE CASE 12 l n i i i l i i i I I i i I l l

5 - -

I 8 _ _

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g l OTSGA SAFETY VALVE FLOW l 7 i i I I I I I I I I i

-5 0 5 10 15 20 25 30 35 40 A5 50 55 60 E

TIME AFTER RUPTURE (MINUTES) a rigure s-4.14. oTscA sarety valve riow g

s-so I

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[ g m I i SINGLE TUBE RUPTURE CASE 12 i i i i I i I l I i o

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( -5 0 5 to 15 20 Ps 30 35 40 45 50 55 so TIME AFTER RUPTURE (MINUTES)

[ Figure 5-4.15. OTSGA MADV Flow

[

5-81

g SINGLE TUBE RUPTURE CASE 12 in i 1 i i a i i i i i i i 5 -

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g SINGLE TUBE RUPTURE CASE 12 in i i i i i a i i i i i 8_

g 8

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Figure 5-4.17. OTSGB EFW Flow l

5-83

g SINGLE TUBE RUPTURE CASE 12 I

in i i i i i i i i i i i 8

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-5 0 5 10 15 20 25 30 35 40 AS 50 55 60 TIME AFTER RUPTURE (MINUTES) l r w e s.4.18. mscesaayvmer w g

s.e4 I

o SINGLE TUBE RUPTURE CASE 12

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-5 0 5 10 13 20 25 30 35 40 45 50 55 60 TIME AFTER RUPTURE (MINUTES)

Figure 5-4.19. OTSGB MADV Flow 5-85 I

g SINGLE TUBE RUPTURE CASE 12 I

u)  : i i i i i i i 8 _ _

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I I

g _ _

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5-86

g SINGLE TUBE RUPTURE CASE 12

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, o j I l l I I I I l i I l 1 1

-5 0 5 10 15 20 25 30 35 40 45 50 55 60 TIME AFTER RUPTURE (MINUTES)

Figure 5-4.21. OTSG Oowncomer Indicated Level

'I lI s-87 l

g SINGLE TUBE RUPTURE CASE 12 i i m i i i i i i i i t, I

's a  %

'A, -

h 8 _

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~

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PCS CORE OUTLET PRESSURE o ------- OTSG TARGET PRESSURE -

LOOP B OTSG PRESSURE LOOP A OTSG PRESSURE O

i I I I I I I I I i o I I 0 5 15 20 25 30 35 40 45 50 55 60 l

-5 10 TIME AFTER RUPTURE (MINUTES)

Figure 5-4.22. Steam Generator Pressure 5-88

I 5.5 SINGLE TUBE RUPTURE CASE 10 This case simulates the rupture of a single tube in OTSGA with the secondary system safety valve sticking open on the first challenge. Pump trip occurs when the subcooling margin at the core outlet is less than 20F*. This case shows the effects of a secondary system breach.

Table 5-5.1 shows the sequence of events for this calculation. Figure 5-5.1 shows the flow rate through the two ends of the ruptured tube. As before, there was more flow through the upper end of the ruptured tube. The break flow reflected the change in the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop.

Figures 5-5.2 and 5-5.3 show the pressurizer indicated level and core outlet pressure, respectively. As a result of the break, the operator had an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result of the decreasing primary system pressure, the pressurizer heaters were energized.

Because of the decreasing pressurizer level, the makeup pump increased its flow.

The operator would have received a high makeup flow alarm at 1.21 minutes after rupture. Manual scram occurred 1 minute after the high makeup flow alarm. After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp drop in average primary system temperature. At 2 minutes after rupture, the HPI flow exceeded the break flow, and the pressurizer level stabilized and then began to increase. The long-term pressurizer level and primary system pressure response reflect changes in the primary system inventory I brought about by operator recovery actions that were postulated to begin 5 minutes after scram, t

I 5-ee g

I Table 5-5.1 SEQUENCE OF EVENTS FOR SINGLE TUBE RUPTURE CASE 10 Event Time After Rupture I

(Minutes)

Single Tube Rupture 0.00 High Makeup Flow Alarm 1.21 E

Reactor Manual Scram (1 Minute after High Makeup Flow) 2.21 m Turbine and Main Feedwater Pumps Tripped 2.21 Operator Initiates Full HPI Flow 2.21 MADVs and MSSVs Lift 2.25 EFW Flow Begins 2.44 OTSGB Level Reaches 30 Inches, 3.0 EFW Flow Begins Cycling to Maintain Level MADV Flow Begins Cycling to Maintain Level OTSGB Pressure Exceeds Target Pressure, TBVs Opened 6.6 Operator Initiates Manual RCS Cooldown 7.21 Operator Throttles HPI to Peduce RCS Pressure 7.21 Operator Initiates Pressurizer Spray to Reduce Pressure 7.21 Analysis Termination Criteria Reached 44.6 Figures 5-5.4 and 5-5.5 show the reactor power and hot leg flow rates for each loop. Prior to scram, the break had little influence on the reactor power since the net mass that left the system was small. Because the subcooling trirgin never g dropped below 20F*, the primary coolant pumps were not tripped.

Figures 5-5.6 and 5-5.7 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. At scram the operator manually initiated full HPI. After recovery began at 7.21 minutes, the operator throttled HPI and used the pressurizer spray to control subcooling margin. The operator manually initiated pressurizer spray when the subcooling margin reached 50F* and terminated pressurizer spray when the subcooling margin dropped to 25F*. For this transient, pressurizer spray (190 gpm) was initiated at 7.21 minutes and never Ei g I terminated. Figure 5-5.6 shows that for most of the transient HPI flow into the I

5-90

(- primary coolant system exceeded the flow out of the system through the ruptured tube. Figure 5-5.7 shows that except for a brief period prior to full HPI

( initiation and after HPI throttling, the primary ccolant system inventory constantly increased.

C Figures 5-5.8 and 5-5.9 show the Loop A and B fluid temperatures in the hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram,

( the hot and cold leg fluid temperatures converged as the need for power removal decreased. Note the rapid drop-off of Loop A saturation temperature due to the stuck open safety valve.

[

Figure 5-5.10 shows the core outlet subcooling margin. The subcooling margin

( reflected changes in the primary syst:m pressure and hot leg temperature. The subcooling was controlled by the operator recovery actions. The minimum subcooling margin observed in this transient was approximately 45F*, No voiding resulted in the RCS in this trartsient except in the pressurizer and upper head.

( Figure 5-5.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remained at a constant teinperature until the pressure in the reactor vessel reached the saturation pressure of the

[ fluid in this region. This occurred at approximately 18 minutes after transient initiation.

[

Figures 5-5.12 through 5-5.20 show a summary of the calculated flows into and out of the Loop A and Loop B secondary systems. Figure 5-5.21 shows the OTSG A and B

[ indicated secondary levels. Figure 5-5.22 shows the pressure behavior in the two OTSGs. These figures are discussed as a group. Immediately after scram, the

( feedeater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure caused the safety valves, the modulating atmospheric dump valves (MADVs),

and turbine bypass valves (TBVs) to cycle. The safety valves in OTSGA stuck open at this time.

[

The early pressure response in the secondary was in turn controlled by these valve actions. Fourteen seconds after scram, the emergency feedwater system (EFW) was actuated. This system was effective in reducing secondary pressure, as it con-sisted of water at approximately 90*F which was sprayed into the OTSG. The OTSGA h EFW system was isolated at 5.7 minutes based on an excessive cooling pressure setpoint of 800 psi. The OTSGB EFW and MADVs were cycled to maintain level at

[

5-91

[

I 30 inches. The OTSGB TBVs were cycled to maintain the desired pressure. The I

5 result of these actions was a cooldown in OTSGB, which closely approximates the desired cooldown.

Meanwhile, the OTSGA was depressurized because of the stuck open safety valve.

The generator was then isolated from EFW, boiled dry, and in effect stopped g participating in the transient except for continued leak flow. 5 The analysis was terminated at 44.6 minutes after rupture with the primary ',ystem pressure below the secondary relief pressure setpoint, primary system pres',ure decreasing, and adequate subcooling margin available.

Comparison of this case and 12 (Section 5.4) show that a stuck open safety valve for the affected steam generator causes the affected steam generator to boil dry, but has little effect on plant recovery. This is because the forced circulation cooldown is being effected by steaming the unaffected steam generator in both cases and the heat input from the affected steam generator is small in both cases.

I I

I I

I I

l 5-92 i

l o m i SINGLE TUBE RUPTURE CASE 10 i e i i i i I

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L OWER END OF RUPTURED TUBE FLOW UPPER END OF RUPTURED TUBE FLOW I i i t 1 I I t t t t

-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES) -

I Figure 5-5.1. Break Flow I

I "-

I

g SINGLE TUBE RUPTURE CASE 10 I

m i i i i i i i o

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l INDICATED PRESSURIZER LIQUID LEVEL l n

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-5 0 5 to 15 20 25 30 35 40 AS TIME AFTER RUPTURE (MINUTES) l Figure 5-5.2. Pressurizer Indicated Level 5-94 I

g_ SINGLE TUBE RUPTURE CASE 10 i g i # 1 i e a i i l

1 i

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m I l----- CORE DUTLET PRESSURE l I o I I I I I I I I I

-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

Figure 5-5.3. Core Outlet Pressure 5-95

o SINGLE TUBE RUPTURE CASE 10 I

e i i e i i i i I l REACTOR 0WER l I

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-5 0 5 10 15 20 25 30 35 40 45 TIME IN MINUTES l

o ,e,e s.s.4. Reer Pw s-96 l

8 SINGLE TUBE RUPTURE CASE 10 8 4 I I I I I I I l RCS FLOW RATE CLOOP B LOOP):

RCS FLOW RATE (LOOP A LOOP) i '

8 -

g - i I

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c Lij W

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0 I

5 f

10 f

15 I

20 f

25 I

30 I

35 I

40 45 TIME AFTER RUPTURE (MINUTES)

Figure 5-5.5. Loop A and B Hot Leg Mass Flow Rate iI 5-97 I

g SINGLE TUBE RUPTURE CASE 10 N I I I I I I I I I

---

(1) NET FLOW INTO RCS g (2) TOTAL HPI FLOW (3) TOTAL BREAK FLOW g

o _

m -

o I

3 n 8,__,\ E U l

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7 I I 1 I I I I I I

-5 0 5 10 15 20. 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

Figure 5-5.6. Flow Into RCS 5-98 I

g g SINGLE TUBE RUPTURE CASE 10 F) i I I I I I I I I I O u,

N I o o

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(1) INTEGRATED NET FLOW INTO RCS -

I (2) INTEGRATED PORY FLOW 8 ------

l (3) INTEGRATED TOTAL HPI FLOW l g (4) INTEGRATED TOTAL BREAK FLOW l

7  :  : 1 1 1 1 I

-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

~

lI l Figure 5-5.7. Integrated Flows Into RCS 5-99 1

1 I

g 6 i SINGLE TUBE RUPTURE CASE 10 i i i i i i i I I

(1) LOOP A OTSG SATURATION TEMPERATURE (2) LOOP A COLO LEG 00WNSTREAM OF PUMPS (3) LOOP A COLO LEG UPSTREAM OF PUMPS (4) LOOP A HOT LEG e s - -

E I

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g l I I I I I I I I

-5 0 5 10 15 20 25 30 35 40 AS TIME AFTER RUPTURE (MINUTES) g i Figure 5-5.8. Loop A Fluid Temperatures 4

5-100 i

i J l FW n 4 L R R R R R R R R C W fU LOOP B FLUID TEMPERATURES (DEG F) 300 350 400 450 500 550 600 650 700 I I i i i a i l

o -

l l, l H -

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w_.

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5 I l I gg I I I I I

I g SINGLE TUBE RUPTURE CASE 10 i

I I

. I I I e i i i l UPPER-UPPER HEAD AVE. LIQUID FRACT. _

l l

I Z 8

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-5 0 5 10 15 20 25 30 35 40 45

,'g TIME AFTER RUPTURE (MINUTES)

Figure 5-5.11. Upper Head Average Liquid Fraction I ~

I s-1"

'I

I g SINGLE TUBE RUPTURE CASE 10 i in i i i i i i  :

s m

I o -

kS 1 I O

N v

3 0 @0 LL o -

E to S -

E cr CD e

m I--

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/

o -

I 8 -

I g l OTSGA BREAK FLOW l I I t 7 I I I I 1

-5 0 5 10 15 20 25 30 35 40 45 E TIME AFTER RUPTURE (MINUTES)

Figure 5-5.12. OTSGA Break Flow 5-104 I

g SINGLE TU9E RUPTURE CASE 10 m I i i i i i i i i I 8 I o o _

I 8 _

I ^o Uo -

I Wm in N

Eo y m tn - -

E d" I $$

_J tL I *8 tt -

W I <

0 en 8 _

F-I g_ _

I o -

I 8' _ _

I g l OTSGl. E ' FLOW l 7 i i i _

i i i i i

-5 0 5 10 3 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

I Figure 5-5.13. OTSGA EFW Flow I

5-105 I

g SINGLE TUBE RUPTURE CASE 10 ._

Ln i I I I I I I I I 8 _

~

I I.

Ch -

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= '

w U)

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=

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l-

-m:HM:-1 E a p.

0 -

g l OTSGA SAFETY VALVE FLOW l 7 i i i i I I I i i .__

-5 0 5 10 15 20 25 30 35 40 -5 TIME AFTER RUPTURE (MINUTES)

Figure 5-5.14. OTSGA Safety Valve Flow 5-106 I

g SINGLE TUBE RUPTURE CASE 10 nn i I I I I I I I I I 0 - _

I E -

s I

LIJ N

I CO

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LL

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g-I }-

O O - -

, o _ i 1 l

g l OTSGA MADV FLOW }

y i  : 1 1 I i I

-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

Figure 5-5.15. OTSGA MADV Flow i

I I e-to' I

l --

g SINGLE TUBE RUPTURE CASE 10 in i 1 i i i i i i o

N I

s m

I G8m - _

Lu m

N Eo m in - _

.l" 3: o I

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ao S -

I--

08 m- _ _

F--

O O

o 8, _ _

8 l OTSGA TBV FLOW l 7  : I I I i i i 0 5 10 15 20 25 30 35 40 45

-5 TIME AFTER RUPTURE (M INUTES) I Figure 5-5.16. OTSGA TBV Flow 5-108 I

I g. SINGLE TUBE RUPTURE CASE 10 m I i i i i i i i i I O.

g-- _

O

~ ~

E I

O g _ _

I ^O U0 LD S U)

N I 2O mm

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v 3: 0 og - -

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ID CD w8-en I l- . - - - - . _ ---- -- ..... ., , . .,

8-g ,

I O _ i - 1 l l 1 I ..

I  ?- -

O I OTSGB EFW FLOW I

l 7_ t I I I I I I I

-5 0 5 10 15 20 25 30 35 40 45 lg TIME AFTER RUPTURE (MINUTES)

Figure 5-5.17. OTSGB EFW Flow I

5-109 I

g SINGLE TUBE RUPTURE CASE 10 i i m I i l I i i i I

8_ _

I 8 _

l o

n o g! -

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v 38 ON

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Figure 5-5.18. OTSGB Safety Valve Flow I

5- m I I

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-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

Figure 5-5.22. Steam Gene r Pressure 5-114 I

5.6 SINGLE TUBE RUPTURE CASE 11 This case simulates the rupture of a single tube in OTSGA with the PORV sticking open on the first challenge. Pump trip occurs at scram. This case shows the effects of feed and bleed cooling.

Table 5-6.1 shows the sequence of events for this calculation. Figure 5-6.1 shows the flow rate through the two ends of the ruptured tube. As before, there was more flow through the upper end of the ruptured tube. The break flow reflected I the changes in the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop.

Figures 5-6.2 and 5-6.3 show the pressurizer indicated level and core outlet pressure, respectively. As a result of the break, the operator had an almost I immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result of the decreasing primary system pressure, the pressurizer heaters were energized.

Because of the decreasing pressurizer level, the makeup pump increased its flow.

The operator would have received a high makeup flow alarm at 1.19 minutes after rupture. Manual scram occurred 1 minute after the high makeup flow alarm. After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp drop in average primary system temperature. The long-term pressurizer level and primary system pressure response reflect changes in the primary system inventory brought about by operator recovery actions that were postulated to begin 5 minutes after scram.

l Figures 5-6.4 and 5-6.5 show the reactor power and hot leg flow rates for each l loop. Prior to scram, the break had little influence on the reactor power since the net mass that left the system was small. The primary coolant pumps were tripped at scram so that the behavior of the plant under natural circulation cooldown conditions with a single tube rupture could be investigated. After pump trip, the flow rates in the individual loops quickly approached stable single-phase natural circulation flow rates. With the PORV stuck open and HPI continuing

( at full flow, the driving head for natural circulation in the unaffected loop decreased because the primary system was cooling down faster than the secondary system. At 18 minutes after rupture, the Loop B hot leg temperature exceeded the l cold leg temperature by 50*F indicating loss of natural circulation. (See Section 3.3 for loss of natural circulation criteria.) natural E Af ter the loss: o(Ir l 3 l

l l

5-115

I Table 5-6.1 SEQUENCE OF EVENTS FOR SINGLE TUBE RUPTURE CASE 11 Time After Rupture Event (Minutes)

Single Tube Rupture 0.00 High Makeup Flow Alarm 1.19 Reactor Manual Scram (1 Minute after High Makeup Flow) 2.19 Turbine and Main Feedwater Pumps Tripped 2.19 Operator Initiates Full HPI Flow 2.19 g MADVs and MSSVs Lift 2.24 5 EFW Flow Begins 2.43 Operator Initiates Manual RCS Cooldown 7.19 Operator Throttles HPI to Reduce RCS Pressure 7.19 Operator Opens PORV to Reduce RCS Pressure (PORV sticks open) 7.19 Operator Attempts to close PORV to Maintain Subcooling Margin 10.0 Subcooling Margin Orops Below 20*F 10.5 Operator Notes Loss of Natural Circulation in Loop B, Opens MADVs 18.8 OTSGA Level Reaches 95% Operating Range EFW Flow begins Cycling to Maintain Level 19.2 Subcooling Margin Rises above 20*F OTSGB Level Greater Than 50%

Operating Range, EFW Flow Begins Cycling to Maintain Level 19.7 OTSGB Pressure Exceeds Target Pressure, TBVs Opened 25.8 E

Analysis Termination Criteria Reached 45.79 5 I

circulation was detected in the unaffected loop (Loop B), it was postulated that the operator would begin to take corrective actions to restore the natural circulation flow rate in that loop. EFW flow to the affected 0TSG was terminated when the level reached the 95% operating range level setpoint at 19.2 minutes after rupture. Because subcooling margin was restored prior to OTSGB reaching the 95% coerating range level setpoint, EFW flow to OTSGB was was terminated when the g

subcooling margin was restored at approximately 20 minutes. The termination of 3 EFW to OTSGA caused the primary-to-secondary temperature difference across the affected 0TSG to decrease, and the driving head for natural circulation in the affected loop slowly decreased until the flow was just feed and bleed. That is, the HPI flow was added and leak flow through the PORV and the broken tube was removed from the primary system. This caused a slow decrease in the flow rates I a

through the loop.

5-116 I

Since the unaffected loop was being cooled by the combined effects of EFW injec-tion into the OTSG and steam flow out of the TBVs, the driving head caused by the primary fluid temperature drop across the OTSGs was not decreased, and the flow I through this loop remained relatively constant after the restoration of natural circulation.

Figures 5-6.6 and 5-6.7 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and res-I ponded to the decrease in pressurizer level. At scram it was postulated that the operator manually initiated full HPI, and the flow reflected changes in the pri-mary system pressure. Recovery was assumed to begin at 7.19 minutes, 5 minutes after scram. It was postulated that the operator then throttled HPI and con-trolled the HPI flow based on the subcooling margin. It was postulated that the I operator would also use the PCRV to control subcooling margin and to aid in the depressurization of the plant since reactc: Coolant pumps were tripped at scram for this transient, and high-head auxiliary pressurizer spray was not available.

After recovery began, the PORV was opened when the subcooling margin reached 50F'. However, the PORV did not recicse when the subcooling margin dropped below.

I 25F'. Figure 5-6.6 shows that for most of the transient, HPI flow into the primary coolant system exceeded the combined flow out of the system through the PORV and ruptured tube. Figure 5-6.7 shows the integrated flow rates into and out cf the primary coolant system. Except for a brief period prior to 'ui' HPI initiation, the primary coolant system inventory constantly increased.

I Figures 5-6.8 and 5-6.9 show the Loop A and B fluid temperatures in tre hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged and then diverged as the RCS pumps tripped and coasted down. The fluid temperatures in the cold legs upstream I of the primary coolant pumps are typically within a few degrees of the OTSG saturation temperatures under natural circulation conditions. The cold leg fluid temperature downstream of the primary coolant pumps is usually colder than the fluid upstream of the pumps due to the addition of lower temperature HPI fluid.

The large drop in the Loop B cold leg is due to a combination of low loop flow and low HPI temperature.

At 19.4 minutes into the transient, the EFW in the affected 0TSG (Loop A) was terminated. This caused the fluid temperature in the affected 0TSG to rise to the hot leg fluid temperature. As the OTSG and hot leg fluid temperatures crossed at approximately 38 minutes after rupture, the affected OTSG became an additional 5-117 I

I heat source instead of a heat sink, and the affected OTSG was slowly cooled by the E

decreasing primary coolant system flow in the affected loop. This caused the loss of 5 natural circulation driving head discussed earlier in relation to Figure 5-6.5.

The cold leg temperature upstream of the pumps in the affected loop folloaed the OTSG temperature.

Figure 5-6.10 shows the core outlet subcooling margin. The subcooling margin reflected changes in the primary system pressure and hot leg temperature. The subcooling was controlled by the operator recovery actions. The minimum subcool-ing margin observed in this transient was approximately IF*. No voiding resulted in the RCS in this transient except in the pressurizer and upper head.

Figure 5-6.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remaining at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in this region. The pressure in the upper head reached the local saturation pressure at approximately 9 minutes after transient initiation. When the pressure reached the saturation pressure, the fluid in the upper head flashed and a steam bubble formed.

Figures 5-6.12 through 5-6.20 show the calculated flows into and out of the Loop A g and loop B secondary systems. Figure 5-6.21 shows the OTSG A and B indicated sec- E ondary levels. Figure 5-6.22 shows the pressure behavior in the two OTSGs. These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shonn) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure g caused the safety valves, the modulating atmospheric dump valves (MADVs), and tur- 5 bine bypass valves (T8Vs) to cycle. The early pressure response in the secondary was in turn controlled by these valve actions. Fourteen seconds after scram, the emergency feedwater system (EFW) was actuated. This system was effective in re-ducing secondary pressure, as it consisted of water at approximately 90*F which I

5 wa4 sprayed into the OTSG. The EFW system also helped increase the level in each of the two OTSGs. Because of the presence of the break in the Loop A OTSG, the level increase rate was higher in OTSGA than in OTSGB. The level in OTSGA reached the 95% operating range level setpoint at 19.2 minutes after transient initiation. The MADVs cycled to maintain this set point. Prior to the OTSGB level reaching 95%, subcooling margin was restored, and the level setpoint dropped to 50% operating range. Since the level in OTSG-B was above 50% when subcooling margin was restored, EFW terminated as soon as subcooling margin was restored.

5-118 I

I After the continuous EFW flow was terminated, the temperature and pressure in the OTSGs increased. In the B OT5G, as the pressure crossed the target pressure, the T8V opened while the EFW system cycled to maintain level at the desired level.

The result of these actions was a cooldown of the unaffected 0TSG which closely approximates the desired cooldown. The analysis was terminated at 45.79 minutes after rupture with the primary system pressure below the secondary relief pressure setpoint and with the plant in a stable operating mode. At the end of the simula-tion, adequate subcooling margin was available, and the plant was being brought to a cold shutdown in a controlled manner. At no time during the simulation did a fuel rod cladding heatup occur.

Comparison of this case and case 2 (Section 5.2) show that for a single ruptured tube, a stuck open PORV causes a more rapid initial depressurization and cooldown I rate and a temporary loss of subcooling. However, over the course of the transient, the stuck open PORV has little effect on the system recovery. It simply increases the primary system losses that have to be made up with HPI flow.

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5-120 I

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5-123 I

@ SINGLE TUBE RUPTURE CASE 11 i i i i i i i g 1 RCS FLOW RATE (LOOP B LOOP)

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g SINGLE TUBE RUPTURE PASE 11 8 I i i i T'- 1 i I (1) LOOP A OTSG SATURATION TEMPERATURE (2) LOOP A COLD LEG DOWNSTREAM OF PUMPS r (3) LOOP A COLD LEG UPSTREAM OF PUMPS L

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[ 5-127

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5-135

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l g in l SINGLE I I TUBEI RUPTURE CASE 11 I I I I I I o

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Figure 5-6.20. OTSGB TBV Flow I

5-139 I

SINGLE TUBE RUPTURE CASE 11 I

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Figure 5-6.21. OTSG Downcomer Indicated Level 5.ao I I

g SINGLE TUBE RUPTURE CASE 11 g i i i; i i i i i i i l

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Figure 5-6.22. Steam Generator Pressure 5-141 I

I Section 6 TEN TUBE RUPTURE CASES I 6.1 GENERAL This section describes the results of five analyses considering the rupture of ten tubes in one steam generator (see Table 6-1.1). The nodalization scheme used for these cases is identical to the benchmark model described in Section 4 except for

]

Case 8 where the ruptures take place at the bottom of the OTSG.

The termination criteria used to end the analysis were the sane as used for the single tube break (see Section 5.1).

I Appendix B presents a fuel clad tercerature versus time plot for each of the ten tube cases.

I I

I l

6-1 I

Table 6-1.1 TEN TUBE RUPTURE CASES Number Case of Pump Trip Other Criterion . Assumptions Remarks No. Tubes 20F* subcooling Baseline ten tube rupture cases 4 10-015GA 0F* subcooling Effect of less restrictive pump trip 5 10-0TSGA criterion 10-0TSGA 20F* subcooling Continue steaming OTSGA Compare two SGTR procedures (isolation 6

versus steaming) 20F* subcooling Ruptures at bottom of 0TSG Effect of different rupture location 8 10-0TSGA 1

9 10-0TSGA 20F* subcooling Failure of water level indica- Effect of overfilling the OTSG

[ tion and control Note: For all cases except case number 8, tube ruptures are modeled as occurring at the top of the OTSG.

l M M M M M M M M M M M . m a

I 6.2 TEN TUBE RUPTURE CASE 4 l This case represents rupture of ten tubes in OTSG-A with pump trip postulated to occur 0.5 minutes after the loss of 20F' subcooling margin. It is the baseline ten tube rupture case.

Table 6-2.1 shows the sequence of events for this calculation. Figure 6-2.1 shows I the flow rate through the two ends of the ruptured tubes. As in the single tube rupture cases, there was more flow through the upper than lower ends of the ruptured tubes. The flow through oath ends of the tubes was relatively constant up until scram, which occurred at 0.78 minutes after rupture. After scram, the break flow reflected the changes in the primary pressure, primary-to-secondary I differential pressure, and density changes due to temperature changes in the affected loop. The flow through the upper ends of the ruptured tubes was calculated to become unchoked at 0.84 minutes after rupture.

Figures 6-2.2 and 6-2.3 show the pressurizer indicated level and core outlet I pressure, respectively. The operatcr had an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure as a result of the break. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result I of the decreasing primary system pressure, the pressurizer heaters were energized however, they could not keep up with the effects of the break. Moreover, the breakers were deenergized when the pressurizer indicated level fell below 5.2 inches to protect the electrical heaters from burn-out. Because of the decreasing pressurizer level, the makeup pump increased flow. However, one makeup pump, at full capacity, could not replace all of the water being lost from the I primary, so the level continued to decline. The operator would have received a high makeup flow alarm at 0.11 minute after rupture. The RCS pressure reached the low pressure scram setpoint at 0.78 minutes after rupture. After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp I drop in average primary system temperature. The long-term pressurizer level and primary system pressure response reflect changes in the primary system inventory brought about by the operator recovery actions that began 5 minutes after scram.

I I

6-3 I

Table 6-2.1 SEQUENCE OF EVENTS FOR TEN TUBE RUPTURE CASE 4 Time After Rupture I

Event (Minutes)

Simultaneous Rupture of Ten Steam Generator Tubes 0.00 Pressurizer Heaters On 0.05 High Makeup Flow Alarm 0.11 Reactor Automatic Scram (RCS Pressure <1900 psia) 0.78 MFWPs Trip at Scram 0.78 Turbine Trip at Scram 0.78 MADVs and MSSVs lift 0.86 Full HPI Initiation (RCS Pressure <1600 psia) 1.06 EFW Flow Begins 1.61 Subcooling Margin Drops Below 20F* 3.19 Operator Trips Reactor Coolant Pumps 3.69 30 Seconds After Loss of 20F' Subcooling Margin Operator Initiates Manual RCS Cooldown 5.78 Maximum Net RCS Outflow Reached, Refill Begins 13.14 OTSG A Reaches 9C% Operating Range, Loop A EFW 13.75 g Terminated, Locp A MADV opened E

OTSG B Reaches 95% Operating Range, Loop B EFW 31.91 Flow Begins Cycling to Maintain Leve Subcooling Margin Exceeds 20*F, HPI Throttled 32.62 E

3 Analysis Termination Criteria Reached 44.75 I

Figures 6-2.4 and 6-2.5 show the reactor power and the hot leg flow rates for each loop. Prior to scram, the break caused the reactor power to decrease due to changes in the fluid density and temperature. It was postulated that the operator tripped the primary coolant pumps 0.5 minutes after the hot leg subcooling margin reached 20F'. Since the subcooling margin reached this level at 3.19 minutes after rupture, the primary coolant pumps were tripped at 3.69 minutes after rup-ture. After pump trip, the flow rates in the individual loops quickly approached stable single-phase natural circulation flow rate levels, but natural circulation was eventually lost in both loops. While flow in Loop B ceased, flow in the hot leg of Loop A continued due to injection flow into the system and flow out through the ruptured tubes in OTSGA. In addition, independent of loss of natural e.. I

I circulation, MADVs for OTSGA were opened at 13.75 minutes to maintain the water level in OTSGA below 95% of the operating range.

I Figure 6-2.6 shows the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. When the pressure reached the HPI initiation set-point of 1600 psia at 1.06 minutes after rupture, full HPI was initiated by auto-matic safety system action. After recovery began at 5.78 minutes, 5 minutes after scram, it was postulated that the operator would take manual actions to bring the plant to a cold shutdown condition. These manual actions would include throttling HPI and using the PORV to control subcooling margin. Because of the loss of 20F*

wbcooling margin, these manual control actions did not occur until subcooling was restored at 32.62 minutes. The necessary subcooling margin (50F') to open the PORV was not reached during the time of this simulation. Figure 6-2.6 shows that after 13.14 minutes into the transient, HPI flow into the primary system exceeded the flow out of the system through the ruptured tubes and remained so for most of the remainder of the transient.

I Figure 6-2.7 shows the integrated flow rates into and out of the primary coolant system. At 13.14 minutes the primary coolant system inventory had decreased by 26687 lbm but thereafter was restored steadily.

Figures 6-2.8 and 6-2.9 show the Loop A and B fluid temperatures in the hot and I cold legs as well as in the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged and then diverged as the RCS pumps tripped and coasted down. The fluid temperature in the cold legs upstream of the primary coolant pumps are typically within a few degrees of the OTSG saturation temperature under natural circulation conditions. The cold leg fluid temperature downstream of the primary coolant pumps was considerably colder than the fluid upstream of the pumps due to the combination of the addition of lower temperature HPI fluid and the low loop flow rate. As natural circulation in Loop B was lost, the cold leg temperatures diverged from the OTSG saturation temperature. The sudden changes in RCS cold leg temperatures occur due to flow direction changes.

Figure 6-2.10 shows the affected loop hot leg subcooling margin. Subcooling was lost at approximately 5 minutes after rupture and was restored at approximately 25 minutes after rupture.

I I e-s I

Figure 6-2.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the upper head region was modeled as a dead-end region connected to the upper plenum of the reactor vessel. The fluid temperature in this region of the reactor vessel did not respond to changes in upper plenum fluid temperature. This resulted in the fluid in this region remaining at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in this region. This occurred at approximately 5 minutes after transient initiation. When this occurred, the fluid in the upper head region flashed.

Figures 6-2.12 and 6-2.20 show the calculated flows into and out of the Loop A and Loop B secondary systems. Figure 6-2.21 shows the OTSG A and B indicated secondary levels. Figure 6-2.22 shows the pressure behavior in the two OTSGs.

These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure caused the safety valves, the modulating atmospheric dump valves (MADVs), and tur-bine bypass valves (TBVs) to cycle. The early pressure response in tle secondary was in turn controlled by these valve actions. Fourteen seconds after scram, the emergency feedwater system (EFW) was actuated. This system was effective in reducing secondary pressure, as it consisted of water at approximately 90'F which was sprayed into the OTSG. The EFW system also helped increase the level in each of the two OTSGs. Because of the presence of the break in the Loop A OTSG, the level increase rate was somewhat higher in this OTSG. Since subcooling margin was lost, the level setpoint was raised to 95% operating range level setpoint. The EFW flow was terminated when the level exceeded 95% operating range and was restarted when the level dropped below the 95% setpoint. After the EFW flow was terminated, the temperature and pressure in the Loop B OTSG increased.

It was postulated that in an attempt to keep the OTSG from overfilling, the operator would open the Loop A MADVs if the Loop A OTSG indicated level exceeded 95% of the operating range. The Loop A MADVs were opened 13.75 minutes after rupture.

Figures 6-2.23 and 6-2.24 ',how ' snapshots' of the calculated liquid temperature and void fraction distri>,utions near the time of minimum RCS mass inventory. At this time, there is li*.tle circulation in either loop, and voids exist in the hot legs and upper portio.ts of the reactor vessel. Na voiding occurred in the core region.of the reacter vessel.

6-6 I

Figures 6-2.25 and 6-2.26 show ' snapshots' of the calculated liquid temperature and void fraction distributions at the end of the simulation. At this time, subcooling margin had been restored and natural circulation flow was about to be restored in the unaffected loop. Natural circulation in the affected loop is inhibited due to the lack of thermal driving head, and flow in this loop is by feed and bleed. The level in the pressurizer was being restored, the ECC flos exceeded the break flow, the primary system pressure was belos the secondary relief pressure setpoint and was decreasing. At the end of the simulation, the plant was being brought to cold shutdown in a controlled manner. At no time I during the simulation did a fuel rod cladding heatup occur.

This case demonstrates that the plant can be cooled down safely with severe primary-to secondary leaks even with the reactor coolant pumps tripped.

I I

I 6-7

g TEN TUBE RUPTURE CASE 4 )

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o TEN TUBE-RUPTURE CASE 4

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I g 6 I i TEN TUBE RUPTURE CASE 4 I i i I I i i I NOTE - ABRUPT CHANGES IN COLD LEG TEMPERATURE CORRESPOND TO FLOW OIRECTION CHANGES I o g -

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-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

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,I 6-15 l

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-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

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6-18 I

I g TEN TUBE RUPTURE CASE 4 I

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I' g TEN TUBE RUPTURE CASEi 4 a m I I i i i I i I g 8, -

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6-21 I

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6-25

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I 6-28 I

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6-33 mm m

6.3 TEN TUBE RUPTURE CASE 5 This case represents a rupture of ten tubes in OTSGA with pump trip postulated to occur whenever the hot leg subcooling margin decreased below 0F' following a decrease in primary pressure below 1600 psia. Case 5 was run to show the effect of a less restrictive pump trip criterion than was used in Case 4.

Table 6-3.1 shows the sequence of events for this calculation. Figure 6-3.1 shows the flow rate through the two ends of the ruptured tubes. As before, there was more flow through the upper ends of the ruptured tubes. The flow through both ends of the tubes declined with the declining RCS pressure until scram, which occurred at 0.78 minutes after rupture. After scram, the break flow declined even more rapidly, reflecting the changes in the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loco.

Figures 6-3.2 and 6-3.3 show the pressurizer indicated level and core outlet pressure, respectively. The operator would have an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure as a result of the break. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result of the decreasing primary system pressure, the pressurizer heaters were energized however, they could not keep up with the effects of the break. Moreover, the heaters were deenergized when the pressurizer indicated level fell below 5.2 inches and the pressure continued to decline. Because of the decreasing pressurizer level, the makeup pump increased its flow however, one makeup pump, at full capacity, could not replace all of the water being lost from the primary, so the level continued to decline. The operator would have received a high makeup flow alarm at 0.11 minutes after rupture. The RCS pressure reached the low pressure scram setpoint at 0.78 minutes after rupture. After scram occurred, there was an even faster decline in pressurizer level and pressure because of the sharp drop in average primary system temperature. At 3.2 minutes after rupture, the HPI flow exceeded the break flow, and the decline in pressurizer indicated level ceased. The long-term pressurizer level and primary system pressure g response reflect changes in the primary system liquid inventory brought about by 3 the operator recovery actions which were postulated to begin 5 minutes after scram.

6-34 I

I Table 6-3.1 SEQUENCE OF EVENTS FOR TEN TUBE RUPTURE CASE 5 I Event Time After Rupture (Minutes) g Simultaneous Rupture of Ten Steam Generator Tubes 0.00 W High Makeup Flow Alarm 0.11 Reactor Automatic Scram (RCS Pressure <1900 psia) 0.78 P:WPs Trip at Scram 0.78 Turbine Trip at Scram 0.78 I MADVs and MSSVs Lift Full HPI Initiation (RCS Pressure <1600 psia) 0.86 1.07 EFW Flow Begins 1.61 Subcooling Margin Drops Below 20F* 3.20 Operator Initiates Manual RCS Cooldown 5.78 I Maximum Net RCS Outflow Reached, Refill Begins Locj B EFW Flow Begins Cycling to Maintain Level 6.24 14.22 OTSGA Reaches 95% Operating Range, MADV flow begins 19.79 Subcooling Margin Exceeds 20F*, HPI Throttled 22.43 Analysis Termination Criteria Reached 27.02 I Figures 6-3.4 and 6-3.5 show the reactor power and hot leg flow rates for each loop. Prior to scram, the reactor power declined due to changes in the RCS fluid temperature. For this transient, it was postulated that the operator would trip the primary coolant pumps when the subcooling margin reached 0F*. This condition was never reached during this transient, so the reactor coolant pumps were never tripped.

I Figures 6-3.6 and 6-3.7 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. When the pressure reached the HPI initiation setpoint of 1600 psia at 1.07 minutes after rupture, full HPI was initiated by automatic safety system action. It was postulated that after recovery began at 5.78 minutes, the operator would take manual actions to bring the plant to a cold shutdown condition. These actions would include throttling I HPI and using the pressurizer spray to control subcooling margin. It was assumed that the pressurizer spray system would be used in preference to the PORV if the reactor coolant pumps were running. Pressurizer spray was to be initiated when 6-35 l

the subcooling margin reached 50F', 5 minutes had elapsed, and the pumps were running. It was to be terminated if the subcooling margin dropped to 25F'. The spray initiation criteria were not reached during this simulation. The HPI was throttled slightly toward the end of the simulation when subcooling margin reached 20F*.

Figure 6-3.7 shows the integrated flow rates into and out of the primary coolant system. For most of the period the integrated flow was negative, indicating that more water had been lost from the primary coolant system than had been added. The inventory loss reached a maximum of 23,500 lbm at 3.3 minutes after rupture, at which time flow into the loop exceeded flow out.

Figures 6-3.8 and 6-3.9 show the Loop A cnd B fluid temperatures in the hot and cold legs as well as in the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged as the power removal requirements diminished.

Figure 6-3.10 shows the affected loop hot leg subcooling margin. The subcooling margin reflected changes in the primary system pressure and hot leg temperature.

The subcooling was controlled by the operator recovery actions. ThJ minimum sub-cooling margin observed in this transient was approximately 2F', which occurred after scram.

Figure 6-3.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remained at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the 5 fluid in the upper head. This occurred at approximately 1.26 minutes after 3 transient initiation. During this transient, voiding occurred only in the pressurizer and upper head.

Figures 6-3.12 through 6-3.20 show the calculated flows into and out of the Loop A g and Loop B secondary systems. Figure 6-3.21 shows the OTSGA and B indicated 5 secondary levels. Figure 6-3.22 shows the pressure behavior in the two OTSGs.

These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure g caused the safety valves, the modulating atmospheric dump valves (MADVs), and 5 turbine bypass valves (TBVs) to cycle. The early pressure response in the secondary was, in turn, controlled by these valve actions. It was postulated that 6-36

the operator would open the OTSG MADVs if the OTSG indicated level exceeded the 95% operating range level, and would open the OTSG TBVs if the OTSG pressure exceeded the target pressure. Fourteen seconds after scram, the emergency feedwater system (EFW) wss enabled. When the reactor coolant pumps are running, I the OTSG level setpoint is at 30 inches. When the OTSG level dropped below the level setpoint, the EFW flow began and was terminated when the level exceeded the level setpoint. In the A OTSG, the level was allowed to increase through leak flow. The level was limited to 95% of the operating range by the MADVs which opened at about 20 minutes, and remained open for the remainder of the simulation.

In the B OTSG, the TBVs were opened as the pressure crossed the target pressure, while the EFW system cycled to maintain the desired water level. The result of these actions was a cooldown of the unaffected 0TSG which closely approximates the desired cooldown.

The analysis was terminated at 27.02 minutes after rupture, with the primary sys-tem pressure below the secondary relief pressure setpoint and with the plant in a stable operating mode. At the end of the simulation adequate subcooling margin was available, and the plant was being brought to cold shutdown in a controlled manner. At no time during the simulation did a fuel rod cladding heatup occur.

Comparing this case and Case 4 for the rupture of ten tubes in one steam generator, it can be seen that continued operation of reactor coolant pumps and use of pressurizer spray provided a more rapid plant cooldown than occurred when I the pumps were tripped and prevented the loss of subcooling. Moreover, maintaining forced circulation provided a symmetric cooldown of both loops and limited voiding to the pressurizer and the upper head of the reactor vessel.

This case highlights the improved plant control that results from applying a putrp trip criterion that does not require tripping the pumps and allows pressurizer spray to be available throughout the transient.

6-37

m TEN TUBE RUPTURE CASE 5 I

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L 7 g TEN TUBE RUPTURE CASE 5 L m i I I I I I I

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6-39

g TEN TUBE RUPTURE CASE 5 ,

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6-41

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g TEN TUBE RUPTURE CASE 5 in i I I i i 1 I -----

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Figure 6-3.7. Integrated Flows Into and Out of RCS 6-44 I

g TEN TUBE RUPTURE CASE 5 N I I I I I I LOOP A OTSG SATURATION TEMPERATURE I LOOP A COLD LEG 00WNSTREAM OF PUMPS LOOP A COLD LEG UPSTREAM OF PUMPS -"

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6-45 I

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I g TEN TUBE RUPTURE CASE 5

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I - -

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w E g TEN TUBE RUPTURE CASE 5

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6-54 I

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5-56 I

@ TEN TUBE RUPTURE CASE 5 I i 1 1 I

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Figure 6-3.21. OTSG Downcomer Indicated Level l

I 6-58 I

g TEN TUBE RUPTURE CASE 5 i i i i i g e i

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-5 0 5 10 15 20 25 30 TIME AFTER RUPTURE (MINUTES)

Figure 6-3.22. Steam Generator Pressure I

6-59

I 6.4 TEN TUBE RUPTURE CASE 6 Case 6, which is the same as Case 4 except for the OTSGA steaming controls, simu-lates the rupture of ten tubes in OTSGA, with pump trip postulated to occur 0.5 minutes after the loss of 20F' subcooling margin. Case 6, unlike Case 4, continues steaming OTSGA rather than isolating the generator. This case shows the effects of using an alternate operating procedure in response to steam generator tube ruptures.

Table 6-4.1 shows the sequence of events for this calculation. Figure 6-4.1 shows the flow rate through the two ends of the ruptured tubes. As before, there was more flow through the upper ends of the ruptured tubes. The flow through both ends of the tubes was relatively constant up until scram, which occurred at Table 6-4.1 SEQUENCE OF EVENTS FOR TEN TUBE RUPTURE CASE 6 Time After Rupture Event (Minutes)

Simultaneous Rupture of Ten Steam Generator Tubes 0.00 Pressurizer Heaters On 0.05 High Makeup Flow Alarm 0.11 Reactor Automatic Scram (RCS Pressure < 1900 Psia) 0.78 MFWPs Trip at Scram 0.78 Turbine Trip at Scram 0.78 MADVs and MSSVs Lift 0.86 Full HPI Initiation (RCS Pressur,e < 1600 Psia) 1.07 EFW Flow Begins 1.6 Subcooling Margin Drops Below 20'F 3.15 Operator Trips Reactor Ceolant Pumps 3.65 30 Seconds After loss of 20*F Subcooling Margin Operator Initiates Manual RCS Cooldown 5.78 OTSG A Reaches 95% Operating Range, 13.75 Loop A EFW Terminated, Loop A MADV opened 0TSG B Reaches 95% Operating Range, 33.33 Loop B EFW Flow Begins Cycling to Maintain Level Subcooling Margin Exceeds 20*F, HPI Throttled 33.51 Analysis Termination Criteria Reached 33.51 6-60

I 0.78 minutes after rupture. After scram, the break flow reflected the changes in the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop. The flow through the upper ends of the ruptured tube was calculated to become uncheked at 0.84 minutes after rupture.

4 -

Figures 6-4.2 and 6-4.3 show tbo pressurizer indicated level and core outlet pressure, respectively. The operator had an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure as a result ci the break. In the case of a tube rupture, the operator would have also received signals from air efector radiation monitors. As a result of the decrtasing primary syste.r. pressure, the pressurizer heaters were energized however, they could not keep up with the effects of the break. The heaters were deenergized when HPI was initiated. Because of the decreasing pressurizer level, the makeup pump increased its flow however, one makeup pump, atfullcapacity,couldnotreplacealloflhewaterbeinglostfromtheprimary, so the level continued to decline. The_ operator would have received a high makeup flow alarm at 0.11 minute after rupture. The RCS pressure reached the low pressure scram setpoint at 0.78 minutes after rupture. After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp drop in averace primary system temperature. The long-term pressurizer level and I primary system pressure response reflect changes in the primary system inventory brought about by the operator recovery actions that began 5 minutes after scram.

I Figures 6-4.4 and 6-4.5 show the reactor power and the hot leg flow rates for each loop. Prior to scram, the break caused the reactor power to decrease due to I

I changes in the fluid density and temperature. It was postulated that the operator tripped the primary coolant pumps 0.5 minutes after the hot leg subcooling margin i reached 20*F. Since the subcooling margin reached this level at 3.15 minutes after rupture, the primary coolant pumps were tripped at 3.65 minutes after rupture.

After pump trip, the flow rates in the individual loops quickly approacted stible single-phase natural circulation flow rate levels, but natural circulation was eventually lost in both the unaffected and the affected loops. However, before Loop A temperatures reached levels that would indicate loss of natural circulation l (see Section 3.3) and actuate opening of MADVs, the MADVs for OTSGA were opened at 14.3 minutes to maintain the water level in OTSGA below 95% of the operating range.

i 6-61

The OTSGB MADVs were opened at 16.6 minutes in response to the loss of natural circulation in loop B (hot leg temperature exceeds cold leg temperature by more than50*F). However, because the temperature difference between OTSGB and the core outlet was greater than 49'F, the MADVs were opened only briefly.

Figure 6-4.6 shows the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. When the pressure reached the HPI initiation setpoint of 1600 psia at 1.07 minutes after rupture, full HPI was initiated by automatic safety system action. After recovery began at 5.78 minutes, 5 minutes after scram, it was postulated that the operator would take manual actions to bring the plant to a cold shutdown condition. These actions included throttling HPI and using the PORV to control subcooling margin. Because of the loss of 20*F subcooling margin, these manual control actions did not occur. The necessary subcooling margin to open the PORV was not reached during the time of this simulation. Figure 6-4.6 shows that at 3.4 minutes into the transient, HPI flow into the primary system exceeded flow out of the system through the ruptured tubes. Figure 6-4.7 shows the integrated flow rates into and out of the primary coolant system. At the end of the calculation, the system inventory had decreased by 29,000 lbm.

Figures 6-4.8 and 6-4.9 show the Loop A and B fluid temperatures in the hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged and then diverged as the RCS pumps tripped and coasted down. The fluid temperature in the cold legs upstream of the primary coolant pumps are typically within a few degrees of the OTSG saturation temperature under natural circulation conditions. The cold leg fluid temperature downstream of the primary coolant pumps is usually colder than the fluid upstream of the pumps due to the addition of lower temperature HPI fluid.

As natural circulation in the loops was lost, the cold leg temperatures diverged from the OTSG saturation temperature. The sudden changes in RCS cold leg I

5 temperature occur due to flow direction changes. E l

l Figure 6-4.10 shows the core outlet subcooling margin. Subcooling was lost at approximately 5 minutes after rupture. Figure 6-4.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remained at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in th,is region. This occurred at approximately 1.2 minutes after transient initiation. When the pressure reached l

6-62

L

[ the saturation pressure, the fluid in the upper head region flashed and a steam bubble formed.

L Figures 6-4.12 through 6-4.20 show the calculated flows into and out of the Loop A and Loop B secondary systems. Figure 6-4.21 shows the OTSGA and B indicated secondary levels. Figure 6-4.22 shows the pressure behavior in the two OTSGs.

These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure caused the safety valves, the modulating atmospheric dump valves (MADVs), and

{ turbine bypass valves (TBVs) to cycle. The early pressure response in the secondary was in turn controlled by these valve actions. It was postulated that the operator would open the OTSG MADVs if the OTSG indicated level exceeded the 95% operating range level, and would open the OTSG TBVs if the OTSG pressure exceeded the target pressure. Fourteen seconds after scram, the emergency feedwater system (EFW) was actuated. This system was effective in reducing secon-r dary pressure, as it consisted of water at approximately 90'F which was sprayed into the OTSG. The EFW system also helped increase the level in each of the tv.o OTSGs. Because of the presence of the break in the Loop A OTSG, the level in-crease rate was higher in this OTSG. Since subcooling margin was lost, the level

{ setpoint was raised to 95% operating range level setpoint. The EFW ficw was term-inated when the level exceeded 95% operating range and was restarted when the level dropped below the 95% setpoint. After the EFW flow was terminated, the temperature and pressure in the Loop A OTSG increased. Continued steaming of OTSGA caused significant heat removal from OTSGB and a pressure response in OTSGB

{ that was far below the target pressure. The large difference between the steam generator pressure and the target pressure caused a reduction in EFW flow to OTSGB.

The calculation was terminated at 33.51 minutes after rupture. At this time, the

{ primary system pressure was below the pressure setpoint of the secondary relicf valve, the OTSGB level was approaching 95%, the OTSGB pressure was returning to the target pressure, and the OTSGA pressure was closely following the target pressure.

[

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6-63

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6-68 l

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g TEN TUBE RUPTURE CASE 6 rs i I i i 1 1 (D t OOP B OTSG SATURATION TEMPERATURE .

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6-72 l

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6-73

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6-76 I

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6-77

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g TEN TUBE RUPTURE CASE 6 to I i I I I i 1

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I g TEN TUBE RUPTURE CASE 6 in I i i i i 1 i

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g TEN TUBE RUPTURE CASE 6 in i i i a i i I e -

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I g TEN TUBE RUPTURE CASE 6 to 1 I I l l l 1 g 8 -

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TEN TUBE RUPTURE CASE 6 I

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6-84 I

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TUBE RUPTURE CASE 6 i i i a o

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Figure 6-4.22. Steam Generator Pressure I

I 6-85 I

I 6.5 TEN TUBE RUPTURE CASE 8 Case 8 simulates the rupture of ten tubes at the bottom of OTSGA. Pump trip occurs when the subcooling margin at the core outlet is less than 20F'. This case shows the effects of ruptures at the bottom of the steam generator.

Table 6-5.1 shows the sequence of events for this calculation. Figure 6-5.1 shows g the flow rate through the two ends of the ruptured tubes. Since the tube ruptures 3 were postulated to occur at the top of the lower tube sheet, the flow resistance of the lower end of the ruptured tubes was less than for the upper end, resulting in more flow from the lower ends of the ruptured tubes. The flow through both ends of the tubes was relatively constant up until scram, which occurred at E

0.66 minutes after rupture. After scram, the break flow reflected the charges in 3 the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop.

Table 6-5.1 I

SEQUENCE OF EVENTS FOR TEN TUBE RUPTURE CASE S Event Time After Rupture (Minutes)

Simultaneous Rupture of Ten Steam Generator Tubes 0.00 High Makeup Flow Alarm 0.09 Reactor Scram (RCS Pressure <1900 psi) 0.66 Turbine and Main Feedwater Pumps Tripped 0.66 MADVs and MSSVs Lift 0.70 Full HPI Initiation (RCS pressure <1600 psi) 0.94 EFW Flow Begins 0.89 g Subcooling Margin Drops Below 20F 3.69 5 Operator Trips Reactor Coolant Pumps 4.19 Opt.rator Initiates Manual RCS Cooldown 5.66 OTSGA Level Reaches 50% Operating Range, 14.0 EFW Flow Begins Cycling to Maintain Level MADV Flow Begins Cycling to Maintain Level Operator Notes Loss of Natural Circulation in 17.6 Loop B, Opens MADVs Analysis Termination Criteria Reached 41.12 I

6-86

Figures 6-5.4 and 6-5.5 show the reactor power and hot leg flow rates for each loop. Prior to scram, the break had little influence on the raattor power since the net mass that left the system was small. The primary coolant pumps were tripped on loss of 20F' subcooling margin. After pump trip, the flow rates in the individual loops quickly approached stable single-phase natural circulation flow rates. EFW flow to the affected 0TSG was terminated when the level reached the 95% operating range level setpoint at 14 minutes after rupture. The setpoint was, at 95% operating range because subcooling margin was lost. After feedwater flow terminated, the temperature and pressure in the affected 0TSG increased. At I 17.6 minutes after rupture, the Loop B hot leg temperature exceeded the cold leg temperature by 50F', indicating loss of natural circulation (see Section 3.3).

After the loss of natural circulation was detected in Loop B, it was postulated that the operator would begin to take corrective actions to restore the natural circulation flow rate in that loop.

Figures 6-5.6 and 6-5.7 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. The control system automatically initiated full HPI when the primary pressure dropped below 1600 osi. Recovery was assumed to begin at .66 minutes, 5 minutes after scram. Because subccoling margin was lost, HPI was not throttled. Figure 6-5.6 shows that 15 ninutes into the transient, HPI flow into the primary coolant system exceeded the floa' out of the system through the ruptured tubes and remained greater for the remainder of the transient.

I Figures 6-5.8 and 6-5.9 shoa the Loop A and B fluid temperatures in the hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged and then diverged as the RCS I pumps tripped and coasted down. The fluid temperatures in the cold legs upstream of the primary coolant pumps are typically within a few degrees of the OTSG saturation temperatures under natural circulation conditions. The cold leg fluid temperature downstream of the primary coolant pumps is ust ally colder than the fluid upstream of the pumps due to the addition of lower temperature HPI fluid.

Figure 6-5.10 shows the core outlet subcooling margin. The subcooling margin reflected changes in the primary system pressure and hot leg temperature. The subcooling was controlled by the operator recovery actions. The minimum subcooling margin observed in this transient was 0F', indicating voiding at the I core outlet.

6-87

Figure 6-5.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remained at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in this region. This occurred at approxir.ately 0.9 minutes after transient initiation.

Figures 6-5.12 through 6-5.20 show a summary of the calculated flows into and out of the Loop A and Loop B secondary systems. Figure 6-5.21 shows the OTSG A and B indicated secondary levels. Figure 6-5.02 shows the pressure behavior in the two OTSGs. These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased pressure caused the safety valves, the modulating atmospheric dump valves (MADVs),

and turbine bypass valves (T8Vs) to cycle. The early pressure response in the secondary was in turn controlled by these valve actions. Fourteen seconds after scram, the emergency feedwater system (EFW) was actuated. This system was effec-tive in reducing secondary pressure, as it consisted of water at approximately 90'F which was sprayed into the OTSGs. The EFW system also helped increase the level in each of the two OTSGs. Because of the presence of the break in the Loop A OTSG, the level increase rate was somewhat higher in this OTSG and reached the 95% operating range level setpoint at 9 minutes, whereas the level setpoint was not reached in loop B. The EFW flow was terminated when the level exceeded 95%

operating range and was restarted when the level dropped below the 95% setpoint.

After the continuous EFW flow was terminated, the temperature and pressure in the OTSGs increased. In the affected OTSG, the MADVs cycled to maintain level. In the OTSGB, the MADV opened briefly in response to the loss of natural circulation in loop B, while the EFW system remained on to achieve the desired level.

The analysis was terminated at 41.12 minutes after rupture with the primary system pressure below the secondary relief pressure setpoint and decreasing. At the end of the simulation, adequate subcooling margin was available.

A comparison of this case, Case 8, with the baseline ten tube rupture case, Case 4 discussed in Section 6.2, show that changing the location of the ten tube ruptures from the top of the steam generator to the bottom of the steam generator had little effect on the plant response.

I 6-88

I g . TEN TUBE RUPTURE CASE 8 N

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6-89 I

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6-90 I

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o TEN TUBE RUPTURE CASE i 8

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6-92 I

g i i TEN TUBE RUPTURE CASE 8 i i i i 1 i RCS FLOW RATE (LOOP B LOOP)

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6-93 lI

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I 6-94 I

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[ 6-95

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g TEN TUBE RUPTURE CASE 8 6 i i i i i i i i i CD LOOP B OTSG SATURATION TEMPERATURE (2) LOOP B COLD LEG DOh'NSTREAM OF PUMPS (3) LOOP B COLD LEG UPSTREAM OF PUMPS (4) LOOP B HOT LEG o

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I 6-97

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6-103

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6-104 4

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6-108 l

I g TEN TUBE RUPTURE CASE 8 I i I i l

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Figure 6-5.22. Steam Generator Pressure I

6-110

6.6 TEN TUBE RUPTURE CASE 9 Case 9 simulates the rupture of ten tubes in OTSGA and the failure of water level control in OTSGA. Pump trip occurs on loss of 20F' subcooling margin. The purpose of this case is to show the effect of overfilling OTSGA.

Table 6-6.1 shows the sequence of events for this calculation. Figure 6-6.1 shows the flow rate through the two ends of the ruptured tubes. As in the other cases with the rupture location near the top of the OTSG, there was more flow through the upper ends of the ruptured tubes. The flow through both ends of the tubes was relatively constant up until scram, which occurred at 0.78 minutes after I rupture. After scram, the break flow reflected the changes in the primary pressure, primary-to-secondary differential pressure, and density changes due to temperature changes in the affected loop.

Table 6-6.1 SEQUENCE OF EVENTS FOR TEN TUBE RUPTURE CASE 9 Time After Rupture Event (Minutes)

Simultaneous Rupture of Ten Steam Generator Tubes 0.00 High Makeup Flow Alarm 0.11 Reactor Scram (RCS Pressure <1900 psi) 0.78 Turbine and Main Feedwater Pumps Tripped 0.78 MADVs and MSSVs Lift 0.82 EFW Flow Begins 1.01 Full HPI Flow (RCS Pressure <1600 psi) 1.06

! Operator Trips Reactor Coolant Pumps 30 Seconds 3.44 After Loss of 20F* Subcooling Margin

g Operator Initiates Manual RCS Cooldown 5.78 l 5 Operator Notes Loss of Natural Circulation in 14.6 Loop B, Opens MADVs l OTSGA Isolated (Hot Leg Temperature <540*F) 19.3 Operator Throttles HPI When Subcooling Margin Exceeds 20F' 21.2 OTSGB Level Reaches 50% Operating Range, 54.5 l EFW Flow Begins Cycling to Maintain Level OTSGB Pressure Exceeds Target Pressure, TBVs Opened 56.3 l Analysis Termination Criteria Reached 56.8 lI 6-111 l

l

I Figures 6-6.2 and 6-6.3 show the pressurizer indicated level and core outlet pressure, respectively. As a result of the break, the operator had an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result of the decreasing primary system pressure, the pressurizer heaters were energized however, they could not keep up with the effects of the break, and the pressure continued to decline. Because of the decreasing pressurizer level, the makeup g flow increased however, the makeup pumps, at full capacity, could not replace all g of the water being lost from the primary, so the level continued to decline. The operator would have received a high makeup flow alarm at 0.11 minuces af ter rup-ture. The control system automatically scrammed the plant when RCS pressure dropped below 1900 psi and initiated full HPI flow when RCS pressure dropped below 1600 psi. After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp drop in average primary system temperature. The long-term pressurizer level and primary system pressure response reflect changes in the primary system inventory brought about by operator recovery actions that were postulated to begin 5 minutes after scram.

Figures 6-6.4 and 6-6.5 show the reactor power and hot leg flow rates for each loop. Prior to scram, the break had little influence on the reactor power since the net mass that left the system was small. The subcooling margin dropped below 20F* at 2.94 minutes after rupture, and the primary coolant pumps were tripped 30 seconds later. After pump trip, the flow rates in the individual loops quickly approached stable single-phase natural circulation flow rates. Since level indi-cation was not operating in OTSGA, EFW flow to the affected 0TSG remained on until the hot leg temperature dropped below 540*F at 19.3 minutes after rupture. After feedwater flow terminated, the temperature and pressure in the affected OTSG g increased. At 14.6 minutes after rupture, the Loop B hot leg temperature exceeded 3 the cold leg temperature by SOF*, indicating loss of natural circulation (see Section 3.3). After the loss of natural circulation was detected in Loop B, it was postulated that the operator would begin to take corrective actions to restore the natural circulation flow rate in that loop by steaning OTSGB.

Figures 6-6.6 and 6-6.7 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operating in the makeup mode and responded to the decrease in pressurizer level. Full HPI was initiated when the RCS pressure dropped below 1600 psi. Recovery was assumed to begin at 5.78 min-utes, 5 minutes after scram. It was postulated that the operator then throttled 6-112 I

HPI ar.d controlled the HPI flow Dased on the subcooling margin. Figure 6-6.6 shows that for most of the transient HPI flow into the primary coolant system exceeded the flow out of the system through the ruptured tubes. Figure 6-6.7 I shows that except for a brief period prior to full HPI initiation, the primary coolant system inventory either remained constant or increased.

Figures 6-6.8 and 6-6.9 show the Loop A and B fluid temperatures in the hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram, I the hot and cold leg fluid temperatures converged and then diverged as the RCS pumps tripped and coasted down. The fluid temperatures in the cold legs upstream of the primary coolant pumps are typically within a few degrees of the OTSG saturation temperatures under natural circulation conditions. The cold leg fluid temperature downstream of the primary coolant pumps is usually colder than the I fluid upstrean of the pumps due to the addition of lower temperature HPI fluid.

Figure 6-6.10 shows the core outlet subcooling margin. The subcooling margin reflected changes in the primary system pressure and hot leg temperature. The subcooling was controlled by the operator recovery actions. The minimum subcooling margin observed in this transient was 0F'.

Figure 6-6.11 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remained at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in this region. This occurred at approximately 1 minute after transient initiation.

Figures 6-6.12 through 6-6.20 shes a summary of the calculated flows into and out of the Loop A and Loop B secondary systems. Figurc 6-6.21 shows the OTSG A and B indicated secondary levels. Figure 6-6.22 shows toe pressure behavior in the two OTSGs. These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shown) in the secondary loop abruptly cea. sed. This caused an immediate pressure increase and secondary level decrease. The increased pressure caused the safety valves, the moduluting atmospheric dump valves (MADVs),

I and turbine bypass valves (TBVs) to cycle. The early pressure response in the secondary was in turn controlled by these valve actions. Fourteen seconds after scram, the emergency feedwater system (EFW) was actuated. This system was effec-tive in reducing secondary pressure, as it consisted of water at approximately 90'F which was sprayed into the OTSG. The EFW system also helped increase the level in each of the two OTSGs. Because of the presence of the break in the Loop 6-113 I

I A OTSG, the level increase rate was somewhat higher in this OTSG. The EFW flow was terminated in OTSGA when the hot leg temperature dropped below 540*F. After the sustained EFW flow was terminated, the temperature and pressure in the OTSGs increased. In the affected 0TSG, the pressure increased to the MADV and turbine bypass valve opening setpoints causing the valves to cycle. In the B OTSG, as the pressure crossed the target pressure at the end of the calculation, the TBV cpened while the EFW system cycled to maintain level at the desired level. At 14.6 min-utes after rupture, the operator opened the Loop B MADVs to restore natural circulation conditions.

The analysis was terminated at 56.80 minutes after rupture with the primary system pressure below the secondary relief pressure setpoint, pretsure decreasing, and adequate subcooling margin available.

This case shows that when water level indication and control fails in such a way I

that there was full EFW flow to the affected steam generator, the steam generator was calculated to overfill early in the transient. However, overfill of the affected stcam generator had little effect on the plant cooldown.

I I

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6-114 I

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6-115 I

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Section 7 FIVE TUBE RUPTURES IN EACH OTSG, CASE 7 Case 7 simulates the rupture of 5 tubes in OTSGA and 5 tubes in OTSGB. Pump trip occurs when the subcooling margin at the core outlet is less than 20F'. This case shows the effects of ruptures in both steam generators.

The termination criteria used to end the analysis were the same as used for the single tube break (see Section 5.1).

I Appendix B presents a plot of fuel clad temperature versus time for this case.

Table 7-1 shows the sequence of events for this calculation. Figures 7-1 and 7-2 show the flow rate through the two ends of the ruptured tubes. Since the tube ruptures were postulated to occur at tne bottom of the upper tube sheet, the flow resistance of the upper end of the ruptured tubes was less than for the lower end, resulting in more flow at the upper end of the ruptured tubes. The break flow I reflected the changes in the primary pressure, primary-to-tecondary differential pressure, and density changes due to temperature changes in the affected loop.

Figures 7-3 and 7-4 show the pressurizer indicated level and core outlet pressure, respectively. As a result of the break, the operator had an almost immediate indication of an upset condition due to the decline in pressurizer level and primary system pressure. In the case of a tube rupture, the operator would have also received signals from air ejector radiation monitors. As a result of the decreasing primary system pressure, the pressurizer heaters were energized how-I ever, they could not keep up with the effects of the break, and the pressure continued to decline. Because of the decreasing pressurizer level, the pres-surizer heaters deenergized and the makeup pumps increased their flow however, the makeup pump, at full capacity, could not replace all of the water being lost from the primary, so the level continued to decline. The operator would have received a high makeup flow alarm at 0.11 minute after rupture. The RCS pressure reached the low pressure scram setpoint at 0.76 minutes. After scram occurred, there was an abrupt drop in pressurizer level and pressure because of the sharp 7-1 I

drop in average primary system temperature. The long-term pressurizer level and primary system pressure response reflect changes in the primary system inventory brought about by operator recovery actions that were postulated to begin 5 minutes after scram.

Table 7-1 SEQUENCE OF EVENTS FOR FIVE TUBE RUPTURES IN EACH OTSG CASE 7 Time After Rupture Event (Minutes)

Simultaneous Rupture of Five Steam Generator Tubes in OTSGA and Five Steam Generator Tubes in OTSGB 0.00 High Makeup Flow Alarm 0.11 Reactor Scram (Primary Pressure <1900 psi) 0.76 Turbine and Main Feedsater Pumps Tripped 0.76 MADVs and MSSVs Lift 0.8 EFW Flow Begins 0.99 Full HPI Flow (RCS Pressure <1600 psi) 1.05 Subcooling Margin Drops Below 20F* 3.2 Operator Trips Reactor Coolant Pumps 3.7 Operator Initiates Manual RCS Cooldown 5.76 OTSGB Level Reaches 95% Operating Range, 21.0 EFW Flow Begins Cycling to Maintain Level MADV Flow Begins Cycling to Maintain Level OTSGA Pressure Exceeds Target Pressure, TBVs Opened 25.5 OTSGB Pressure Exceeds Target Pressure, TBVs Opened 33.3 OTSGA Level Reaches 95% Operating Range, 33.3 EFW Flow Begins Cycling to Maintain Level MADV Flow Begins Cycling to Maintain Level g Analysis Termination Criteria Reached 128.97 g Figures 7-5 and 7-6 show the reactor power and hot leg flow rates for each loop.

Prior to scram, the break had little influence on the reactor power since the net mass that left the system was small. The primary coolant pumps were tripped 0.5 minutes after the subcooling margin reached 20F*. Subcooling margin reached 20F* at 3.2 minutes after rupture and the pumps tripped at 3.7 minutes. After pump trip, stable flows were not established in the individual loops. Rather, there was a small amount of feed and bleed flow to each OTSG. It appeared that steam collecting in the top of the hot leg (candy cane) impeded natural

\ 7-2 l

circulation. The hot leg temperature exceeded the cold leg temperature by 50F' at 13.5 minutes after rupture in Loop B and at 16 minutes after rupture in Loop A, indicating loss of natural circulation (see Section 3.3). After the loss of natural circulation was detected, it was postulated that the operator would begin to take corrective actions to restore the natural circulation flow rate in the loops.

Figures 7-7 and 7-8 show the flow rates into and out of the primary coolant system. The HPI flow prior to scram was operatino in the makeup mode and res-I ponded to the decrease in pressurizer level. At scram the control system auto-matically initiated full HPI. The operator then controlled the HPI flow based on the subcooling margin. Because the hot leg subcooling margin was not restored until about 110 minutes, HPI was not throttled. Figure 7-7 shows that HPI flow into the primary coolant system exceeded the flow out of the system through the ruptured tubes at about 57 minutes. At about this time the primary system pressure was 600 psi and the core flooding tanks began to supply water to the vessel. The core flooding tank flow is not shown individually, but is combined in the net flow into the system. This flow helps to make the net flow into the primary system positive. This is supported by Figure 7-8 which shows that the primary coolant system inventory initially decreased, remained constant, and then began to increase after 83 minutes. Figures 7-9 and 7-10 show the Loop A and B fluid temperatures in the hot and cold legs as well as the OTSG saturation temperatures. Immediately after scram, the hot and cold leg fluid temperatures converged. After the RCS pumps tripped and coasted down, the hot and cold leg fluid temperatures diverged. The fluid temperatures in the cold legs upstream of the primary coolant pumps are typically with'n a few degrees of the OTSG saturation temperatures under natural circulation conditions. The cold leg fluid temperature dcwnstream of the primary coolant pumps is usually colder than the fluid upstream of the pumps due to the addition of lower temperature HPI fluid.

Figure 7-11 shows the core outlet subcooling margin. The subcooling margin reflected changes in the primary system pressure and hot leg temperature. The subcooling was controlled by the operator recovery actions. The minimum sub-cooling margin observed in this transient was OF'.

Figure 7-12 shows the liquid fraction (1.0 - void fraction) of the upper head region. As before, the fluid in this region remained at a constant temperature until the pressure in the reactor vessel reached the saturation pressure of the fluid in this region. This occurred at approximat'ely 1 minute after transient initiation.

7-3

Figures 7-13 through 7-22 show a summary of tha calculated flows into and out of the Loop A and Loop B secondary systems. Figure 7-23 shows the OTSG A and B indicated secondary levels. Figure 7-24 shows the pressure behavior in the two OTSGs. These figures are discussed as a group. Immediately after scram, the feedwater and steam flow (not shown) in the secondary loop abruptly ceased. This caused an immediate pressure increase and secondary level decrease. The increased E

pressure caused the safety valves to lift once and the modulating atmospheric dump g valves (MADVs) and turbine bypass valves (TBVs) to cycle. The early pressure response in the secondary was in turn controlled by these valve actions. Fourteen seconds after scram, the emergency feedwater system (EFW) was actuated. This system was effective in reducing secondary pressure, as it consisted of water at approximately 90*F which was sprayed into the OTSG. The EFW system also helped increase the level in each of the OTSGs. Because the subcooling margin was less than 20F*, the EFW flow was terminated when the level in an OTSG exceeded 95%

operating range and was restarted when the level dropped below the 95% setpoint.

The MADVs were opened when the level exceeded the 95% operating range setpoint.

After the sustained EFW flow was terminated, the temperature and pressure in the OTSGs increased. The pressure increased to the TBV opening setpoints and the valves cycled to maintain the desired pressure. The result of these actions was a cooldown of both OTSGs which closely approximates the desired cooldown.

Thus even in the event of a simultaneous rupture of five tubes in each steam generator, a controlled shutdown was achieved.

74

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Figure 7.24. Steam Generator Pressure 7-28 I I'

I  !

I i l

Section 8 REFERENCES I 1. V. H. Ransom et al. RELAPS/ MODI Code Manual Volume 1: System Models and Numerical Methods. NUREG/CR-1826, March 1982.

2. RETRAN - A Proaram for One-Dimensional Transient Thermal-Hydraulic Analysis of Complex Fluid Flow Systems. Electric Power Research Institute, Palo Alto, California, EPRI CCM-5 (1978) and NP-2175 (1981).

3. RETRAN Simulation of the TMI-1 Turbine Test. Trans. Am. Nucl. Soc., Vol. 32, 1979.

4. L. C. Pwu and T. G. Broughton. RETRAN Simulation of the TMI-2 Startup Overfeed Incident. Nuclear Technology, Vol. 54, 1981.

5. Babcock & Wilcox Nuclear Power Generation Division. Impact on an GTSG Tube Rupture with Concurrent loss of Offsite Power. Technical Document 86-1118045-00, April 1980.

6. T. G. Broughton and N. G. Trikouros. RETRAN PWR Applications at GPU, Nuclear Technology, Vol. 54, 1981.

I I

I I

I I

I *-'

I

f L

L Appendix A TRIPS AND CONTROL This appendix describes the trips and controls which were used to simulate both the automatic and manual operator recovery actions during OTSG tube rupture transients.

~

A.1 CONTROL SYSTEM INPUTS Several controllers required common input quantities. The steam generator secondary indicated level (in inches) was calculated from the steam generator downcomer liquid fraction using the relationship:

indicated level = 390.33048 x (downcomer liquid fraction)

The steam generi Jr secondary level in units of percent operating range was calculated from the steam generator secondary indicated level (in inches) using the relationship:

level (% operating range) = [(indicated level) x .3425 ) - 32.88

( The pressurizer average liquid fraction was calculated by computing a volume weighted average of the liquid fractions in the nine pressurizer control volumes. The pressurizer indicated liquid level (in inches) was calculated from the average pressurizer liquid fraction using the expression:

level = 12 x [(pressurizer ave liquid fraction) x 39.73 -3.537]

~

Note that the pressurizer was not empty when the indicated liquid level was zero because a small fluid volume exists below the lower levei tap (pressure sensor).

The volume of liquid in the pressurizer below the lower level tap determines at what computed level the pressurizer is empty. Most B&W plants have pressurizers with a 400-inch level range, while the rest have pressurizers with a 320-inch level range. Those with a 400-inch level range have a smaller volume of liquid below the lower tap. The pressurizer in this analysis had a 400-inch level range A-1 W

and was empty when the computed level was -42.44 inches. The location of the g pressure taps on the pressurizer precluded the operator from knowing when the 3 pressurizer was completely empty.

The subcooling margin was calculated by subtracting the local saturation temperature from the local computed temperature. The saturation temperature was g determined at the local computed pressure. 3 For cases where the operator continued steaming the OTSG, the desired OTSG pressure was tabulated as a function of time after scram. The resulting table represented a pressure time history which would establish a 100*F per hour RCS g cooldown rate. The tabulated values, as a function of time after scram, are given g in Table A-1.

Table A-1 DESIRED OTSG PRESSURE AS A FUNCTION OF TIME AFTER SCRAM Time After Scram (seconds) Desired 0TSG Pressure (psia)

-1.0E+90 1040.

300. 1040.

1200. 885.

2100, 712.

3000. 566.

3900. 444.

4800. 344.

5700. ,

262.

6600. 196.

7500. 144.

8400. 103. g 9300. 72. 5 11200. 33.

12900, 13.

I I

A-2 I

In addition to the common input quantities required by several controllers, several controllers required common trips. These included the scram, recovery, and loss-of-natural-circulation trips.

I Scram occurred when the hot leg pressure dropped below 1900 psia or 1 minute after the makeup flow reached 170 gpm, whichever occurred first (the 1-minute delay is an assumed operator response time).

The recovery trip enabled several control actions which simulated the manual operator control actions. Recovery was assumed to begin 5 mirutes af ter scram (the 5-minute delay is the assumed time required for the operator to diagnose the accident and to begin the procedures required to bring the plant to cold shutdown).

I Loss of natural circulation was assumed to have occurred if any of the following conditions existed:

(a) the cold leg temperature in the loop was greater than the fluid temperature in the OTSG downcomer by more than 35F*,

(b) the hot leg fluid temperature in the loop was greater than the cold leg fluid temperature in the loop by more than 50F*,

I (c) the hot leg temperature in the loop was not within plus or minus 10*F of the fluid temperature in the upper plenum.

A.2 CONTROL SYSTEM DESCRIPTION In this section, the key systems and their associated controls are described.

A.2.1 MAIN FEEDWATER I The feedwater flow was constant until scram. After scram, the feedwater mass flow was ramped to zero ficw in 0.1-seconds. The feedwater fluid conditions were assumed constant at a pressure of 1400 psia and a temperature of 462.7'F.

A.2.2 STEAM CONTROL VALVE The steam control valve position was constant until scram. After scram, the valve position was ramped to zero in 0.333-seconds.

I I

A-3 I

I A.2.3 STEAM GENERATOR SECONDARY SAFETY VALVES Five banks of safety valves were modeled on each of the steam generator secondary steam lines. The valve characteristics are given in Table A-2.

Table A-2 OTSG SAFETY VALVE CHARACTERISTICS Capacity (1bm/sec)

I Valve Bank Opening Setpoint Closing Setpoint of Saturated Steam Number (psia) (psia) @ 1200 psia 1 1065 1033 801.3 2 1070 995 400.6 3 1072 997 400.6 4 1095 1018 400.6 .

5 1107 1030 400.6 I

A.2.4 TURBINE BYPASS VALVES (TBV)

The turbine bypass valves were modeled with RELAPS valve components. The full open junction areas were selected to give a total flow rate equal to 22.5% of the full power steam flow at a steam line pressure of 907.6 psia. The function describing valve position before scram is given in Table A-3. After scram, the g valve position was set to full open whenever steam line pressure exceeded 1040 g psia and was closed whenever ti.e steam line pressure dropped below 994 psia. For cases where the operator continued steaming the OTSG, the TBVs began opening when the OTSG pressure exceeded the desired pressure (the desired pressure is described in Section A.1 and in Table A-1) and were full open at 10 psid above the target pressure.

I I

I A-4 I

, Table A-3 TURBINE BYPASS NORMALIZED VALVE POSITION AS A FUNCTION OF STEAM LINE PRESSURE BEFORE SCRAM .

I Steam Line Pressure (psia)

Normalized Valve Posi; ion (fraction of Full open)

0. 0.0 917.6 0.0 927.6 0.5 947.6 1.0 1.0E+80 1.0 A.2.5 MODULATING ATMOSPHERIC DUMP VALVES (MADVs)

The MADVs were modeled as control valves whose positions were controlled by the RELAP5 control system. The junction area of these valves was chosen such that I each valve would pass 3.2% of the steam flow in each OTSG (3.2% of 1537.4 lbm/s of saturated steam at 1025 psia).

The MADVs were operated in two modes:

(1) After accident initiation, the MADVs opened and closed I automatically on steam generator pressure. The MADVs began opening at 1035 psia and were full open at 1060 psia. The area of the MADVs varied linearly with the pressure.

(2) After accident recovery, the MADV control logic simulated manual control of the valves by the operator. The MADVs began opening when the OTSG liquid level became greater than 95%

operating range or when loss of natural circulation was I detected in the loop.

Figures A-1 and A-2 show control block diagrams of the controllers on the affected and unaffected 0TSG MADV systems, respectively. Tables A-4 through A-6 show functional relationships used by the MADV controllers.

I I

A-5

I Table A 4 MADV STEM POSITION AS A FUNCTION OF STEAM GENERATOR PRESSURE Pressure Valve Stem Position (psia) (Fracticn of Full Open)

0. 0.0 1035. 0.0 1060. 1.0 1450. 1.0

\

Table A-5 MADV VALVE POSITION AS A FUNCTION OF DIFFERENCE BETWEEN FLUID TEMPERATURE IN OTSG AND FLUID TEMPERATURE IN UPPER PLENUM Temperature Difference Valve Position \

(*F) (Fraction of Full Open)

-1.0E+6 0.0 j -51. 0.0

-49. 1.0 1.0E+6 1.0 Table A-6 MADV VALVE POSITION AS A FUNCTION OF DIFFERENCE BETWEEN '

OTSG PRESSURE AND DESIREJ OTSG PRESSURE Pressure Difference Valve Position (PSID) (Fraction of Full Open)

-1.0E+90 0.

O. O.

100. 1.

1.0E+90 1.

A-6 I

( A.2.6 EMERGENCY FEEDWATER (EFW) SYSTEM The EFW system was represented as a time-dependent junction in which flow was

( equal to a control variable. The maximum EFW flow was 79.9 lbm/sec for each OTSG. The EFW system was activated whenever both of the following conditions were r met: 1) time after scram was greater than 14 sec, and 2) the OTSG level was below L a variable level setpoint. If the pumps were running, the level setpoint was 30 inches (-22.58% operating range). If the pumps were tripped, the level setpoint

{ was 50% operating range. If the core outlet subcooling margin decreasad to below 20F', the level setpoint was 95% operating range (manual operator acc.on).

[ After EFW was enabled, the flow was a function of pressure above the desired 0TSG pressure as tabulated in Table A-7. As described in Section A.1, the desired 0TSG

{ pressure was computed to yield a 100*F/hr cooldown rate. Figure A-3 gives a control block diagram for the EFW control system in the unaffected 0TSG. The controls for the affected 0TSG were identical to the unaffected 0TSG, except the level setpoint was reduced to zero operating range whenever the temperature in the affected loop dropped to 540*F.

Table A-7 FRACTION OF FULL EFW FLOW AS A FUNCTION OF PRESSURE ABOVE DESIRED PRESSURE Pressure Above Desired Pressure (PSID) Fraction of Full EFW Flow

-1.0E+90 0.00

-400. 0.00

-150. 0.35

-100. 0.60

{ -50. 1.00 11.0E+90 1.00 A.2.7

{ PRESSURIZER HEATERS Five banks of pressurizer heaters were modeled. The characteristics of the pressurizer heaters are given in Table A-8. Table A-9 shows functional

{ relationships used by the pressurizer heater controllers. The power to the

[

A-7

I pressurizer heaters was controlled directly by the RELAPS control system. The pressurizer heater controls perform several functions: (1) prior to the start of recovery, the heaters maintained the hot leg pressure at the desired pressure setpoint; (2) after recovery began, the heaters controlled pressure to establish the desired subcooling margin; (3) the heaters were disabled whenever the liquid fraction in the pressurizer was below 10 percent (5.2 inches indicated liquid level. A control block diagram for the pressurizer heaters is shown in Figure A-4.

Table A-8 _

PRESSURIZER HEATER CHARACTERISTICS Bank Number Bank on Setpoint Bank off Setpoint Maximum Power (psia) (psia) (KW) 1 2150 2170 126 2 2150 2170 126 g 3 2150 2170 504 5 4 2135 2155 378 5 2120 2140 5( 4 Table A-9 PRESSURIZER HEATER POWER VERSUS SUBC00 LING MARGIN Subcooling Margin '

Pressurizer Heat.er Power I

(*F) (<W)

I

-500. 1638.

10.00 1638.

18.00 0.

l 100000. O.

l I

A-8 I

I A.2.8 PRESSURIZER POWER OPERATED RELIEF VALVE (PORV)

The PORV was used by the operator during the accident recovery portion of the transient to help control subcooling margin. The PORV flow characteristics were based on the EPRI safety relief valve testing program experimental data. The operator opened the PORV if the following conditions were met: (a) the indicated pressurizer indicated level was greater than 40 ir. es, (b) five minutes had elapsed since scram (c) the subcooling margin was greater than 50F*. The operator closed the PORV whenever the pressurizer indicated level dropped below 40 inches, or whenever the subcooling margin dropped below 25F*.

A.2.9 PRESSURIZER SPRAY The pressurizer spray system was used by the operator during the steady-state operation of the plant to control RCS pressure and during the accident recovery I portion of the transient to help control subcooling margin. The pressurizer spray system was used in preference to the PORV for controlling subcooling margin if the pumps were running.

Prior to recovery, the pressurizer spray control valve was opened by automatic I control when the RCS hot leg pressure exceeded 2220 psia and was closed when the pressure dropped below 2170 psia. During accident recovery, the operator opened the pressurizer spray control valve if the following conditions were met: (a) the subcooling margin was greater than SOF*, (b) five minutes had elapsed since scram (assumed operator response time to begin recover / actions), and (c) the primary I coolant pumps had not been tripped.

A.2.10 HIGH-PRESSURE INJECTION (HPI) SYSTEM The HPI system was modeled as four time-dependent junctions. The flow for each was equal to one-fourth of a control variable. The controllers for the HPI control valve operated in several modes during the transient: (1) Until the HPI injection trip was received, the HPI system operated in the makeup mode, where I flow was a function of pressurizer level; (2) After receipt of the injection trip but before recovery, full HPI flow was initiated whenever the hot leg pressure was less than 1600 psia (automatic control action), subcooling margin was less than 20F* (assumed manual control action), or 1 minute after the makeup flow reached the maximum makeup flow of 169.9 GPM (assumed manual control action), (3) During recovery, when certain conditions existed, the HPl flow was reduced. The conditions for reducing HPI flow included certain subcooling requirements, as well as time after scram conditions.

1 A-9 lI

A control block diagram of the HPI controls is shown in Figure A-5. The E

functional relationships used by the HPI controls are shown in Tables A-10 through 3 A-12.

Table A-10 MAKEUP FLOW VERSUS INDICATED PRESSURIZER LEVEL Indicated Pressurizer Level Makeup Flow (Inches) (lbm/sec)

-1.0E+80 23.7317 211. 23.7317 220. 0.0 1.0E+80 0.0 Table A-11 HPI FLOW AS A FUNCTION OF RCS PRESSURE RCS Pressure HPI Flow (psia) (gpm) 15 850 1350 830 1550 800 1935 689 2515 475 3000 0 1.0E+9 0 I

I I

I A-10 I

Table A-12 1.0 MINUS HPI FLOW AS A FUNCTION OF HOT LEG SUBC00 LING MARGIN I H. L. Subcooling Margin (Deq F) 1.0 Minus Fraction of HPI Flow (Fraction)

-1.0E+80 0.0

20. 0.0 I 35.

100.

0.5 1.0 1.0E+80 1.0 A.2.11 RUPTURED TUBE FLOW Early attempts involved modeling the long section of the ruptured tube explicitly, 1.e., modeling the long section of the ruptured tube as several control volumes I and junctions. When this approach was used, the running time, mass error accumulation, and calculated flows were unacceptable. Instead, the long section was modeled using the control system to control the flow through a time-dependent junction as a function of primary-to-secondary differential pressure. The functional relationship between the calculated flow rate and the primary-to-secondary differential pressure, shown in Figure A-6, was developed from a smaller RELAP5 model in which the long section of the ruptured tube was modeled explicitly.

Modeling the short section of the ruptured tube presented difficulties as well.

In early results, the flow through the short section of the ruptured tube always remained choked, even though the pressure differential between the steam generator inlet plenum and the steam generator secondary became very small. It was later discovered that the flow rates through this junction were calculated to be much too large when the choking option was not being used. This problem appears to be due to an error in the RELAP5/M001 abrupt area change model. This problem has been observed by other researchers (A-1) and occurs when junctions of very small areas are connected to control volumes of much larger areas. To solve this problem, the control system was employed to calculate the flow through this junction when the flow as unchoked. When the choked flow exceeded the unchoked flow, the valve which controlled the choked flow was closed, and a time-dependent junction was used to calculate inertial flow for the rest of the transient.

l l A-11 l

The following modeling approach was used to simulate the mass flow from the long and short ends of the ruptured tubes in the OTSG. The long section of the i

ruptured steam generator tube was modeled using a RELAPS time-dependent junction. Consistent with Figure A-6, the mass flow rate for this time-dependent junction was given by the expression:

Mdot = C * ((DELTA P)

• RH0]**0.5 where Mdot = Junction Mass Flow Rate in ibm /sec C = .227135 (1bm/sec) [(in**2/lbf) (ft**3 lbm)l**0.5 DELTA P = Elevation Head Adjusted Primary-to-Secondary Differential Pressure in Ibf/in**2 RHO = Upstream Fluid Density in ibm /ft**3 The formula used for calculating the DELTA P included terms for the elevation I

pressure drop, as well as a term for the frictional pressure drop of the ruptured

)

tube. In the calculation of the elevation pressure drop, the fluid density in the  ;

tube was assumed to be the same as the donor volume fluid density.

The short section of the ruptured steam generator tube was modeled using two junctions. One junction was used when the flow was choked and the other junction was used when the flow was unchoked.

A RELAPS time-dependent junction was used for the unchoked flow condition. The mass flow rate for this time-dependent junction was calculated per the above expression, except that a value of 0.6392 was used for the constant C.

For choked flow, a standard RELAPS junction using a discharge coefficient of .7353 was used to determine the critical flow rate for both subcooled and saturated conditions. A test was made at each time step to determine if the unchoked flow exceeded the choked flow. When the unchoked flow exceeded the choked flow, the choked flow junction was closed and the unchoked flow junction was opened. The logic was such that flow was allowed through only one junction at a time.

I A-12 I

A.2.12 VENT VALVE The vent valve model used the RELAPS time-dependent junction component. The RELAPS control system was employed to control the liquid and vapor fluid velocity through the valve. The equation solved is Darcy's formula, or

[2*144*g c*aPb [288g aP3 y =l c

' l**0.5 = l .- I**0.5

\ / \

/

where v = fluid velocity through the valve in ft/sec gc = gravitational constant = 32.174 lbm-ft/lbf-sec 2 aP = differential pressure across the valve in lbf/in2 k = valve resistance coefficient - dimensionless o = fluid density at the valve in Ibm /ft 3 The valve resistance coefficient was computed as a function of the valve opening angle, which in turn was computed as a function of the valve differential pressure. A control block diagram of the vent valve controls is provided in Figure A-7. The functional relationships used by the vent valve controls are provided in Table A-13 and Table A-14. These functional relationships were developed from the vent valve model test data which are found in Reference A-2.

!I i

I A-13 l

Table A-13 VENT VALVE LOSS COEFFICIENT VERSUS VALVE OPENING ANGLE i Valve Opening Angle Valve Loss Coefficient (Oegrees) (Dimensionless) 0.25 1600.

1.0 400.

2.0 200.

2.5 100.

3.0 75.

4.0 50.

5.0 34.

6.0 26.

7.0 20.

8.0 17.

9.0 13.

10. 11.5

11. 10.0

12. 9.1

13. 7.5

4. 6.8

15. 6.3

16. 5.8

17. 5.4

18. 5.0

19. 4.7

20. 4.3

21. 4.1 1.0E+90 4.1 I

l I A-14

I L Table A-14 VENT VALVE OPENING AN3LE AS A FUNCTION OF THE VALVE DIFFERENTIAL PRESSURE Valve Differential Pressure Valve Opening Angle (PSI) (degrees)

-1.0E+99 0,0 0.06 0,0 0.26 21.0 L 1.0E+99 21.0

[

E L

E E

E E

E E

[

[

A-15

[

m- .

+_ ............................................. _ .................+

I VALVE AREA IS REPRESENTED AS A TABULAR WNCTION OF VALVE POSITION I I OR I I NORMALIZED AREA =F(CNTRL* TAR 300) I I WHEh2 I I CNTRLVAR 300= NORMALIZED POSITION I I AND THE WNCTIONAL RELATION BEWEEN

• POSITION AND AREA IS LINEAR I

+.............................._...................................+

I

+...................................................................+

I CNTRLVAR 300=CNTRLVAR 301 + CNTRLVAR 303 I I CNTRLVAR 301 REPRESENTS THE VALVE POSITION DUE TO PRESSURE I I CNTRLVAR 303 REPRESENTS THE V ALVE POSITION DUE TO OPERATOR I I RECOVERY PROCEDURES. I

+.............. ...___............_.................. ...........__+

I I

+----------------..---------+ I I CNTRLVAR 301 I I I IS VALVE STEM POSITION I I I AS A FUNCTION OF STEAM I I I GENERATOR PRESSURE AS I I I DEFINED BY TABLE A.4 I I

+...........................+ I g I g

...___......_.............+ +............................+

I CNTRLVAR 257 I I CNTRLVAR 303 I I IS A UNIT TRIP FUNCTION. I I IS THE PRODUCT OF CNTRLVAR I I IT IS USED TO ENABLE THE I)>>>>>>>>>I 257 AND CNTRLV AR 305. I I ACCIDENT RECOVERY MADV I I I I LOGIC I I I

+ ....... .................+ +...............___..._......,

1 +...................._..........................+

I CNTRLVAR 305 I I IS THE VALVE'S POST. RECOVERY POSITION = I I us I SUM OF CNTRLVAR 306 AND CNTRLVAR 307 I I

+... ................________.......... . .......+

I I

. _ _ . . . . . . . . . . . _ . . . . . _ . , . . _ . . . . . _ . . . . . . . . . . . . . _ +

j CNTRLVAR 307 I I CNTRLVAR 306 I I I IS EQUAL TO 1.0 IF I I IF LOSS OF N ATURAL CIRC. I I CNTRLVAR 308 EXCEEDS 95. I I (TRIP 651 : TRUE), THEN I I AND IS RESET TO ZERO IF I I CNTRLVAR 307 = FUNCT OF I I CNTRLVAR DROPS BELOW 90. I I CNTRLV AR 260 WHERE FUNCT. I I I I IS DEFINED BY TABLE A-5 I

+....._........._...........+ + ... .......................+

I I

+...........................+ 4_...........................+

I CNTRLV AR 308 I I CNTRLVAR 260 I I IS THE S.G. LEVEL EXPRESS-I I IS THE DIFFERENCE BEW EEN I I ED IN PERCENT OF OPERAT- I I AFFECTED OTSG TEMPERATURE I I ING PASCE I I AND THE TEMPERAWRE OF I I I I THE UPPER PLENUM I

, _ . . . . . . . . . . . . . . . . . . . . . . _ . . + + . . . . . . . . . . . . . . . . . . . . . . . . . . . _ ,

Figure A-1. Control Block Diagram of the Affected OTSG MADV System A-16

+e. ................................... ........_..................+

I VALVE AREA IS REPRESENTED AS A TABULAR FUNCTION OF VALVE POSITION I I OR I I NORMALIZED AREA =F(CNTRLVAR 310) I i I WHERE I I I I

CNTRLVAR 310= NORMALIZED POSITION I AND THE FUNCTIONAL RELATION BEWEEN POSITION AND AREA IS DEFINED I IN TABLE

^

68 I

I

+.......................__......._...............................+

I

+........................................................___........+

I CNTRLVAR 310=CNTRLVAR 311 + CNTRLVAR 313 I I CNTRLVAR 311 REPRESENTS THE VALVE POSITION DUE TO PRESSURE I I CNTRLVAR 313 REPRESENTS THE VALVE ICSITION DUE TO OPERATOR I I RECOVERY PROCEDURES. I

^ ^

+. ........... ...... ............................... .............+

I I I

+---------------------------+

CNTRLVAR 311 I I

I I

I IS VALVE STEM POSITION I I I AS A FUNCION OF STEAM I I I GENERATOR PRESSURE AS I I I DEFINED BY GNRL TABLE 399 I I

+.............._____........+ I I

+...........................+ ,..................... ......+

I CNTRLVAR 257 I I CNTRLVAR 313 I I IS A UNIT TRIP FUNCTION. I I

I IS THE PRODUCT OF CNTRLVAR I I IT IS USED TO EN ABLE THE I>>>>>>>>>>I 257 AND CNTRLV AR 315. I I ACCIDENT RECOVERY MADV I I I I LOGIC I I I I +...........................+ +...........................+

I I

+...................................._...........+

I CNTRLVAR 315 I I IS THE V ALVE'S POST-RECOVERY POSITION = I I SUM OF CNTRLVAR 316 AND CNTRLVAR 327 I I I

+_.................................... _........_+

I I

, +_..........................+ .............___...........+

l I CNTRLVAR 316 I I CNTRLVAR 327 I i I IS EQUAL TO 1.0 IF I I IF LOSS OF NATUR AL CIRC. I I CNTRLVAR 318 EXCEEDS 95. I I (TRIP 656 = TRUE), THEN I l I AND IS RESET TO ZERO IF I I CNTRLVAR 327 = FUNCT OF I l I CNTRLVAR DROPS BELOW 90. I I CNTRLVAR 270 WHERE FUNCT. I

I I I IS DEFINED BY TABLE 70. I j +...........................+ + . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,

I I l

+.. _.......................+ +............................+

I CNTRLVAR 318 I I CNTRLVAR 270 I I IS THE S.G. LEVEL EXPRESS-I I IS THE DIFFERENCE BEWEEN I I ED IN PERCENT OF OPERAT- I I AFFECTED OTSG TEMPERATURE I I ING RANGE I I AND THE TEMPERATURE OF I I I I THE UPPER PLENUM I

+...........................+ .......................... +

Figure A-2. Control Block Diagram of the Unaffected OTSG MADV A-17 I

l ll

+ ... ......... ............... ..____........ ..........__....__.....+

I THE EW SYSTEM IS REPRESENTED AS A TIME-DEPENDENT JUNCTION WHOSE FLOW I I IS EQUAL TO CNTRLVAR 406 WHFN ENABLING

• TRIP 614 IS SET TRUE. I

+......._-_................................__....._................._..+

I e

+. _........._______......__...........___.... ...... ..................+

I CNTRLVAR 406=CNTRLVAR 404 + 79 9 X CNTRLVAR 295 WHERE CNTRLVAR 295= 1 I I IF LOSS OF NATURAL CIRCULATION IS DETECTED AND IS EQUAL TO ZERO I I OTHERWISE. CNTRLVAR 406 IS LIMITED

• BETWEEN 0. & 79.9 (FULL FLCW) I p........._..........._............ ....................................+

I E

+._.................._............._..._...........................__..+ g I CNTRLVAR 404 = FUNCTION OF CNTRLVAR 403 WHERE FUNCTION AL RELATIONSHIP I I IS GIVEN IN TABLE A 7 CNTRLVAR 403 REPRESENTS ACTU AL - DESIRED OTSG I I PRESSURE TO EFFECT A 100 DEG F/HR COOLDOWN RATE. I

^

+.... .....____..................._ .................. ......... . .....+

I

+............... ................_................__ .......____ .......+

I CNTRLV AR 403 = OTSG PRESSURE . CNTRLV AR 402 WHERE CNTRLV AR 402 I I REPRESENTS THE DESIRED PRESSURE. ^ I

+...__............... ........._... ....................................+

I

+.....___.. ..............................____............ ....... ... .+

I CNTRLV AR 402 = FUNCTION OF CNTRLV AR 401 WHERE CNTRLV AR 401 IS THE I I TIME AFTER SCRAM Ila SECONDS, AND TABLE A-1 GIVES THE RELATIONSHIP I

+___ . ................_ ..........a______.._ ...........____.. ......._+

I

+............__................................_.......................+

I CNTRLV AR 401 = TIME - CNTRLV AR 400 WHERE CNTRLVAR 400 IS TIME 0F TRIP I I 517 (SCRAM TRIP) I

+.................._....................................................

I I

Figure A-3. Control Block Diagram for EFW System B A-18 I

1

I

+.....______................................. _ ... ____...............

I POWER TO PRESSURIZER HEATERS = CNTRLVAR 131 WHERE I I I CNTRLVAR 131 = CNTRLVAR 132 X CNTRLVAR 133 AND WHERE I Q(TRLVAR 132 IS THE TEST TO SEE IF THE PRESSURIZER CONTAINS LIQUID I

+. ... _... *................................_..._~..__......... ___.+

I I I I +............._..............

I CNTRLVAR 132 = 0. IF LEVEL I I IS BELOW .1 OTHERWISE I

+....... _. _........................

I CNTRLVAR 133 = CNTRLVAR 134 +

I CNTRLVAR 135 WHERE CV 134 AND 135 I I

I CNTRLVAR 132 = 1.

I I I IS THE PRE AND POST RECOVERY CONT.I

+.........................._, +..~.......__... * ................+

I I

---

I I I I

(PRE RECOVERY CONTROLLER) I I I

+ . _ _ _ _ . . _ _ _ _ _ _ _ . . . . . . . . . . . . . . . . + +........................ _ .......

(POST-RECOVERY CONTROLLER) I I CNTRLVAR 134 = CNTRLVAR 136 IF I I CNTRLVAR 135 = CNTRLVAR 137 IF I I TRIP 519 IS TRUE, OTHERWISE I I TRIP 520 IS TRUE, OTHERWISE I I CNTRLVAR 134 = 0. I I CNTRLVAR 135 = 0. I

+..............*.................++.............*..__..............+

I I

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . +................. .................

I CNTRLVAR 136 IS A FUNCTION OF I I CNTRLVAR 139 IS A FUNCTION OF I I HOT LEG PRESSURE, AND IS THE I I CNTRLVAR 143 WHERE TABLE A-9 I I SUM OF SEVER AL TRIP UNITS.

I I I DEFINES FUNCTIONAL RELATIONSHIP I

+_..............................,+................*.................+

+.....................................................................+

I I CNTRLVAR 143 = HOT LEG SUBC00 LING MARGIN I I = Q4TRLVAR 144 THOT I I AND WHERE CNTRLV AR 144 : TSAT EVALUATED AT PHOT I

+..................................*.............__...................+

I

+................................................_...................+

I CNTRLVAR 144 IS A FUNCTION OF HOT LEG PRESSURE WHERE FUNCTIONAL I I RELATIONSHIP IS GIVEN IN TABLE 16 I

+................................. ...................................+

I Figure A-4. Pressurizer Heaters Control Block Diagram A.19 I

1

I I

l I

+_.......................____....._................_................+

I I THE TOTAL HPI FLOW = HPI FLOW + NORMAL MAKEUP I

I OR CNTRLVAR 199 : CNTRLVAR 191 + CNTRLV AR 198 *

+-................................................................+

I I

+----------------------------------------.---+ I I HAKEUP FLOW s CNTRLVAR 198 WHERE I I I CNTRLVAR 198 : CNTRLVAR 197 X CNTRLVAR 196 I I I AND WHERE CNTRLVAR 197 IS A TRIP UNIT THAT I I

=

I TEST THE BEFORE HPI TRIP (634) AND WHERE I I I CNTRLVAR 196 IS A FUNCTION OF PRZR LVL I I I WHICH IS DEFINED BY TABLE A-10. I I g

+--------------------------------------------+ I g I

+_____......................................._..._...........__.....

I HPI FLOW IS EQUAL TO CNTRLVAR 191 I I

E g

I WHERE CNTRLV AR 191 = DESIRED HPI FLOW I

I CNTRLVAR 191: (CNTRLVAR 188) X (CNTRLVAR 190) X (CNTRLVAR 181)

I WHERE CNTRLVAR 188 : FULL HPI FLOW, CNTRLV AR 189 = FRACTION I CNTRLVAR 181 TESTS THE~ HPI ENABLING TRIP (612) I I AND

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

I I I

+------------------------------+ I+-------------------------------+

I I CNTRLV AR 190=1.0.CNTRLV AR 189I I I CNTRLVAR 188 : F(PRESSU RE)

I WHERE CNTRLVAR 189 IS THE I I I WHERE FUNCTIONAL RELATIONSHIP I I THROTTLE CONTROLLER I I I IS GIVEN IN TABLE A-11 I

+....._.... ...................+ I +....._ .................... ...+

I I I +------..-----------------+

I I IF HPI TRIP I I I (TRIP 612 .EQ. TRUE) I l g

I I CNTRLVAR 181: 1.0 I I I OTHERWISE CNTRLVAR 181:0.I I +------.------------..-----+

I

+_...............___....._....................................._...+

I CNTRLVAR 189 (CNTRLVAR 164) X (CNTRLVAR 185) X (CONTRLVAR 186) I I WHERE CNTHLVAR 184 TESTS SUBC00 LING MARGIN (TRIP 511) I g I CNTRLVAR 166 TESTS FOR ELAPSED TIME (TRIP 617) I g I AND CNTRLVAR 185 IS A FUNCTION OF HOT LEG SUBC00 LING MARGIN WHERE I I

I FUNCTION AL RELATIONSHIP IS DEFINED IN TABLE A-12.

+....... .......................................... ............. ...

I Figure A-5. HPI Control Block Diagram A-20 i

I

m

• RELAP5 MODEL OF LONG SECTION OF RUPTURED TUBE g

E - 1 I I I I I I CD 0 0 0 MASS FLOW RS R FUNCTION OF PRIMARY TO 3 =

SECONDRRY DIFFERENTIAL PRESSURE Lt.J I

(D D

l-O I L2 !

D 0 - -

I l--

Q_

D I LL O

I Z O

s I--

I Sm m

~ ~

d I Z O

l I I C

D O

l l

i I Z I o F-I -

I 2 O

LL I e i i i i i i I

-200 0 200 400 600 800 1000 1200 14C DIFFERENTIAL PRESSURE (PSID)

Figure A-6. RELAPS Model of a Long Section of Ruptured Tube I

A-21 I

I

+_______....____....______________.......____....______________...__....+

! THE VENT VALVES ARE REPRESENTED AS A SINGLE TIME. DEPENDENT JUNCTION l l THE VELOCITY FOR WHICH IS EQUAL TO CNTRLVAR 99 AND WHERE l l CNTRLVAR 99 = %.26 e SQRT(CNTRLVAR 98) l

+_...________________....__....___5------------------------------------+

1

+-_ ...____.._____... _____..._______________________..............___+

l CNTRLVAR 98 m (CNTRLVAR 90) / (CNTRLVAR %) l l WHERE CNTRLVAR 90 = VALVE DIFFERENTIAL PRESSURE AND l l WHERE CNTRLVAR % = PRODUCT OF K FACTOR AND UPSTREAM DENSITY l

+_..____....._______...__.g________..___________________......5-------+

l l

____...__.._______...__..______..________..__...______+ l l CNTRLVAR 96 = CNTRLVAR 95

• RHO 4010000 WHERE l l l CNTRLVAR 95 = VALVE K FACTOR l l

.__________________...___.g_______________.......________+ l g i I

+_ ______.. ___________________________. ____________....+ l l

l CNTRLVAR 95 = FUNCTION OF CNTRLVAR 94 WHERE I l I CNTRLVAR 94 : VALVE OPENING ANGLE AND WHERE l FUNCTIONAL RELATIONSHIP BEWEEN VALVE K FACTOR AND I l

]

l l 3 i VALVE OPENING ANGLE IS GIVEN IN TABLE A-13 I l

_____......_________....g._____........__.......______+ l l I E

+ ____________________________........_____......________+ l B l CNTRLVAR 94 = FUNCTION OF CNTRLVAR 90 WHERE l l l CNTRLVAR 90 m VALVE DIFFERENTIAL PRESSURE AND l l l WHE RE FUNCTIONAL RELATIONSHIP BEWEEN VALVE OPENING l l l ANGLE AND VALVE DIFF. PRESSURE IS GIVEN IN TABLE A-14 l l

. __..__..______ ....__.g....__..........___.......____+ 1

+_....._____. __...__..... _____....._____......______.....__... .......+

l CNTRLVAR 90 : TIME AVERAGED VALVE DIFFERENTIAL PRESSURE I l = .05 8 CNTRLV AR 89 + .95

• CNTRLVAR 88 WHERE l I CNTRLVAR 89 IS PRESENT VALUE OF YALVE DIFFERENTIAL FRESSURE AND l l CNTRLVAR 88 IS OLD TIME VALUE OF VALVE DIFFERENTIAL PRESSURE l

I 3

+__....___....________...5-------------------------------------------G-+

1 I

+______.________......_____________......_______......_____.....____+l l CNTRLVAR 89 =[ P 4010000 _ ( .5

• 4 7168

• RHO 4010000 / 144.)] - I l I [ P 7010000 - ( .5

• 3 7396

• RHO 7010000/ 144. )] l l l WHERE 3 7396 AND 4.7168 ARE THE HEIGHTS OF VOLUMES 701 AND 401 !l l NOTE THAT THE TERM ( .5

• H ' RHO / 144. ) REPRESENTS A l l l ELEVATION HEAD PRESSURE DROP CORRECTION FROM THE VOLUME CENTER l l l TO THE JUNCTION ELEVATION. l l

......__.........________......___.____..___...._____...__.......+l g I

+_____........__.._____ ..__+

5 l CNTRLVAR 88 = CNTRLVAR 90 l Figure A-7. Vent Valve Control Block Diagram A-22 ,

I; 1

l

E L

REFERENCES E

A-1 Samuel L. Thompson. " Thermal-Hydraulic Analysis Research Program Quarterly Report, January-March 1982." NUREG/CR-2843, Vol. 1. Sandia National Laboratories, October 1982.

A-2 John Klingenfus, " Review of Vent Valve Performance and Cold Leg Mixing,"

Presentation to the B&W Owners Group, NRC Meeti1g, March 3, 198..

L

[

E E

E E

Y

[

[

[

A-23 uusis i __ _ . _ _ __ _

[

g E

Appendix B FUEL CLADDING SURFACE TEMPERATURE This appendix presents twelve fuel cladding temperature plots - one for each RELAPS case run. The cases are presented in order of case number. The

[ temperatures plotted are for the surface of the top heat slab in the core. The other core temperatures were observed to have similar behavior.

Note that in all cases the maximum temperature occurred during normal, steady-state operation. After scram occurred, the temperature remained well below the steady-state temperature.

E E

E E

[

[

[

[

B-1 h ini ,. . ...

I g SINGLE TUBE RUPTURE CASE 1 i

e i i g

I 8 - -

I e

o W

O a g

Wa x

D t--

I W

O.

E

~8 - -

W U

l LL D

l

'D o g

o$ -

< 3

._J U

a W

D O, _

I I

-5 0 5 10 15 TIME AFTER RUPTURE (MINUTES) l Figure B-1. Single Tube Rupture Case 1 e.2 I I

r I SINGLE TUBE RUPTURE CASE 2 g

to e i i i i i i i i i I

g - -

c I 0 W

8 w@

D I }-

W I Q.

Z W8 _ _

F- sn W

U I LL D

W o I ~ "

O N J

U I a W

D l

1g* _ _

I I -

g i i i I I I i i i i I

-5 0 5 10 15 20 25 30 35 40 45 50 55 l TIME AFTER RUPTURE (MINUTES)

Figure B-2. Single Tube Rupture Case 2 I

g e.3 I

g to i SINGLE TUBE RUPTURE CASE 3 I I I I I I I I I

I J I

gl cw a W 3 9

Wy - -

K D

F-W Q

x B W8 _ _ a F- n W

U LL

& a D

M o E o@ ~ ~

_J U

l

_J B W 5 D

LL o 0 - -

I o g h l l l l l l l l l E

-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

Figure B-3. Single Case Rupture Case 3 I

e-4 l

I

I o TEN TUBE RUPTURE CASE 4

$ i i i e i e i i i i i i I

I I E - -

c0 I W 9

I W CL@

D I F--

W I Q.

I WO F- in I W U

LL I T D

W o

~

~

O N I <

__J U

i -J W

D

, 3 '8* _

l 5 I

l I o

-5 I

0 I

5 I

10 I

15 I

20 l

25 30 1 1 35 I

40 45 l I 50 l

55 1

60 65 g TIME AFTER RUPTURE (MINUTES)

, ngure e-4. Ten Tube au gure a se 4 I s.s I

l

! o TEN TUBE RUPTURE CASE 5 i i i i I I

8 o

S O

W Q

Wh x

- - I D E F-

< l W

Q.

E w8 I- in W

U LL E E D 3 W o

~

O N

__J U

_J W

D 8, _ -

I O

m 1 i i i i i

-5 0 5 to 15 20 25 30 TIME AFTER RUPTURE (MINUTES) l B-5. Ten Tube Rupture Case 5 I

B-6 I

i j o TEN TUBE RUPTURE CASE 6

! $ i i i i i I i I l l 8-cO I w 9

I wg T

\

D I

I l-Z w i I Q_

I W8 F- n I W U

I 1.L T

D O ~

I

~

g3 E

__J U

I a W

D I ' 8, _

I h i i 1 I I

-5 0 5 10 15 20 25 30 35 g TIME AFTER RUPTURE (MINUTES)

Figure B-6. Ten Tube Rupture Case 6 I

I e-7 I

. . . . i

o

$. I FIVE - FIVE TUBE RUPTURE CASE 7 i i i i i i i i i i i I

~ ~

I l I l e

w I

o h gs 2

l l-w h - -

W e

o a0 h 3 d E

$ k/ I 8

I

~

l

\

V I h I i i i i i I i i i i i I

-10 0 10 20 30 40 50 00 70 80 90 100 110 120 130 TIME AFTER RUPTURE (MINUTES)

Figure B-7. Five - Five Tube Rupture Case 7 I

I e-8 l

I

I o

$ i i TEN TUBE RUPTURE CASE 8 i i i i i I I I ,

I I

- ~

E c

I Pu l

I Su D

N -

I B W8 wo - -

I ti Li.

I i W o aN ~ ~

U I d D

'8 I _ -

I h 1 i i I I I I

-5 0 5 10 15 20 25 30 35 40 45 TIME AFTER RUPTURE (MINUTES)

Figure B-8. Ten Tube Rupture Case 8 I

I e-e I

o ~ TEN TUBE RUPTURE CASE 9 ~

g l- i i n i i i i 1 i i i i

]

I t  !

3 i ,

I I

^ t i ,

I Lt.  !  !

I L3 l E LLI O

E v

ta g - - i x

D H '

x I w

Q.

X wo sg - -

i s

w U

Li. -',  !

x D

W o m - -

OS

< l J [ i U .

_J '

W D \

LL o

? - ~

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