NUREG/CR-2726

SAND82-1137

R3

Printed August 1983

Light Water Reactor Hydrogen Manual

Allen L. Camp, John C. Cummings, Martin P. Sherman,

Chester F. Kupiec, Robert J. Healy, Jeffrey S. Caplan,

John R. Sandhop, James H. Saunders

Prepared by

Sandia National Laboratories. W' , 0

Albuquerque, New Mexico 87185 and Livermore, California 94550 ' ,'j, ,

for the United States Department of Energy

under Contract DE-AC04-76DP00789 i ,

and

General Physics Corporation,

1000 Century Plaza , ,

Columbia, Maryland 21044

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!i I:'•

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Prepared for1

U. S. NUCLEAR REGULATORY COMMISSION
NOTICE

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United

States Government nor any agency thereof, or any of their employees, makes any warranty, expressed or implied, or assumes any

legal liability or responsibility for any third party's use, or the

results of such use, of any information, apparatus product or process disclosed in this report, or represents that its use by such

third party would not infringe privately owned rights.

Available from

GPO Sales Program

Division of Technical Information and Document Control

U.S. Nuclear Regulatory Commission

Washington, D.C. 20555

and

National Technical Information Service

Springfield, Virginia 22161
NUREG/CR-2726

SAND82-1137

R3

LIGHT WATER REACTOR HYDROGEN MANUAL

SANDIA NATIONAL LABORATORIES

Allen L. Camp

John C. Cummings

Martin P. Sherman

GENERAL PHYSICS CORPORATION

Chester F. Kupiec

Robert J. Healy

Jeffrey S. Caplan

John R. Sandhop

James H. Saunders

Manuscript Completed: January, 1983

Date Published: June, 1983

Sandia National Laboratories

Albuquerque, NM 87185

Operated By

Sandia Corporation

for the

U. S. Department of Energy

Prepared for

Division of Accident Evaluation

Office of Nuclear Regulatory Research

U. S. Nuclear Regulatory Commission

Washington, D.C. 20555

Under Memorandum of Understanding DOE 40-550-75

NRC FIN No. A 1246
Author's Note

While there are no current plans for updating this manual, persons who wish to

point out errors or suggest revisions should send comments to the address

shown below. If time and funding permits, we will attempt to pass on these

comments to other recipients of the manual in an appropriate manner.

Reactor Safety Studies

Division 9441

Sandia National Laboratories

P. 0. Box 5800

Albuquerque, NM 87185

ii
ABSTRACT

A manual concerning the behavior of hydrogen in light water reactors has

been prepared. Both normal operations and accident situations are addressed.

Topics considered include hydrogen generation, transport and mixing, detection,

and combustion, and mitigation. Basic physical and chemical phenomena are

described, and plant-specific examples are provided where appropriate. A wide

variety of readers, including operators, designers, and NRC staff, will find

parts of this manual useful. Different sections are written at different

levels, according to the most likely audience. The manual is not intended to

provide specific plant procedures, but rather, to provide general guidance

that may assist in the development of such procuedures.

iii
TABLE OF CONTENTS

Pag e

Chapter 1 - Introduction and Objectives 1-1

1.1 Statement of the Problem 1-1

1.2 Hydrogen Problems in LWRs 1-1

1.3 Hydrogen Research Efforts 1-2

1.4 Description of Manual 1-4

Chapter 2 - Hydrogen in Light Water Reactors 2-1

2.1 Production of Hydrogen 2-1

2.1.1 Summary 2-1

2.1.2 Steam:Zirconium Reaction 2-1

2.1.3 Steam:Steel Reaction 2-3

2.1.4 Radiolysis of Water 2-7

2.1.5 Core:Concrete Interactions 2-10

2.1.6 Other Sources 2-13

2.1.7 Time Sequence of Hydrogen Production 2-16

2.2 Hydrogen Solubility, Transport, and Mixing 2-19

2.2.1 Introduction 2-19

2.2.2 Solubility of Hydrogen in Water 2-19

2.2.3 Transport and Mixing Within Containment 2-24

2.2.4 Air:Steam:Hydrogen Concentration Within Containment 2-26

2.3 Combustion of Hydrogen 2-28

2.3.1 Introduction 2-28

2.3.2 Example Calculation 2-28

2.3.3 Conditions Necessary for Combustion 2-36

2.3.4 Deflagrations 2-42

2.3.5 Combustion of a Steam:Hydrogen Jet 2-47

2.3.6 Detonation of Hydrogen 2-49

2.3.6.1 Detonation Limits 2-49

2.3.6.2 Transition to Detonation 2-54

2.3.6.3 Detonation Pressures and Temperatures 2-54

2.3.6.4 Local Detonations 2-55

2.3.6.5 Missile Generation 2-59

2.4 Mitigation Schemes 2-60

2.4.1 Deliberate Ignition 2-60

2.4.2 Water Sprays, Fogs and Foams 2-61

2.4.3 Pre-Accident Inerting 2-61

2.4.4 Post-Accident Inerting 2-65

2.4.5 Partial Pre-Inerting 2-65

2.4.6 High-Point-Vent Flaring 2-66

2.4.7 Other Methods 2-66

iv
Page

Chapter 3 - Hydrogen Behavior and Control--Normal Operation 3-1

3.1 Introduction 3-1

3.2 Hydrogen Considerations Common to PWRs and BWRs 3-1

3.2.1 Radiolysis 3-1

3.2.2 Radiation Synthesis 3-2

3.2.3 Control of Hydrogen from Radiolysis and Radiation

Synthesis 3-3

3.2.4 Corrosion 3-4

3.2.5 Electrical Generators 3-8

3.2.6 Hydrogen Bulk Storage Facility 3-11

3.2.7 Gas Chromatography 3-12

3.2.8 Battery Room 3-12

3.2.9 Resin Beds 3-13

3.3 Hydrogen Considerations Specific to PWRs 3-13

3.3.1 Reactor Coolant System 3-14

3.3.1.1 Pressurizer 3-14

3.3.1.2 Control Rod Drive Mechanisms 3-16

3.3.1.3 RCS Leakage 3-18

3.3.2 Chemical and Volume Control System 3-18

3.3.3 Containment Entry 3-19

3.3.4 Gaseous Waste Disposal 3-19

3.4 Hydrogen Considerations'Specific to BWRs 3-22

3.4.1 Reactor Coolant System 3-22

3.4.2 Off-Gas System 3-22

3.4.3 Chemistry 3-27

3.4.4 Containment Entry 3-27

Chapter 4 - Hydrogen Behavior and Controi--Accident Conditions 4-1

4.1 Introduction 4-1

4.2 Containment Structure and Integrity 4-1

4.2.1 LWR Containment Comparison 4-1

4.2.2 PWR Containments 4-4

4.2.3 BWR Continments 4-7

4.3 Indications of a Loss-of-Coolant Accident 4-10

4.3.1 Introduction 4-10

4.3.2 PWR Indications Internal to the Reactor

Coolant System 4-13

4.3.2.1 Temperature 4-13

4.3.2.2 Flow 4-13

4.3.2.3 Pressure 4-15

4.3.2.4 Pressurizer Level 4-15

4.3.2.5 Reactor Vessel Water Level 4-17

4.3.2.6 Nuclear Instrumentation 4-17

4.3.3 PWR Indications External to the Reactor

Coolant System 4-22

V
Page

4.3.3.1 Containment Pressure 4-23

4.3.3.2 Containment Temperature 4-23

4.3.3.3 Containment Humidity 4-23

4.3.3.4 Containment Activity 4-23

4.3.3.5 Containment Sump Level 4-23

4.3.4 BWR Indications Internal to the Reactor

Coolant System 4-23

4.3.4.1 Temperature 4-23

4.3.4.2 Flow 4-23

4.3.4.3 Pressure 4-24

4.3.4.4 Reactor Vessel Level 4-24

4.3.4.5 Nuclear Instrumentation 4-28

4.3.5 BWR Indications External to the Reactor

Coolant System 4-28

4.3.5.1 Drywell/Containment Pressure 4-28

4.3.5.2 Drywell/Containment Temperature 4-29

4.3.5.3 Drywell/Containment Activity 4-29

4.3.5.4 Suppression Pool Water Level 4-29

4.4 Indications of Hydrogen Production 4-29

4.4.1 Indications of Hydrogen Production Internal

to the Reactor Coolant System of a PWR 4-30

4.4.1.1 Temperature 4-30

4.4.1.2 Flow 4-30

4.4.1.3 Pressure 4-32

4.4.1.4 Pressurizer Level 4-34

4.4.1.5 Reactor Vessel Water Level 4-34

4.4.1.6 Reactor Coolant Sampling 4-34

4.4.1.7 Reactor Coolant Activity 4-34

4.4.2 Indications of Hydrogen Production External

to the Reactor Coolant System of a PWR 4-38

4.4.2.1 Containment Pressure 4-38

4.4.2.2 Containment Temperature 4-38

4.4.2.3 Containment Humidity 4-38

4.4.2.4 Containment Sampling 4-39

4.4.2.5 Steam Line Radiation 4-40

4.4.2.6 Gross Radiation Level Detection 4-40

4.4.3 Indications of Hydrogen Production Internal

to the Reactor Coolant System of a BWR 4-41

4.4.3.1 Temperature 4-41

4.4.3.2 Flow 4-41

4.4.3.3 Pressure 4-42

4.4.3.4 Reactor Vessel Water Level 4-42

4.4.3.5 Reactor Coolant Activity 4-44

4.4.4 Indications of Hydrogen Production External

to the Reactor Coolant System of a BWR 4-44

4.4.4.1 Drywell/Containment Pressure 4-44

4.4.4.2 Drywell/Containment Temperature 4-46

4.4.4.3 Drywell/Containment Humidity 4-46

4.4.4.4 Drywell/Containment Sampling 4-46

4.4.4.'5 Steam Line Radiation Monitoring 4-47

4.4.4.6 Gross Radiation Level 4-47

4.4.4.7 Sump Leak Detection 4-47

4.4.4.8 Suppression Pool Temperature 4-48

vi
Page

4.5 Hydrogen Detection 4-48

4.5.1 Combustion Detector 4-49

4.5.2 Solid-State Detector 4-50

4.5.3 Electromechanical Detector 4-50

4.5.4 Thermal Conductivity Detector 4-50

4.5.5 Absorption Detector 4-50

4.5.6 Detector Availability 4-51

4.6 Transport and Mixing of Hydrogen 4-51

4.6.1 Introduction 4-51

4.6.2 Hydrogen Transport Pathways in a PWR 4-53

4.6.2.1 Hydrogen Transport Through the Reactor

Vessel Head Vent 4-53

4.6.2.2 Hydrogen Transport Through the Hot Leg

and Cold Leg Piping 4-57

4.6.2.3 Hydrogen Transport Into the Pressurizer

and Pressurizer Relief Tank 4-58

4.6.2.4 Hydrogen Transport From Containment to

Other Buildings 4-60

4.6.2.5 Considerations to Minimize Hydrogen

Transport to Other Buildings 4-62

4.6.3 General Hydrogen Transport Pathways in a BWR 4-63

4.6.3.1 Hydrogen Transport Through a Reactor Coolant

System Break 4-63

4.6.3.2 Hydrogen Transport Through a Stuck Open

Safety/Relief Valve to the Suppression Pool 4-66

4.6.3.3 Primary Containment Leakage to the Secondary

Containment (Mark I and II BWR Designs) 4-66

4.6.3.4 Hydrogen Transport via the Drywell Purge

System and Vacuum Breaker 4-68

4.6.3.5 Hydrogen Transport Through the Bypass Leakage

Paths From the Drywell 4-70

4.6.3.6 Considerations to Minimize Hydrogen Release

to Other Buildings 4-72

4.6.4 Air Handling Fans 4-74

4.7 Hydrogen Combustion 4-74

4.7.1 introduction 4-74

4.7.2 Potential Sources of Accidental Hydrogen

Ignition 4-75

4.7.3 Evidence of Hydrogen Combustion in PWRs 4-76

4.7.3.1 Containment Pressure Effects 4-77

4.7.3.2 Pressurizer Pressure Effects 4-77

4.7.3.3 Steam Generator Pressure Effects 4-77

4.7.3.4 Containment Temperature Effects 4-79

4.7.3.5 Containment Gaseous Sampling 4-79

4.7.4 Evidence of Hydrogen Combustion in BWRs 4-79

4.7.4.1 Drywell/Containment Pressure Effects 4-79

4.7.4.2 Drywell/Containment Temperature Effects 4-82

4.7.4.3 Drywell/Containment Gas Samples 4-82

4.7.5 Possible Flame Acceleration Channels 4-82

Vii
Page

4.8 Residual Hydrogen (Postburn) Considerations

in Containment 4-94

4.9 Methods of Controlling Liberated Hydrogen 4-98

4.9.1 Hydrogen Recombiners 4-98

4.9.1.1 Types 4-99

4.9.1.2 Capabilities 4-105

4.9.1.3 Positive and Negative Aspects 4-105

4.9.2 Deliberate Ignition of Hydrogen 4-107

4.9.2.1 Method 4-107

4.9.2.2 Grand Gulf Nuclear Station 4-110

4.9.2.3 Sequoyah Nuclear Plant 4-112

4.9.2.4 Capabilities 4-113

4.9.2.5 Positive and Negative Aspects 4-114

4.9.3 Combination Water Fog or Spray with

Deliberate Ignition 4-114

4.9.3.1 Method 4-114

4.9.3.2 Positive and Negative Aspects 4-117

4.9.4 Short and Long-Term Venting Capabilities 4-118

4.9.4.1 Methods 4-118

4.9.4.2 Venting Times and Capabilities 4-122

4.9.4.3 Positive and Negative Aspects 4-122

4.9.5 Halon Combustion Suppressant System 4-122

4.9.5.1 Halon as a Flame-Quenching Agent 4-122

4.9.5.2 Halon Post-LOCA Hydrogen Suppressant System 4-124

4.9.5.3 Halon Injection Times and Capabilities 4-128

4.9.5.4 Positive and Negative Aspects 4-128

4.9.6 Postaccident-Inerting with Carbon Dioxide 4-129

4.9.6.1 Method 4-129

4.9.6.2 Positive and Negative Aspects 4-129

4.9.7 Pre-Inerting, Partial Pre-Inerting, and

Post-Accident Inerting with Nitrogen 4-129

4.9.7.1 Methods 4-129

4.9.7.2 Positive and Negative Aspects 4-130

4.9.8 Oxygen Removal by a Gas-Turbine 4-131

4.9.8.1 Theory of Operation 4-131

4.9.8.2 Positive and Negative Aspects 4-134

4.9.9 Summary of Control System Positive and

Negative Aspects 4-134

Appendix I - The Three Mile Island Unit 2 Accident Scenario I-1

Appendix II - Gaseous Void Detection and Sizing Reactor Coolant System II-1

Appendix III- Venting Time Period for. Reactor Vessel Head Vent III-1

List of Abbreviations A-1

Glossary G-1

Index X-1

viii
LIST OF FIGURES

Figure Page

2-1 H2 Production Per Unit Area from the Zr:H2 0 Reaction 2-4

2-2 Total H2 Production From the Zr:H2 0 Reaction 2-5

2-3 H2 Production Per Unit Area From the Steel:H2 0 Reaction 2-8

2-4 H2 Production From Zinc-Based Paint 2-14

2-5 H2 Production From Galvanized Steel 2-15

2-6 Hypothetical H2 Production for Various Reactions 2-18

2-7 Henry's Law Constant for Hydrogen in Water 2-21

2-8 Mole Fraction-of Dissolved Hydrogen Under Various Conditions 2-22

2-9 Hydrogen Concentration in Water Under Various Conditions 2-23

2-10 Theoretical Adiabatic, Constant-Volume Combustion

Pressure for Hydrogen:Air Mixtures 2-29

2-11 Theoretical Adiabatic, Constant-Volume Combustion

Temperature for Hydrogen:Air Mixtures 2-30

2-12 Adiabatic, Constant-Volume Combustion Pressure for

Various Containment Initial Conditions 2-31

2-13 Adiabatic, Constant-Volume Combustion Temperature for

Various Containment Initial Conditions 2-32

2-14 Effect of Initial Temperature on Downward Propagating

Flammability Limits in Hydrogen:Air Mixtures 2-38

2-15 Flammability Limits of Hydrogen in Air Diluted'

With CO2 and N2 2-39

2-16 Flammability and Detonation Limits of Hydrogen:Air:Steam

Mixtures 2-40

2-17 Deflagration Limits, H2 :Air:CF3Br(Halon 1301) 2-41

2-18 Spark Ignition Energies for Dry Hydrogen:Air Mixtures 2-43

2-19 Normalized Pressure Rise Versus Hydrogen Concentration 2-44

2-20 Laminar Burning Velocity of Hydrogen:Air Mixtures 2-46

2-21 Minimum Spontaneous Ignition Temperature of

Hydrogen : Air:Steam Mixtures 2-48

2-22 Theoretical Chapman-Jouguet Detonation Velocity for

Hydrogen :Air Mixtures 2-50

2-23 Experimental Measurement of Detonation Cell Size for

Hydrogen:Air Mixtures at Atmospheric Pressure 2-52

2-24 Estimates of Minimum Sizes of Various Geometries for

Detonation Propagation in Terms of Detonation Cell Width 2-53

2-25 Theoretical Detonation Pressure and Normally Reflected Detonation

Pressure for Hydrogen:Air Mixtures 2-56

2-26 Theoretical Detonation Temperature and Normally Reflected

Detonation Temperature for Hydrogen:Air Mixtures 2-57

2-27 Pressure Distribution Behind Planar, Cylindrical, and Spherical

Detonation Fronts When, = 1.4 (Approximation for Hydrogen:Air

Mixtures) 2-58

2-28 Final Temperature as a Function of Initial Hydrogen Concentration

and Volume Fraction of Water Drops 2-62

2-29 Ratio of Final to Initial Pressure as a Function of Initial

Hydrogen Concentration and Volume Fraction of Water Drops 2-63

2-30 Vaporization Time Versus Droplet Radius at Various Combustion

Stoichiometries 2-64

ix
Figure Page

3-1 Chemical & Volume Control System 3-7

3-2 General Arrangement of a Typical Generator Assembly 3-9

3-3 Typical Generator Shaft Seal Assembly 3-10

3-4 Control Rod Drive Mechanism 3-17

3-5 Gaseous Radioactive Waste Disposal System 3-20

3-6 Schematic Diagram of a Typical BWR System 3-23

3-7 Typical Off-Gas System Recombiner Assembly 3-25

4-1 Comparison of Containment Volumes and Design Pressures

(Typical 1200 MWe Plants) 4-2

4-2 Volume Percent Hydrogen in Containment vs. Percent Metal-Water

Reaction Following a LOCA 4-3

4-3 Typical Large Dry Containment 4-5

4-4 Simplified Diagram of Ice Condenser Containment 4-6

4-5 Maine Yankee Containment Post-LOCA Percent Hydrogen Concentration

vs. Time 4-8

4-6 Mark I BWR Drywell/Primary Containment 4-11

4-7 Section View of a Mark III Containment Structure and Internals

(Grand Gulf Nuclear Station) 4-12

4-8 Typical Incore Thermocouple System 4-14

4-9 Typical Pressurizer Pressure and Level Transmitter Arrangement

(Byron & Braidwood - Westinghouse) 4-16

4-10a Heated-Junction Thermocouple Arrangement 4-18

4-10b Heated-Junction Thermocouple (HJTC) Response 4-18

4-11 Radioactive Sources Used for Continuous Level Measurement 4-20

4-12 Detector Locations for the Excore Nuclear Instrumentation

(Typical Westinghouse PWR) 4-21

4-13 Jet Pump Instrumentation Block Diagram 4-25

4-14 Reactor Vessel Level Instrumentation - Simplified Diagram 4-26

4-1.5 Typical Reactor Vessel Level Detector 4-27

4-16 Map of Core Exit Temperatures ( 0 F) at 240-300 Minutes for

the TMI-2 Incident 4-31

4-17 Reactor Vessel Refilled by Manual Initiation of Safety

Injection Core Temperatures Decreasing 4-33

4-18 Typical Heated Reference Leg Level Instrument Inside Drywell

(Referred to as a Yarway Instrument) 4-43

4-19 Typical Cold Reference Leg Level Instrument 4-45

4-20 The TMI Reactor Coolant System Showing Hydrogen Generation

During the Inadequate Core Cooling Condition 4-52

4-21 Reactor Vessel Head Vent 4-55

4-22 Cold Leg Break Steam Flow Path Schematic 4-58

4-23 Babcock and Wilcox Reactor Coolant System Arrangement Low

Profile or Lowered Loop Configuration 4-59

4-24 Babcock and Wilcox Reactor Coolant System Arrangement High

Profile or Raised Loop Configuration 4-60

4-25 Typical PWR Pressurizer Vent System 4-62

4-26 Possible Hydrogen Release Paths From the Containment

Building to the Auxiliary Building (PWR) 4-65

X
Figure Page

4-27 Direct Cycle Reactor System 4-69

4-28 Reactor Vessel Water Level and Primary System Flows

Immediately After a Loss-of-Coolant Accident 4-70

4-29 Main Steam System (Mark I BWR) 4-72

4-30 Drywell Purge System and Post-LOCA Vacuum Relief System 4-74

4-31 Mark I Drywell/Primary Containment Ventilation and Inerting 4-76

4-32 Potential Drywell Leakage Paths for Hydrogen from a BWR

Mark III Design 4-78

4-33 Reactor Building Pressure vs Time 4-83

4-34 Effect of Hydrogen Ignition on Measured Steam Pressures 4-85

4-35 Reactor Building Temperature During Hydrogen Ignition

at Three Mile Island Unit 2 4-86

4-36 Pressure Response to Global Burns 4-88

4-37 Temperature Response to Global Burns 4-88

4-38 Pressure Response to Local Burns 4-89

4-39 Temperature Response to Local Burns 4-89

4-40 Pressure Response to Continuous Burns 4-90

4-41 Temperature Response to Continuous Burns 4-90

4-42 Pressure At Center of Roof In Zion Calculation 4-93

4-43 Simplified Diagram of Ice Condenser Containment 4-95

4-44 Cutaway View of Ice Condenser 4-96

4-45 Plan View - Cubicle Loop (Typical) North Anna Power Station

Units 1 and 2 4-97

4-46 Inside-Containment Thermal Hydrogen Recombiner 4-100

4-47 Schematic of Recombiner System 4-101

4-48 Thermal Recombiner Package 4-103

4-49 Schematic Representation of the Outside-Containment Thermal

Re combiner 4-104

4-50 Reactor Coolant System Gas Vent (PWR) 4-120

4-51 Conceptual Diagram of Halon 1301 Post-LOCA Hydrogen

Suppression System for Ice Condenser 4-125

4-52 Diagram of Valving and Piping for Five Halon Storage Vessels 4-126

4-53 Gas Turbine Combuster System Schematic 4-133

I-1 TMI-2 Scenario: Initial Conditions - System Steady at 97%

Power Operating Conditions 1-2

1-2 Three Mile Island Unit 2 Plant Arrangement 1-4

1-3 TMI-2 Scenario: System Nearly Liquid Solid. Liquid expanding

with increasing temperatures 1-5

1-4 TMI-2 Scenario: Reactor Coolant Pressure and Pressurizer

Level vs Time 1-6

I-5 TMI-2 Scenario: Following Bursting of the Quench Tank Rupture

Disk, Water Flowed to the Containment Sump, From Which It

Was Pumped to the Auxiliary Building 1-7

1-6 TMI-2 Scenario: Primary System Pressure and Temperatures Nearly

Constant Following Secondary Steam Condition. Primary voids

increasing I-8

1-7 TMI-2 Scenario: Loop A Pumps Operating. Loop B stagnant after

shutdown of Loop B pumps. Primary voids increasing 1-9

xi
Figure Page

I-8 TMI-2 Scenario: Source Range Indication vs. Time 1-10

1-9 TMI-2 Scenario: All Pumps Off. Reactor core drying out and

heating up. Superheated steam flowing to pressurizer and to

one steam generator and condensing I-ll

1-10 TMI-2 Scenario: Core Dryout and Heatup Continuing. Hydrogen

generation by steam zirconium reaction in hotter regions 1-12

I-ll TMI-2 Scenario: Core Partially Quenched by Fluid During Loop B

Pump Start. Heatup resumes I-14

1-12 TMI-2 Reactor Vessel Refilled by Manual Initiation of Safety

Injection. Core temperatures decreasing 1-15

1-13 TMI-2 Scenario: System Pressurized by High Pressure Injection

System. Intermittent liquid release through top of pressurizer

Heat removal by heatup of injected water. Heat steam generator

heat transfer blocked by hydrogen 1-16

1-14 TMI-2 Scenario: Primary System Depressurizing and Releasing

Hydrogen Through the Pressurizer Into the Containment 1-17

1-15 TMI-2 Scenario: Reactor Building Pressure vs Time 1-18

1-16 TMI-2 Primary System Pressurizer Reaches a Minimum Pressurizer

Temperature Returns to Saturated Condition. Liquid in system

maintained during depressurization by high pressure injection

and core flood tanks 1-20

1-17 TMI-2 Scenario: Steam Generators Blocked by Hydrogen. Reactor

vessel level decreasing. Primary system pressure increasing.

Minimal make-up flow 1-21

1-18 TMI-2 Scenario: System Repressurized by High Pressure Injection.

Natural'circulation to steam generators blocked by hydrogen 1-22

1-19 TMI-2 Scenario: Forced Circulation Reestablished in Loop A'

With Heat Removal Via Loop a Steam Generator 1-23

1-20 TMI-2 Scenario: Radioactive RCS Water Pumped From Containment

to the Auxiliary Building 1-25

1-21 TMI-2 Scenario: Reactor Building Temperatures During Hydrogen

Ignition 1-26

1-22 TMI-2 Scenario: Effect Hydrogen Ignition on Measured Steam

Pressures 1-27

1-23 TMI-2 Scenario: Pressure Rises Resulting From Ignition of

Hydrogen in Air in 12 Foot Diameter Sphere at 18'C 1-29

1-24 TMI-2 Scenario: Core Water Level-Time Approximately 135-142

Minutes After Turbine Trip 1-30

1-25 Approximate Thermionic Response of a Self-Powered Neutron

Detector (Typical) 1-31

1-26 TMI-2 Scenario: Map of Core Exit Temperature (9 0 F), 240-300

Minutes 1-32

1-27 TMI-2 Scenario: Source Range Neutron Detector Field of View

vs. Core Mixture Level 1-33

1-28 TMI-2 Scenario: Source Range Trace During the Incident 1-34

III-1 Reactor Coolant System Pressure vs. Hydrogen Flow Rate 111-3

xii
Acknowledgments o

Any task as large and comprehensive as preparing this manual requires

the cooperation of a large number of people. In this case, we received

valuable comments and assistance from a variety of sources including the NRC,

utilities, vendors, architect-engineers, consultants, and Sandia and General

Physics staff. Listed below are many of the people who have helped with this

effort. We apologize to anyone we may have overlooked.

Cliff Anderson

U. S. Nuclear Regulatory Commission

David Bigbee

Mississippi Power and Light Company

John D. Boyajian

Combustion Engineering Incorporated

Gilbert Brown

Stone & Webster Engineering Corporation

Nelson Brown

General Public Utilities

Three Mile Island Nuclear Station

Jim Carter

Technology for Energy Corporation

Scott B. Coon

General Physics Corporation

Russel DeVore

Pennsylvania Power & Light

Gary J. Dickleman

General Physics Corporation

Jim Dickson

Indiana and Michigan Electric Company

James E. Flaherty

GPU Nuclear

Edward L. Fuller

Technology for Energy Corporation

Roger Garner

Virginia Electric & Power Company

Sam Hobbs

Mississippi Power & Light Company

xiii
Andrew Hogg

Virginia Electric & Power Company

Kevin Holtzclaw

General Electric Company

Gregory Hudson

Duke Power Company

Elaine E. Huff

General Physics Corporation

Phil Lain

Westinghouse Electric Corporation

John T. Larkins

U. S. Nuclear Regulatory Commission

Robert Leyse

Electric Power Research Institute

David Nelson

Donald C. Cook Nuclear Station

Indiana & Michigan Electric Company

William J. Newell

General Physics Corporation

Dan Patton

Bechtel Power Corporation

Douglas L. Reeder

EG&G

John Richardson

Mississippi Power and Light Company

Carl Schultz

Zion Nuclear Power Station

Commonwealth Edison Company

Robert Stratman

Cleveland Electric Illuminating Company

Joanne M. Sutch

General Physics Corporation

Loren Thompson

Electric Power Research Institute

Edouard H. Trottier

General Physics Corporation

xiv
Kenneth Vehstedt

American Electric Power Service Corporation

S. Visner

Institute of Nuclear Power Operations

Andre Kevin White

Virginia Electric & Power Company

Elvin L. Wilson

Virginia Electric & Power Company

Pat Worthington

U. S. Nuclear Regulatory Commission

Edwin Zebroski

Institute of Nuclear Power Operations

Joseph N. Zerbo

General Physics Corporation

Sandia National Laboratories:

M. Berman, 9441

R. K. Cole, 9441

V. M. Loyola, 2513

E. W. Shepherd, 9441

R. G. Spulak, 9412

xv

CHAPTER 1

INTRODUCTION AND OBJECTIVES

1.1 STATEMENT OF THE PROBLEM

Since the accident at Three Mile Island (TMI), there has been a great

deal of interest regarding the problem of hydrogen production and combustion

in light water reactors (LWRs). As discussed in detail in Appendix I, it

appears that, during the TMI accident, the core was uncovered for a time, and

significant quantities of hydrogen were produced and released into containment. This hydrogen eventually ignited and resulted in about a 28 psig (192

kPag) peak pressure within containment. While this particular event did not

endanger the TMI containment, there is concern that other, weaker containments

might be vulnerable to hydrogen combustion or that more severe pressure rises

might be seen under other accident conditions. In addition to the TMI accident, there have also been several incidents where hydrogen combustion occurred in off-gas systems.

Because of the above concerns and the interest shown regarding these

problems, Sandia National Laboratories and General Physics Corporation, under

the sponsorship of the Nuclear Regulatory Commission, prepared this manual.

It is intended to provide information at a general but comprehensive level on

the subject of hydrogen behavior. Numerous references are cited -to provide

more details on particular subjects. The manual is directed toward a wide

variety of potential readers. The basic physical and chemical phenomena are

discussed in order to provide a framework for later chapters. The phenomenological discussion also includes subjects which are topics of current research

efforts, and therefore contain some uncertainties. In addition to providing

background information for the remainder of the manual, the basic discussions

(and the sections on mitigation systems) may be useful to plant designers.

The sections on hydrogen behavior during normal *operation should be useful to

operators and supervisors. The sections on behavior during accidents may be

of additional value to utility personnel and to NRC staff..

The manual is not intended to replace specific plant manuals, or to provide procedural directions to operators. Rather, this report is intended as a

guide to utility staff when they are formulating their own plant-specific procedures. Note that it is not the purpose of this manual to predict the likelihood of hydrogen-generating accidents or- assess the radiological consequences of such accidents.

1.2 HYDROGEN PROBLEMS IN LWRs

The major concerns regarding hydrogen are that the static or dynamic

pressure loads from combustion may breach containment or that important,

safety-related equipment may be damaged due to either pressure loads or high

temperatures. In order to assess the possible threats, it is necessary to

understand how hydrogen is produced, how it is transported and mixed within

containment, and how it combusts.

1-1
The major production mechanisms are steam:zirconium reactions,

steam:steel reactions, radiolysis of water, core:concrete interactions, and

corrosion of zinc and aluminum. A discussion of the conditions necessary for

these reactions to occur and reaction kinetics is presented in Chapter 2.

Hydrogen transport and mixing involve transport out of the primary system

(accounting for the hydrogen remaining dissolved in water.) and mixing within

the containment atmosphere due to forced and natural convection and diffusion. Transport and mixing determine where, when, and for how long certain

combustible mixtures are likely to be present. Combustion can occur if the

mixture meets certain flammability criteria and an ignition source is present. The presence of steam, carbon dioxide, or other diluents can have a significant effect upon combustion. The basic processes mentioned above are discussed in Chapter 2.

Once the basics are understood, we can address hydrogen behavior in various types of reactors during different situations. As discussed in Chapter 3,

hydrogen control is an important part of normal plant operations. Most reactors employ some type of gas treatment system to deal with hydrogen and other

gases. Some reactors deliberately maintain certain levels of hydrogen in the

coolant in order to reduce the oxygen inventory.

If a loss-of-coolant accident (LOCA) occurs, then there exists the potential to produce large quantities of hydrogen. Normally, core uncovery is

necessary (but not sufficient) for significant hydrogen generation. The particular accident scenario dictates the timing and rate of hydrogen generation. Chapter 4 deals with hydrogen behavior in various types of reactors

during accident situations.

1.3 HYDROGEN RESEARCH EFFORTS

There are three major research programs in progress that address issues

of hydrogen behavior in LWRs: two industry-sponsored programs and one

NRC-sponsored program. The industry-sponsored programs are the Electric Power

Research Institute (EPRI) programI-I to investigate hydrogen combustion and

control, and the Industry Degraded Core Rulemaking (IDCOR) programI-2 which

deals with a broad range of subjects includig hydrogen. The NRC-sponsored

programI-3 deals with hydrogen production, transport, combustion, and control.

The EPRI program focuses on hydrogen combustion behavior with studies of

the deliberate ignition, water fog, and water spray approaches to hydrogen

control. The primary near-term objective is to determine and demonstrate

methods of effective hydrogen control so that the integrity of containment and

safety-related equipment can be ensured. Several projects have been initiated

for investigation of the following issues:

1. Lower flammability limits in nuclear reactor accident environments and effectiveness of various ignition sources;

2. Character of deflagrations in nuclear reactor containments and

effectiveness of control or mitigation methods;

1-2
3. Nature of hydrogen mixing and distribution in large compartmentalized volumes with both natural and forced convection processes; and

4. Potential for acceleration of deflagrations or transition to

detonation, and effectiveness of control methods.

The effects of hydrogen combustion on nuclear safety-related equipment have

been studied in conjunction with other tests, and model development activities

have been initiated. The experimental work in this program is being accomplished in test volumes ranging in size from 0.6 to 75,000 ft 3 (17 liters to

2100 m3 ).

The IDCOR program is being managed by the Technology for Energy Corporation. While the IDCOR program involves many phenomena associated with degraded-core accidents in general, specific tasks related to hydrogen include:

1. Determine the rate and amount of zirconium oxidation and hydrogen generation during severe accidents;

2. Determine the hydrogen distribution in containment;

3. Determine the combustion limits of H2 :air:steam:CO2 mixtures;

4. Survey hydrogen and oxygen detectors;

5. Evaluate pre-inerting as a mitigation scheme;

6. Evaluate fog/spray suppression;

7. Evaluate controlled burn and extinguishing systems; and

8. Identify a minimum set of equipment and evaluate the capability

to survive a degraded-core environment.

Some of the above tasks are being carried out in conjunction with the EPRI

program.

The NRC-sponsored program is managed by Sandia National Laboratories.

The program involves assessment of the threat to nuclear power plants (containment structure, safety and control equipment, and the primary system)

posed by hydrogen combustion; assessment of proposed hydrogen control and disposal methods; and development of new concepts. The program includes analytical modelling, computer simulation, and experimentation on several scales.

The analysis portion of the program can be broken down into the use of existing computer codes; the development of new or significantly modified computer

codes (specific to LWR hydrogen problems); and the development of simple

models or correlations.

The experimental portion of the Sandia program consists of tests (and

supporting analyses) in a variety of facilities ranging from laboratory scale

to field scale. A large portion of the experimental work has been conducted

1-3
in two cylindrical tanks. A steam:H2 jet facility is being used to investigate autoignition and flame stability phenomena. A field-scale channel called

"FLAME" will soon be available to study the effects of obstacles and venting

on flame acceleration. In addition, a cooperative program with McGill University is under way to investigate flame acceleration, deflagration-to-detonation transition, and flame quenching.

1.4 DESCRIPTION OF MANUAL

Chapter 2 is intended to be a discussion of basic phenomena related to

hydrogen. Production, transport and mixing, combustion, and mitigation are

all discussed in some detail. Chapter 3 examines hydrogen behavior and control in reactors during normal operation, paying particular attention to

chemical and off-gas systems. Chapter 4 examines hydrogen behavior and control in reactors during accident conditions. Indications of hydrogen production and combustion are discussed along with some observations and recommendations for particular types of reactors. Appendix I presents a description of

what happened at TMI with regard to hydrogen, to the best of our knowledge at

present. Appendix II examines the detection and sizing of gaseous voids in

reactor coolant systems, and Appendix III discusses reactor vessel head venting.

References for Chapter 1

1-1 L. Thompson, "EPRI Research on Hydrogen Combustion and Control for

Nuclear Reactor Safety," Electric Power Research Institute, Proceedings

of the Fourth World Hydrogen Energy Conference, Pasadena, CA, New York,

Pergamon Press (1982).

1-2 Personal Communication from E. L. Fuller, Technology for Energy Corporation (April 6, 1982).

1.3 J. C. Cummings and M. Berman, "Hydrogen Behavior and Control Studies at

Sandia National Laboratories," SAND82-0870A, Sandia National Laboratories.

1-4
CHAPTER 2

HYDROGEN IN LIGHT WATER REACTORS

2.1 PRODUCTION OF HYDROGEN

2.1.1 Summary

There are a number of potential sources of hydrogen during a severe reactor accident. The two most important reactions producing hydrogen are:

Steam:zirconium and

Steam:steel.

Other important sources of hydrogen are:

Radiolysis of water,

Core:concrete,

Corrosion of zinc-based paint and galvanized steel, and

Corrosion of aluminum.

The steam:zirconium and steam:steel reactions are the most important

early in the accident (first few hours). In the event that the core falls

through the bottom of the vessel, core:concrete interactions become important. Radiolysis and corrosion can produce significant quantities of hydrogen, but over longer time periods (many hours to several days). Each of the

six reactions is discussed in more detail below. The chemistry of some of

these processes is very complex and not well understood. A large fraction of

the information presented is taken from Ref. 2-1. Numerous other references

are provided here and in Ref. 2-1 for those who wish for more details.

2.1.2 Steam:Zirconium Reaction

Steam and zirconium can react to produce hydrogen any time that the zirconium is heated to a sufficiently high temperature and an adequate supply of

steam is present. Typically, a zirconium temperature in excess of 1832°F

(1000C) is required to produce a high reaction rate2- 1 , indicating that the

steam:zirconium reaction is only important when the reactor core is partially

or completely uncovered.

The chemical formula for the reaction of zirconium with steam is:

Zr + 2H2 0 - -ZrO 2 + 2H2 + Energy (Heat) (2-1)

Thus for every mole of zirconium reacted, two moles of hydrogen are produced

(or 0.044 lbm of H2 per lbm of Zr reacted). The reaction is exothermic,

2-1
releasing 2765 Btu/lbm of zirconium reacted (140 kcal/gm-mole). By assuming

that all of the available zirconium reacts, one can estimate the maximum

amount of hydrogen that can be released from this reaction. Note that some

small amount of zirconium may react with the U02 , and thus not be available

to react with steam. Typical numbers are 2200 lbm (1000 kg) of hydrogen for a

PWR and 4400 lbm (2000 kg) of hydrogen for a BWR 2 -. These numbers will

vary depending on the size of the reactor and the number of fuel assemblies in

the core.

The rate at which hydrogen is produced from the steam:zirconium reaction

depends upon the accident scenario, and in particular, upon the clad temperature and availability of steam. Assuming that steam is present in sufficient

quantities, the amount of zirconium reacted as a function of time and temperature can be calculated from the following expression 2 - 2 :

W = K(T)t (2-2) zr

Wzr = the mass of metal reacted per unit surface area,

lbm/ft 2 (kg/m 2 ).

K(T) = an experimentally determined parabolic rate constant,

lbm2 /ft 4 /s (kg 2 /m4 /s).

t = the time, s

K(T) is usually expressed in the following form:

K(T) = A exp[-B/RT] (2-3)

where A is a constant, B is the activation energy, and R is the gas constant.

Numerous values for K(T) exist in the literature, but the Cathcart-Pawel 2 -3

formulation is typical:

A = 12.3 lbm2 /ft 4 /s (294 kg 2 /m4 /s)

B = 7.195 x 104 Btu/ib-mole(l.672 x 10 8 J/kg-mole)

R = 1.98583 Btu/lb-mole/°R(8.31429 x 10 3 J/kg-mole/K)

Knowing that the reaction of 1.0 lbm of zirconium with steam will produce

0.044 lbm of hydrogen, we can combine the previous equations in order to determine the amount of hydrogen produced per unit surface area as a function of

time:

2-2
W = 0.044[12.3 exp[-7.195 x 104 /1.98583/T]t]I/2 ibm (2-4) 2 ft 2

or

W = 0.044[294 exp[l.672 x 10 8/8.31429 x 10 3/Tt] 1 / 2 kg (2-5)

H2 m2

where T is in OR for the first equation and is in K for the second equation.

Figure 2-1 shows examples of hydrogen production for four different clad

temperatures. The total area of cladding in a TMI-type reactor is roughly

5.27 x 104 ft 2 (4.9 x 10 3 m2 ). Figure 2-2 shows the same examples as

Fig. 2-1, while factoring in the clad surface area. These numbers will, of

course, vary from plant to plant.

It should be emphasized that the reaction is exothermic and tends to

drive itself once started. The heat of reaction can dominate other heating

mechanisms above about 1832 0 F (1000 0 C). It should also be emphasized that the

reaction rate depends very much upon the accident scenario. The temperature

must be high enough (requires uncovered core) and a supply of steam must be

present.

Once the core starts to slump, what happens is uncertain. If a core at a

very high temperature falls into water at the bottom of the vessel, rapid production of steam and hydrogen may occur. However, the production rates will

depend on how the core slumps, with the important parameters being the molten

core particle size, available surface area, the temperature, and the amount of

unreacted zirconium remaining.

2.1.3 Steam:Steel Reaction

Large quantities of steel are present within the walls of the reactor

vessel, the core support structures, and other objects within a reactor. This

steel may be oxidized to produce hydrogen when it is heated to high temperatures and exposed to steam. Oxidation of steel by high temperature steam is

highly complex, and several different oxide forms are possible. Fe 3 04 is

a major product; however other forms involving Fe, Cr, and Ni are possible2 - 4 . As with the oxidation of zirconium, these reactions are exothermic,

releasing -277.6 Btu/lbm of steel reacted (-8.6 kcal/gm-mole), depending upon

the composition of the steel.

Normally, the oxidation of steel is not important below temperatures of

about 2192OF (1200 0 C), and prolonged core uncovery would probably be required

to achieve these temperatures. However, as the melting point of steel is

approached at 2498-2732OF (1370 0 -1500*C), the oxidation rate of steel can

become much larger than that of zirconium.

2-3
H2 PRODUCTION

0.042 0.21

ClQ T =35000 R 0.18 07 %0.035- (1944K) E

E

0.15 <

W 0.028- T=3000°R w

(1667K)

0.12 t- Z/ z

: 0.021-

J.. T=2660O 0.09n w

04 (1478K) C14 x 0.014- IU- 0.06 U0 0

Cl, Cln coT= 2300°R Clo

< 0.007 0.203 o <

0.000 0.00

100 5 101 50 10 2 500 103 5000 104

TIME (s)

Figure 2-1. H Production Per Unit Area From The Zr:H 0 Reaction

22
H2 PRODUCTION

2400.0

E

0

Cl,

C0)

1000.0

800.0

600.0 ej

0

C0,

400.0 C)

200.0

!-

100 5 101 50 102 500 103

500 0.00

5000 104

TIME(s)

Figure 2-2. Total H2 Production From The Zr:H20 Reaction
Investigations into the oxidation kinetics of steel indicate that two

stages of oxidation exist 2 - 5 . The oxidation is characterized initially

(5-30 minutes) by linear kinetics:

AWsteel = [225.1 exp(-7.99 x 10 4 /RT]t lbm/ft 2 (2-6)

where

AWsteel = mass gained per unit of steel surface

R = gas constant = 1.98583 Btu/lb-mole/OR

T = temperature (OR)

t = time (s)

or

AWsteel = [1.1 x 103 exp(-4.44 x 10 4 /RT)]t kg/m 2 (2-7)

where

R = gas constant = 1.98583 cal/gm-mole/K

T = temperature (K)

The second stage of steel oxidation is characterized by parabolic kinetics:

AWsteel = [1.005 x 107 exp(-l.519 x 10 5 /RT)] 1 / 2 tl/ 2 lbm/ft 2 (2-8)

or

AWsteel = [2.4 x 108 exp(-8.43 x 10 4/RT)] 1 / 2 tI/ 2 kg/m 2 (2-9)

where the symbols are those defined above. The mass of hydrogen generated can

be determined from

= 222s2eeI - (2-10) WH2 M02 see

where

W H= the mass of hydrogen produced per unit of steel surface H2 (in same units as AWsteel)

M H = the molecular weight of hydrogen = 2.002

2-6
M0 = the molecular weight of oxygen = 31.998

2 = the number of hydrogen moles produced for each mole of

oxygen reacted.

Figure 2-3 shows a plot of hydrogen production versus time for four different

temperatures. For these calculations we have assumed that linear kinetics

govern the production rate.

In order to calculate the hydrogen production from the steam:steel reaction for a particular reactor we need to estimate the surface area of steel in

a reactor that would be exposed to steam and could be expected to reach the

necessary temperatures. Such steel surfaces as control-rod cladding, core

barrels, control-rod guide tubes, and core support plates should be considered. Additionally, if core slump occurs, then the bottom of the reactor

vessel and nearby structures should be considered. Typically, a few thousand

square feet of steel may have the potential to participate in the steam:steel

reaction.

2.1.4 Radiolysis of Water

Radiolysis of water occurs during both normal operation and accidents.

Radiolysis involves the decomposition of water molecules by radiation

(a, 8, y, or n). Radiolysis of water (H2 0) can produce OH, H, H02 ,

and H2 0 2 .

2 - 6 These products can subsequently react with either

themselves or other chemicals present in the water to produce a variety of

products. An important point to be noted is that H2 and 02 can be

produced by radiolysis. 2 - 7 Radiolysis can occur in the core, or elsewhere

in the primary system, or in containment (if fission products are transported

to those areas).

The rate of hydrogen and oxygen generation is controlled by three factors:

(1) the decay energy, (2) the fraction of this energy that is absorbed by the

water, and (3) the effective rate of hydrogen and oxygen production per unit

of energy absorbed by the water. The yield of a product species due to the

radiolysis of water is generally expressed as that product's "G" value (molecules of product formed per 100 eV of energy absorbed). Distinction must be

made between the primary or direct radiolytic yield of a species and the net

yield of the same species. The direct or primary yield is usually expressed

as a subscript to G while the net or actual yield is written as a parenthetical notation. Thus GH2 is the hydrogen formed directly from the water by radiation, while G(H2 ) is the net hydrogen formed directly by radiation and

indirectly by all subsequent chemical reactions. The G(x) value can be larger

or smaller than Gx due to secondary reactions taking place between the

various radiolytic species and the solutes. Typical values 2 - 8 of GH2 in pure

water are 0.44 for B + y for radiation, 1.12 for fast neutrons,

2-7
H2 PRODUCTION

4m

a.

z

0~

C0

Cfo

0.005

0.004

0.003

0.002

0.001

0.000

CkJ

0.024 E

0)

x.Y.

0.020 w

I0.016 z

w

0.012 Z

w(9

0

0.008 cca

-i0.004 0

C0

Cfo

GD

100

101 10 2

TIME (s)

500 103

Figure 2-3. H2 Production Per Unit Area From The Steel: H 20 Reaction
and 1.70 for the recoil nuclei from the reaction 1 0 B(n,a) 7Li. Since

molecular oxygen is not produced directly by radiolysis, G02 = 0; however,

G(02) is not necessarily zero.

A closed water/gas system will eventually attain equilibrium with

respect to radiolytic decomposition of the water. The concentration of

gaseous products at equilibrium will be a function of the reactor power

density, the water pH and temperature, and the impurity (solute) type and concentration. Once equilibrium is attained, G(H2 ) = G(0 2 ) = 0 (although

the concentrations of H2 and 02 may not be zero). It is well established

that small quantities of hydrogen (less than 10-3 moles/liter) dissolved in

pure water or boric acid solutions will effectively limit the equilibrium condition to one in which negligible 02 is present. This technique is employed

routinely in PWR nuclear plants.

An open water/gas system will not attain an equilibrium condition

because the product species are being continuously removed. A typical BWR

power plant operates in such a manner. If the water is boiling vigorously,

H2 and 02 will be produced in stoichiometric portions and G(0 2 ) = 1/2

G(H ) = 1/2 GH_. For pure water exposed to 8 + Y radiation, this would result

in the production of -22 molecules of 02 and 44 molecules of H2 for each

i04 eV of radiation energy.

The specific accident scenario can have a major effect on the relative

importance of radiolytic production of H2 and 02. In order to realistically estimate the effects of radiolysis, it is necessary to know the extent

and distribution of fission-product release, the water temperature and pH, the

degree of bubbling and turbulence of the water, and the types and quantities

of impurities dissolved in the water. Presently we cannot assess the effect

of simultaneous variations in several of these parameters. We can state, however, that the rate of production of combustibles from radiolysis is slow compared to the rates from the high-temperature Zr:steam and steel:steam reactions when the latter reactions are occurring.

The rate of radiolytic decomposition of pure water increases linearly

with the reactor decay power but the equilibrium concentrations of product

species in a closed system increase as the square root of the power. Variations in pH have little effect on a-irradiated water, but not much is known

about the effect of pH variations with other forms of radiation. It has been

speculated that pH variation may have a significant effect when combined with

solutes 2 - 8 . Increasing temperature will tend to decrease equilibrium concentrations of product species in pure water, but it has been suggested that

increasing temperature will enhance solute effects due to increased reaction

rates between solute molecules and radiolytically produced radicals 2 - 8 .

The effect of vigorous boiling or bubbling of the water can be quite

significant. The products of radiolysis are constantly removed from the

liquid, and therefore, recombination of the H2 and 02 in solution is inhibited. Radiolysis of the vapor phase itself has not been studied extensively,

but this may become an important issue in an accident.

2-9
The effects of the many possible solutes are not well understood. The

impurities can react with the radiolytically produced radicals and upset the

chemical balance. Only very small quantities of impurities are necessary to

upset this balance (Ref. 2-7).

One of the key questions associated with the accident at TMI-2 concerned

radiolytic decomposition of the reactor coolant water and the possibility that

a combustible mixture of H2 and 02 might exist inside the reactor. Armed

with our present understanding of the TMI-2 accident scenario, it can be

stated that the probability of such an occurrence was very small 2 - 1 because

there was probably an excess of hydrogen and steam and not enough oxygen for

the mixture to be combustible. It cannot be stated, however, that the probability was zero (or would be zero for all conceivable accidents).

There are many uncertainties associated with radiolytic decomposition of

water in a LOCA. It is most useful to carry out sample calculations as part

of a parametric analysis. Consider the two key parameters to be the net yield

G value for hydrogen, G(H2 ), and the fraction of reactor-shutdown (decay)

radiation absorbed by the water, f (Ref. 2-7). In order to proceed we set the

product G(H2 ).f equal to 1.0 and then all results can be scaled with the

"correct" value of G(H2 )'f. Results of calculations for a 3300 MW(t)

reactor are given in Table 2-1. While these calculations probably overestimate the yield and rate by a considerable margin, there are too many unknowns

to say that conclusively.

Table 2-1

CONSERVATIVE CALCULATION OF RADIOLYSIS YIELD AND

RATE FOR A 3300 MW(t) REACTOR WITH G(H2 )'f = 1.0

Time after Integrated Radiolysis Yield and Rate with

Shutdown Decay Energy G(H2 )'f = 1.0 for a 3300 MW Reactor

(s) MJ/MW Total Yield Average Rate

(Ref. 2-7) lbm kg Ibm/s kg/s

102 6 8.8 4 .0881 .04

103 25 37.4 17 .0322 .0146

104 160 242.3 110 .0229 .0104

105 800 1207.0 548 .0106 .0048

106 3500 5286.3 2400 .0044 .0020

2.1.5 Core:Concrete Interactions

In the unlikely event that a reactor accident progresses to the point of

gross fuel melting, the reactor vessel may be penetrated. Collapse of the

molten reactor core materials into the reactor cavity could initiate vigorous

I

2-10
gas generation as this high temperature melt attacked the concrete basemat of

the reactor.

Gas generation during the interaction of molten fuel, cladding, and steel

with concrete occurs in three stages 2 - 1 :

1. Thermal decomposition of the concrete to yield gaseous products,

2. Passage of these gases up through the melt, and

3. Chemical evolution and reaction of the gases as they emerge from the

melt.

Most concrete used in reactor applications is either Type II or Type I

Portland cement combined with various types of aggregate materials. When such

concrete is heated, three major regions of gas generation are usually observed:

1. Release of molecular and physically entrapped water between 86°

and 446°F (30°-230°C),

2. Release of water chemically constituted as hydroxides in the

concrete over the interval 662° to 932°F (350°-500°C), and

3. Release of carbon dioxide from the aggregate and the cementitious phases over the interval 11120 to 1832°F (600°-I000°C).

Typically, concrete is 4 to 9 weight percent water and 0 to 45 weight percent

carbon dioxide.

The rates of these three events can be determined from2 - 9 :

dt = K exp(-E/RT)(l-m)n

dt

where

= fraction of decomposing species lost from the concrete

t = time

R = gas constant

T = absolute temperature.

Values for the constants K, E, and n are shown in Table 2-2.

2-11
Table 2-2

KINETIC PARAMETERS FOR CONCRETE DECOMPOSITION1,2

Basaltic Limestone Common Generic Southeastern

Reaction Concrete Sand Concrete United States Concrete

Loss of evaporable E=11600 E=1O000 E=11000

water (n=l) (E=20899) (E=19818)' (E=19818)

K=4.4x10 6 K=l.29xlO6 K=1.29x1O6

Loss of chemical E=41900 E=40800 E=40800

water (n=l) (E=75487) (E=73505) (E=73505)

K=2.8x10 1 2 K=1.96x10 1 2 ý :K=l.96X10 1 2

Precarboxylation E=42600 E=38300 E=45800

(n=l) (E=76748) (E=69362) (E=82313)

K=3.6x10 9 K=l.98xlO7- K=l.73xlO9

Decarboxylation --- E=37000 E=44900

(n=2/3) (E=66659) (E=80892)

--- K=3.6x10 7 K=l.94xlO6

IE in units of cal/mole (Btuilbmole);,K in units of minutes- 1 .

2 Standard errors in E-10 percent; standard errors in K-30-50 percent.

In order to calculate actual gas generation rates due to thermal decomposition, detailed modelling of heat transfer from the core melt to the concrete is required. However, we can estimate that a few thousand kilograms of

hydrogen might be generated under the worst conditions.

Gases generated by the attack of the molten core material on concrete

will pass up through the melt and react with it. Steam and carbon dioxide

released from the concrete will readily oxidize metallic constituents of the

melt and produce hydrogen and carbon monoxide. Acutal rates of oxidation will

depend upon the rate of gas generation, melt geometry, contact time, gas and

melt composition, and temperature and pressure. Therefore, it is difficult to

make quantitative statements regarding the kinetics of gas-melt reactions.

When the gases from the concrete emerge from the melt, they can'continue

to react. If there is sufficient air present, it appears that spontaneous

ignition of hydrogen and -carbon monoxide is likely. If ignition does not occur, other reactions are likely. At temperatures above 2732 0 F (1500°C), the

gases will tend to equilibrate according to the reaction:

H2 + CO 2 "- H2 0 + CO (2-12)

Normally, as the gas cools, the H2 and CO2 content increases at the expense of the H20 and CO. As the gas temperature falls below 1340°F (727 0 C),

2-12
coking and hydrogenation become possible. Coking is the precipitation of

solid carbon from the gas, and hydrogenation is the reaction of gases to form

methane and other hydrocarbons.

In summary, quantitative predictions of hydrogen generation from

core:concrete interactions are difficult. However, we can say that the potential exists to produce large quantities of hydrogen due to the large mass of

water available in the concrete.

2.1.6 Other Sources

Other materials are present within containment that can react to form

hydrogen. Zinc-based paint, galvanizing, and aluminum can react with water to

produce hydrogen. Additionally, radiolysis of organic material may also lead

to hydrogen production.

Corrosion of zinc-based paint and galvanizing is a function of temperature, composition, surface area, and pH of the spray solution. A detailed

examination of the effects of these parameters can be found in Ref. 2-10.

However, for example purposes it is reasonable to assume that the reactions

proceed according to: 2 - 1 1

-B / R

W = C e Area t (2-13)

where

WH2 = mass of H2 produced, lbm (kg)

C = constant = 2.643 x 103 lbm/ft 2 /hr = 1.292 x 104 kg/m 2 /hr

B = activation energy = 26123 Btu/lb-mole = 14500 cal/gm-mole

R = gas constant = 1.98583 Btu/lb-mole/°R = 1.98583 cal/gm-mole/K

T = absolute temperature, °R (K)

Area = surface area, ft 2 (m2 )

t = time, hours.

This equation agrees well with the data presented in Ref. 2-10.

A typical PWR contains about 1.5 x 105 ft 2 (1.39 x 104 m2 ) of

zinc-based paint and about 3 x 104 ft 2 (2.8 x 103 m2 ) of galvanized

steel. 2 - 1 2 , 2-13 Figures 2-4 and 2-5 show the quantity of hydrogen produced

as a function of time for these reactions, assuming the above surface areas.

Note that the total quantities produced are about 233 lbm (106 kg) of H2

from corrosion of paint and about 115 lbm (52 kg) of H2 from corrosion of

galvanized steel. While in some reactors these numbers may be higher, this is

still significantly less hydrogen than can be produced from other reactions

discussed previously in this chapter.

2-13
H 2 PRODUCTION

240.0

200.0

E

04

U0

(0

C0

160.0

120.0

120.0

100.0

80.0

N

60.0 u0

40.0

20.0

I

80.0

40.0

0.0

1

0.0

103

TIME (hours)

Figure 2-4. H2 Production From Zinc-Based Paint
H 2 PRODUCTION

120.0

100.0

U0

Z>,

80.0

60.0

60.0

50.0

40.0

5-,

Ie~j

30.0 LL0

20.0

10.0

0.0

103

!

U,

40.0

20.0

0.0

100 101 102

TIME (hours)

Figure 2-5. H2 Production From Galvanized Steel
The surface area of aluminum has been estimated to be 475 ft 2 (44 m2 )

in a typical containment.2- 1 3 The corresponding mass of aluminum is about

1250 lbm (568 kg). Under LOCA conditions of 300OF (149 0C), a maximum of about

139 lbm (63 kg) of hydrogen could be produced over a 7-day period, given the

surface area and mass of aluminum identified above and a production rate of

0.88 lbm/hr (0.4 kg/hr). Other estimates of the mass of aluminum in containment have been as high as 4000 lbm (1800 kg).

Organic materials such as cable insulation, epoxy paints, lubricating

solutions, and gasket seals may produce combustible gases (primarily hydrogen

or methane) due to radiolysis and corrosion. For most nuclear plants, the

quantity of combustible gas that could be produced from organic materials inside containment is relatively small.

An example of hydrogen generation from radiolysis of cable insulation

(polyethylene) follows. The yield of hydrogen, G(H2 ), for polyethylene is

5 molecules for 100 eV of absorbed radiation.2-14 If we take 200 Mrad as a

30-day radiation dose for the cable insulation, then the dose per pound is

roughly 6 x 1024 eV (1.3 x 1025 eV/kg). A typical containment might have

105 lbm (4.5 x 104 kg) of cable insulation. Therefore, roughly 220 lbm

(100 kg) of hydrogen could be generated from radiolysis of cable insulation

over a period of 30 days.

2.1.7 Time Sequence of Hydrogen Production

An exact calculation of hydrogen production versus time during a severe

accident would require a detailed analysis of the accident scenario as well as

modelling of certain physical phenomena that are not well known. However, it

is useful to examine the question from a qualitative viewpoint.

Of the sources of hydrogen discussed in this chapter, the most important

one is probably the steam:zirconium reaction. This reaction requires temperatures above 1832 0 F (1000 0 C) which may occur within the first few hours of a

severe accident (after core uncovery).* Large amounts of hydrogen may also be

produced from steam:steel reactions. These reactions are initiated after the

steam:zirconium reaction due to the higher temperatures required; however,

they are still initiated during the first few hours of the accident and can be

concurrent with the steam:zirconium reaction.

Core:concrete interactions do not occur unless the core has fallen

through the reactor vessel. Once the interactions start, vigorous gas generation results. Corrosion of paint and other surfaces within containment may

begin when hot steam is released into containment or the containment sprays

are activated. However, these reactions are slow, taking many hours to produce relatively small quantities of hydrogen.

*For the purposes of this discussion, a severe accident is one in which the

core becomes uncovered for a period of time and a degraded-core situation

occurs.

2-16
Radiolysis is always present in a reactor. The rate of radiolysis can

increase during the accident as fission products are released from the fuel.

However, radiolysis is still a long-term concern relative to the steam:zirconium reactions. Using the information presented earlier in this chapter and

making certain assumptions, we can estimate the relative quantities and timing

of hydrogen production for the various reactions (see Fig. 2-6). Figure 2-6

should be treated as qualitative in nature, as actual numbers depend upon the

specific reactor and accident sequence.

2-17
HYPOTHETICAL H2 PRODUCTION

104

kjiO

.0

002

104

04

0L

0

101

10

0

101

TIME (min)

Figure 2-6. Hypothetical H12 Production for Various Reactions
2.2 HYDROGEN SOLUBILITY, TRANSPORT, AND MIXING

2.2.1 Introduction

The transport and mixing of hydrogen determines when and where combustion

is likely to occur. Some hydrogen will remain dissolved in water, with actual

amounts depending upon the temperature, pressure, and composition. Hydrogen

that does enter the. containment atmosphere will mix with the steam and air due

to forced or free convective motion and diffusion. The rate at which mixing

will occur depends upon the particular mixing mechanisms at work. The following sections present discussions of solubility and mixing, followed by some

observations regarding what may be expected to occur under actual accident

conditions. Detailed analysis of hydrogen transport generally requires

sophisticated computer modelling; consequently, many of the discussions that

follow are qualitative in nature.

2.2.2 Solubility of Hydrogen in Water

The solubility of hydrogen is a measure of how much hydrogen will remain

dissolved in water under various conditions. Solubility of hydrogen in water

can be treated fairly well by assuming that both the gas and the liquid solution are ideal. We can then assume that Henry's law is obeyed:

PH2 = H(T)XH2 (2-14)

where

P H = partial pressure of hydrogen in the gas

2

H(T) = Henry constant (this constant is also a weak function

of pressure, but that effect is ignored here)

X = mole fraction of hydrogen in the liquid.

For a system containing a two-phase mixture of steam and hydrogen, the total

pressure, P, will be the sum of the partial pressures PH and PH 0- PH 0 is approximately equal to the saturation vapor pressure of water at tRe mixture temperature. Therefore, PH2 0 can be taken directly from any set of steam tables.

PH2 is then

PH = P - PH20, (2-15)

H2 H20

and the mole fraction of hydrogen in the liquid phase is

XH = (P - PH 0 )/H(T). (2-16)

2-19
H(T) has been experimentally determined over a wide temperature range and is

plotted in Fig. 2-72-15. Detailed expressions for H(T) can be found in Ref.

2-15. Using appropriate values for H(T), we can determine the amount of

hydrogen dissolved, and Figs. 2-8 and 2-9 show some results for various conditions. The following example illustrates the use of these figures.

Example Calculation

Suppose you wish to determine the maximum amount of hydrogen that could

be dissolved in a PWR reactor coolant system under normal operation conditions.

Mass of Water = 2.44 x 105 kg

Temperature = 2880C = 550*F

Pressure = 15.17 MPa = 2200 psia

From Fig. 2-9, the hydrogen concentration is approximately 7.5 x 103 cm3

H2 /kg H20. The total volume of H2 is then

37.5x10 3 2 2.4x 50 9 3 8 3 VH 2 = 7.5 X 10 kg3H2 0. 2.44 x 10 kg H2 0 = 1.83 x 10 cm = 1.1 x 10 in. H2 kg H2 0

(2-17)

The density of hydrogen at standard conditions, assuming ideal gas behavior, is

kK

PM 1 atm 2.015 kg-mole - 0.0824 -•3 = 0.005 ibm (2-18)

H2 RT 0.082056 atm m3 298 K m ft3

kg-mole K

Hydrogen concentration in water is reported in the form of cc hydrogen (at

standard temperature and pressure) per kilogram of water in Fig. 2-9, therefore this density value calculated can be used in any calculations similar to

those in this example. Finally, we can calculate the total mass of hydrogen

dissolved.

Mas 2 .8 x19 c3 1-6 m___k

Mass H =1.83x10 c -6 3 0.0824 = 151 kg = 333 lbm (2-19)

cm m

The effect of boric acid or other chemicals present in the water is

generally to reduce the amount of hydrogen dissolved. However, it appears

that, in most cases, the effects are small.

2-20
l/T (103 R1

-)

0.9 1.1 1.3 1.5 1.7 1.9 2.1

! I I I I I I

18.0 160.0

E" 140.0

0

.f..

b 15.0 0"

D 120.0

E (D

1~ 12.0E

100.0 co

0

0

z

< 9.0 80.0 • - 60 z

z -

o 0z .o1o

60.0 o S6.00

-JD C)40.0

z

z 3 0 M

I z

20.0 Wu I

0.0 00.0

1.5 1.9 2.3 2.7 3.1 3.5 3.9

l/T (10-3 K-1)

Figure 2-7. Henry's Law Constant For Hydrogen In Water

2-21
TEMPERATURE, 0F

10-2

z

z

C,

0

0

0

z

0

Lw

-j

0

x

10-

9

8

7

6

10-4

0 50 100 150 200 250

TEMPERATURE, 0C

300 350

Figure 2-8. Mole Fraction Of Dissolved Hydrogen Under Various Conditions

2-22
TEMPERATURE, OF

100 200 300 400 500 600

1

UJ2.0

04

E

0 0.6•

o 0.5

0O.4

LU

w

o .J 0.3

0

0.1 -

0.2 ,

0 50 100 150 200 250 300 350

TEMPERATURE, 0C

Figure 2-9. Hydrogen Concentration in Water under-Various Conditions

2-23
The discussions above have dealt with closed systems at equilibrium.

Little is known about the dynamics of hydrogen solubility (i.e., how fast

equilibrium will be attained during a transient event). It is widely believed

that turbulent effects will cause a rapid approach to equilibrium, but the

details are not well known 2 -1 6 .

Dissolved hydrogen may be released whenever a change in the temperature

and pressure occur. Figures 2-8 and 2-9 clearly show that a decrease in

pressure (such as when a relief valve opens) will reduce the amount of

hydrogen in solution. The effects of temperature changes are more complex,

depending upon the particular temperature and pressure region.

2.2.3 Transport and Mixing Within Containment

The transport and mixing of hydrogen, oxygen and steam inside containment

are critical in determining how and when combustion will occur (if at all).

Rapid mixing could result in burns that are global in nature, while slow

mixing may lead to localized burning. Mass is normally transported around

containment due to natural or forced convection and diffusion.

If significant pressure differences exist within containment there will

be bulk gas motion (carrying along H2 , 02, etc) from the high pressure to

the low pressure region. This motion occurs very rapidly, with the time

required to equalize pressure depending upon the pressure difference, the flow

area, and the flow resistance. Mass transfer due to pressure differences will

dominate other forms of mass transfer whenever large pressure differences

exist.

Natural convection occurs due to density differences (buoyant effects)

within the containment atmosphere. Convective motions tend to form loops with

lighter gases rising up one side and heavier gases falling down the other.

The convective gas velocity will increase with increasing values of

9 ýPZ (2-20)

where g is the gravitational constant and • sthe density gradient in the az

vertical direction. For a mixture of ideal gases, the density can be found

from

p = PW/RT (2-21)

where P is the absolute pressure, W is the average molecular weight, R is the

universal gas constant, and T is the absolute temperature. The average

molecular weight for a hydrogen:air:steam mixture is

W = 2.02XH2 + 2 8 . 9 7Xair + 18.02XH20 (2-22)

where the Xi is the mole fraction of species i. Note that the addition of

hydrogen reduces the average molecular weight. Therefore, if hydrogen is

introduced low in the containment, the drop in the molecular weight and the

possible higher temperature of this mixture will give it a lower density than

the atmosphere in the top of the containment. This can lead to rapid natural

2-24
convective motions and mixing of the containment atmosphere. The condensation

of steam on containment surfaces can also produce composition and temperature

gradients and thus lead to substantial natural convection.

In practice, accurate predictions of mixing due to natural convection are

difficult due to the complicated geometries and the complexity of convective

motions inside a containment building. Typical RALOC 2 - 1 7 calculations for a

Mark III BWR containment show that natural convection, for certain accidents,

could mix the containment atmosphere in about 20 minutes. 2 - 1 8 For other

cases, it is fair to say that natural convection can normally be expected to

mix the gases over a time period from a few minutes to a few hours. This may

not be true if density inversions occur, as discussed further in this section.

Forced convection can occur due to the presence of fans or jets from a

pipe break or open valve. The degree of mixing from forced convection

depends, of course, upon the flow rates and velocities associated with the

particular fan or jet. One can get a feel for the mixing times by comparing

the volumetric flow rate with the volume of a particular containment compartment. Significant mixing will occur in a time frame on the order of the time

required to turn over the entire compartment volume. Usually, forced convection involves higher gas velocities than natural convection. These higher

velocities may induce turbulence, and thus, enhance mixing.

Forced convection mixing may also occur due to operation of the containment sprays. Current analytical capability does not allow us to model mixing

due to sprays in any detail. However, observation of sprays in operation and

intuition tell us that mixing due to sprays may be quite rapid. The sprays

entrain air, inducing bulk mass motion, and create both large and small-scale

turbulence. Complete mixing should occur within a few minutes.

Diffusion occurs due to concentration gradients. Gases will tend to diffuse from regions of high concentration to regions of low concentration

according to Fick's law:

J A= -D ABVCA (2-23)

where JA is a vector describing the molar fluxes of component A relative to

the bulk gas velocity, DAB is the diffusion coefficient for component A diffusing through component B, and VCA is the concentration gradient for component A.

Typical values for DAB at 1 atmosphere are 2 - 1 9 :

DAB = 0.68 ft 2 /hr (0.06 m2 /hr) for 02 - Air at 32°F (273 K)

DAB = 2.7 ft 2 /hr (0.24 m2 /hr) for H2 - Air at 32*F (273 K)

DAB = 1.01 ft 2 /hr (0.09 m2 /hr) for H2 0 - Air at 770F (298 K)

The diffusion coefficient goes approximately as T3 / 2 and P-1 .

2-25
The most important thing to note about diffusion is that its effect falls

off very rapidly as the size of the volume increases. The time to mix a

volume is proportional to the square of the length scale. Normally, we can

expect that diffusion alone would take days in order to mix the containment

atmosphere. 2- 2 0 Thus, diffusion will only be important for slow release

rates.

An important issue in the discussion of mixing is whether or not locally

high concentrations of hydrogen due to stratification may be expected at positions other than near the hydrogen source. Intuitively, one might expect that

since hydrogen is less dense than air, it might gather at the top of containmenrit However, if the hydrogen is released near the bottom of containment, it

will be substantially mixed before it reaches the top. Stratification of

initially mixed hydrogen:air mixtures in containment is negligible. Once

mixed, the gases will not appreciably unmix. Only in the case where the

hydrogen is released near the top of containment, and there is no forced or

natural convection, can we expect the stratified upper hydrogen layer to

remain for a long time, until diffusion mixes it. The tendency to homogenize

rather than stratify has been observed experimentally. 2 - 2 1 In any case, it

is clear that, if substantial forced convection or mechanisms such as steam

condensation that produce substantial natural convection are present, the

degree of stratification and its duration will not be extensive.

Detailed calculations of hydrogen transport and mixing within containment

are generally beyond the capability of any hand calculation. However, the

above discussion should have given the reader a qualitative feel for the

various transport and mixing mechanisms. In addition to RALOC, computer codes

such as COBRA-TF, 2- 2 2 TEMPEST, 2- 2 3 and KFIX2 - 2 4 are being developed or

modified for transport calculations. Given the complexities of the geometries

and the uncertainties in the source terms, significant uncertainties in the

transport calculations will continue to be present.

2.2.4 Air:Steam:Hvdrogen Concentrations Within Containment

While detailed calculations are beyond the scope of this manual, it is

useful to consider qualitatively what may happen during a severe reactor accident. In most cases, hydrogen and steam will be released near the bottom of

the containment and will mix with the air above. Thus initially, there will

be a hydrogen concentration gradient from bottom to top. Steam may be removed

using a suppression pool, an ice condenser, fan coolers, or containment

sprays, depending upon the type of reactor and accident.

The degree of mixing that will occur before combustion depends upon the

hydrogen release rate, available mixing mechanisms, and availability and location of ignition sources. If the hydrogen release rate is fast relative to

the time required for mixing, then very steep concentration gradients would be

expected. On the other hand, if the release rate is very slow, then nearly

homogenous mixtures would be expected.

To determine what is a fast or slow hydrogen release rate, consider the

discussion of mixing mechanisms in the previous section. Except during

combustion when pressure-driven flows will dominate, the fastest mixing

2-26
mechanisms available are either the containment sprays or forced convection

mechanisms such as jets or fans. These mechanisms may be expected to mix the

atmosphere within a time period of a few minutes to a few tens of minutes.

Thus a hydrogen release over a period of seconds would tend not to be well

mixed, while a release over a period of hours would probably be well mixed.

Combustion may begin near the bottom of the containment due to the higher

hydrogen concentrations expected there. This depends, of course, upon the

availability of ignition sources and the particular hydrogen concentration.

Once combustion begins, pressure-driven flows will occur, and also the hot

gases will tend to rise to the top of the containment due to buoyant forces.

The presence of steam can be very important when evaluating the behavior

of hydrogen within containment. Consider an accident where no containment

heat removal systems are available initially. Large quantities of steam and

hydrogen may be present; however, there may be so much steam that the hydrogen, oxygen, and steam mole fractions are not within the flammability limits

(see the next section). If the contaiment sprays or some other containment

heat removal systems are turned on, the removal of steam will cause the hydrogen and oxygen mole fractions to increase and may make the resulting mixture

combustible. This can also happen over the long term even without containment

heat removal systems, as steam condenses out on the containment walls. The

point of this discussion is that emergency operating procedures should address

the possible effects of any actions related to containment cooling and consider the possibility of hydrogen combustion.

2-27
2.3 COMBUSTION OF HYDROGEN

2.3.1 Introduction

Combustion of hydrogen according to the reaction:

2H2 + 02 ). 2H 2 0 + energy (heat) (2-24)

results in the release of about 5.2 x 104 Btu/lbm of hydrogen burned

(57.8 kcal/gm-mole). The main concern over hydrogen combustion in nuclear

reactor containments is that the high pressure generated might cause a breach

of containment and a release of radioactivity. A second concern is that the

resultant high temperature or pressure might damage important safety-related

equipment. The pressure and temperature obtained from the complete combustion

of hydrogen in air, adiabatically (without heat loss) and at constant volume,

are shown in Figs. 2-10 to 2-13. The use of these figures is explained further in Section 2.3.2. The thermal response of equipment requires experiments

and/or detailed modelling of heat transfer for a specific device and a knowledge of the environment the equipment will be exposed to. One analysis that

assumed no containment sprays were operating has been performed indicating

that a threat to equipment may exist. 2 - 2 5

Combustion waves are usually classified either as deflagrations or

detonations. The term "explosion" is somewhat ambiguous and should be

avoided. Deflagrations are combustion waves in which unburned gases are

heated by thermal conduction to temperatures high enough for chemical reaction

to occur. Deflagrations normally travel subsonically and result in quasistatic (nearly steady state) loads on containment. Detonations are combustion

waves in which heating of the unburned gases is due to compression from shock

waves. Detonation waves travel supersonically and produce dynamic or impulsive loads on containment in addition to quasi-static loads. Under some conditions supersonic deflagrations and quasi-detonations may occur, resulting in

a gray area between combustion waves that are definitely deflagrations and

those that are definitely detonations.

In the following sections an example calculation, the conditions necessary for combustion, deflagrations, steam:hydrogen jets, and detonations are

discussed in detail.

2.3.2 Example Calculation

With the aid of Figs. 2-10 and 2-11, or 2-12 and 2-13, the pressure and

temperature that would be caused by an adiabatic, constant-volume, complete

combustion of a homogenous hydrogen:air:steam mixture can be estimated.

Figures 2-10 and 2-11 can be used for cases in which the steam mole fraction

before the burn is small. This might be the case in the wetwell (or outer

containment) of a Mark III BWR or the upper compartment of an ice condenser

containment. Figures 2-12 and 2-13 are to be used when the conditions before

the combustion are steam saturated. For initial temperatures not far above

normal room temperature, the steam mole fraction is small even in a saturated

atmosphere. In that case either set of figures could be used.

2-28
9 1 1 1 1 1 1 1 I

I STOICHIOMETRIC INITIAL CONDITIONS

N8 RATIO T =536.4 OR = 298 K

0- d P 1 =14.696 psia =

a: 0.1013 MPa

D 7 Ci) 100% RELATIVE

0)w HUMIDITY

a . 6

5-

7w

S4- DOWNWARD PROPAGATION LIMITSwcc

a.

3-

z_U. UPWARD PROPAGATION LIMITS -,

0 8 16 24 32 40 48 56 64 72

INITIAL HYDROGEN CONCENTRATION, VOLUME PERCENT

03

Figure 2-10. Theoretical Adiabatic, Constant-Volume Combustion Pressure

for Hydrogen:Air Mixtures
Ld

cr

w

Na.

z

ILL

3000

2800

2600

2400

2200

2000

1800

1600

1400

1200

1000

800

600

400

0

al , 1

INITIAL CONDITIONS

STOICHIOMETRIC T1 = 536.40 R = 298 K

RP 1 = 14.696 psia

0.1013 MPa

100% RELATIVE

HUMIDITY

6000

5600

5200

4800

4400

4000

3600

3200

2800

2400

2000

1600

1200

,Ann

0

LU

-J

z

M

- I~J~

8 16 24

INITIAL HYDROGEN

32 40 48

CONCENTRATION,

56

VOLUME

64 72

PERCENT

80

Figure 2-11. Theoretical Adiabatic, Constant-Volume

for Hydrogen:Air Mixtures

Combustion Temperature
c00ý). Rrr>

2150

310

290 1950

270

1750

•~ - 250

IL 230

w 2 01550

cr

w0 210 "

(, 1350

-r 170 1150

o/

0

T 150

o 950

< 130

110 INITIAL CONDITIONS 750

STEAM PARTIAL PRESSURE

90 CORRESPONDS TO SATURATION

AT TEMPERATURE T1 550

70 AIR PARTIAL PRESSURE

CORRESPONDS TO 14.7 psia (101kP•)

50 - SATURATED AT 300K (5400R) (oof) 350

4 8 12 16 20 24 28 32 36 40 44. 48 52

HYDROGEN MOLE FRACTION, PERCENT

Figure 2-12. Adiabatic, Constant-Volume Combustion

Pressure For Various Containment Initial Conditions

2-31
2800

z

-J

LU

a: D

w

1-

0

0

C')

0

2600

2400

2200

2000

1800

1600

1400

1200

1000

5100

4900

4700

4500

4300

4100

3900

3700

z

3500 2

z

3300 a:

3100

2900

2700

2500

2300

2100

1900

4 8 12 16 20 24 28 32 36 40 44 48

HYDROGEN MOLE FRACTION, PERCENT

52

Figure 2-13. Adiabatic, Constant-Volume Combustion Temperature For

Various Containment Initial Conditions

2-32
We will describe the procedure to be used in the computations in the next

paragraph. For all the calculations absolute pressures and temperatures

should be used.

Absolute Pressure = Gauge Pressure + Atmospheric Pressure (2-25)

Typically, for normal atmospheric pressure,

Pressure (psia) = Pressure (psig) + 14.7 (2-26)

Pressure (Mpaa) = Pressure (Mpag) + 0.101 (2-27)

For temperature,

Temperature (Rankine) = Temperature (Fahrenheit) + 460 (2-28)

Temperature (Kelvin) = Temperature (Celsius) + 273 (2-29)

The subscripts A, S and H2 refer to air, steam, and hydrogen. The analysis

considers three times: to, the time at the start of the accident; tl, the

time just before the combustion; and t 2 , the time just after the combustion. The object of the calculation is to determine P(t 2 ) and T(t 2 ), the

pressure and temperature just after combustion. We will assume that conditions at time to are known, and that sufficient information about conditions

at time tI is known so that the unknown gas conditions at that time can be

computed.

Consider the example when the conditions at the start of the accident are:

P(to) = 14.7 psia (0.101 MPa)

T(to) = 560°R (311 K) ( ýo0

Relative Humidity = 50%

Just before the combustion the temperature is 590°R (328 K), the air is saturated and a hydrogen detector measures 10 volume percent (mole fraction)

hydrogen (see Table 2-3).

For all three time periods, the total pressure is the sum of the partial

pressures of air, hydrogen and steam,

p = p A + p + p (2-30) S H2

Initially, there is no hydrogen, PH2 (to) = 0. The saturation steam pressures are determined from "Steam Tables" found in thermodynamics textbooks or

engineering handbooks. We have

PSAT(To) = PSAT( 5 6 0 °R (311 K)) = 0.95 psia (0.0065 MPa) (2-31)

Ps(to) = relative humidity * PSAT(TO) = 0.48 psia (0.0033 MPa) (2-32)

2-33
Therefore, the initial air partial pressure is

PA(to) = 14.7 - 0.5 = 14.2 psia (0.098 MPa) (2-33)

From steam tables we obtain, at tI,

Ps(tl) = PSAT(Tl) = 2.2 psia (0.015 MPa) (2-34)

The air partial pressure at t, is

PA(tl) = (Tl/To)PA(to) = (590/560) * 14.2 = 15.0 psia (0.103 MPa) (2-35)

The hydrogen mole fraction is

XH 2 =P =P2//P (2-36)

which leads to

PH P2 = (PA A* + PS) * XHH /(i.0 - XH ) (2-37) 2 -X2

Hence

PH (tI) = 17.2 * 0.1/0.9 = 1.9 psia (0.013 MPa), (2-38)

P1 = 17.2 + 1.9 = 19.1 psia (0.131 MPa) (2-39)

We now estimate the postburn conditions using Figs. 2-10 and 2-11.

Figure 2-10 gives the final/initial pressure ratio for burns with a given set

of initial conditions. However, the pressure ratio is insensitive to the

initial pressure, and insensitive to small changes in initial temperature.

The influence of initial steam mole fraction can be greater. The figures were

computed using a humidity corresponding to a steam mole fraction of 3%. At

590°R (328 K) the steam mole fraction for 100% relative humidity will be

higher, but will be still small enough to use Figs. 2-10 and 2-11. From Fig.

2-10, we determine that P(t 2 )/P(tl) = 4.2, hence P(t 2 ) = 4.2 * 19.1 =

80.2 psia (0.55 Mpa). An approximate final temperature can be estimated from

Fig., 2-11 by adding to the temperature found from the figure the difference

between T(tl) and 536 0 R (298 K).

T(t2)-'z 1230 + 30 = 1260 K (2270°R)

When applicable, the use of Figs. 2-12 and 2-13 is simpler than using Figs. 2-10 and 2-11. These figures are applicable when the conditions at the

start of the accident are near P(to) = 1 atm (0.101 MPa), T(to) = 540'R

(300 K), and the conditions just before the combustion are steam saturated.

It should be noted that the curves for constant T(tl) in the two figures

correspond to varying pressure, P(tl), and varying steam mole fraction. At

all points on the curves, the composition has been adjusted to saturation conditions. Much of the work in describing the conditions at time tI is not

needed here because that information has been incorporated into the figures.

For a temperature of 590°R (328 K), we determine that P(t 2 ) = 4.9 atm =

72.0 psia (0.50 MPa), and T(t 2 ) = 2340°R (1300 K).

2-34
The results of thermochemical calculations on a computer give values P(t 2 ) =

74.4 psia (0.51 MPa), T(t 2 ) = 2401°R (1334 K). The difference between the

results (summarized in Table 2-3) gives an indication of the accuracy to be

expected from the simple graphical methods. If higher accuracy is required,

results can be from one of several thermochemical computer programs such as

that of Gordon and McBride. 2 - 2 6

Table 2-3

COMPUTATION OF ADIABATIC, CONSTANT-VOLUME PRESSURE AND TEMPERATURE

Time before Time before Time after Time after

Accident Combustion Combustion Combustion

to t t 2 t 2

using Figs. using Figs.

2-10, 2-11 2-12, 2-13

Pressure - psia(MPa) 14.7(0.101)* 19.1(0.131) 80.2(0.55) 72.0(0.50)

Temperature - OR (K) 560(311)* 590(328)* 2270(1260) 2340(1300)

Hydrogen Mole Fraction 0.0* 0.1*

Air Partial Pressure -

psia (MPa) 14.2(0.098) 15.0(0.103)

Steam Partial Pressure -

psia (MPa) 0.48(0.0033) 2.2(0.015)

Hydrogen Partial

Pressure - psia (MPa) 0.0(0.0) 1.9(0.013)

* Data directly from measured initial conditions

If the pressure and temperature before the combustion are accurately

measured and the hydrogen mole fraction measurement is absent or less accurate, the hydrogen mole fraction can be estimated (assuming saturation) from

the relations,

PH P - PA- m (2-41)

XH2 = P H2/P (2-42)

Some hydrogen detectors may remove the water vapor content of the hydro- •-

gen:air:steam mixture. In this case the measured hydrogen mole fraction (of

the dry hydrogen:air mixture) will be larger than the value in the original

mixture. The correction required to recover the original value is

2-35
X (l- Xs)X ' (2-43)

2 2

where X H' is the hydrogen mole fraction the dry hydrogen:air mixture and XS

is the steam mole fraction in the original hydrogen:air:steam mixture,

XS = Ps/P (2-44)

2.3.3 Conditions Necessary for Combustion

For substantial combustion of hydrogen to take place, the gaseous mixture

must be flammable, and an ignition source must be present. For a mixture of

flammable gases such as hydrogen and air, the flammability limits are defined

as the limiting concentrations of fuel, at a given temperature and pressure,

in which a flame can be propagated indefinitely. Limits for upward propagation of flames are wider than those for downward propagation. Limits for

horizontal propagation are between those for upward and downward propagation.

There is some doubt concerning the applicability of flammability limits,

as defined above, to accident conditions. There may be scale effects due to

the large size of reactor containments as well as variations in flammability

due to the ignition source strength. It is known that flames can propagate

for short distances in mixtures which are outside the standard flammability

limits. Flammability limits are useful guidelines and are not expected to

_-•7 vary substantially, but do not appear to be fundamental quantities.

The lower flammability limit is the minimum concentration of hydrogen

required to propagate a flame, while the upper limit is the maximum concentration. At the lower limit, the hydrogen is in short supply and the oxygen is

present in excess. At the upper limit of flammability for hydrogen in air,

the oxygen is in short supply, about 5% oxygen by volume. The behavior of the

upper limit of flammability of hydrogen with various mixtures such as air:

steam is more easily understood if one considers it as the lower flammability

limit of oxygen.

In large PWR containments we are usually interested in the lower limit of

flammability, there being large amounts of oxygen present. In the much

smaller BWR containments, particularly the inerted containments,. we may be

interested in the upper flammability limit.

For hydrogen:air mixtures, the flammability limits of Coward and

Jones 2 - 2 7 are still accepted. Values for hydrogen flammability in air

saturated with water vapor at room temperature and pressure are given in

Table 2-4.

2-36
Table 2-4

HYDROGEN FLAMMABILITY LIMITS IN STEAM-SATURATED AIR2-27

Lower Limit, Vol % Upper Limit, Vol %

Upward Propagation 4.1 74

Horizontal Propagation 6.0 74

Downward Propagation 9.0 74

In reactor accidents the conditions inside containment prior to hydrogen

combustion may include elevated temperature, elevated pressure, and the

presence of steam. The flammability limits widen with increasing temperature. At 2120F (100C) the lower limit for downward propagation is approximately 8.8% (see Fig. 2-14). In the temperature range of interest, the widening of the downward propagation limits is small. No data for the widening of

the upward or horizontal propagation limits were found.

If the containment atmosphere is altered by the addition of carbon

dioxide, steam, nitrogen, or other diluent, the lower flammability limit will

increase slowly with additional diluent, while the upper flammability limit

will drop more rapidly. With continued increase in diluent concentration the

two limits approach one another until they meet and the atmosphere is

inerted. A flame cannot be propagated a significant distance for any fuel:air

ratio in an inerted atmosphere. Figure 2-15 shows the flammability limits

with the addition of excess nitrogen or carbon dioxide. Note that for 75%

additional nitrogen, the atmosphere is inert. 2 - 2 7 , 2-28 This corresponds to

5% oxygen at the limit of the flammable region, a value very close to that of

the upper limit for hydrogen:air combustion. Roughly speaking, hydrogen:oxygen:nitrogen mixtures will be flammable if the hydrogen concentration

is above 4% and the oxygen concentration is above 5%. For carbon dioxide, the

atmosphere is inerted when the carbon dioxide concentration is 60% or above,

corresponding to 8% oxygen or less. The larger specific heat of the carbon

dioxide reduces the flame temperature and flame velocity; hence carbon dioxide

suppresses flammability more than nitrogen. It requires about 60% steam to

inert hydrogen:air:steam mixtures. The triangular diagram of Shapiro and

Moffette 2 - 2 9 indicates regions of flammability and detonability of hydrogen:air:steam mixtures. It has been widely reproduced and appears as Fig.

2-16.

In addition to diluents such as steam or carbon dioxide which can have a

large thermal effect on a flame, certain substances react chemically to inhibit hydrogen combustion. For example, Halons (halogenated hydrocarbons)

appear to cause quenching by interacting with free radicals such as H, 0, and

OH. Figure 2-172-30 shows the flammability limits for a mixture of

H2 :air:CF3 Br (Halon-1301).

2-37
600

500,

0

0

Ia.

I-- 2

nW

400

300

200

0 . 1 IIII 0

5 10 70 75 80 85

HYDROGEN (%)

Figure 2-14. Effect of Initial Temperature on Downward Propagating

Flammability Limits in Hydrogen:Air Mixtures

2-38
PERCENT OF OXYGEN

IN MIXTURE OF DILUENT GAS+AIR

16 14 12 10 8 6 4 2 0

LIO +

z z

00-

z

~LL (

00

70

0 10 20 30 40 50 60 70 80 90 100

PERCENT OF DILUENT GAS IN MIXTURE OF

DILUENT GAS+AIR

Figure 2-15. Flammability

CO 2 and N2

Limits Of Hydrogen In Air Diluted With

2-39
100% AIR

100% 80 60 40 20 100%

H2 PERCENT H2 STEAM

FLAMMABILITY LIMITS

68°F - 187*F AT 0 psig (20'C - 8WC AT 101 kPa)

0------ 3000F - 0 psig (149°C -101 kPa )

•- - 3000F - 100 psia (149 0 C - 892 kPa)

Figure 2-16. Flammability and Detonation Limits

of Hydrogen:Air:Stem Mixtures

2-40
CF3Br

o NO DEFLAGRATION

o DEFLAGRATION

PROPAGATED

& PARTIAL

PROPAGATION /

700F (21 0 C)

14.696 psia (101.3 kPa)

DRY GASES

SQUIB IGNITION

H2 AIR

Figure 2-17. Deflagration Limits, H2 :Air:CF3Br(Halon 1301)

2-41
Ignition of dry hydrogen:air mixtures, particularly when the mixtures are

well within the flammability limits, can occur with a very small input of

energy 2 "2 9 . Common sources of ignition are sparks from electrical equipment

and from the discharge of small static electric charges. The minimum energy

required from a spark for ignition of a quiescent hydrogen:air mixture is of

the order of tenths of a millijoule. The ignition energy required as a function of hydrogen concentration is shown in Fig. 2-182-31. For a flammable

mixture, the required ignition energy increases as the hydrogen concentration

approaches the flammability limits. The addition of a diluent, such as steam,

will increase the required ignition energy substantially. As mentioned

previously, high energy ignition sources can cause mixtures outside the flammability limits to burn for some distance.

2.3.4 Deflazrations

Deflagrations are flames that generally travel at subsonic speeds relative to the unburned gas. Deflagrations propagate mainly by thermal conduction from the hot burned gas into the unburned gas, raising its temperature

high enough for a rapid exothermic chemical reaction to take place. The

propagation of a deflagration can be understood by examining the flammability

limits discussed in the previous section. Consider a quiescent mixture of

hydrogen:air. For hydrogen concentrations below about 4.1% there will be no

significant propagation away from an ignition source. For hydrogen

concentrations between 4.1 and 6.0%, there will be upward propagation from the

ignition source. Hydrogen concentrations between 6.0 and 9.0% will produce

both upward and horizontal propagation, and hydrogen concentrations above 9.0%

will produce propagation in all directions, although the upward propagation

may be faster than the downward propagation. Exact values for propagation

limits will, of course, vary with temperature, pressure, and the presence of

diluents. The degree of turbulence is also very important with turbulence

tending to enhance combustion as long as the turbulence is not violent enough

to "blow out" the flame.

It has been found in several small and medium-scale laboratory

experiments that when hydrogen:air mixtures with hydrogen concentrations in

the range 4-8% were ignited with a spark, some of the hydrogen was not

burned 2 - 3 2 to 2-36. The resultant pressure rise was below that predicted

for complete combustion, as shown in Fig. 2-192-35. Experimental results

with a spark ignition source indicate that the completeness of combustion in

quiescent mixtures increases with increasing hydrogen concentration, and is

nearly complete at about 8-10% hydrogen. The range of incomplete combustion

corresponds to the range in which the mixture is above the flammability limit

for upward propa- gation, but below the flammability limit for downward

propagation. In upward propagation of lean hydrogen:air flames, "separated

globules" of flame have been observed. 2 - 3 7 Even when ignition occurs at the

bottom of a chamber, the upward propagating flame fails to burn some of the

hydrogen. As shown in Fig. 2-19 for the "fans on" cases, turbulence and

mixing of the gases can sig- nificantly increase the completeness of

combustion.

The phenomenon of incomplete burning of lean hydrogen:air mixtures may be

of great importance in reactor safety. Combustion of lean mixtures, below 8%

hydrogen, appears to be a method of partly eliminating hydrogen without significant pressure rise.

2-42
I I I I I I ' I 1 I I I )

4 -44.0

-42.0 2_-

cow

-J

0

cc

w

z

w

z

0

z

1

.8

1.0

0.8

0.6 .61-

.41- -10.4

.21- -10.2

co

(0

w

z

0

z

0

z

(D

I_-

.08

.06

0.1

0.08

0.06

-10.04 .040-

-- 0.02 .02 -

I I I I I I I I I I I I

0 =

0

I --0.01

10 20 30 40 50 60 70

HYDROGEN IN AIR, PERCENT BY VOLUME

Figure 2-18. Spark Ignition Energies For Dry Hydrogen: Air Mixtures

2-43
5 I '

4-

w ADIABATIC, ISOCHORIC

(0: BURN CALCULATION

C',- 2 0

5 3 - co 0 F

w 

0 2 0 LLDYTS ,0

01 0BM(FURNO, ET AL.)

' go 0 FENWAL-DRY

TESTS

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

PERCENT H2

Figure 2-19. Normalized Pressure Rise Versus Hydrogen Concentration

2-44
Another important parameter when studying deflagrations is the flame

speed. The flame speed determines how much time is available for heat transfer during a burn. Heat transfer results in pressures and temperatures below

those predicted in Figs. 2-10 to 2-13. The dominant heat transfer mechanisms

are evaporation of containment sprays, radiation, and convection. Some reactors also contain fan coolers. Normally, if the sprays are on, they will

dominate the heat transfer process. Radiation heat transfer can also be

important due to the high gas temperatures expected during a hydrogen burn.

Convection may be less significant over the short time of a burn. One note is

that the presence of sprays may significantly increase the flame speed due to

the increased turbulence induced by the sprays. Typically, pressure rises

above 80% of the adiabatic pressure rises are predicted for reasonable values

of the flame speed, assuming complete combustion. The flame speed is discussed in detail below. Warnitz2-38 computed the laminar burning velocity*

for hydrogen:air mixtures and compared his results with those of several other

workers. The results are shown in Fig. 2.20. The maximum laminar burning

velocity of hydrogen:air mixtures is about 9.8 fps (3 m/s) near a concentration of about 42% hydrogen. The burning velocity becomes much smaller as the

flammability limits are approached. The effect of diluents such as nitrogen

is to reduce the burning velocity by reducing the flame temperature. Steam

also reduces the burning velocity, but by less than the amount expected from

equilibrium flame temperature considerations. 2 - 3 9 '

2 - 4 0 ' 2 - 4 1

The laminar burning velocity will be changed only slighly by moderate

changes in ambient temperature and pressure.2-31 For a 90°F (50 0 C)

temperature rise above room temperature, the increase in laminar burning

velocity is less than 0.7 fps (0.2 m/s). The variation of hydrogen:air flame

speed with pressure is very small for pressure changes in the range of

interest for reactor containments. Recent work by Liu and MacFarlane considering the effects of temperature and steam concentrations on burning

velocities may be found in Ref. 2-42.

The plane or spherically-expanding laminar flame front has been shown to

be unstable. Freely propagating laminar flame fronts, if they do not become

turbulent, have complex cellular structures. Hydrogen-lean flames tend to

form nonsteady cellular structures, and will eventually become turbulent. For

hydrogen-rich flames, one expects "widespread wrinkled irregular steady surfaces.-2-43

As noted above, it is likely that a laminar deflagration in containment

will become turbulent. Many turbulent flames have average burning velocities

in the range 2 to 5 times the laminar burning velocity. There may be a

potential for large flame accelerations in fairly rich mixtures, generating

"quasi-detonations."

*The laminar burning velocity (in a Lagrangian sense) denotes the speed of

gases at a steady burner. Propagating laminar flames have flame speeds (in an

Eulerian sense) which are 5-7 times faster due to volumetric expansion of the

burned gases.

2-45
400

E

t0

0

-j

w

z

300 -

200 -

STOICHIOMETRIC

MIXTURE

III, I , I i.

160

120

80

0

m.

)j

Z.

0

100F- --440

0.2 0.4 0.6 0.8

HYDROGEN MOLE FRACTION

Figure 2-20. Laminar Burning Velocity of Hydrogen:Air Mixtures

2-46
If the turbulent flame speed (laboratory system) becomes greater than about

one-tenth of the sound speed (the sound speed is approximately 1150 fps (350

m/s) in containment air), shock waves will be formed ahead of the flame

front. Dynamic loads, in addition to static loads, will be imposed on the

containment structure.

One acceleration mechanism under active study is the action of obstacles

in the path of flames. 2 - 4 3 Many obstacles that might potentially cause

flame acceleration, such as pipes, pressure vessels, etc, are present in the

lower sections of most containments. The mechanisms governing flame acceleration in the presence of obstacles may represent a balance of positive and

negative factors associated with flame folding and turbulence. Two positive

factors that lead to an increase in burning rate are the increase in flame

area due to folding, and the increase in the local burning velocity of the

folds due to higher turbulent diffusivities associated with fine-scale

turbulence. The increase in flame area is a result of the gas flow ahead of

the flame being greatly perturbed by the presence of obstacles. The negative

factors that lead to a decrease in the burning rate are reaction quenching due

to excessive flame stretching, and rapid cooling due to turbulent mixing.

Very fast burns may also occur due to the presence of a very intense ignition

source. As was suggested earlier, this could be a jet of hot combustion

products formed subsequent to ignition in some adjoining semi-confined volume.

The subject of fast deflagrations and quasi-detonations is one of active

current research. It is currently not well understood. Further work will be

needed to determine its importance to hydrogen combustion in reactor containments.

2.3.5 Combustion of a Steam:Hydrogen Jet

If the hydrogen is injected into containment in the form of a

steam:hydrogen jet, it is possible that hydrogen may start to burn as a

turbulent diffusion flame. A diffusion flame is one in which the burning rate

is controlled by the rate of mixing of oxygen and fuel. For the jet to burn,

it is necessary that at some locations the hydrogen:air:steam mixture be within flammability limits.

Combustion can begin either because of an outside ignition source, or

because the mixture temperature is above the spontaneous ignition temperature. Shapiro and Moffette 2 - 2 9 in 1952 presented experimental results on

the spontaneous ignition temperature of hydrogen:air:steam mixtures applicable

to stationary gases, or moving gases with obstacles in the path acting as

flame holders (see Fig. 2-21). The spontaneous ignition temperature is in the

range of 959-1076°F (515-580°C). A stable flame will occur at a distance from

the orifice such that the turbulent burning velocity is equal to the gas flow

velocity. There is evidence to suggest that for a particular set of conditions (temperature, pressure, and composition), there is a minimum orifice

2-47
590

o0O -1075 LL

,w 30% H2 0

Ix LU

D 570-c

-1050

,,6, 20% H 2 0 0-

w

I- w

Z550 -1025

o z

0

z10% H2 0 10

0 530-

w 0 z w

0% H2 0 -975 Z

Z 520-I 0 z

a. 0

510 950 C)

500 1I I

0 10 20 30 40 50 60

PERCENT H2

Figure 2-21. Minimum Spontaneous Ignition Temperature

of Hydrogen:Air:Steam Mixtures

2-48
diameter required for flame stability. 2 - 4 4 This minimum diameter is typically on the order of a few millimeters or less, and therefore, all practical

sized orifices will support a stable hydrogen flame.

2.3.6 Detonation of Hydrogen

A detonation is a combustion wave that travels at supersonic speeds relative to the unburned gas in front of it. For hydrogen:air mixtures near

stoichiometric this speed is about 6600 fps (2000 m/s) (see Fig. 2-22). The

compression of the unburned gas by shock waves in the detonation raises the

gas temperature high enough to initiate rapid combustion.

We will attempt to answer as well as possible the following three

questions:

1. Under what conditions is a hydrogen:air or hydrogen:air:steam

detonation possible in containment?

2. If a detonation is possible, what is the likelihood that it will

occur?

3. What pressure loads could a detonation cause?

We can answer the first question fairly well (at least with regard to hydrogen:air mixtures) and also the third question. The second question concerns

the transition from deflagration to detonation and is still not well understood after more than 50 years of investigation. We can say that, in most

postulated reactor accidents scenarios, deflagrations are much more likely

than detonations.

2.3.6.1 Detonation Limits

Hydrogen:air mixtures near stoichiometric (about 29% hydrogen, two parts

H2 to one part 02) are known to be detonable. Mixtures departing from

stoichiometric, either in the hydrogen-lean or hydrogen-rich direction are

increasingly more difficult to detonate. It has been generally believed that

beyond certain mixture ratios of about 18% and 58% hydrogen, hydrogen:air mixtures could not be detonated. These "detonation limits" were measured by

attempting to cause detonations in long tubes of rather small diameter. It

has recently been observed, however, that the "detonation limits" are functions of the tube diameter, and not universal values at given mixture concentrations, temperatues and pressures.2- 4 4 ,2- 4 6 Our understanding of the

possibility of sustaining a detonation in hydrogen:air mixtures, as well as

other gas mixtures, has greatly increased within the last few years. We will

present a summary of this new understanding that replaces the older idea of

fixed detonation limits.

There are three levels of sophistication used in considering detonation

wave structure. For many purposes one can ignore the three-dimensional

detonation wave structure and consider the wave as an infinitely thin surface

2-49
2200

7000

E 2100 -

ioo

0 2000 0

j -6500

z z

1700

0 190050

z z

0 I6000 0

~-1800 w

1700-

-5500

18 22 26 30 34 38 42 46 50 54 58

HYDROGEN CONCENTRATION, VOLUME PERCENT

Figure 2-22. Theoretical Chapman-Jouguet Detonation Velocity

for Hydrogen:Air Mixtures
separating the unburned and burned gas, the Chapman-Jouguet model (C-J

model). The wave thickness for hydrogen:air at room pressure is about

0.4-4 in. (1-10 cm). The first model of detonation wave structure, the

Zel'dovich, von Neumann, and Doring model (the ZND model) considered the

detonation as being a normal shock wave followed by a deflagration. Within

the last 20 years it has been found that the detonation wave is composed of

unsteady oblique shock waves moving in an everchanging cellular structure

(characterized by its transverse dimension), a "foamy" detonation front. This

concern with detonation wave structure has been of interest to scientists concerned with detonations, but up to now has had little practical significance.

The cell size, X, in a detonation is a fairly easy quantity to measure. It ties together the chemical reaction rate with the gross macroscopic

propagation behavior of detonations. The farther a mixture is from stoichiometric, and hence the less energetic the chemical reaction, the larger is the

detonation cell size. It appears that the smallest diameter tube in which a

detonation will propagate is one whose diameter is about a third of a cell

width. The cell width for hydrogen:air has been accurately measured over an

extensive range of hydrogen:air ratios (see Fig. 2-23).2-46 For example, at

16% hydrogen the cell size is about 9.6 in (24.5 cm). This means that a 16%

hydrogen mixture detonation should be able to propagate down a tube 3.2 in.

(8.2 cm) in diameter. The larger the tube diameter, the wider is the range of

detonable hydrogen concentrations. Note that 16% hydrogen is below the

usually accepted detonation limit; in fact, a detonation has been observed in

a 12 in. (30 cm) tube at a hydrogen concentration of 13.8%.2-47

The knowledge of hydrogen:air cell size is valuable for more than tube

detonation limits. It is known that if a detonation is to propagate from a

tube into an open space, there is a minimum tube diameter for which the

detonation will propagate, the critical tube diameter. For smaller tube diameters, the detonation will fail when leaving the tube. Experimental results

show that the critical tube diameter is about 13 cell widths. For a 16%

hydrogen mixture the critical tube diameter is therefore 10.5 ft (3.19 m).

For a rectangular duct, the critical duct height varies from about 11 cell

widths (for a square duct) to about 3 (for a wide duct). For propagation into

an open space confined on one side of the duct, there is some evidence that

the critical duct height lies between 1.5 and 5.5 cell widths. Figure 2-24

shows the relationship between geometry and cell size for the geometries discussed above.

The developments described above possibly answer the first question,

"Under what conditions is a hydrogen:air detonation possible in containment?"

The detonation limits are not fixed but depend on the geometry being wider for

larger sizes. The curve of cell size versus hydrogen fraction rises steeply

on the hydrogen-lean side. However, detonations have been observed at

hydrogen concentrations as low as 13.8%. For the large geometrical scales in

containments, detonations may propagate in leaner mixtures. Still to be

answered in this area is the effect of steam, initial temperature, and initial

pressure on detonation cell size.

2-51
1000

900

800

700

600

500

400

300

30

20

10

9

8

7

6

E

•200

3-

100

o 90

80

o 70

S60

0 50

w

o 40

w

a,.

0

IZ

I-I

0

Z

w

0

Iz

1.0

0.9

0.8

0.7

0.6

0.5

0.4

10 1 L. I - I • 10 20 30 40 50 60

HYDROGEN CONCENTRATION (VOLUME %)

Figure 2-23. Experimental Measurement of Detonation Cell Size for

Hydrogen:Air Mixtures at Atmospheric Pressure

2-52
i,, I lo () D 1/3X

PROPAGATION DOWN A CYLINDER

O D,> 13X ROUND

TUBE

D

-j

11 SQUARE

TUBE

I D>3X

WIDE RECTANGULAR TUBE

PROPAGATION FROM A TUBE INTO A LARGE OPEN SPACE

"CRITICAL TUBE DIAMETER"

10- ~D >1.5 X-5.5 X

MINIMUM CLOUD THICKNESS FOR PROPAGATION CONFINED

ON ANY ONE SIDE

Figure 2-24. Estimates of Minimum Sizes of Various Geometries For Detonation

Propagation In Terms Of Detonation Cell Width.

2-53
2.3.6.2 Transition to Detonation

A detonable mixture may only deflagrate (burn)and not detonate. Detonations can start directly by the use of a vigorous shock wave coming from a

high explosive, strong spark, or laser. Approximately 1 gm of tetryl explosive will initiate a spherical detonation of a stoichiometric hydrogen:air

mixture. The increase in explosive charge required as the mixture departs

from stoichiometric is roughly proportional to the increase in detonation cell

size. Detonations can also start from deflagrations that accelerate to high

speeds pushing shock waves ahead of the burn front until at some point shock

heating is sufficient to initiate the detonation. Sources of such highly

accelerated flames are high speed jets coming from semiconfined regions and

flames passing through fields of obstacles.

Deflagration-to-detonation transition is probably the least understood

aspect of detonation theory at this time. Measurements have been made of the

distance required to have transition to detonation in smooth tubes. Distances

many times the tube diameter have been required. If obstacles are inserted

into the tube, the required distance to detonation is greatly reduced. The

motion of the expanding gases around the obstacles leads to greatly increased

flame front area, rapid flame acceleration and rapid transition to detonation. Confinement greatly promotes transition, but one cannot rule out

transition to detonation in a containment if a detonable mixture of sufficient

size is present. The second question, "If a detonation is possible, what is

the likelihood that it will occur?" therefore cannot be satisfactorily

answered at present.

2.3.6.3 Detonation Pressures and Temperatures

For the purpose of studying the pressures and temperatures caused by a

detonation, it is sufficient to ignore the detonation wave structure and consider it as a thin surface, a discontinuity. Chapman and Jouguet found that

the conservation equations for mass, momentum, and energy, together with the

appropriate thermodynamic relations and an equation of state did not lead to a

unique solution for the detonation speed and hence pressure and temperature.

Consequently, they assumed that the detonation traveled at a speed such that

the flow behind the detonation was sonic relative to the detonation. With

this assumption one can compute a unique detonation speed for each hydrogen:air mixture, and find the corresponding temperature and pressure behind

the detonation wave. The results are shown in Figs. 2-25 and 2-26. It is an

experimental fact that the measured speeds of detonations are approximately

equal to the calculated C-J values. Various theoretical arguments have been

advanced over the years to explain the near validity of the assumption of

sonic speed behind the detonation. They are not totally convincing. However,

the C-J theory provides reasonably correct values for detonation speed,

temperature, and pressure. This theory does not give any information about

the issues previously discussed, viz., detonation limits and transition to

detonation.

2-54
The burned gases behind a detonation are moving in the direction of the

detonation. When a detonation hits a rigid wall, the gases must be brought to

rest. This is accomplished by a reflected shock wave. We will consider only

the case of a detonation wave striking a wall at normal incidence. The

reflected shock wave further compresses the burned gas, increasing the detonation pressure by a factor of about 2.3. The pressures and temperatures predicted behind the normally reflected shock wave are also shown in Figs. 2-25

and 2-26.

If a detonation propagates down a tube, starting from a closed end, there

will be a series of rarefaction (expansion, pressure reducing) waves behind

the detonation reducing the gas velocity to zero about midway between the

detonation wave and the rear wall. The pressure and temperature are also

reduced by the rarefaction waves. For a spherically expanding detonation, the

effect of the rarefaction waves behind the detonation is even more pronounced. The case of a cylindrically expanding detonation is intermediate

between the planar and spherically expanding case. Results for these cases

are shown in Fig. 2-27.2-48 R in this figure is the distance from the origin

of the detonation to the detonation front. The origin is the rear wall for

the planar case, the axis for the cylindrical case, and the center of the

sphere for the spherical case. x is the distance from the origin to the point

of interest. The abscissa of Fig. 2-27 is the ratio x/R. Note that R = Ut,

where U is the detonation speed and t is the time since the start of the

detonation at the origin. One can convert the results of Fig. 2-27 into a

pressure history at a given position.

The above solutions for an expanding detonation are valid only for the

simple geometries considered. In a containment one expects wave reflections

from walls and obstacles to give rise to complex shock wave patterns. Wave

interactions may lead to dissipation or, possibly, to wave focusing which can

give rise to very high local peak pressures.

2.3.6.4 Local Detonations

In all the previous sections on detonations it has been assumed that the

detonation is taking place in a homogeneous combustible mixture. Such detonations are global, traveling throughout the containment. With the exception of

the strongest containments, containments will probably not be able to withstand the quasi-static pressures (adiabatic isochoric pressures) generated

after the detonation, even without the additional dynamic loads due to detonation. It is therefore more appropriate to consider the effect of detonations

when only a local portion of the containment atmosphere is detonable.

Consider a detonable cloud of hydrogen:air surrounded by air. As the

detonation wave leaves the cloud, it will change into an expanding decaying

shock wave. The shock wave intensity drops fairly rapidly if the shock wave

expands spherically. Within a distance equal to 3 cloud radii, the shock wave

pressure will drop to a value low enough to no longer threaten the containment

structure. However, it has been found in detailed computer calculations 2 - 4 9 ' 2 - 5 0 that, because of the containment geometry, the shock waves

2-55

I
30

24

20

18

-38

36

o.

co,

34a0

0

32

C,,

30w

28

26

-24

58

uI

Ul~ cmJ

0

ICl,

CO, wU

cc

16

14

12

10IL

18 22 26 30 34 38 42 46 50 54

HYDROGEN CONCENTRATION, VOLUME PERCENT

Theoretical Detonation Pressure and Normally Reflected

Detonation Pressure for Hydrogen:Air Mixtures

Figure 2-25.
6000

Lj

Ia.

02

wU

U,

3200

3000

2800

2600

2400

2200

2000

18 22

Figure 2-26.

5700

5400

0~

45100 4800 Lj

3900

S3600

26 30 34 38 42 46 50 54 58

HYDROGEN CONCENTRATION, VOLUME PERCENT

Theoretical Detonation Temperature and Normally Reflected

Detonation Temperature for Hydrogen:Air Mixtures
w

Co

C'

w

aFw

LU

0

z

a1.08

0.97

0.88

0.75

0.64

0.53

0.42

0.31

0.20 '-

0.00 0.20 0.40 0.60 0.80 1.00

NORMALIZED POSITION OR DISTANCE

Figure 2-27. Pressure Distribution Behind Planar, Cylindrical

and Spherical Detonation Fronts When y = 1.4

(Approximation for Hydrogen:Air Mixtures)

2-58
may be focused in local regions, such as the top center of the containment

dome, giving rise to large local peak pressures and impulses. Local detonations may be dangerous in and near the detonable cloud, and may be dangerous

at locations farther away if shock focusing effects are significant.

2.3.6.5 Missile Generation

Missiles may be generated when combustion (deflagration or detonation)

occurs in a confined region or when a propagating combustion front produces

dynamic pressure loads on equipment. Such missiles may pose a threat to the

containment structure itself, as well as representing a potential threat to

safety and control equipment. For instance, electrical cables may not be

expected to withstand the impact of a door or metal box. The actual risk to

plant safety posed by missiles generated from hydrogen combustion depends upon

a number of independent factors. Consequently, methods of probabilistic risk

assessment need to be applied to individual plants to determine the severity

of the threat.

2-59
2.4 MITIGATION SCHEMES

2.4.1 Deliberate Ignition

Deliberate ignition may be suitable for containments that are threatened

by combustion of rich mixtures (>10% H2 ) but can readily survive combustion

of hydrogen at lean mixtures (<10% H2 ). As shown previously in Fig. 2-10,

the adiabatic combustion of lean mixtures will produce a lower pressure rise

than rich mixtures. Additionally, combustion of lean mixtures will produce

pressures and temperatures lower than the adiabatic, isochoric values due to

heat transfer and, in many cases, incomplete combustion. The success of deliberate ignition methods depends primarily upon the hydrogen and steam release

rates, atmosphere mixing mechanisms, and igniter performance.

The hydrogen release rate coupled with the atmosphere mixing mechanisms

determine the atmosphere composition in both space and time. The hydrogen

release rate depends upon the particular accident scenario. Very rapid

releases of hydrogen may occur if the core slumps and falls into water below.

As stated previously, a hydrogen release over a period of seconds would tend

not to be well mixed, while one over a period of hours might be well mixed.

The implications for deliberate ignition are somewhat unclear. If the hydrogen release is very rapid, high concentrations may be present near the release

point. Deflagration will tend to be local in nature, and expansion into the

rest of containment will tend to keep the pressure rises low. On the other

hand, one must also consider the possibility of a detonation whenever locally

high concentrations exist. It should also be noted that rapidly repeated

deflagrations in a local region may eventually inert that region, leading to

hydrogen being transported to the rest of containment. For the case of slow

releases, global deflagrations become possible. Because of the very different

phenomena that can occur depending upon how the hydrogen is released and

mixed, it may be advisable to include hydrogen detectors placed at a few key

locations within containment. These detectors would allow the operator to

intelligently control a deliberate ignition system and perhaps even turn certain igniters off if the possibility of a local detonation exists.

Another important factor of deliberate ignition schemes is igniter performance. Most of the systems proposed have used glowplugs for the igniter.

Glowplugs appear to rovide reliable ignition for hydrogen concentrations of

about 8% and above 2 - , while the ignition probability for hydrogen concentrations below 8% is less certain. The ability of igniters to perform

reliably at lean concentrations is somewhat dependent upon the location of the

igniter. An igniter located near a ceiling cannot initiate significant

combustion until the downward propagation limits (-9% H2 in quiescent mixtures, somewhat lower in a turbulent environment) are reached, while an

igniter centrally located or located near a floor may initiate combustion at

much leaner concentrations. Combustion initiated at the bottom of a volume

will tend to be more complete for lean mixtures due to the larger volume of

hydrogen that is burned.

2-60
2.4.2 Water Sprays, Fogs, and Foams

Deliberate ignition schemes can be coupled with the use of sprays, fogs,

or foams to provide significant pressure reduction during a hydrogen burn.

Sprays, fogs, and foams operate under similar principles. The water acts as a

large thermal capacitance, with substantial amounts of energy absorbed in

evaporation. Figures 2-28 and 2-29 show the theoretical temperatures and

pressures expected for the complete, adiabatic, constant-volume combustion of

hydrogen:air mixtures including the evaporation of water. 2 - 5 1

The success of these methods depends upon the density of water in the

atmosphere and the drop size. The drop size needs to be small enough, that

evaporation can occur on a time scale that is shorter than or comparable to

the total burn time. Figure 2-30 shows the vaporization time versus droplet

radius for various combustion conditions. 2 - 4 9

Most American reactor containments have spray systems in place. In

general, these systems will produce liquid densities less than 0.01 volume

percent and drops that might be larger, than optimal for hydrogen burn mitigation. However, the low densities are compensated somewhat by the large flow

rates that may introduce a significant amount of water during a burn. Also, a

significant fraction of the drops will evaporate even if some of them are

larger than desired. Water fog systems can produce drops of the desired size;

however, achieving high density may be fairly difficult. 2 - 5 1 , 2-52 Foams

appear promising with respect to water density; however, more research is

needed regarding foam maintenance, mixing of hydrogen and air in foams, foam

breakup and evaporation, and impact on other reactor systems.

One cautionary note regarding these systems is that the flame speed can

be increased substantially due to the small-scale turbulence generated. However, the potential for pressure reduction is significant, and these schemes

merit further attention, particularly for containments in which deliberate

ignition is marginal without the addition of sprays, fogs or foams.

2.4.3 Pre-Accident Inerting

Pre-accident inerting may be an option for those reactors that have relatively small or weak containments or for other reasons cannot survive even

lean combustion. Pre-accident inerting has been chosen for use in Mark I and

Mark II BWR containments. Normally, the containment atmosphere is diluted

with nitrogen until the oxygen concentration is below 4%. Nitrogen is the

leading candidate for the diluent gas due to its low cost and nontoxic characteristics. The main problem with pre-accident inerting is that life-support

systems are required for personnel entering the containment. This may impact

both routine and emergency maintenance capability, although the problems associated with Mark I and Mark II BWR containments have not been severe.

Another problem with inerted containments is the possibility of oxygen buildup

due to leakage from outside, leakage from compressed air systems, and radiolytic decomposition of water. Oxygen monitoring systems should be used with

any inerting scheme to warn of a noninert environment.

2-61
3000

2500

Lii 2000

w

a_ 1500

w

5000

4500

4000

3500 L

3000

2500 w

2000

1500

1000

I*

1000

500

5 10 15 20 25 30 35 40 45 50

INITIAL HYDROGEN CONCENTRATION, VOLUME PERCENT

Figure 2-28. Final Temperature as a Function of Initial Hydrogen

Concentration and Volume Fraction of Water Drops

55
8

7

w

(I)

w

z

w

w

az

6

5

4

3

0t

2

5 10 15 20 25 30 35 40 45 50

INITIAL HYDROGEN CONCENTRATION, VOLUME PERCENT

Ratio of Final to Initial Pressure as a Function of Initial Hydrogen

Concentration and Volume Fraction of Water Drops

Figure 2-29.
w-j

0-

0

I'

100 1 1 I . I I 1

10- 5 10- 4 10- 3 10-2 10-1 10 0 101 102 103

VAPORIZATION TIME (s)

Figure 2-30. Vaporization Time Versus Droplet Radius

at Various Combustion Stoichiometries
2.4.4 Post-Accident Inerting

Post-accident inerting would avoid one of the major problems of preaccident inerting, namely, the problem of needing life-support systems for

routine maintenance. Post-accident inerting could be accomplished either

through oxygen depletion or through the addition of a diluent.

Oxygen depletion would involve the use of combustion chambers or engines

to burn up the available oxygen. The devices could be located external to

containment (connected by piping) or inside of containment with cooling provided to prevent excessive heating of the atmosphere. A major concern with

such a system would be the time required to inert the containment after the

onset of the accident. The containment should be inerted before the hydrogen

concentration has time to reach dangerous levels. The type and number of

devices should be determined by the size of containment and likely accident

scenarios, and procedures for turning on the devices early in the accident

should be established.

The addition of a diluent such as nitrogen, CO2 or Halon can be accomplished very rapidly. However, a major difference between adding a diluent in

a post-accident situation and adding one in a pre-accident situation is that,

in the post-accident situation, it may not abe possible to bleed off excess

gas and, thus, the baseline pressure will be raised. Figure 2-15 in the

previous section shows the flammability limits of hydrogen in mixtures of

hydrogen:air:nitrogen and hydrogen:air:carbon dioxide. Adding enough nitrogen

to inert the atmosphere would raise the pressure a factor of 4, while adding

enough CO2 to inert the atmosphere would raise the pressure by a factor of

2.5, assuming that no steam is present. One way to reduce the pressure rise

would be to use coupled volumes. The diluent gas would be contained either in

an adjoining building or in large gas bags within containment. During an

accident, the volumes would be connected, and diluent gas and air would mix

with a much lower or negligible pressure rise.

Post-accident Halon injection would raise the pressure by less than a

factor of 2. However, Halon may decompose either chemically, thermally, or

radiolytically to produce HF and HBr acids, and these products would have to

be dealt with.

2.4.5 Partial Pre-Inerting

Deliberate ignition or post-accident inerting may be coupled with partial

pre-inerting. A partially inerted containment would contain 14-15% oxygen,

which would allow personnel to work without additional life-support systems.

For deliberate ignition schemes, partial pre-inerting would mean fewer burns

before the oxygen is depleted and probably less energetic burns. For postaccident inerting, partial pre-inerting would provide a significant head start

and reduce the time required to achieve an inerted condition.

2-65
2.4.6 High-Point-Vent Flaring

High-point-vent flaring allows the controlled burning of hydrogen as it

exits the primary system. This technique is most useful in situations where

hydrogen is collecting at specific points within the primary system and can be

released in a controlled manner. The method essentially involves combustion

of a steam:hydrogen jet, subject to the constraints discussed earlier. The

vents should be configured such that safety-related equipment is not damaged

during the flaring. This method should not be thought of as a panacea, as it

will do little good in accidents involving large pipe breaks or stuck-open

relief valves at random locations. Another system would be required to deal

with these events. However, whenever possible, high-point-vent flaring,

should provide a benign way of burning hydrogen.

2.4.7 Other Methods

Other methods, such as filtered venting, augmented cooling, or strengthened containments, may be considered if none of the methods described above

appear adequate. However, it may be difficult to design vents that can handle

the rapid transients involved, and augumented cooling or stre'ngthened containments can be very expensive to implement. Additional research into mitigation

schemes will be performed during the next few years. It is to be expected

that different schemes will be proposed for different types of reactors,

depending upon containment size and likely accident scenarios.

2-66
References for Chapter 2

2-1 M. P. Sherman, et al, The Behavior of Hydrogen During Accidents in Light

Water Reactors, NUREG/CR-1561 SAND-1495, Sandia National Laboratories,

Albuquerque, NM (August 1980).

2-2 R. E. Pawel, J. Electro Chem. Soc. 126, 1111-1118 (1979).

2-3 J. V. Cathcart, et al, Zirconium Metal-Water Oxidation Kinetics IV,

Reaction Rate Studies, ORNL/NUREG-17, Oak Ridge National Laboratory, Oak

Ridge, TN (August 1977).

2-4 R. E. Wilson, et al, "Isothermal Studies of the Stainless Steel-Steam

Reaction," pp. 150-153 in Chem. Eng. Div. Semi-Annual Progress Report,

July-December 1965, USAEC Rept. ANL-7125, Argonne National Laboratory

(May 1966).

2-5 J. t. Bittle, et al, "Oxidation of 304L Stainless Steel by Steam and

Air," Corrosion NACE, Vol. 25 No. 1 (January 1969).

2-6 T. H. Row, et al, Design Considerations of Reactor Containment Spray

Systems, Part 1, ORNL-TM-2412, Oak Ridge National Laboratory (April

1969).

2-7 S. E. Turner, "Radiolytic Decomposition of Water in Water-Moderated

Reactors Under Accident Conditions," Reactor and Fuel-Processing Technology, 12(1), 6679 (Winter 1968-69).

2-8 P. Cohen, Water Coolant Technology of Power Reactors, Chapter 4, Gordon

and Breach, NY (1969).

2-9 D. A. Powers, "Empirical Model for the Thermal Decomposition of Concrete," Trans. Amer. Nucl. Soc., 26 400 (1977).

2-10 V. M. Loyola and J. E. Womelsduff, The Relative Importance of Temperature, pH, and Boric Acid Concentration on Rates of H2 Production from

Galvanized Steel Corrosion, Sandia National Laboratories, Draft (April

1982).

2-11 D. Van Rooyen, Memorandum, Brookhaven National Laboratory (April 7,

1978).

2-12 H. E. Zittel, Radiation and Thermal Stability of Spray Solutions in ORNL

Nuclear Safety Research and Development Program Bimonthly Report for

September-October 1970, ORNL-TM-3212, Oak Ridge National Laboratory.

2-13 J. R. Lopata, "Control of Containment H2 Levels Evolved from Zinc

Primers During a LOCA," Power Engineering, 48-51 (November 1974).

2-14 The Radiation Chemistry of Macromolecules, Vol. 1, Ed. by Malcolm Dole,

Academic Press, New York (1972).

2-15 D. M. Himmelblau, "Solubilities of Inert Gases in Water," J. Chem. Eng.

Data, 5:10-15 (1960).

2-67
2-16 EPRI Meeting on Hydrogen Hazards in Nuclear Reactors, EPRI Hdq., Palo

Alto (March 1980).

2-17 H. L. Jahn, Hydrogen Distribution After a Loss-of-Coolant Accident in

the Subdivided Containment of Light Water Reactors--Translation,

NUREG/CR-1831, SAND80-6031, Sandia National Laboratories (November 1980).

2-18 J. C. Cummings, et al, Review of the Grand Gulf Hydrogen Igniter System,

NUREG/CR-2530, SAND82-0218, Sandia National Laboratories, Draft (January

1982).

2-19 J. R. Welty, et al, Fundamental of Momentum, Heat and Mass Transfer,

John Wiley & Sons, NY (1969).

2-20 G. J. E. Willcutt, Jr., and R. G. Gido, Mixing of Radiolytic Hydrogen

Generated Within A Containment Compartment Following a LOCA,

NUREG/CR-0304, LA-7421-MS, Los Alamos (1978).

2-21 G. Langer, et al, "Experimental Investigation of the Hydrogen Distribution in the Containment of a Light Water Reactor Following a Coolant

Loss Accident," Battelle Institute e.V. Frankfurt, NRC Translation 801

(October 1980).

2-22 Private Communication from L. D. Buxton, Sandia National Laboratories,

and M. J. Thurgood, Pacific Northwest Laboratories (1981).

2-23 Private Communication from L. D. Buxton, Sandia National Laaboratories,

and D. S. Trent, Pacific Northwest Laboratories (1981).

2-24 Private Communication from L. D. Buxton, Sandia National Laboratories,

and J. Travis, Los Alamos National Laboratory (1981).

2-25 W. H. McCulloch, et al, Hydrogen Burn Survival: Preliminary Thermal

Model and Test Results, NUREG/CR-2730, SAND82-1150, Sandia National

Laboratories, to be published.

2-26 S. Gordon and B. J. McBride, "Computer Program for Calculations of Complex Chemical Equilibrium Compostions, Rocket Performance, Incident and

Reflected Shocks and Chapman-Jouguet Detonations," NASA SP-273 (1971).

2-27 E. F. Coward and G. W. Jones, Limits of Flammability of Gases and

Vapors, Bulletin 503, Bureau of Mines, U. S. Department of Interior

(1952).

2-28 B. Bregeon, et al, "Near-Limit Downward Propagation of Hydrogen and

Methane Flames in Oxygen-Nitrogen Mixtures," Comb. & Flame, 33:33-45

(1978).

2-29 Z. M. Shapiro and T. R. Moffette, Hydrogen Flammability Data and Application to PWR Loss-of-Coolant Accident, WAPD-SC-545, Bettis Plant, (September 1957).

2-68
2-30 E. T. McHale, Hydrogen Suppression Study and Testing of Halon 1301:

Phases I and II, Atlantic Research Corp. Report No. ARC 47-5647; Maritime Administration, U. S. Department of Commerce, Contract RT-3900,

(December 1976).

2-31 I. L. Drell and F. E. Belles, Survey of Hydrogen Combustion Properties,

NACA R 1383, National Advisory Committee for Aeronautics (1958).

2-32 A. L. Furno, E. B. Cook, J. M. Kuchta and D. S. Burgess, "Some Observations on Near-Limit Flames," 13 Sym. on Comb., Pittsburgh, Comb. Inst.,

593-599 (1971).

2-33 B. C. Slifer and T. G. Peterson, Hydrogen Flammability and Burning

Characteristic in BWR Containments, NEDO-10812, 73NED49, General Electric (April 1973).

2-34 M. P. Paulson and J. 0. Bradfute, "Pressure and Temperature Transients

Resulting from Postulated Hydrogen Fires in Mark III Containments," EI

75-4, Energy Inc.

2-35 M. Berman, Light Water Reactor Safety Research Program Quarterly Report,

January-March, 1981, NUREG/CR-2163/lof4, SAND81-1216/lof4, Sandia

National Laboratories, Albuquerque, NM (July 1981).

2-36 W. E. Lowry, et al, Final Results of the Hydrogen Igniter Experimental

Program, NUREG/CR-2486, UCRL-53036, Lawrence Livermore National Laboratory (February 1982).

2-37 G. W. Keilholtz, Hydrogen Considerations in Light-Water Power Reactors,

ORNL-NSIC-12, Oak Ridge National Laboratory (February 1976).

2-38 J. Warnitz, "Calculation of the Structure of Laminar Flat Flames II:

Flame Velocity and Structure of Freely Propagating Hydrogen-Oxygen and

Hydrogen-Air Flames," Ber Bunsenges Phys Chem. 82:643-649 (1978).

2-39 D. K. Kuehl, "Effects of Water on the Burning Velocity of Hydrogen-Air

Flames," ARS, 32:1724-1726 (1962).

2-40 A. Levy, "Effects of Water on Hydrogen Flames," AIAA J, 1:1239 (1963).

2-41 G. Dixon-Lewis and A. Williams, "Effects of Nitrogen, Excess Hydrogen

and Water Additions on Hydrogen-Air Flames," AIAA J, 1, 2416-2417 (1963).

2-42 D. D. S. Liu and R. MacFarlane, "Laminar Burning Velocities of Hydrogen-Air Flames," AECL-7359, AECL 7360 (1980).

2-43 G. I. Shivashinsky, "On Self-Turbulization of a Laminar Flame," Acta

Astron, 5:569-591 (1978).

2-44 M. Berman, Light Water Reactor Safety Research Program Semiannual

Report, April-September 1981, NUREG/CR-2481, SAND82-0006, Sandia

National Laboratories (February 1982).

2-69
2-45 Yu. M. Annushkin and E. D. Sverdlov, "Stability of Submerged Diffusion

Flames in Subsonic and Underexpanded Supersonic Gas-Fuel Streams,"

Translation, Combustion, Explosions,, and Shock Waves, 14, 5 (1978).

2-46 C. M. Guirao, R. Knystautas, J. H. Lee, W. Benedick, and M. Berman,

"Hydrogen-Air Detonations," to be presented at the 1982 Combustion

(International) Symposium, Haifa, Isreal (1982).

2-47 J. Lee, et al, "Hydrogen Air Detonations," Second International Workshop

on the Impact of Hydrogen on Water Reactor Safety," Albuquerque, NM

(October 1982).

2-48 M. R. Grandry, "Hydrogen Detonation Model Using the Random Choice

Model," M.I.T. Master's Thesis (June 1981).

2-49 R. K. Byers, CSQ Calculations of H2 Detonations in the Zion and

Sequoyah Nuclear Plants, NUREG/CR-2385, SAND81-2216, Sandia national

Laboratories, to be published.

2-50 M. A. Delichatsios, M. B. Genadry, M. N. Fardis, Calculations of Hydrogen Detonations in Nuclear Containments by the Random Choice Method,

M.I.T., R81-30 (December 1981).

2-51 M. Berman, et al, Analysis of Hydrogen Mitigation for Degraded Core

Accidents in the Sequoyah Nuclear Power Plant, NUREG/CR-1762,

SAND80-2714, Sandia National Laboratories (March 1981).

2-52 A. L. Camp, X-Ray Measurements of Water Fog Density, NUREG/CR-2767,

SAND82-1292, Sandia National Laboratories, (November, 1982).

2-70
Chapter 3

HYDROGEN BEHAVIOR AND CONTROL -- NORMAL OPERATION

3.1 INTRODUCTION

Chapter 2 discussed the processes and mechanisms whereby hydrogen can be produced in and dispersed throughout a light water reactor plant. It also

included sections on the conditions necessary for and consequences of hydrogen

combustion (or deflagration) and detonation. This chapter will discuss the

behavior and control of hydrogen during normal plant operation - i.e., the

specific locations at which hydrogen can be found, the problems that this

hydrogen can cause, and the ways in which it can be controlled.

Hydrogen can be found in both PWRs and BWRs during normal operating conditions; its presence is not necessarily a cause for concern. To properly judge

whether its presence in a particular location or at a particular concentration

is unusual or undesirable requires an understanding of its role during routine

conditions. That role will be examined thoroughly in this chapter.

The next section concerns hydrogen considerations common to PWRs and BWRs.

Subsequent sections discuss considerations that are characteristic of one type

of plant. Throughout the chapter, examples are presented based on experience

at various individual plants. Readers must intepret for themselves how these

examples can be related to any other plant.

3.2 HYDROGEN CONSIDERATIONS COMMON TO PWRs AND BWRs

There are major differences in some of the systems associated with PWRs and

BWRs. However, from a hydrogen standpoint there are many aspects which are

common to both types of plants. The objective of this section is to discuss

these common considerations.

3.2.1 Radiolysis

A significant source of hydrogen and oxygen gas production during operation of

a nuclear power plant is the dissociation of water when exposed to radiation.

This process is known as radiolytic decomposition, or radiolysis.

As discussed in detail in section 2.1.4, radiolysis occurs when a water molecule absorbs energy in an interaction with radiation. This radiation can come

from numerous different sources -- the most notable of which are products of

the fission process, including neutrons, electrons, x-rays, gamma rays, protons, deuterons, helium ions, and recoil fragments. The single most important

mechanism for radiolytic decomposition is dissociation initiated by proton

recoils. 3 - 1 (These protons and hydrogen nuclei result from previous neutron

interactions with the water molecules.)

3-1
The initial stages of radiolysis involve the excitation of the water molecule,

and its subsequent dissociation into hydrogen and hydroxyl radicals. This is

shown in Eq. (3-1) and (3-2):

H20 + excitation energy---PH 20* (*denotes an excited state) (3-1)

H20*---H+ + OH- (3-2)

An ionizing particle, in its path through the water, leaves behind a track of

"spurs" or energy-rich zones. These spurs are clusters of free radicals where

molecules dissociate in a short time in relation to that required for appreciable diffusion. 3- 2 Once the H+ and OH- radicals have been liberated,

two things can happen: they can react with each other immediately, or they

can diffuse into the solution, where they may react with each other or with

other molecules in the solution. A variety of products may be formed by these

reactions, including hydrogen peroxide (H20 2 ). Although oxygen gas is not

a direct product of radiolysis, it is produced by the decomposition of hydrogen peroxide.

The high radiation level in the reactor core causes the dissociation of the

coolant at a very rapid rate. However, the radicals formed by this dissociation tend to recombine with each other quickly to form water; hence, the net

effect is actually small.

3.2.2 Radiation Synthesis

Another process that occurs in the reactor coolant and yields undesirable

by-products is radiation synthesis. Radiation synthesis reactions involve

nitrogen. Nitrogen can be introduced into the coolant by air in-leakage into

unpressurized auxiliary systems or into systems or components which are open

during refueling or maintenance outages. (For example, in PWRs, the pressurizer is inerted with a nitrogen blanket during plant outages.)

Nitrogen gas can also be produced in the coolant by the following oxygen-hydrazine reaction:

02+ N2H4 -- 2H2 0 + N2 (3-3)

In an operating reactor, several reactions can occur involving excess nitrogen. If excess hydrogen is present, ammonia can be formed by the following

reaction:

3H2 + N2 = 2NH3 (3-4)

The ammonia increases the pH and conductivity of the coolant, but is removed

by the ion exchangers. The most adverse effect of ammonia is that it tends to

exhaust the cation resins of the mixed-bed ion exchangers prematurely.

If excess oxygen is present, the formation of nitric acid could result:

3-2
2N 2 + 502 + 2H2 0 +-4HNO3 (3-5)

The production of nitric acid decreases the pH of the coolant and accelerates

the corrosion of metals. In the absence of either excess hydrogen or excess

oxygen, ammonium nitrate is formed.

NH3 + HN03-- NH4 NO3 (3-6)

Ammonium nitrate is slightly acidic and lowers the coolant pH, but is present

in such small amount that it has little effect.

3.2.3 Control of Hydrogen from Radiolysis and Radiation Synthesis

The problems associated with the products of radiolysis and radiation synthesis are many. If the concentrations of hydrogen and oxygen become too high,

combustion may result. Excess oxygen also causes corrosion. Nitrogen reactions with either excess hydrogen or excess oxygen in the coolant also have

adverse consequences. For these reasons, methods have been developed for gas

control in commercial nuclear power plants.

As previously mentioned, the majority of the dissociated water molecules

quickly recombine. In a PWR, the free gas that remains -- being in a closed

system -- reaches an operating equilibrium pressure that depends on the nature

of the radiation, radiation intensity, coolant temperature, and the presence

of various dissolved substances in the water. In general, this steady-state

gas pressure increases with radiation intensity, but decreases with elevated

temperatures. Many dissolved impurities also cause an increase in steady

state pressure. In a PWR, the solution to gas control is quite simple. A

pre-determined level of dissolved hydrogen (typically about 25 cm3/kg) is

maintained in the reactor coolant. This tends to promote the recombination of

free hydrogen and oxygen by the reaction:

2H2 + 02 0__ 2H20 (3-7)

This reaction may be enhanced by the intense gamma radiation present during

power operation. In this way, the hydrogen and oxygen content of the coolant

can be kept very low. The production of ammonia and nitric acid by radiation

synthesis is also retarded.

Gas control in a BWR is somewhat more difficult. The very nature of the BWR

as a single-loop power cycle (and, therefore, an open gas system) may preclude

the use of dissolved hydrogen as a means of oxygen control. In a BWR, the

product species are continually being removed, and the system cannot reach a

state of equilibrium. For this reason, gas is continuously being produced,

causing volumes of gas that far exceed those produced in PWRs. Experiments

have shown representative figures for BWR gas production from beta and gamma

radiation to be approximately 22 molecules of oxygen and 44 molecules of

hydrogen per 10,000 eV of radiation energy. 3 1 , 3 5

The gases produced in the core of a BWR are swept up with the steam through

the moisture separators and steam dryers and into the turbines. As the steam

3-3
loses thermal energy and condenses, the hydrogen, oxygen, and other noncondensable gases move straight through to the main condenser in gaseous form.

From there, the steam jet air ejectors move the noncondensable gases into the

plant's Off-Gas System. (This system is described in detail elsewhere in this

chapter.) The primary device for hydrogen and oxygen control in a BWR is the

recombiner. In it, hydrogen and oxygen gas recombine to form water in the

presence of high heat and a platinum or palladium catalyst. Again, the hydrogen content is the limiting factor, and the reaction continues until the

hydrogen is exhausted. A BWR produces a tremendous amount of gaseous waste.

Approximately 100-150 SCFM of waste gas, about 90% of which is hydrogen and

oxygen, is generated. One result of the large volumes of gas that must be

handled is that commercial BWRs have occasionally had hydrogen combustion in

the Off-Gas System. This will be discussed in detail in a later section.

In summary, water exposed to the high radiation levels in a nuclear reactor

decomposes by a process called radiolysis. Although most molecules quickly

recombine to form water, some remain in the water as dissolved hydrogen and

oxygen. Generally, the presence of neutrons (especially high-energy neutrons)

promotes the dissociation of water molecules, while gamma rays tend to aid in

their recombination. Hydrogen and oxygen gases are undesirable because of

their adverse effects on reactor performance, (see sections 3.2.4 and 3.3.1)

both alone and in combination with nitrogen. For this reason, suppression is

the primary goal of gas control in nuclear reactors. PWRs and BWRs, because

of their fundamentally different designs, require different methods of gas

controls. Control is easily accomplished in a PWR by maintaining a small

amount of dissolved hydrogen in the reactor coolant. A BWR must employ recombiners with an extensive Off-Gas System.

3.2.4 Corrosion

At various times, hydrogen or oxygen can be present in the Reactor Coolant

System of a nuclear plant, as was mentioned in section 3.2.1. Both gases

affect the rate of general corrosion. In addition, hydrogen is a product of

some corrosion processes. A thorough understanding of these facts requires a

sound knowledge of how and why corrosion occurs, which is discussed in this

section.3-6

Obviously, corrosion in any system is undesirable since it weakens the structure and can cause eventual failure. Most of the materials employed in the

Reactor Coolant System will corrode in pure water at operating temperature.

The practical utility of these materials depends on the development of protective films of corrosion products that slow down the rate of attack to values

that give useful lifetimes for the materials. In addition to the general or

uniform type of attack, most materials are susceptible to one or more of a

variety of local forms of corrosion, such as pitting, cracking, and galvanic

and crevice corrosion. These local forms of corrosion are usually caused by a

specific component or impurity in the water or the mechanical arrangement of

the component.

Once the tightly adherent protective film mentioned above has formed, very

little general corrosion will occur in a Reactor Coolant System. Therefore,

3-4
general corrosion is of little significance from the standpoint of failure of

any of the metal components. However, it is important from a water purity and

general cleanliness standpoint. This is because any of the corrosion products

that become suspended in the coolant can eventually become activated, which

would contribute to increased radiation levels.

These suspended corrosion products are in the form of a finely divided

material called CRUD. The slurry of CRUD is unstable in the sense that the

solids will settle out in areas of low water velocity. These areas then

become the source of considerable quantities of radioactivity, causing difficulties in repair and maintenance.

In addition, it has been found that these suspended solids tend to precipitate

on areas with a high heat or radiation flux. This means that the surfaces of

the fuel elements may become covered with deposits of corrosion products.

These deposits reduce the heat transfer efficiency and increase the internal

temperature of the fuel.

The rate at which general corrosion occurs is dependent upon several controllable factors, including:

o Oxygen content of the coolant

o Hydrogen content of the coolant

o Coolant pH

o Coolant temperature

o Presence of corrosion inhibitors

The major concern of this manual is with the first two factors. Therefore,

only these two will be discussed in detail. However, before proceeding with

this discussion, the factors will be mentioned briefly:

o Oxygen content of the water -- The oxygen content must be kept as

low as possible in order to minimize corrosion (generally below

about 0.1 ppm in PWRs). This is done by using deaerated makeup

water, maintaining an excess of dissolved hydrogen in the water to

combine with the oxygen, or adding oxygen scavengers such as hydrazine (N2H4 ). (Hydrazine is usually added to the reactor

coolant only during startup. This is because hydrogen is ineffective at removing oxygen when there is no flux field, which is the

condition existing prior to startup.)

o Hydrogen content of the water -- Dissolved hydrogen in water is a

weak corrosion inhibitor, but its major effect is the reduction of

the oxygen content by the recombination reaction. This reaction

requires a radiation field to be effective.

o pH -- The corrosion rate for most metals in water with a pH above 7

is considerably less than in that with a pH of 7 or below. Furthermore the corrosion products seem to form a more adherent film

at a high pH.

o Temperature -- In general, as temperature is increased the corrosion rate increases and the protective film of corrosion products

becomes less adherent.

3-5
o Inhibitors -- Corrosion inhibitors are used to reduce corrosion in

relatively low temperature systems. For example, some Component

Cooling Water (CCW) Systems contain potassium chromate for corrosion control. Potassium chromate produces an insoluble chromate

film on the surface of the metal, which reduces the corrosion reaction rate. Corrosion inhibitors such as potassium chromate are not

effective in the Reactor Coolant System since they decompose under

conditions of high temperature and strong radiation flux.

For a PWR or BWR with a reactor coolant temperature above 500 0 F, water tends

to break down into hydrogen and oxygen due to radiolysis. (A detailed

explanation of the radiolysis process was presented in Chapter 2.)

In an effort to promote a hydrogen and oxygen recombination probability, PWR

facilities maintain a certain level of dissolved hydrogen in the Reactor

Coolant System. Typically, this is 25-35 cm3 of hydrogen per kg of reactor

coolant. Hydrogen addition to the Reactor Coolant System is not done in

BWRs. Since boiling occurs continuously in a BWR, continuous hydrogen addition would be necessary to maintain an inventory in the coolant. Such a

process is impractical.

The hydrogen is introduced into the PWR Chemical and Volume Control System

(CVCS) in the volume control tank (VCT).* Figure 3-1 shows the letdown and

charging sections, including the volume control tank, of the CVCS for the Zion

Nuclear Plant, which is a Westinghouse 4 -loop PWR.

In a PWR, water from one of the RCS cold legs is let down (i.e., drained or

bled off) (about 70 gpm) through a purification flow path through heat

exchangers, demineralizers, and filters in an effort to continually process a

portion of the reactor coolant water. This purification flow path then goes

to the VCT. At this tank hydrogen is added to the reactor coolant water

during normal plant operation to help scavenge any oxygen present. The VCT

also provides the pressure necessary for the charging pumps, which pump the

water back to one of the cold legs of the RCS.

Typically, a hydrogen overpressure of about 15-20 psig (100-140 kPa) in the

vapor space of the VCT will serve to maintain about 25-35 cm3 /kg of hydrogen

in the reactor coolant. The hydrogen will combine with the excess oxygen to

form water, greatly reducing the amount of oxygen in the reactor coolant, and,

hence, the amount of corrosion that occurs.

* In general, this tank is referred to as the volume control tank for

Westinghouse and Combustion Engineering plants, and as the make-up tank for

Babcock and Wilcox plants. However, other names may be employed by individual

plants. For example, at Duke Power Company's Oconee Nuclear Station it is

called the letdown storage tank.

3-6
LETDOWN

HEAT EXCHANGER

MIXED BED

DEMINERALIZER

IA

-a..

Figure 3-1. Chemical and Volume Control System
3.2.5 Electrical Generators

The electrical generator in a nuclear power station converts the rotational

energy supplied by the turbine into electrical energy for commercial distribution. The generator consists of three major parts:

o The frame

o The stator

o The rotor

Figure 3-2 shows the general arrangement of a typical generator assembly. 3 -7

The generator frame supports and houses the stator core and windings and the

generator rotor, and provides multiple flow paths through the generator for

the hydrogen cooling gas. The frame is a casing constructed of welded steel

plates. It provides an air-tight enclosure for the stator and rotor. The

hydrogen coolers are mounted above the stator core in the top of the generator.

Current produced in the generator results in a significant amount of heat

being developed during operation. Efficient operation necessitates dissipating this heat by cooling the generator. It is cooled by pure hydrogen pressurized to about 75 psig (500 kPa). Hydrogen was chosen as the cooling medium

because it is noncorrosive and nonconductive, and has a high thermal conductivity. Also, its low density minimizes windage heating. The hydrogen is maintained in a high state of purity to prevent combustible or detonable mixtures

of air and hydrogen from accumulating, and to provide the proper coefficient

of heat transfer. 3 -8

Hydrogen is circulated through the interior of the generator by a blower

mounted on the turbine end of the generator shaft. The generator rotor and

rotor windings are ported to allow cooling gas flow. Cooling gas flow through

the stator core is accomplished by spacing the core laminations intermittently

with spacer blocks. Coolers mounted on the top of the generator remove the

heat absorbed by the hydrogen.

Since the generator is cooled with hydrogen, which is combustible, the generator casing must be an airtight, leak-proof enclosure to prevent hydrogen

leakage to the atmosphere. A shaft sealing arrangement is provided where the

rotor shaft penetrates the generator casing. This seal provides a double barrier to atmosphere for the hydrogen. Figure 3-3 shows a typical shaft seal

and seal oil arrangement.

In addition to preventing hydrogen leakage to the atmosphere, the shaft seal

also minimizes contamination of the hydrogen with air, moisture, or oil

vapor. To accomplish these purposes the seal is constructed with a dual sealing arrangement with two sources of seal oil.

Two potential problems can exist with the generator hydrogen cooling

system:3-9

3-8
LO

Figure 3-2. General Arrangement of a Typical Generator Assembly
Air Side Gland Seal Oil Maintained Hydrogen Side Gland Seal Oil

at 12 psi Above Machine Gas Pressure liaintained at same Pressure as

/ Air Side Oil

Labyrinth

Seal Rings

Air Side

Annular Space

Hydrogen Side

Annular Space

Hydrogen Side Seal

Oil Drain

Figure 3-3. Typical Generator Shaft Seal Assembly

3-10
o Hydrogen leakage from the bulk storage facility supplying the electrical generator or from the generator itself could cause a combustible mixture to be formed in air. At one plant* where such an

event occurred, hydrogen leaked from the generator's cooling system, through the seals, to the exciter area. Ignition of the

hydrogen occurred, causing structural damage and one personnel

injury. 3- 1 0

o Hydrogen can become entrained in the seal oil used for the generator. It can come out of solution where it is vented to atmosphere

from the oil reservoir. One facility** had a fire in the vent

stack of the roof of the turbine building. Apparently, the fire

was caused by a combustible mixture of hydrogen being released

through the stack.

The purity of the gas in the electrical generator is determined by a hydrogen-purity-indicating transmitter and purity-meter blower, which are normally

located in a hydrogen control panel. Typically, two switch assemblies are

provided with the purity-indicating transmitter. The switch assemblies are

set to produce a "hydrogen purity high or low" alarm on the hydrogen control

panel. Normally, the high limit is set at about 100% and the low limit at 90%.

3.2.6 Hydrogen Bulk Storage Facility

Bulk hydrogen storage is required at nuclear generating stations because

hydrogen is used for the following purposes:

o Internal cooling of the electrical generator (BWRs and PWRs).

o It is added to and maintained in solution in the RCS to scavenge

oxygen and thereby reduce the rate of general corrosion (PWRs only).

o Testing of some types of hydrogen recombiners (BWRs and PWRs).

Various arrangements are used at different facilities. Each arrangement

typically consists of the following components:

o Hydrogen tube trailers

o Hydrogen storage tanks

o Hydrogen storage bottles

Fill stanchions are used to hook the hydrogen tube trailers to a hydrogen control cabinet. Grounding wire connections are provided for both the fill stanchion and the hydrogen tube trailers. The grounding wires run to a copper

* Palisades Nuclear Power Station, which is a PWR in South Haven, Michigan,

operated by Consumers Power Company. This event occurred on February 4, 1982.

** Zion Nuclear Plant, a PWR in Zion, Illinois, that is operated by Commonwealth Edison Company. The fire occurred during the summer of 1977.

3-11
grounding rod located away from the bulk hydrogen storage facility. These

wires are intended to reduce the possibility of a hydrogen ignition due to a

static electricity spark.

Hydrogen header pressure is typically in the range of 100 to 150 psig (0.7 to

1.0 MPa). The header is protected from overpressure by a relief valve. If

the relief valve were to open, hydrogen and oxygen would come in contact,

which could produce a combustible gas mixture. Therefore, the relief valve is

fitted with a flame arrester.

3.2.7 Gas Chromatography

A gas chromatograph (GC) is an apparatus that can be used to analyze a gas

sample for various constituents, such as hydrogen, oxygen, nitrogen, carbon

monoxide, and carbon dioxide. At a nuclear power station, gas chromatographs

may be used in two locations:

o As part of the Gaseous Radioactive Waste System

o As part of a High Radiation Sampling System (HRSS)* to sample the

containment atmosphere

In a radioactive waste system the chromatograph determines hydrogen and oxygen

content in the cover gases of various reactor plant tanks. When used as part

of a High Radiation Sampling System, it:

o Determines the presence of selected gases in the containment during

routine plant operation

o Provides backup hydrogen determination in a post-accident mode

o Determines the containment atmosphere conditions prior to personnel

entry3 - 1 !

Hydrogen is employed in a gas chromatograph for two purposes:

o As a calibration gas to check the accuracy of the hydrogen analyzer

portion of the unit

o As a carrier gas when sampling the containment for carbon monoxide

No serious problems have been recorded regarding the use of this type of gas

analyzer at the time of this writing. It does, however, contain a hydrogen

source, which, if not carefully controlled and operated, could create a combustible gas concern.

3.2.8 Battery Room

Another potential problem area involving the generation of hydrogen in a

nuclear power plant is the battery room. A plant is typically equipped with

250 VDC and 125 VDC battery systems. Typically, the 250 VDC system consists

of two banks of 120 lead-calcium storage cells, and the 125 VDC system

contains four banks of 60 cells. Each bank is mounted in two rows of battery

racks and located in its own battery room. 3 - 1 2

* Commonwealth Edison Company is installing such a system in each of its

plants.

3-12
During operation, as the batteries change chemical energy to electrical

energy, the sulfuric acid content of the electrolyte becomes depleted. Therefore, the batteries must be recharged if they are to be used continuously.

This is done by connecting a DC charging source so that current will flow

through the battery in the opposite direction, driving the acid back into the

electrolyte. The by-products of this charging process, or electrolysis, can

present a potential problem. As a cell becomes nearly charged, the charging

current becomes greater than that necessary to force the remaining amount of

sulfuric acid back into the electrolyte. This results in ionization of the

water in the electrolyte, causing hydrogen gas to be liberated at the negative

plate of the battery and oxygen gas to be liberated at the positive plate.

Although the release of these gases is undesirable, the process is necessary

to develop a full charge in the cell. 3 -13

Several simple, but extremely important methods are used to prevent hydrogen

combustion in the battery rooms. First, the rooms are well-ventilated to prevent excessive hydrogen buildup. The battery room ventilation system

typically limits hydrogen concentration to less than 2% of the total volume of

the room and maintains a constant temperature of 77°F. The air flow rate is

approximately ten air changes per hour. As an additional precaution, no open

flame or smoking is allowed in the proximity of the battery room. Also, any

work in the room must be performed with nonsparking tools made of brass,

aluminum, or wood. 3 - 1 4

To date there have been no major accidents involving hydrogen gas in the

battery rooms at nuclear plants. However, extreme care must continue to be

exercised to ensure the safe operation of this potentially hazardous system.

3.2.9 Resin Beds

In 1975, hydrogen combustion occurred in the acid day tank of the condensate

demineralizer regeneration system at a BWR facility. The hydrogen was formed

when moisture from the atmosphere interacted with concentrated sulfuric acid

in the tank because of the depletion of the desiccant in the vent line. It is

believed that combustion was caused by a spark from a nearby welding operation. The resultant ignition blew the top off the day tank and broke the vent

and fill piping. As a result of this event, acid was deposited on nearby

equipment, cable trays, and the floor. 3 - 1 5

3.3 HYDROGEN CONSIDERATIONS SPECIFIC TO PWRS

The objective of this section is to discuss hydrogen concerns that are pertinent to pressurized water reactors but that, due to differences in plant

design, are not directly applicable to boiling water reactors.

3-13
3.3.1 Reactor Coolant System

3.3.1.1 Pressurizer. During normal operating conditions, the pressurizer is

approximately 50% full of water;* the remaining space is occupied by the steam

bubble. Noncondensable gases contained in the Reactor Coolant System will

tend to collect in the pressurizer steam space. Hydrogen is one of these noncondensable gases.

The pressurizer is designed to compensate for pressure transients and maintain

constant system pressure. During a pressurizer outsurge (pressure decrease),

electric immersion heaters in the bottom of the pressurizer are energized to

convert more of the water to steam and thereby increase the pressure. In the

case of a pressurizer insurge (pressure increase), a spray nozzle at the top

of the vessel is activated. The cool spray condenses some of the steam,

causing a reduction in system pressure. If the pressure increases to a level

beyond that which can be suppressed by the pressurizer spray, power-operated

relief valves (PORVs) are opened (automatically or by remote control), allowing steam to flow out of the pressurizer. This steam is piped to a pressurizer relief tank (PRT) where it is condensed. Should neither the spray nor

the relief valves be sufficient to suppress the over-pressure conditions,

self-actuating code safety valves will open to release the excess steam.**

The presence of noncondensable gases, such as hydrogen, in the pressurizer

vapor space affects the response of the pressurizer to level changes. Since

hydrogen is added to the reactor coolant to scavenge oxygen and nitrogen and

to help control the radiolytic decomposition of water, it can be found in the

pressurizer vapor space under normal circumstances. The amount of hydrogen in

the vapor space will depend upon many factors including:

o RCS hydrogen concentration

o Hydrogen addition frequency

o Spray usage

o Noncondensable gas removal rate

The solubility of a gas in water depends on:

o Temperature. At a given pressure and temperature above about 500°F

(260°C), a gas will generally become less soluble as the temperature increases; at lower temperatures the reverse may be true (see

section 2.2).

* The actual percentage will vary from plant to plant. In addition, for

plant's with programmed pressurizer levels, this percentage will be less at

lower power levels.

** Lifting of the spring-loaded code safety valves reduces RCS pressure by

reducing the water and gas inventory in the system. At one time some plants

used this method to help prevent actuation of a high-pressure reactor trip

during a transient. However, following the TMI-2 incident the NRC mandated

that plants implement procedures to assure the reduction of the likelihood of

automatic actuation of the pressurizer PORV during anticipated transients. 3 - 1 6

Thus, this method is no longer used, and lifting of the safety valves during

normal operation is considered undesirable.

3-14
o Pressure. The hydrogen dissolved is linearly proportional to the

partial pressure.

The pressurizer is the region of highest temperature in the RCS, and it has a

large free water surface. Hydrogen can be expected to leave the water volume

in the pressurizer until the partial pressure of hydrogen is sufficient to

inhibit further release. At that point the concentrations of hydrogen in the

water and in the steam will remain in equilibrium until conditions change.

Normal insurges and outsurges will not significantly alter the total hydrogen

content of the pressurizer since the mass changes are small. The use of

sprays, however, will cause large increases in hydrogen content. Spray water

is relatively hydrogen-rich and, as it enters the pressurizer, it breaks into

small drops and its surface area increases. The spray is rapidly heated by

the steam and, at the same time, it reduces the pressurizer pressure. All of

these conditions (the sudden drop in pressure, the sudden heating of a hydrogen-rich liquid, and the sudden increase in free-surface area) will promote

the release of dissolved hydrogen. The total hydrogen content of the pressurizer will increase and a new equilibrium condition will result. In this

new condition, more hydrogen will be contained in the vapor space.

If the hydrogen content of the vapor space increases sufficiently, it will

result in what is called the "hard bubble phenomenon." This phenomenon occurs

when the percentage of hydrogen (and other noncondensable gases) in the pressurizer vapor space is so large that the system reacts almost as if it were

solid (i.e., as if no vapor space existed).

Sandia National Laboratories has proposed a simple rule of thumb that can be

used to diagnose the presence of a hard bubble: If the pressure is greater

than the saturation pressure plus 60 psig, a hard bubble exists. (The 60 psig

factor is to account for the hydrogen normally present.)

The presence of a hard bubble may not be readily apparent from pressurizer

behavior. Consider the following situations:

o If an insurge occurs when a hard bubble does not exist, it will

result in an initial increase in pressure. This pressure increase

will increase the solubility of the gas in the vapor space (solubility and pressure are directly proportional), thus forcing more

of the gas into solution in the water. If the insurge is large

enough, pressurizer spray will be actuated to limit the size of the

pressure increase. The final result will be a new equilibrium

pressure for which the pressure is close to the initial pressure

prior to the insurge.

0 If an insurge occurs when a hard bubble is present, it will again

result in an initial increase in pressure. As in the case when no

hard bubble exists, the pressure increase will force more gas into

solution, and, if the increase is of sufficient magnitude, it will

result in spray initiation. However, the spray will not reduce

pressure because the pressure vapor space contains too large a percentage of noncondensables (recall that this was the definition

3-15
of a hard bubble). In this case the new equilibrium pressure will

be higher than the initial pressure. How much higher it is will

depend upon the magnitude of the insurge, and will determine

whether the operator will notice any abnormality. For small

insurges such as are encountered during normal operating conditions, the difference between the final and initial pressures may

be small enough that the operator will not recognize the existence

of the hard bubble. For a large insurge, the operator would see a

rapid and large increase in pressure.

Similar conditions could be described for an outsurge.

The point to remember is that when a hard bubble is present, rapid level

changes are accompanied by pressure changes that are more rapid than normal --

something the operator may not be expecting.

There are subtle indications available to the operator that will show the

formation of a hard bubble before a large transient occurs. These indications

include trends that may not be normally noticed. For example:

o A slow, steady decrease in RCS hydrogen concentration, accompanied

by increased additions

o Frequent use of pressurizer spray, for whatever reason, raising

pressurizer hydrogen content

o Slower than normal response to normal level changes, i.e., pressure

taking longer than normal to stabilize

o Pressure greater than the saturation pressure corresponding to

pressurizer liquid temperature

The best indication would be, of course, to sample the pressurizer vapor space

for hydrogen. However, currently this is not usually done.

3.3.1.2 Control Rod Drive Mechanisms. One consideration to be examined when

adding hydrogen to the RCS is the possibility of control rod drive mechanism

(CRDM) damage due to the presence of excessive noncondensable gases collecting

in the reactor vessel head region. At concentrations of 100 cm3 /kg or more,

is is possible for noncondensable gases to come out of solution and collect in

the CRDM housings. This can cause the hydraulic buffer to function improperly

during a reactor trip (reactor scram). Figure 3-4 shows a simplified sketch

of a Babcock and Wilcox CRDM. 3 - 1 7 Note that the approximate damaging concentration of gas (100 cm3 /kg) is not the maximum allowable dissolved hydrogen concentration, but the concentration of all noncondensable gases in the

reactor coolant. It is estimated that approximately 60 cm3/kg of additional

noncondensable gases (mostly xenon and krypton) are introduced into the RCS

during operation. For this reason, some stations have placed limitations of

about 40 cm3 /kg on the amount of hydrogen added to the system. Although the

only plant* that has confirmed the need for such a limitation is a Babcock and

Wilcox facility, 3 - 1 8 a simlilar concern may also exist for Combustion

Engineering and Westinghouse PWRs. If it does exist, similar limitations may

be needed for these plants.

* Three Mile Island Nuclear Station, in Goldsboro, Pennsylvania, which is

operated by Metropolitan Edison Company.

3-16
Position

Indication

NOTES:

1. The leadscrew is sh

in the fully insert

position.

2. Although it is no

shown, the upper

motor tube extend!

ward a number of

to allow for full le,

screw withdrawal.

Assembly

Own

ed

t Bellville

Spring

up- Assembly

feet

adRotor

Tube

Buffer

Piston

Assembly

Upper Motor

Tube Extension

/Annul is

Coolant Venting Holes

Torque Taker

Stator

n

Stator

Water Jacket

Assembly

Radial Bearing

Segment

Arm StopSynchronizing/ .Bearing ý/

Segment Arm

Pivot Pin

Thrust

Bearing

Leadscrew

Assembly

Ball

Check Valve

Assembly

-Reactor

Closure

Head

Nozzle

Figure 3-4. Control Rod Drive Mechanism

3-17
The control rod drive mechanism is used to raise, lower, and maintain control

rod position in response to the signal sent to the control rod drive motor.

Figure 3-4 shows the component parts of a CRDM.

During operation, the CRDM is filled with water. In the event of a reactor

trip, the lead screw will fall while the buffer piston assembly displaces the

water. The water that was originally around the leadscrew, between the torque

taker and the torque tube, is forced through the control venting holes in the

annulus between the torque tube and the upper motor tube extension. This

arrangement cushions or buffers (hence the name) the fall of the control rod.

If this water is replaced by noncondensable gases, the buffer piston action

would be lost, causing possible damage to the CRDM during a reactor trip. As

a result, damage to the CRDM housings could breach the RCS boundary, causing a

loss of coolant.

3.3.1.3 RCS Leakage. Typically, 1 gpm of unidentified leakage and a maximum

of 10 gpm of identified leakage are allowed according to the technical

specifications. 3 - 1 9 Assuming an approximate water density of 1 gm/cm3 and

about 35 cm3 /kg of hydrogen dissolved in the coolant, a leakage rate of 11

gpm from the RCS could result in:

11 gl35 x ig x ig x cm3H 2 x 3785 cm3 x 60 min x 11 in cm3 l3 kg gal h

10-5 ft3 3.1 ft3 H2

3.531 x 3 h

cm

That is, 3.1 ft 3 /hr of hydrogen could be released into containment if the

technical specification leakage rate for the RCS were occurring. This is a

small rate, and is generally neglected.

3.3.2 Chemical and Volume Control System

The Chemical and Volume Control System (CVCS) at a nuclear reactor facility

performs many important functions including:

o Maintenance of a programmed water level in the pressurizer

o Control of water chemistry, activity level, and soluble boric acid

concentration (for reactivity control) in the RCS

o Processing reactor coolant to effect recovery and reuse of soluble

boric acid and makeup water

Figure 3-1 showed water let down from the RCS being demineralized and filtered

within the normal letdown and charging system. During certain plant operations it is necessary to divert a portion of the letdown flow to the holdup

tanks (HUTs) where it is stored until it can be processed. A typical HUT can

have a capacity of about 120,000 gallons. When nearly filled with RCS letdown

water, this same holdup tank could contain about 560 ft 3 of hydrogen. 3 -6

Normally, a small nitrogen overpressure is maintained in the holdup tanks;

however, as they are filled, the fractional amount of hydrogen in the HUTs

3-18
increases. One PWR facility,* for example, actually measured a hydrogen concentration of 8% in one of its tanks. 3 - 2 0 Theoretically, the presence of

hydrogen in an inerted holdup tank should not create a flammability problem.

However, in the process of removing hydrogen from the HUTS, large quantities

of water must be shifted from tank to tank in an effort to purge a given HUT

of its free hydrogen. (Not carefully venting these tanks with nitrogen during

this process could result in a tank's collapsing.)

The purged hydrogen gas must then be vented to the Waste Disposal System (WDS)

and be stored in gas decay tanks until it can be discharged from the plant.

To avoid the possibility of hydrogen combustion in the vent header system

while gas is being displaced from the holdup tanks to the vent header, components discharging to the vent header system are restricted to those containing no air or aerated liquids. The vent header, typically, is operated at

a slight positive pressure (approximately 0.5 psig minimum to 2.0 psig maximum) to prevent in-leakage.

3.3.3 Containment Entry

There are three distinct types of PWR containments: large dry, ice condenser,

and subatmospheric. Regardless of the type of containment employed, at every

PWR facility periodic entry into containment is required. Routine containment

entries are made during shutdown periods and during operation. For plants

with ice condenser containments, daily entries are necessary because of the

technical specification requirement to inspect the doors separating the ice

bays from the rest of the containment.

Many requirements must be satisfied before an entry can be made. Some of

these requirements are dependent upon the type of facility involved. However,

in every case the gas concentrations in the containment atmosphere must be

checked. Oxygen content must be sufficient (typically, at least 17%) to

ensure a breathable mixture; otherwise, a self-contained breathing apparatus

(SCBA) must be used. Hydrogen content must be such as to pose no threat of

combustion. During normal conditions such a threat should not exist.

3.3.4 Gaseous Waste Disposal

The Gaseous Radioactive Waste (Radwaste) System in a PWR is designed to

collect, hold, and dispose of all potentially radioactive gaseous waste

generated by the station. Typically, it is designed with sufficient capacity

to store the collected gases for at least 45 days, and to allow for radioactive decay prior to release to the environment. It also provides cover

gases (nitrogen and hydrogen) to various holding tanks within the plant, and

the means to monitor these gases within the system. Figure 3-5 shows a typical Gaseous Radioactive Waste Disposal System for a PWR.

Prior to each routine refueling shutdown the Reactor Coolant System must be

degassed. Degassification is intended to reduce the hydrogen concentration in

the RCS to approximately 5 cm3/kg. During this process the hydrogen supply

* The Donald C. Cook Plant which is located in Bridgman, Michigan. This

plant is operated by Indiana and Michigan Electric Company.

3-19
GASEOUS RADIOACTIVE WASTE SYSTEM

TO PLANT VENT

t•a

C

PRESSURIZER RELIEF TANK

AND HEACTOR

COOLANT DRAIN TANK

RECYCLE HOLDUP TANKS

SAMPLE SYSTEM

VOLUME CONTROL TANK

SPENT RESIN

STORAGE TANK

RECYCLE EVAPORATORS

VOLUME CONTROL TANK

This assembly is not a standard component of the

Gaseous Radioactive Waste

Disposal System for all

plants.

N2 SUPPLY

TO AUXILIARY

BUILDING

Figure 3-5. Gaseous Radioactive Waste Disposal System
to the CVCS volume control tank (VCT) is secured, and the nitrogen supply to

the VCT is placed in service. By using pressurizer sprays and heaters, and

opening the power-operated relief valve (PORV), hydrogen can be collected in

the pressurizer and subsequently vented. The hydrogen gas is vented through

the PORV to the pressurizer relief tank (PRT) and, in turn, from the PRT to

the Gaseous Radwaste Disposal System.

The system also contains an automatic gas analyzer that monitors all of the

auxiliary system equipment where hydrogen and oxygen content must be controlled. Hydrogen and oxygen content are analyzed automatically to indicate

the existence of a combustible mixture.

The tanks in which the gases are held to allow for radioactive decay prior to

release are called, appropriately, gas decay tanks. One plant* experienced a

hydrogen ignition in one of the gas decay tanks during a cold shutdown. This

incident resulted in a release of about 8.8 curies of noble gases and in minor

damage to the tank. The hydrogen combustion was made possible by the presence

of air contamination in the inert nitrogen system that is used to minimize the

oxygen concentration in the tank. (The increasing oxygen concentration was

not detected because the gas analyzer in the system was inoperable.) The

apparent source of the ignition was the oxygen recombiner in the cryogenic

waste gas treatment assembly.**

In this incident, the source of air was instrument air that leaked through

check valves at the cross connections between the instrument air and nitrogen

lines. Leakage occurred in this direction since, under normal operating conditions, the pressure in the instrument air system is higher than that in the

nitrogen system. The nitrogen system provided a backup gas supply to the

air-operated steam supply valve for the steam-driven auxiliary feedwater

pump. This backup was installed to provide a safety-grade auxiliary feedwater

system that would satisfy the single-failure criteria. Other cross connections, which apparently did not leak, had been installed previously to provide

a redundant gas supply to the air-operated pressurizer relief valves and the

associated block valves.

Following the ignition, all tanks that might have been affected were sampled.

It was determined that most of the tanks had oxygen levels above 10%.

Generally, the gas in PWR waste gas systems is hydrogen-rich, and the oxygen

concentration is controlled to prevent flammable gas mixtures. Flammable concentrations of gas mixtures can be avoided by limiting either the hydrogen or

the oxygen concentration to less than the minimum combustibility limits discussed in Chapter 2.

To eliminate the possibility of recurrence at this plant, those portions of

the nitrogen system that are a backup supply to the air system have been

* This incident occurred in July 1981, at San Onofre Nuclear Generating Station Unit 1. This plant is operated by Southern California Edison Company.

It is located near San Clemente, California.

** Not all PWR facilities employ a cryogenic waste gas treatment assembly as

part of the Gaseous Radwaste Disposal System.

3-21
completely separated from the balance of the nitrogen system that supplies

cover gas. Bottles of compressed nitrogen are now used to provide the backup

to the air system.

One other instance of a flammable mixture in a gas decay tank has been

reported.* Flammable concentrations of hydrogen and oxygen were discovered in

the waste gas decay tanks. The flammable gas mixtures were created after the

reactor coolant picked up oxygen from the air during a refueling and maintenance outage. In this case, no ignition occurred., However, the information

notice issued by the NRC pointed out that licensees need to devote more attention to the potential effects of nitrogen-air system cross connections when

systems are modified to use nitrogen as a backup to air systems. In cases

where cross connections exist, the potential for formation of flammable gas

mixtures should be evaluated. The NRC has recommended that a sampling program

be considered to assure that flammable gas mixtures do not exist in

tanks.3-21

3.4 HYDROGEN CONSIDERATIONS SPECIFIC TO BWRS

The objective of this section is to discuss hydrogen considerations that are

of concern for boiling water reactors, but that, due to differences in plant

design, are not pertinent to pressurized water reactors.

3.4.1 Reactor Coolant System

Figure 3-6 illustrates the basic BWR cycle. In this cycle, the reactor

coolant absorbs energy as it passes up through the reactor core. The energy

absorption causes a water-to-steam transformation. The steam passes through

steam dryers in the upper part of the reactor pressure vessel and then flows

to the turbine.

As previously discussed, some of the water passing through the core undergoes

radiolytic decomposition because of the intense radiation field that is present. Some of the hydrogen and oxygen produced during this process is carried

with the steam to the turbine and main condenser. These gases are removed

from the condenser by the steam jet air ejectors (SJAEs), along with other

noncondensable gases that are present (such as trace amounts of the noble

gases, krypton and xenon), and processed through the Off-Gas

System.3-22

3.4.2 Off-Gas System

A BWR nuclear power plant produces a substantial volume of gaseous wastes. In

order to properly control these gases, plants employ an Off-Gas System that

takes noncondensable gases from the main condenser and processes them in an

appropriate manner before releasing them to the atmosphere. One of the most

critical aspects of the Off-Gas System is the disposal of the large amounts of

hydrogen contained in the off-gas mixture. The lower combustible limit of

hydrogen in air is 4.1% by volume, while an off-gas mixture typically contains

* This incident occurred at Arkansas Nuclear One Unit 1, in August 1980.

This plant is located in Russelville, Arkansas, and is operated by Arkansas

Power and Light Company.

3-22
Reactor

Pressure Vessel

LA

W• Cooling Water

Figure 3-6. Schematic Diagram of a Typical BWR System
6 to 8% hydrogen. Thus, the Off-Gas System is a potentially hazardous area,

in which a spark may cause an ignition. Combustion of hydrogen in the Off-Gas

System has not been a rare occurrence during operation. The industry average

has been about one combustion for every four years of plant operation. 3 -23

Changes have been made in Off-Gas System design since the early BWR models to

reduce the hydrogen concentration in the system, but the system still must be

properly and carefully operated to ensure that hydrogen ignition does not

occur.

In recent generation BWRs, the primary method of reducing hydrogen concentrations in the Off-Gas System is through the use of recombiners. A recombiner

causes free hydrogen and oxygen to combine to form water. A typical off-gas

recombiner is shown in Figure 3-7; its general characteristics are described

below.

The Off-Gas System is divided into two sections: the recombiner section and

the charcoal adsorber section. The recombiner section is designed to reduce

off-gas volume by recombining hydrogen and oxygen into water. This volume

reduction (typically around 90%) allows for a significant increase in the

holdup time for the radioactive waste gases. Increased holdup time allows for

more decay of short-lived isotopes and results in a reduction of the activity

released from the stack. A recombiner unit usually consists of a feed gas

condenser and two recombiner sections. Each recombiner section contains a

preheater, recombiner, and condenser. The charcoal adsorber train consists of

a series of filters, adsorber beds, and coolers.

All noncondensable gases in the main condenser are removed by the steam jet

air ejectors (SJAEs) and passed to the feed gas condenser where any steam

remaining is condensed and drained to the main condenser. The gas mixture is

removed by a motive steam jet. The jet compresses and dilutes the gas to

assure a hydrogen concentration of less than 4% before introduction into the

primary recombiner preheater. The preheater increases the temperature of the

gas to about 300OF in preparation for entry into the primary recombiner. The

increase in temperature is required to promote a more efficient reaction. The

primary recombiner is a pressure vessel containing a platinum/palladium catalyst cartridge. Under the proper conditions, the presence of this catalyst

promotes the recombination of' hydrogen and oxygen to form water. Recombination greatly reduces the volume of waste gas and decreases the hydrogen concentration to less than 1%. This results in a substantially reduced probability of hydrogen combustion. The recombination reaction is highly exothermic, causing the production, not of liquid water, but of 800°F steam. A

primary recombiner condenser is included to condense the newly formed steam.

The condensate is drained to the main condenser, while the remaining gas is

run through the secondary recombiner section via a recycle jet. The secondary

section is identical to the primary except that it handles a significantly

lower volume of gas. At the conclusion of this sequence, the condensate

drains to the main condenser while the remaining gases are moved into the

holdup pipe. 3 - 2 4

As was previously mentioned, BWRs have been plagued in the past with hydrogen

ignitions in the Off-Gas System. They have occurred for a multitude of

reasons, ranging from lightning striking the stack and sparks from static

electricity to catalyst migration and sparks from recombiner flow control

valves. Regardless of the cause, with the technology currently available, it

3-24
FROM

MAIN STEAM LINE

TO

OFF-GAS SYSTEM

U',

Figure 3-7. Typical Off-Gas System Recombiner Assembly
is generally agreed that such problems should not occur. The nation's only

manufacturer of BWRs, General Electric (GE), has made recommendations concerning the design and operation of recombiner systems. Some of the more significant recommendations are discussed below.

Some external ignitions could be prevented if loop seals (J-tubes filled with

water that are designed to handle either positive or negative pressure surges)

are of adequate length and kept filled. The length of the loop seals should

be compatible with system pressure and should allow for protection against

potential pressure surges. In some cases it might be necessary to enlarge the

discharge legs to make the seals non-siphonable. The seals should be kept

full at all times and flushed periodically with demineralized water.

Ignitions have also occurred when leftover piping was used to bypass the

recombiner. Once a recombiner is operable, the capability to bypass it must

be rendered inoperable (and preferably removed) since there is a significantly

increased probability of ignition due to migration of catalyst, leaking or

sparking valves, or other related problems.

Another hazard is that of ignitions in downstream piping that is not combustion-resistant. An ignitable mixture can reach such a zone either through

recombiner failure or loss of stack dilution air. According to GE, plant procedures should forbid operation unless the recombiner or the stack dilution

fan is running. 3- 2 5 Plants with operating recombiners should maintain a

continuous flow of stack dilution air sufficient to dilute the full hydrogen

flow (without recombiners) to below 4%. This allows for a safety margin

should the recombiner become inoperable. However, extended operation with a

failed recombiner is not recommended since it increases the chance of creating

problems such as wetting the charcoal or blowing a loop seal. GE recommends

that redundant recombiner trains be maintained in a hot-standby condition at

all times during operation. In augmented off-gas systems, flow of the dilution medium entering the recombiner must be absolutely assured. Its volume

should not be moderated with reactor power, and there should be no possibility

of loss of diluent flow when there is off-gas flow.

Other GE-recommended operating practices are (a) non-sparking trim should be

used to fabricate valves exposed to process gas to avoid acting as potential

ignition sources; (b) caution should be exercised if higher than normal radiation levels are noted in the Off-Gas System area, since such conditions could

be accompanied by released hydrogen; (c) the off-gas area should be a "no

smoking" area; and (d) test procedures that involve instrument lines that

might have a high hydrogen content should contain appropriate precautions. 3- 2 5

The off-gas systems have undergone considerable modification in the past

several years. As a result, different generations of BWRs are equipped differently to handle the problem of hydrogen in the Off-Gas System. The most

prevalent method of dealing with this problem today is the employment of

recombiners in conjunction with stack gas dilution. These technological

advances in hydrogen control in the Off-Gas System have significantly reduced

the frequency of combustion events.

3-26
3.4.3 Chemistry

As previously discussed, the hydrogen produced by radiolysis is controlled by

recombiners in the Off-Gas System. No chemical additives are introduced into

the Reactor Coolant System for hydrogen control.

3.4.4 Containment Entry

Periodic entry into the containment may be necessary during normal operation.

Because of the nature of the radiation and temperature environments that may

be present, such entries will require special precautions. If the primary

containment is inerted with nitrogen, the oxygen concentration will be too low

to be breathable, and respiratory equipment will be required. All of these

considerations should be (and generally are) covered by plant-specific procedures governing containment entry.

From a hydrogen standpoint, the concentration within the primary containment

should be too low to present any unusual problems during normal operating conditions.

3-27
REFERENCES

3-1. Edward J. Hart, "Water," Nucleonics (Oct. 1961): 45-6.

3-2. Aron Kupperman, "Diffusion Kinetics," Nucleonics (Oct. 1961): 38.

3-3. Samuel Glasstone and Alexander Sesonske, Nuclear Reactor Engineering

(New York: Van Nostrand Reinheld, 1981), pp. 471-472.

3-4. S. E. Turner, "Radiolytic Decomposition of Water in Water-Moderated

Reactors under Accident Conditions," Reactor and Fuel-Processing Technology

(Winter 1968-1969): 6679.

3-5. P. Cohen, Water Coolant Technology of Power Reactors (New York: Gordon

& Breach, 1969).

3-6. General Physics Corporation, "Marble Hill Nuclear Generating Station

Systems Manual: Chemical and Volume Control System," 1980, Public Service

Indiana.

3-7. "Byron Nuclear Generating Station Systems Training Manual: Main Generator System," Commonwealth Edison Co.

3-8. General Physics Corporation, "Byron Nuclear Generating Station Systems

Training Manual: 1979, Commonwealth Edison Co.

3-9. Carl Schultz, Zion Nuclear Generating Station, Personal Communication to

Chester F. Kupiec, General Physics Corp., Oct. 20, 1981.

3-10. Steve Jewell, William Ast III, and Tom Renner, "Non-Nuclear Blast Shuts

Palisades!" Herald Palladium (Kalamazoo, Mich.: Feb. 5, 1982).

3-11. "Containment Air High Radiation Sampling System," Zion Nuclear Plant

Units 1 and 2, SDD#5307-SDD-01, Revision 0, (1980), pp. 1-13.

3-12. Pennsylvania Power and Light Company, "Susquehanna Steam Electric Station System Descriptions: DC Electrical Distribution," Pennsylvania Power and

Light Co., pp. 24a-1 - 24b-25.

3-13. Bureau of Naval Personnel, Basic Electricity (Washington, D.C.:

Government Printing Office, p. 47.

3-14. Louisiana Power and Light Company, "Waterford Steam Electric Station

Technical Specifications," Louisiana Power and Light Co., pp. 3/4 8-8 - 3/4

8-10.

3-15. H. W. Godbee and E. L. Compere, ed., "Plant Safety Features," Nuclear

Safety (Mar. - Apr. 1979): 181.

3-16. Nuclear Regulatory Commission, "Nuclear Incident at Three Mile Island -

Supplement," IE Bulletin 79-05B (Washington, D.C.: Nuclear Regulatory Comm.,

1979) p. 3.

3-28
3-17. General Physics Corporation, "Rod Control System," Rancho Seco Systems

Training Lesson Plans (Columbia, Md.: General Physics Corp).

3-18. Nelson D. Brown, Three Mile Island Nuclear Station, Personal Communication with Chester Kupiec, General Physics Corp., Oct. 16, 1981.

3-19. "Technical Specifications for the North Anna Station," (1981), sec. 3.

3-20. James Dickson and David Nelson, Ronald C. Cook Plant, Personal Communication with Chester F. Kupiec, General Physics Corp., Oct. 8, 1981.

3-21. Nuclear Regulatory Commission, "Hydrogen Ignition at San Onofre Unit

1," IE Information Notice 81-27 (Washington, D.C.: Nuclear Regulatory Comm.,

1981).

3-22. R. W. Deutsch, F. B. Lobbin, and W. R. Scott, Jr., Practical Nuclear

Power Plant Technology, vol. 1 (Columbia, MD.: General Physics Corp., 1974),

ch. 1.

3-23. Bernard J. Verna, "Off-Gas System Explosions - Part 1," Nuclear News

(Nov. 1976): 53.

3-24. Pennsylvania Power and Light Company, "Susquehanna Steam Electric Station System Descriptions: Off-Gas System and Recombiner," Pennsylvania Power

and Light Co., pp. 32b-1 - 32b-7.

3-25. Bernard J. Verna, "Off-Gas System Explosions - Part 3," Nuclear News

(Mar. 1977): 41-2.

3-29

Chapter 4

HYDROGEN BEHAVIOR AND CONTROL -- ACCIDENT CONDITIONS

4.1 INTRODUCTION

The possibility of hydrogen combustion inside the reactor vessel was a major

concern of the public and of utility personnel during the Three Mile Island

incident. There was no such combustion in the vessel, but the question comes

to mind: "Was the fear justified?" Although the possibility exists for substantial amounts of hydrogen to be produced in the reactor vessel during accident conditions, it is highly unlikely that flammability limits would be

reached because of the low oxygen concentration in the reactor coolant system

(see Chapter 2). However, a large portion of the hydrogen eventually would be

transferred to the containment atmostphere (e.g., via venting or through a

reactor coolant system break), possibly creating an environment capable of

sustaining a combustion.

This chaper is devoted to a discussion of hydrogen behavior and control under

accident conditions. The principal topics covered include containment integrity, indications of a loss-of-coolant accident (LOCA), indications of hydrogen production, hydrogen transport and mixing, indications of hydrogen combustion, and mitigation schemes. An effort has been made to integrate the

theoretical aspects emphasized in Chapter 2 with the operational and emergency

aspects that could arise during an accident condition.

4.2 CONTAINMENT STRUCTURE AND INTEGRITY

4.2.1 LWR Containment Comparison

The principal concern over hydrogen combustion in nuclear reactor containments

is that it is possible for a high pressure to be generated that could breach

containment integrity and initiate a release of radioactivity to the environment. Nominal design and failure pressures vary from one containment to

another; numbers for typical PWR and BWR containments for 1200 MWe plants are

shown in the bar graph in Figure 4-1. Typical containment net free volumes

are given along with nominal values for design pressure.

4 - 1

If a LOCA occurs, hydrogen could be liberated through a metal-water reaction.* Figure 4-2 shows the resultant hydrogen concentration for each containment type solely from this source of hydrogen. Note that the curves for--

the smaller containment types show a gradual bending at higher hydrogen concentrations. This is because the containment atmosphere initially contains

other constituents besides hydrogen; therefore, the hydrogen concentration can

never reach 100%. In addition, as the volume of hydrogen generated increases,

containment pressure increases due to this added gas volume. For a given

* For most plants this would be a zirconium:steam reaction. However, several

plants have fuel elements clad with stainless steel, instead of zircaloy. In

these plants the reaction would be a stainless-steel:steam reaction.

4-1
CONTAINMENT NET FREE VOLUME x 10"6 (ft 3 )

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.6 1.8 2.0

I I I I I I I I I

VOLUME 1W

VRBW

DESIGN PRESSURE = 45 psig MARK 11

VOLUME

~ DESIGN PRESSURE =12 psig

]j PWR

= ICE

CONDENSER

VOLUME

SDESIGN PRESSURE = 15 psig

] BWR

MARK III

VOLUME

DESIGN PRESSURE =45 psig

PWR

SUB-ATMOSPHERIC

VOLUME I

DESIGN PRESSURE = 60 psig

I I I I I I I

0 10 20 30 40 50 60 70

PWR

I DRY

CONTAINMENT DESIGN PRESSURE (psig)

Figure 4-1. Comparison of Containment Volumes and

Design Pressures (Typical 1200 MWe Plants)

4-2
r

70 PWR-DRY, V = 2,000,000 ft 3

C.

CU

E

I.-

z 60 w

z

z

50

z

w

o 40

30

20

10

PWR--DRY, V =3,500,000 ft3 -

0 1

0 10 20 30 40 50 60 70 80 90 100

METAL-WATER REACTION (percent)

Figure 4-2. Volume Percent Hydrogen in Containment

vs. Percent Metal-Water Reaction Following

a LOCA

4-3
percent metal-water reaction, these effects (i.e., an increase in hydrogen

concentration and the subsequent pressure rise) will be more pronounced for

the smaller sized containments. The combination of these facts explains the

shape of the curves in Figure 4-2.

A second concern about hydrogen combustion is that the resultant high temperature, or high pressure, might damage safety-related equipment. The pressure

and temperature obtained from the complete combustion of hydrogen in air,

adiabatically and at constant volume, were shown in Figures 2-10 and 2-11

respectively.

Hydrogen combustion is only one of several mechanisms that can generate high

containment pressures. The release of steam that would accompany a LOCA also

causes an increase in containment pressure. Further, condensing steam can

react with certain metals in containment such as zinc or aluminum, to liberate

additional hydrogen. This was discussed in detail in Chapter 2.

4.2.2 PWR Containments

In general, three types of PWR containment designs exist. These types are

listed in Table 4-1; two of them are shown in Figures 4-3 and 4-4.

Table 4-1

PWR CONTAINMENT TYPES

Containment Types Design Pressure

(Typical)

Large Dry -60 psig (500 kPaa)

Atmospheric

Sub-atmospheric -45 psig (412 kPaa)

Ice Condenser -12 psig (184 kPaa)

Of primary concern in an accident situation is whether the hydrogen concentration would challenge containment integrity if a deflagration occurred. Consider the pressures involved using the large dry atmospheric containment as an

example. Table 4-1 shows that a typical design pressure is 60 psig (500

kPaa). Assuming an initial pressure in containment of about one atmosphere

(14.7 psia or about 100 kPaa), a five-fold pressure increase to about 75 psia

(60 psig or 500 kPaa) would be required to reach the design pressure during a

deflagration.

Nominally, the failure pressure for a containment (with all margins of safety

removed) can be greater than twice the design pressure. For example, a probabilistic risk assessment (PRA) was performed for one station* employing a

Westinghouse PWR. The dry volume containment had a design pressure of

47 psig. The PRA for this plant gives an ultimate capacity of 125 psig with

* Indian Point Station Unit 3, near Buchanan, New York. This station is

operated by The Power Authority of the State of New York.

4-4
UNIT #•1

REACTOR

AM LOCK

Figure 4-3. Typical Large Dry Containment

4-5
Figure 4-4. Simplified Diagram of Ice Condenser Containment

4-6
100% confidence, and 145 psig with 95% confidence. In addition, one specialist's opinion rates the ultimate capacity of Stone and Webster sub-atmospheric containments (typical design pressure of 45 psig) as 100 psig. 4 -2

In general, the ultimate capacity of a containment structure is two-to-three--

times the design pressure. Some PWRs employ ice condenser containments, such

as that shown in Figure 4-4. These containments have smaller volumes and

lesser design pressures than other PWR containments. This is because the ice

is used as a heat sink in the event of the design basis accident. The ice

will reduce the containment pressure by condensing the steam liberated during

such an incident.

An example of how the hydrogen concentration can increase in containment is

given in Figure 4-5, which shows the postulated post-LOCA hydrogen concentration versus time for the Maine Yankee Atomic Power Station.*4- 3 Figure 4-5

makes the simplifying assumption that the zircaloy-water reaction for the LOCA

occurs all at once, and, similarly, that all of the aluminum in containment

oxidizes at the onset of the incident. Note that Figure 4-5 assumes less than

1% of the cladding has reacted.

4.2.3 BWR Containments

As a result of the requirements in section 50.44 of 10CFR, all Mark I containments are inerted. In the Federal Register of October 2, 1980, the NRC stated

that a long-term rulemaking proceeding related to the consideration of

degraded or melted cores in safety regulation was in progress. This review

would include a reevaluation of positions on the inerting of reactor containments. Pending completion of this process, the NRC felt that it would be prudent to establish certain inerting requirements for operating plants and those

that would become operational in the near term. Therefore, at the time of

this writing, the NRC is considering amending Section 50.44 to require that:

o All operating Mark I and Mark II BWRs be inerted.

o Mark I and II BWRs under construction be inerted upon operation.

o Licensees now operating PWR plants or Mark III BWR plants, or

license applicants that plan to operate these plants study the

various methods of controlling the behavior of large amounts of

hydrogen before the containment is threatened, or of mitigating the

consequences of accidents, involving the generation of large

amounts of hydrogen. 4 -5

If a LOCA occurred at a BWR facility, a steadily increasing pressure in the

primary containment/drywell would result. If operation of the Emergency Core

Cooling System and other water delivery systems are compromised in some

manner, the possibility exists for an inadequate core cooling (ICC) condition

to develop. If an ICC condition arose, it would be possible for a metal-water

reaction to commence in the core. In the event that a metal-water reaction

* A PWR facility located in Wiscasset, Maine, and operated by the Maine

Yankee Atomic Power Company.

4-7
I W iL EUJI a @0 u 1 0 lU t U uf ri u u u u [rUa u lu r C

- core condition.

5

z

0 1-4 TOTAL - -

4-,

z

0

z z

3-

0

n-" . / JZINC PA 0

_ ___ -ZIRCALO_ WA rE

ALUMINUM

OOTHi

14 1016

TIME (seconds)

Figure 4-5. Maine Yankee Containment Post-LOCA Percent

Hydrogen Concentration vs. Time
occurred, hydrogen would be liberated, as was discussed in Chapter 2. The

approximate volume percent of hydrogen which could fill the containment was

shown in Figure 4-2. In this figure, the top curve represents the volume percent in a Mark I or II containment/drywell as a function of percent metal

water reaction in the reactor core. One of the lower curves in Figure 4-2 is

for a Mark III containment. Note that Mark III containments are substantially

larger than either the Mark I or II type. Further information is given in

Table 4-2, which shows some possible hydrogen pressure effects in BWR containments. 4 - 6 For those cases where a hydrogen burn occurs, this table assumes

that only a single hydrogen burn occurs (and that sufficient oxygen exists for

this burn to occur). The table does not take into account any hydrogen. recombiner system or specially installed hydrogen igniter system (HIS). In addition, the values for design and failure pressures are the nominal published

values. The pressures listed in Table 4-2 incorporate a safety factor. These

values are only intended to give a general notion of the possible effects on a

BWR containment where it is assumed that no mitigation scheme is employed;

they should be regarded in this light.

Table 4-2

HYDROGEN PRESSURE EFFECTS ON BWR CONTAINMENT TYPES

(ASSUMING NO MITIGATION SCHEMES ARE EMPLOYED)

Parameters Mark I Mark II Mark III

Design Pressure, psig (nominal) 60 45 15

Failure Pressure, Est., psig 120 140 72

Estimated Pressure 50% Metal- 19 19 4-5

Water Reaction, No Burn, psig

Estimated Pressure, >>200 >>200 55

30% Metal-Water Reaction,

With Burn, psig

Estimated Pressure, >>200 >>200 100

50% Metal-Water Reaction,

With Burn, psig

Percent Metal-Water Reaction >100 >100 100

To Reach Estimated Failure

Pressure With No Burn

Percent Hydrogen Necessary 13-16 15-20 8-12

To Reach Estimated Failure

Pressure With Burn

Note that from a containment failure pressure point-of-view, a hydrogen deflagration is worse in Mark I and Mark II containments because of their

4-9
smaller volumes. If a hydrogen ignition occurred, however, the resultant

pressure increase as a function of initial hydrogen concentration would be as

shown in Figure 2-10.4-7 It should be emphasized that both the Mark I and

II containments are inerted. For facilities with Mark I or II containments,

the operating oxygen concentration in the containment/drywell must be less

than 4% by volume to meet technical specification requirements. This essentially guarantees that a hydrogen deflagration could not take place within

this environment.

Figure 4-6 shows a typical BWR Mark I containment; a Mark II design is shown

later in Figure 4-32.

Figure 4-7 shows a profile view of a typical BWR MarkIII containment. Mark I

and II containments are inerted. For Mark III containments, where no inerting

is used, methods of controlling large amounts of hydrogen may be necessary to

ensure that the hydrogen does not threaten containment integrity.

4.3 INDICATIONS OF A LOSS-OF-COOLANT ACCIDENT

4.3.1 Introduction

Examination of those parameters that are indicative of a LOCA is the first

step in detecting the onset of an inadequate core cooling condition. It is

the ICC condition that ultimately can result in hydrogen production within the

reactor vessel. Further, as previously discussed, the liberation of high

temperature water or steam into containment can produce oxidation reactions

that can liberate hydrogen.

In this section, those key parameters that are indicative of a LOCA will be

considered for both PWRs and BWRs. The discussion will identify those parameters that, when considered collectively, can normally be used to identify

the presence of a LOCA. It should be emphasized, however, that where these

same parameters are considered individually the indications are not necessarily exclusive to a LOCA. Individual subsections discuss indications of

conditions internal and external to the Reactor Coolant System separately for

PWRs and BWRs.

4-10
z

IU

z

U.)

CI.-

z

z

0

U

o

SOIL AND ROCK I . I , I , I , I

0 10 20 30 40

FEET

Figure 4-6. Mark I BWR Drywell/Primary Containment

4-11
Figure 4-7. Section View of a Mark III Containment Structure

and Internals (Grand Gulf Nuclear Station)

4-12
4.3.2 PWR Indications Internal to the Reactor Coolant System

Indications of conditions internal to the Reactor Coolant System (RCS) that

are measured in operating nuclear plants and can provide evidence or a LOCA

include:

o Temperature

o Flow

o Pressure

o Pressurizer level

o Reactor vessel level

o Nuclear instrumentation

4.3.2.1 Temperature. Temperatures within the primary system are measured by

incore thermocouples and RCS hot leg resistance temperature detectors (RTDs).

The incore thermocouple system continuously monitors coolant outlet temperatures of selected fuel assemblies in the reactor core. These temperatures are

used for control room indication and plant computer analysis. The thermocouples are positioned at the top of the core to measure fuel assembly outlet

temperatures. A simplified drawing of a thermocouple channel as used in the

incore thermocouple system is shown in Figure 4-8.4-8 A LOCA could be

accompanied by abnormally large increases in the indicated temperatures.

Abnormally high thermocouple temperatures may be indicative of voiding in the

reactor core which may be followed by the production of superheated steam. In

the event of a drop in RCS inventory, heat transfer from the excessively hot

cladding will also contribute to an increase in the measured temperatures.

The hot leg RTDs will also experience an increase in temperature shortly after

the core exit thermocouples show a temperature rise, because they are located

15 to 20 feet downstream from the core exit thermocouples.

Those PWRs (e.g., many Westinghouse facilities) employing RTD bypass manifolds

may not show this temperature rise. These manifolds sample a fraction of the

RCS hot leg and cold leg flow. An RCS break (or tripping reactor coolant

pumps (RCPs)) will cause a drop in flow to the RTD manifold. Thus, there will

be little or no change in the hot leg or cold leg temperatures sensed by these

RTDs, and, hence, little or no change in the indicated temperatures. Therefore, core exit thermocouples tend to be the better indication of possible

voiding in the reactor vessel. Those RTDS installed in the reactor coolant

hot-leg piping itself will provide similar temperature indications, however,

the RTDs provide a less accurate measure of reactor core temperature conditions.

4.3.2.2 Flow. The power production rate in a LWR is limited not by the

amount of fuel, but by the ability to transfer energy from the fuel. A given

power level will require a minimum core flow rate to ensure adequate core

cooling to prevent exceeding thermal design limits. Reactor coolant flow

typically is found by one of two methods.4-6,4-8

o Measuring differential pressure across the steam generator

o Measuring differential pressure in a 900 piping elbow in the RCS

piping to the steam generator

4-13
THERMOCOUPLE

MEASUREMENT

JUNCTION

THERMOCOUPLE

JUNCTION BOX

THERMOCOUPLE

CONTROL

CABINET

REFERENCE

TEMPERATURE

160OF or 71 0C

Figure 4-8. Typical Incore Thermocouple System

4-14
If a LOCA occurred there would be a lesser mass flow rate through the system.

Further, as the RCS pressure dropped to saturation conditions, some flow

anomalies would result because of the lesser mass flow rate. The abnormal

reactor coolant pump flow indications seen by the operator could include:

o Decrease in pump motor current

o Increase in pump temperature

o Increase in pump vibration

4.3.2.3 Pressure. A LOCA, depending upon its magnitude, can result in a drop

in RCS pressure. A reactor trip and ECCS actuation could both be initiated by

a low pressure condition. ECCS actuation on low pressure can be an indication

of a LOCA.

In general, RCS pressure is measured at the pressurizer (see Figure 4-9).

Pressurizer pressure can be compared with the saturation temperature corresponding to the hot leg temperature to ensure that a subcooled system exists

within the reactor vessel and, thus, an adequate heat removal rate exists.

Post-TMI-2, PWR facilities have installed subcooling margin monitors (SMMs) to

monitor the margin to saturation within the reactor vessel. Typically, a subcooling margin monitor receives input signal data from pressurizer pressure

transmitters, core exit thermocouples, and hot and cold leg RTDs. Data from

each input source is processed as a temperature signal. The monitor obtains

the highest temperature from the various inputs. This temperature is a

measure of the margin to saturation in the reactor vessel or RCS. The SMM

would provide one of the first indications that pressure had dropped and that

the RCS was at saturated conditions if a LOCA occurred. There is a multiplicity of inputs to the SMM. The SMM must be well maintained, otherwise, its

usefulness could be marginal. (For example, input from an aging thermocouple

that has become noisy could result in invalid signals.)

4.3.2.4 Pressurizer Level. Pressurizer level is another potential indication

of a LOCA. Classically, it was assumed that if a LOCA occurred, the pressurizer would empty first because it is the highest elevation point in the

RCS. In fact, in previous years, many PWR facilities initiated safety injection (ECCS actuation) on low pressurizer level coincident with low pressurize

pressure.

However, since then it has been shown that some LOCA scenarios do not necessarily result in a rapid pressurizer level drop. A notable example was the

TMI-2 incident. Here the loss of coolant occurred through the pressurizer

power-operated relief valve (PORV) at the top of the pressurizer. In this

incident (described more fully in Appendix I) pressurizer level initially

dropped, and then, about one minute into the incident, it rose rapidly. This

rapid rise in pressurizer level confused the operators, causing them to reduce

makeup flow to the RCS and to reinitiate letdown flow. These actions caused a

reduction in RCS inventory that ultimately led to an ICC condition.

In general, pressurizer level should drop due to a LOCA -- especially for a

large LOCA that is not in the pressurizer steam space. However, "peculiar"

pressurizer, behavior can also be an indication of a LOCA (such as the

small-break LOCA at TMI-2) -- but in this case other indications such as

4-15
CONDENSING CHAMBER

WET 

VVA I :rV REFERENCE 

VOLUME LEG

HEATERS

PT

HP LP PRESSURE DIFFERENTIAL o' TRANSMITTER PRESSURE

TRANSMITTER

SURGE LINE

Figure 4-9. 

Arrangement 

Typical Pressurizer Pressure and Level Transmitter (Byron & Braidwood - Westinghouse)

4-16
those considered in this section must be used in conjunction with pressurizer

level to verify the existence of the LOCA.

4.3.2.5 Reactor Vessel Water Level. In the past, PWRs have not measured

reactor vessel water level. It has been assumed, since the pressurizer is at

the highest elevation in the RCS, that if pressurizer level is maintained it

can be assumed that the core is covered. However, as demonstrated during the

TMI-2 incident, a rapid RCS pressure drop caused steam formation in the

reactor vessel that resulted in water being forced into the pressurizer.

Thus, voiding may exist in the core while pressurizer level is maintained.

The potential for misinterpretation as to whether the core is covered (such as

could occur with an existing pressurizer level with voiding in the core), has

led to the installation of systems to provide an unambiguous measurement of

reactor coolant inventory above the reactor core. One such system involves

the use of heated-junction thermocouples.

The basic heated-junction thermocouple system consists of a heater and two

thermocouple junctions, as shown in Figure 4-10a. 4- 8 Under normal operating

conditions, the two thermocouples would be near the same temperature since

core flow will remove energy from the heater. Thus, the differential voltage

between the thermocouples will be small. If the water is replaced by a steam/

water mixture (which has less efficient heat transfer characteristics), the

thermocouple nearest the heater will heat up very rapidly, resulting in a much

larger output potential than that of the unheated thermocouple. If the core

becomes uncovered at the height of the thermocouple, a substantial rise in

output voltage will occur with a response time of about 1 second. Acceptance

tests have shown that the heated junction exhibits a sharp response similar to

that of an electronic bistable device. Figure 4-10b shows a typical

heated-junction thermocouple response curve.

Thus, the heated-junction thermocouple system, by providing an indication of

reactor vessel water level, can indicate the existence of a LOCA. In the case

of a large-break LOCA, this indication would be rapid (a matter of seconds,

perhaps). For a small-break LOCA, it may take minutes to hours to see the

drop in reactor vessel water level. In either case, it would disclose when

the core could become uncovered, which is of concern because if an uncovered

core becomes inadequately cooled a fuel cladding metal-water reaction could

occur.

4.3.2.6 Nuclear Instrumentation. Nuclear instrumentation at PWR stations

includes the:

o Excore Nuclear Instrumentation System

o Incore Instrumentation System

These systems provide vital information to the reactor operator and process

computer, and supply input (trip) signals to the Reactor Protection System.

The use and importance of the nuclear instrumentation systems in the evaluation of the nuclear (and power generating) behavior of the core is obvious.

However, these systems can also provide additional information concerning

adverse core cooling conditions. If water level drops in the reactor core,

both the excore and incore nuclear instrumentation, will be affected. Much

4-17
COPPER

INCONEL 700

SN

CHROMEL A

B

C

(-I

1 ALUMEL

ALUMEL 2

CHROMEL

COPPER

HEATER POWER 40 VAC, 1 AMP NOMINAL = 35 WATTS

V (A-B) = ABSOLUTE TEMPERATURE UNHEATED JUNCTION

V (C-B) = ABSOLUTE TEMPERATURE HEATED JUNCTION

V (A-C) = DIFFERENTIAL TEMPERATURE

Figure 4-10a. Heated-Junction Thermocouple Arrangement

t STEAM

HJTC

OUTPUT

WATER

TEMPERATURE 570 F

PRESSURE 1200 PSI

TIME ----

Figure 4-10b. Heated-Junction Thermocouple (HJTC) Response

4-18
could be said about the possible behavior of this instrumentation during a

LOCA of this magnitude, however, one fact is certainly clear: the readings

will be off-normal. Some examples of this possible off-normal behavior are

discussed below.

If the core is uncovered by a LOCA, increased neutron and gamma leakage will

result. This increase in leakage would be seen by the excore nuclear instrumentation, and would be indicated by an increased signal strength. In fact,

during the incident at TMI-2, the excore nuclear instrumentation indicated

that a two-phase mixture had developed in the reactor core. At about 20

minutes into the incident, a greater neutron leakage caused these detectors to

show an increased count rate (as shown in Appendix I, Figure 1-28). To better

understand this phenomenon, consider a system which employs radioactive

sources for level measurement in a tank, as shown in Figure 4-11. In this

system as long as the water level in the tank is high, the detector output

will be low, since the water acts as a radiation shield. As the water level

drops, the shielding decreases, and the detector output increases. A similar

effect can be observed with the excore instrumentation associated with PWR

cores. 4 - 8 These detectors (Figure 4-12) measure a fraction of the fast

neutrons that leak from the core. If the only variable is reactor power

(indicated by neutron population), changes in detector output correspond to

changes in power. However, if the water level in the core drops, the reduction in neutron shielding results in a higher detector output. Thus,

unexpected increases in indicated power could be due to the core being

uncovered.

The Incore Instrumentation System uses either movable or fixed miniature fission chambers, or fixed miniature self-powered neutron detectors (SPNDs).

Both detectors could show an increase in signal strength due a two-phase

water-steam mixture in the reactor vessel. The SPNDs are primarily sensitive

to the neutron flux, and are uncompensated for gamma radiation. In general, a

drop in signal strength might be expected during core uncovery, however,

because the SPND exhibits thermionic behavior, it will yield an output current

proportional to the detector temperature. Theoretically, as the core became

uncovered, the fission chambers should indicate a smaller signal strength,

while the self-powered neutron detectors can actually indicate a larger signal. (See Appendix I and Figure 1-25 for a brief discussion of SPND thermionic behavior.)

The fission chambers may be movable through the height of the core, or permanently installed at prescribed locations. Note that these detectors exhibit

a response to both thermal neutrons and gamma radiation. The detector

response to gamma radiation is smaller in amplitude because the detector is

less sensitive to gamma radiation. Ordinarily, the gamma ray component of the

detector output is reduced or removed by one of the following techniques:

o Setting a pulse discriminator in the detector circuit to remove the

smaller amplitude gamma ray-induced pulses

o Employing a counting statistics technique which results in making

the gamma response negligible (the Campbelling Technique)

Thus, during normal conditions the system indication would be proportional to

neutron leakage from the core, and, hence, to core power level.

4-19
RADIOACTIVE

SOURCE

Note: This a measurement device designed

-for a tank. The figure does not show a

reactor, however, the principles employed

in the device are also applicable for

measuring level in a nuclear reactor.

INDICATOR

€0

CN FF

L

-- -DETECTOR

~LIQUID LEVEL

INDICATOR

Radioactive Sources Used for Continuous

Level Measurement

RADIOACTIVE/

SOURCES

Figure 4-11.

I

4-20
SPARE

POWER

RANGE 0

CHANNEL

4

0

SOURCE &

INTERMEDIATE

RANGE

CHANNEL

I

-I

POWER

RANGE

CHANNEL

-- 0

SOURCE &

INTERMEDIATE

RANGE

CHANNEL

2

POWER

RANGE

CHANNEL

3

0

POWER 0

RANGE

CHANNEL SPARE

2

PLAN VIEW

POWER RANGE

DETECTORS

INTERMEDIATE

RANGE DETECTOR

SOURCE RANGE

DETECTOR

ELEVATION

Figure 4-12. Detector Locations for the Excore Nuclear

Instrumentation (Typical Westinghouse PWR)

4-21
If the core was uncovered during a LOCA, however, the indicated power would

change. The relative number and magnitude of the gamma-induced pulses would

increase so that the detector circuitry would not eliminate all of them. However, the dominant effect would be the sharp drop in neutron-induced pulses

because of the sharp decrease in the number of thermal neutrons. Because of

these effects, the fission chamber detector output would drop during a LOCA.*

The self-powered neutron detectors generally are installed at fixed elevations

and specific radial positions throughout the reactor core. This type of

detector yields a given output current for a specific neutron flux in the

reactor core. However, it was found during the TMI-2 incident that SPNDs that

became uncovered indicated very high output currents by comparison with those

SPNDs that remained covered during the incident. This behavior was due to the

thermionic effect on this detector.

During normal conditions, the neutron flux causes the SPND center wire to

become radioactive. This rhodium wire then emits beta particles. The net

positive charge on the wire causes a current flow, which is used as the output

signal.

When the core is uncovered by a LOCA, the rhodium wire will heat up and emit

electrons. This emission results in a net positive charge on the wire, again

causing a current flow. Thus the SPND output would indicate an increase in

power.

In summary:

o Excore nuclear instrumentation can read high during a LOCA.

o Incore nuclear instrumentation can read high or low depending upon

the detector type and the degree of voiding. In either case,

"peculiar" instrumentation behavior coupled with other control

board RCS indications can be used to detect a LOCA.**

4.3.3 PWR Indications External to the Reactor Coolant System

There are several indications of conditions external to the Reactor Coolant

System that can indicate the onset of a LOCA. These are:

o Containment pressure

o Containment temperature

o Containment humidity

o Containment activity

o Containment sump water level

* It is possible that heating of the detector could result in an increased

output indication due to a thermionic effect. However, insufficient information is available on this point.

** For those plants with both fission chambers and SPNDs, a LOCA could cause

the fission chamber output to drop and the SPND output to rise: a prime

example of "peculiar" behavior! (See Appendix I for a discussion of how SPND

behavior following a LOCA compared to the normal plant shutdown behavior.)

4-22
4.3.3.1 Containment Pressure. A LOCA will discharge water and steam into the

containment atmosphere, thereby causing a containment pressure increase. This

pressure increase can cause safety injection actuation (ECCS initiation). The

containment pressure increase coupled with an RCS pressure decrease is indicative of a LOCA.

4.3.3.2 Containment Temperature. During a LOCA, a sharp temperature rise in

containment will accompany the pressure rise caused by the discharge of high

temperature coolant.

4.3.3.3 Containment Humidity. If a LOCA occurred, containment humidity

should increase along with the pressure and temperature in containment. However, many PWR containments operate with fairly high humidities during normal

operations. As a result, an increase in relative humidity is not nearly as

significant as increases in containment pressure and temperature as an indication of a LOCA.

4.3.3.4 Containment Activity. A main steam line break will cause many of the

same indications as a LOCA. Containment activity is one of the best indications to differentiate between the two occurrences. Containment activity is

normally low. During a LOCA, activity from the RCS will be discharged to the

containment atmosphere. This activity will cause the area radiation monitors

in containment to read high during a LOCA.

4.3.3.5 Containment Sump Level. Rising sump levels are indicative of some

type of pipe break in containment. If this is coupled with high containment

activity levels it is an indication of a break in the RCS; i.e., of a LOCA.

4.3.4. BWR Indications Internal to the Reactor Coolant System

The indications of a loss of reactor coolant in a BWR are similar in many

respects to those for a PWR. The presently measured indications of conditions

internal to the Reactor Coolant System include:

o Temperature

o Flow

o Pressure

o Reactor vessel level

o Nuclear instrumentation

4.3.4.1 Temperature. Temperature indications in BWRs are not as abundant as

in PWRs, nor are they relied upon as heavily as in PWRs. Typically, temperature is inferred from pressure since normal operation is at saturation conditions. Recirculation loop temperatures are available; steam line temperatures

may be available at some plants. Overall, temperature is not a primary indicator of a loss-of-coolant accident.

4.3.4.2 Flow. As with a PWR, the power production rate in a BWR is limited

not by the energy production rate, but by the energy removal rate. Thus, BWRs

require a minimum flow rate for a given reactor power. Typically, the reactor

coolant mass flow rate is monitored by measuring the differential pressure

across a venturi in the steam line piping leaving the reactor vessel.

4-23
BWRs have abundant core flow information available. Total core flow is

obtained by summing the flow through each jet pump (see Figure 4-13), and is

displayed in the control room. Individual jet pump flows are available at a

remote panel. Core plate differential pressure is recorded and can be used to

determine gross changes in core flow or flow distribution. Recirculation loop

flow, which provides the driving flow to the jet pumps, also is displayed.

A LOCA would reduce the flow rate through the core. As previously stated,

inadequate core flow would result in an increase in cladding temperature,

which could lead to an ICC condition. However, flow anomalies could also

indicate the onset of core cooling problems. For example, variation in the

individual jet pump flow rates could indicate an abnormal distribution of

reactor coolant entering the reactor core.

4.3.4.3 Pressure. Reactor vessel pressure is sensed using the reactor vessel

level reference legs. Pressure signals are provided to the ECCS and Feedwater

Control System. A rapid pressure drop is one of the principal indications of

a LOCA.

4.3.4.4 Reactor Vessel Level. Reactor vessel level indications are abundant

in BWRs. Typically, four or more ranges are available; use of a particular

range depends on the operating conditions in the core. Figure 4-14 is an

example of the level ranges. 4 - 9 Since the detectors for each range are

separate, and since overlapping exists between ranges, there is redundant

level indication in the control room. Level is measured by comparing the

pressure exerted by a fixed column of water in a reference leg to the pressure

exerted by the height of water in the vessel, as schematically shown in

Figure 4-15. The reference leg is at a lower temperature than the vessel,

and, thus, there will be a density difference between the water in the vessel

and the reference leg. This difference will result in an error in the indicated level. Various methods are employed to account for the density effect

during normal operation, including:

o Correcting the signal from the level transmitter with a milliampere

signal proportional to vessel pressure

o Calibrating the level range instruments with respect to the containment environment that would exist when the range would normally

be used

o Making no correction, since error makes level indication more conservative (acutal level > indicated level)

If a LOCA occurred, a rapid drop in reactor vessel water level would occur.

This drop would be an immediate indication of a LOCA.

Once the released coolant enters the containment it will heat up the atmosphere and surroundings, including the reference leg. This would reduce the

temperature, and density, difference between the two legs, causing a higher

than actual level indication. For the postulated DBA-LOCA, the reactor vessel

water level indication can be 10 to 15% in error for the expected temperature

rise in containment. If the reference leg water should flash to steam, the

reactor vessel water level indication can become useless. Therefore, it is

important to remember that once a LOCA has started the indicated vessel level

may become invalid.

4-24
LEGEND

= Summer

VN = Square Root Extractor

FI = Flow Indicator

PDI = Pressure Differential Indicator

F~ZJ

I I

U,

Inputs from

Flow Transmitters

I I II iI

Instrumentation [pI (Penetration

Low Pressure

Connection Inputs from

Square Root Extractors

for Flow Transmitters

Core

Plate

f ICore P

To Reactor " Water Cleanup

-- System ----

L

Excess Flow Typical Connection

below Check Valve to Remaining Flow

e -• Transmitters A Recirculation-..j___ Loop Total Jet -- L

Pump Flow

Signal -

B Recirculation Loop

Jet Pump Total Flow Signal

Recorder

Figure 4-13. Jet Pump Instrumentation Block Diagram
SHUTDOWN

RANGE

NARROW RANGE POST- ACCIDENT

POST-ACCIDENT RECORDER CONDENSING CHAMBER RECORDER

REACTOR

VESSEL

LT rLL LT NARROW LT

)RANGE

FUEL ZONE R RANGE FUEL ZONE

LT RANGE

Figure 4-14. Reactor Vessel Level Instrumentation - Simplified Diagram
CONDENSING CHAMBER

P W Primari

IOUTPUT SIGNAL j

Figure 4-15. Typical Reactor Vessel Level Detector

4-27
4.3.4.5 Nuclear Instrumentation. The Neutron Monitoring System (NMS) for a

BWR consists exclusively of incore instrumentation. The source range monitors

(SRMs) and intermediate range monitors (IRMs) are both movable detector

systems. They employ miniature fission counters (pulse-type output) and

miniature fission chambers (current-type output) respectively. BWR facilities

also employ fixed incore fission chambers in the Local Power Range Monitoring

(LPRM) System.

Because of their greater sensitivity, it is the source range and intermediate

range nuclear instrumentation systems that can be of most value in ascertaining the severity of a LOCA. Note that these detectors exhibit a response

to both thermal neutrons and gamma radiation. The detector response to gamma

radiation is pulses of a smaller amplitude than those caused by neutrons, due

to a lesser detector sensitivity to gamma radiation. Ordinarily, the gamma

ray component to the detector output may be reduced or removed by one of the

following techniques:

o Setting a pulse discriminator in the detector circuit to remove the

smaller amplitude gamma ray-induced pulses.

o Employing a counting statistics technique that results in making

the gamma response negligible (the Campbelling Technique)

Thus, during normal operation, the detector output corresponds directly to the

neutron flux, and, hence, to the core power level.

If a LOCA occurred, two-phase flow through the core would increase. Thus the

fluid density in the core would be less. Since the neutrons are slowed down

by the coolant, a decrease in density would increase the mean free path of the

neutrons. This increased mean free path would result in a higher neutron flux

at the detectors, and therefore, in an increase in detector output.

However, as the detector itself becomes uncovered and the two-phase flow

becomes pure steam, detector output should drop because the fission detector

is more sensitive to thermal neutrons than to the high energy neutrons

initially emitted by the fission process.

4.3.5 BWR Indications External to the Reactor Coolant System

There are several indications external to the Reactor Coolant System that are

indicative of a LOCA in a BWR. These are:

o Drywell/containment pressure

o Drywell/containment temperature

o Drywell/containment activity

o Suppression pool water level

(Note: Drywell/containment refers to the drywell in Mark I or II BWR designs,

but to both the drywell and containment in a Mark III BWR design.)

4.3.5.1 Drywell/Containment Pressure. BWRs employ a pressure monitoring

system that continuously monitors the pressure in the drywell and suppression

pool (torus at some facilities). This system is capable of detecting a leak

in the Reactor Coolant System and of measuring the pressure increase arising

from a LOCA.

4-28
4.3.5.2 Drywell/Containment Temperature. The drywell containment temperature

monitors measure drywell atmosphere, suppression pool atmosphere, and suppression pool water temperature. The temperature sensors are situated to ensure

that representative measurements are obtained. A rapid rise in temperature

can be an indication of a LOCA. (The general vicinity of the break can be

determined if a rise is seen on one sensor, followed by rises on nearby

sensors.)

4.3.5.3 Drywell/Containment Activity. BWRs employ a fission product radiation monitoring subsystem that monitors air particulate iodine and noble gases

within the drywell containment. If the detected radiation exceeds a predetermined value, an annunciator is energized in the control room. If a LOCA

occurred, this alarm should be energized.

In addition, there are drywell/containment and suppression pool gamma radiation monitors. These monitors are intended to be operable following a design

basis accident. High level alarms associated with this instrumentation would

also be annunciated in the control room.

4.3.5.4 Suppression Pool Water Level. Water level in the suppression pool is

continuously monitored. The instrument provides trip logic for the reactor

and for Emergency Core Cooling System actuation if a high level is reached. A

high level in the suppression pool is yet another indication of a LOCA.

4.4 INDICATIONS OF HYDROGEN PRODUCTION

The previous section emphasized those parameters that should be examined to

determine whether a loss-of-coolant accident has occurred. The existence of a

LOCA is of great concern because it can be the first step toward an inadequate

core cooling condition. An ICC condition could ultimately develop into a condition in which hydrogen could be liberated by the steam reaction with the

fuel cladding, and, eventually, by other reactions if the accident is not terminated (see Chapter 2). If this occurred, there are a great number of potential indications, in addition to hydrogen detectors within the containment, of

the presence of hydrogen or of whether a hydrogen combustion occurred. The

following discussion examines each of these parameters individually, and discusses their behavior if hydrogen were liberated during an accident condition.

The indications of hydrogen production internal to the Reactor Coolant System

will be considered first, followed by those indications that are external to

the Reactor Coolant System. Keep in mind when reading this section that

instrumentation varies from plant to plant, thus not all indicators will be

available at every nuclear power station.

Further, various indications of an inadequately cooled core and the resultant

production of hydrogen will be discussed. The existence of any one of these

indications may or may not indicate hydrogen production. One must examine all

available data, and then make a knowledgeable assessment of the actual core

conditions.

One of the principal lessons learned from the TMI incident was that key operational or safety decisions should not be made based on a single parameter;

4-29
instead all available data should be evaluated before rendering an important

safety decision during a plant emergency. This lesson should be kept in mind

when reading the subsequent material.

It will be seen later in this chapter that it is not necessary to be

absolutely sure that hydrogen is present. Not every mitigation scheme

requires the absolute certainty of the presence of hydrogen before it is

initiated. For example, one scheme, a hydrogen igniter system, may be placed

in service if only the possibility of hydrogen production exists.

4.4.1 Indications of Hydrogen Production Internal to the Reactor Coolant

System of a PWR

4.4.1.1 Temperature. The incore thermocouple system may be helpful in determining if a hydrogen-producing environment exists within the reactor vessel.

For example, Figure 4-16 shows the core exit thermocouple readings that

occurred during the TMI-2 incident. From these data taken at approximately

1000 psig, it can be seen that reactor coolant inventory must have been low

and superheated conditions must have existed at various core locations. Thus,

a distinct probability existed that hydrogen production had commenced.

Temperature can provide a first indication of the extent of core damage

(hence, of hydrogen production). The thermocouple system provides a map of

core exit temperatures and can thus be used to determine if the entire core is

inadequately cooled or if the phenomenon is localized (see Figure 4-16). An

abnormally low temperature reading (such as F3 in Figure 4-16) may be due to

thermocouple failure caused by excessive core damage.

Another indicator of poor thermal-hydraulic conditions and of possible hydrogen production in the core is the hot leg temperature, which is measured by an

RTD. RTDs can be installed in a thermowell directly in the RCS hot leg piping

(Combustion Engineering and Babcock & Wilcox plants) or in a bypass manifold

connected to the RCS (Westinghouse design). The most frequently used metal

for the RTD is platinum, which has a resistance linearly dependent on temperature to about 12500 F. A temperature above saturation temperature for the

operating pressure would be indicative of a significant amount of voiding in

the core and the production of superheated steam. This abnormal thermal

hydraulic condition would not adequately remove the stored energy of the

cladding. Thus, an increase in cladding temperature and, possibly, in the

metal-water reaction rate would occur. Obviously, if this reaction rate

increases, more hydrogen is produced. (Above 1800°F one may assume that the

hydrogen generation commences as a result of the water reaction with the clad.)

4.4.1.2 Flow. Reactor coolant flow indication does not by itself indicate

that hydrogen production is occurring. However, if adequate core cooling

(i.e., coolant flow) is not maintained for the existing power level, the

cladding temperature will increase. If this situation continues to the point

that an ICC condition develops, hydrogen production can occur.

Flow anomalies may also indicate the onset of an ICC condition that could lead

to hydrogen production. There are several potential causes of flow anomalies,

4-30
1 2 3 4 5 6 7 8 9 10 11 12

71 1 II7

13 14 15

281 1325

469 1 957 325

1196 500 217

599 1926 2580 326

80 2366 2378 323 555

375 2272 1774 1806 1875 234

260 2452 12952176 1852

1811 632 1760

373 1566 382 296 17741

A

B

C

D

E

F

G

H

K

L

M

N

0

P

R

325 2171 23271348 252

1 1 431 1 1.I578 12167 111

~3561 462 11138 3081

-4-4 -4-1-4-I-I -9- t -

291

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Figure 4-16. Map of Core Exit Temperatures ( 0F) at 240-300 Minutes for the TMI-2 Incident

4-31
one of which is the collection of steam or noncondensable gases (such as

hydrogen) at high points in the RCS. During the incident at TMI, gases

collected in the "candy cane" regions of the RCS piping at the steam generator

inlets (see Figure 4-17).

Abnormal reactor coolant pump indications may indicate flow anomalies. Abnormal indications may include:

o Decrease in pump motor current

o Increase in pump temperature

o Increase in pump vibration

During operations, if indications of less than normal flow or of flow

anomalies are present, other instrumentation should be checked for evidence of

hydrogen production.

When reactor coolant pumps (RCPs) are secured and natural circulation cooling

is employed, core flow is determined from a differential temperature measurement.

Using the abundant temperature information available from PWR process instrumentation, an estimate of the flow rate can be calculated using the simple

heat transfer relationship:

Q = mc T (4-1)

where:AT = Th - Tc (4-2)

Th = hot leg temperature (OF)

Tc = cold leg temperature (OF)

Q = rate of energy transfer (Btu/h)

m = mass flow rate (ibm/h)

cp = specific heat capacity of water at constant pressure

(Btu/lbm-F)

A high AT (e.g., greater than full power AT) would indicate an inadequate core

flow rate for the power generation rate. Hence, cladding temperatures may

rise above the threshold for the metal-water reaction. This AT is an

extremely important indication of cooling flow during natural circulation

cooldown. Further, any noncondensable gas binding of the RCS piping would be

manifested by a high AT during a natural circulation cooldown.

4.4.1.3 Pressure. By itself, pressure cannot be used to verify the presence

of hydrogen. However, the operator may be able to use pressure in conjunction

with other parameters to verify that hydrogen is present. For example, assume

that a LOCA has occurred that resulted in an inadequate core cooling condition

and hydrogen production. Further, assume that RCS pressure has been restored

and that there is a void in the upper part of the reactor vessel (determined

by measuring reactor vessel water level). If under these circumstances, the

Reactor Coolant System is rendered subcooled and the void remains, then it can

be assumed that this is a noncondensable gas void. Further, if in trying to

increase RCS pressure a sharp pressure increase is observed, this noncondensable gas is displaying the hard bubble phenomenon previously described in

Chapter 3.

4-32
JPRIMARY WATER

SECONDARY WATER

FJ STEAM

= STEAM/HYDROGEN

t 3.5 hours

P 1500 psig

IA

IA

I. I

Figure 4-17. Reactor Vessel Refilled by Manual Initiation of Safety Injection

Core Temperatures Decreasing
The non-condensable gas void may also be comprised of nitrogen from the ECCS

nitrogen accumulators (or safety injection tanks or core flood tanks, depending on the plant) used at many PWR facilities. To know whether this is so,

one must know whether these tanks, which use compressed nitrogen gas, actually

discharge into the RCS.

In summary, with noncondensable gases present in the RCS, pressurizer pressure

control would not respond normally. If this is the case, the guideline in

Appendix II may be used to determine the size or the gaseous void.

4.4.1.4 Pressurizer Level. The presence of hydrogen in the Reactor Coolant

System will cause pressurizer pressure and level controls to respond

abnormally. As has been mentioned, the presence of noncondensables (such as

hydrogen) creates a hard bubble phenomenon. That is, from a pressure viewpoint, the hydrogen void almost appears as a solid water volume.

In general, pressurizer level must be used in conjunction with other parameters, such as temperature and pressure, to indicate the presence of hydrogen. Abnormal behavior, such as a sharp RCS pressure rise resulting from a

small pressurizer level increase, would be expected if the hard bubble phenomenon exists.

4.4.1.5 Reactor Vessel Water Level. A major concern during accident transients is to ensure that the core is covered by reactor coolant. High and low

pressure safety injection systems are designed to ensure coolant is available

even during the most limiting accident conditions. Obviously, without enough

water to cool the core, cladding temperatures will rise, resulting in hydrogen

production from the metal-water reaction. Thus, reactor vessel level is an

extremely important parameter to observe to ensure adequate core cooling.

PWR facilities are currently installing or planning to install either differential pressure sensors or heated-junction thermocouple systems to determine reactor vessel water level.

4.4.1.6 Reactor Coolant Sampling. The reactor coolant can be sampled for

many items, including hydrogen concentration. When the coolant is sampled for

hydrogen, a liquid sample is drawn. While this will indicate the presence of

hydrogen in the RCS, it will not be an accurate measure of the concentration

in the pressurizer steam space. To obtain such a measurement, a gaseous

sample would have to be drawn.

4.4.1.7 Reactor Coolant Activity. The reactor coolant normally will contain

activation products. The source of these radionuclides may be the water

itself, structural material in the core, a suspended (insoluble) solid, a

soluble neutron absorber such as boron, a soluble corrosion product, or other

impurities in the water. The major sources of long-lived radioactivity identified in the RCS are activation products.

These activation products should not be confused with fission products that

could be released into the reactor coolant if an ICC condition led to fuel

damage. Inadequate core cooling can result in fuel damage from a steam reaction with the fuel cladding (see Chapter 2). Therefore, abnormally high RCS

activity could denote fuel damage.

4-34
The presence of fuel damage, then, is a potential indicator of a

steam-cladding reaction; such a reaction would liberate hydrogen. Therefore,

it is safe to say that any time there is significant fission product leakage

into the RCS, there should be an ever-present concern about hydrogen production.

Differentiating between activation products and fission products is relatively

straightforward. It is a matter of utilizing standard laboratory counting

techniques to identify the individual radionuclides in an RCS sample.

Table 4-3 lists the primary coolant activation products, along with their

major source in the RCS.

Table 4-3

PRIMARY COOLANT ACTIVATION PRODUCTS

Nuclide Half-life

12.26 yr

17 N

5730 yr

7.1 s

14.4 s

110 min

9.96 min

2 4 Na

31lS

15 h

2.6 h

14.3 d

1.83 h

27.8 d

Reaction

10B(n,20) 3H

6Li (n,a) 3H

14N(n,p) 14C

16 O(n,p) 16N

170(n,p) 17N

180(p,n) 18F

160(p,a) 13N

23 24 Na (n,*Y) Na

3 0 Si (n,-Y) 31Si

31 32 P (n,*Y) P

40Ar(n,Y) 41Ar

50Cr (n,*'I) 51Cr

54Fe(n,p) 54Mn

5 4Fe(n,Y) 55Fe

Major source

Boron in coolant

Lithium in coolant

Nitrogen in water

Water

Impurity in water

Impurity in water

Impurity in water

Air in water

Steel & high-nickel

Water

Water

Water

4 1Ar

51Cr

54Mn

5 5

Fe

alloys

312 d Steel & high-nickel

alloys

2.7 yr Steel & high-nickel

alloys

4-35
5 6 Mn 2.6 h

59 Fe

59 Ni

45 d

8 x 104 yr

92 yr

6 5Ni 2.6 h

71 d

5 5 Mn (n , ) 56Mn

58 59 Fe (n,Y) ,9Fe

58 Ni (n ,*Y) 59 Ni

62Ni(n,Y) 63Mo

6 4 Ni(n,Y) 65Ni

5 8Ni(np) 58CO

5 9Co(n,Y) 60CO

6 3Cu(n,Y) 64CU

9 5 Zr(n,Y) 95Zr

96 97

Zr(n,Y) Zr

109 ll0M

Ag(n,Y) Ag

114 115

Cdr(n,y) Cd

180 181

W(n,Y) W

186 187

W(n,y) W

Steel & high-nic

alloys

Steel & high-nic

alloys

Steel & high-nic

alloys

Steel & high-nic

alloys

Steel & high-nic

alloys

Steel & high-nic

alloys

Stellite steel

17-4 pH steel

Zircaloy-4

Zircaloy-4

Control rod (b)

Control rod (b)

Steel, carbides,

stellite

Steel, carbides,

stellite

kel

'kel

kel

kel

kel

kel

6 0

Co

64Cu

95 Z

97 Zr

llOmAg (a)

115 cd(a)

181 W

187 W

5.24 yr

12.9 h

65 d

16.8 h

253 d

53.5 h

130 d

24 h

I

(m)

(a)

(b)

Denotes a metastable state.

In plants with B4C control rods fission is the

only source of these nuclides.

Also a fission product.

4-36
From Table 4-4, it can be seen that hydrogen, in the form of radioactive

tritium, can be produced within the reactor coolant. Tritium, however, can

also be produced in the nuclear fuel by means of ternary fission. (Ternary

fission results in three fission products instead of the usual two from binary

fission.) Ternary fission occurs approximately once out of every 12,000 fission events in the reactor.

Table 4-4

SOURCES OF TRITIUM FROM NEUTRON REACTIONS

Reaction Threshold

1 0 B(n,2a)T 1 0B (n,c) 7 Li(n,nc))T

1 0 B (n,2c)T

7Li (n,na)T

6 Li(n,c))T

2 D (n,Y)T

1 MeV

Thermal;3 MeV

10.0 MeV

3 MeV

Thermal

Thermal

The list of fission products is extensive; Table 4-5 shows a partial listing

in order of decreasing escape rate coefficients. (Those with the greatest

probability of escape have the highest escape rate coefficients.) Those that

escape most readily are the fission product gases, or volatile fission products. Table 4-5 also includes the semi-volatile fission products, such as

the iodine isotopes, and the non-volatile fission products.

Table 4-5

FISSION PRODUCTS

Nuclide

131m xe

13 3m Xe 133mx

133Xe

135mxe

1 3 5Xe

138Xe

85mKr

8 5 Kr

Half-life

11.96 h

2.26 d

5.27 d

15.70 min

9.16 h

14.20 min

4.40 h

10.74 yr

76.00 min

2.79 h

1 3 8 Cs

8 9 Sr

9 0 Sr

91Sr

92Sr

88Rb

89Rb

9 9

Mo

Nuclide Half-life

30.2 yr

32.2 min

50.8 d

28.9 yr

9.67 h

2.69 h

17.7 min

15.2 min

66.6 h

84.0 min

87Kr

88Kr

4-37
131I 8.065 d 12.8 d

133I 20.8 h 140La 40.2 h

141Ce 32.5 d 143Pr 13.6 d

143Ce 33.0 h 144Pr 17.3 min

1341 52.30 min 90y 64.0 h

1351 6.70 h 91 58.8 d

134Cs 2.06 yr 92 3.54 h

136Cs 13.00 d 93 10.1 h

9 5Nb 3.5 d 1 4 4Ce 284.4 d

102Ru 39.4 d 1 3 2 Te 78.0 h

4.4.2 Indications of Hydrogen Production External to the Reactor Coolant System of a PWR

4.4.2.1 Containment Pressure. If hydrogen is liberated into containment following a LOCA as a result of a steam reaction with the fuel cladding, there

would be an increase in containment pressure. However, a containment pressure

increase will also occur as a result of reactor coolant flashing to steam following a Reactor Coolant System break. Therefore, a pressure increase in containment is not, by itself, a sufficient indicator of the presence of hydrogen. However, the existence of a LOCA should caution the operational staff

that the potential for hydrogen production exists.

4.4.2.2 Containment Temperature. If a LOCA occurred containment temperature

would rise as coolant was released into the containment building. If hydrogen

is created within the reactor core by a fuel cladding-steam reaction, and subsequently released to the containment, it would be impossible to detect its

presence from temperature effects alone. However, as with a containment pressure increase, the containment temperature increase indicates the potential

for hydrogen production.

4.4.2.3 Containment Humidity. Since many pressurized water reactor stations

operate with high relative humidities in containment during normal full-power

operation, the use of this parameter as an indicator of the presence of hydrogen seems somewhat unlikely. However, for those facilities whose relative

humidity in containment is significantly less than 100%, a sudden increase in

humidity is indicative of a loss-of-coolant condition (although, it may be

only an excessive RCS leakage condition). As a result, a sudden increase in

containment humidity should be compared with other parameters discussed in

this section, because a possible ICC condition may be approached. Approaching

an ICC condition could ultimately result in hydrogen production from the reaction between the hot steam in the core and the hot fuel cladding.

4-38
4.4.2.4 Containment Sampling. Post-accident sampling of the containment is,

of course, a direct method of determining the presence of hydrogen. During

examination of the containment atmosphere sample it is important to determine

the oxygen concentration as well, since this measurement can be used to determine the amount of hydrogen initially present in the containment atmosphere.

This is true because a drop in the oxygen concentration would occur during a

hydrogen combustion. In order to use this technique, however, the containment

must be sampled with sufficient frequency to ensure that an accurate measure

of the oxygen concentration exists. If it is known then any sudden drop in

oxygen concentration clearly would be indicative of a reaction with the hydrogen in containment.

For example, during the TMI-2 incident, the hydrogen and oxygen concentrations

were measured 3 days following the onset of the incident. On March 31, 1979,

at 0600 hours, the hydrogen and oxygen concentrations of a sample of dry air

in containment were measured to be: 4-11

o H2 concentration = 1.7%

o 02 concentration = 16.1%

(Note: These data are from a dried air sample. In the sample, hydrogen oxygen, and nitrogen concentration are measured; the sum of their concentration

equals 100%.)

Because the precise oxygen concentration was not known prior to the start of

the incident, the TMI staff engineers assumed that it was the normal concen-

*tration in dry air, i.e., 20.9%. With this assumption, the oxygen concentration would have dropped a total of:

20.9% - 16.1.% = 4.8%

Since 2 moles of hydrogen react with one mole of oxygen to form water, the

amount of hydrogen that was initially burned would have been:

2 x 4.8% = 9.6%

These calculations are based upon the oxygen concentration in containment

being 20.9%. However, there is reason to believe that the oxygen concentration in a dry atmospheric containment is less, than the standard concentration

for normal air. The oxygen in containment can react with many type of metals;

the resultant oxidation of the metals in containment would tend to reduce the

free oxygen concentration to less than 20.9%. If this was the case at TMI-2,

then the drop in the oxygen concentration would have been less that 4.8%, and,

hence, the actual hydrogen concentration would have been less than 9.6.*

* Because of the conditions existing at TMI, this calculation may be considered valid. In any case, it should have been conservative. However, it

should be emphasized that this method cannot be used at all times. Oxygen

concentration may be reduced by other methods besides reaction with hydrogen.

For example, injection of a gas into containment will lower the oxygen mole

fraction. Therefore, it cannot always be assumed that the difference between

the final and initial oxygen concentrations corresponds to the amount of oxygen that reacted with hydrogen.

4-39
4.4.2.5 Steam Line Radiation. The steam generator tube rupture has the

potential for a large off-site radioactivity release. If the Emergency Core

Cooling System (ECCS) capabilities are hampered in some way, this particular

accident could ultimately result in a degraded-core condition. If an ICC condition were to exist, then hydrogen could be produced by steam reaction with

the hot fuel cladding. Releasing hydrogen through the ruptured steam generator tube(s) is highly undesirable because it could be released to the environment along with the fission product radioactivity from the damaged fuel. If

ignited by some spark upon its release (through a steam line power-operated

relief valve (PORV), for example), it could damage the valve through which

release was taking place. This could also provide a fission product release

path from the RCS to the steam line (via ruptured steam generator tubes) and

directly to the environment through a damaged relief valve.

The presence of high steam line radiation is not a sufficient indicator of

hydrogen production, but it is a good warning to key the operations staff to

ensure that emergency core cooling is maintained to guarantee sufficient core

cooling, so as not to allow an emergency condition such a this to result in a

degraded-reactor-core condition.

4.4.2.6 Gross Radiation Level Detection. A previous section discussed the

nuclides in the RCS that could indicate potential reactor core damage. It

should be emphasized that at any time when RCS activity levels are rising, the

vital RCS parameters should be monitored and evaluated to determine the source

of this activity. An increasing RCS activity could point to existing or

potential fuel damage which could ultimately lead to hydrogen generation.

An example where radiation level detection could have been used as a potential

indication of a degraded core condition and possible hydrogen production

occurred during the TMI-2 incident. Here an RCS sample was being taken during

the morning of the incident and was being recirculated in the sample line in

an effort to get a representative sample. As a result of the sampling operation, radiation levels became unusually high in the sample area. This

unusually high radiation level warranted notification of the shift supervisor. If the shift supervisor had known about the high RCS activity, he would

have had an additional clue that a possible damaged core situation existed.

Gross radiation indications from reactor coolant samples are one measure of

potential core damage that could lead to hydrogen generation. High radiation

in the containment is another measure of potential reactor core damages. In

an effort to be better prepared to monitor this, nuclear power stations are

installing higher range area radiation monitors in containment.

At TMI-2, the radiation monitor in containment had a range of 106 R/hr,

which was adequate to meet the conditions of the accident. In a review of the

monitoring capabilities of other plants shortly after the ThI-2 incident, however, it was found that very few operating facilities had instrumentation capable of measuring in excess of 106 R/hr. 4 - 5 For this reason, the NRC

recommended that high range monitors capable of reading up to 108 R/hr be

installed. 4-12

4-40
Sharply increasing radiation levels from RCS samples or containment area

radiation monitors are a possible measure of a degraded reactor core. These

levels can, in fact, indicate the likelihood of hydrogen generation. Therefore, they should be considered as yet another indication for operations personnel to consider in analyzing the severity of an emergency condition.

4.4.3 Indications of Hydrogen Production Internal to the Reactor Coolant System of a BWR*

4.4.3.1 Temperature. Temperature instrumentation for the BWR Reactor Coolant

System is found in the recirculation loops, where thermocouples mounted on the

piping measure the temperature of the recirculation flow. In addition, thermocouples are mounted in a pre-determined pattern over the outside of the

reactor pressure vessel to monitor vessel skin temperatures. During heatup

and cooldown conditions these thermocouples are used to ensure that thermal

stresses applied to the vessel walls do not exceed the prescribed limitations

of the reactor vessel brittle fracture considerations that are outlined in

Appendices F and G of 10CFR50. 4 - 1 3

It has been suggested 4 - 2 that reactor vessel temperature instruments not be

utilized during large scale LOCas. The vessel thermocouples provide heatup or

cooldown information for normal evolutions where one is concerned with reactor

vessel stresses; they do not give an accurate measure of core temperature.

On the other hand, recirculation flow temperature is indicative of core

temperature during periods of recirculation pump operation. However, during a

LOCA in which recirculation pump flow is lost, these loop temperatures will

not provide an accurate measure of core temperature.**

For these reasons, the usefulness of the Reactor Coolant System temperature

instruments as an indicator of hydrogen production is quite limited.

4.4.3.2 Flow As mentioned in section 4.3, abundant core flow information is

available for a BWR. For example, core plate differential pressure is

recorded and can be used to determine gross changes in core flow or flow distribution. Recirculation loop flow, which provides the driving flow to the

jet pumps, is also displayed. Jet pump flows are also monitored.

* In BWR facilities employing an inerted drywell (primary containment),

oxygen detection is also important because the possibility of oxygen production during the radiolysis process will exist following a LOCA.

** This is based on several discussions concerning the use of skin temperature thermocouples as a potential indicator of an ICC condition. These discussions were with members of the operational staffs of several BWR facilities, including:

o Susquehanna Steam Electric Station (January 1981)

o James A. FitzPatrick Nuclear Power Plant (April 1981)

o Grand Gulf Nuclear Station (September 1981)

4-41
Inadequate core flow will result in an increase in cladding temperature that

could lead to hydrogen production. Similarly, an abnormal distribution in

core flow can indicate a possible cooling restriction that may lead to an ICC

condition and to hydrogen production.

Finally, abnormal operation of the recirculation pumps may indicate a flow

anomaly such as two-phase flow. This, too, could indicate a possibility of

hydrogen production as a result of inadequate core cooling.

4.4.3.3 Pressure. Operating experience has shown that reactor pressure is a

good indicator of the conditions existing in the BWR core during many accident

conditions.4-14 For example, during a DBA-LOCA, a rapid depressurization will

take place as soon as the liquid inventory in the downcomer and separator

region is depleted and steam exits the break. Typically, this would require

only about 9 seconds from the time the break occurs; within approximately 30

seconds, the reactor vessel would be completely depressurized. During the

period of almost zero vessel pressure, the core would still be generating a

large amount of heat and would most likely have fuel temperatures approaching

2000OF in the most severely affected areas. The effect of high temperature

coupled to low system pressure may result in a superheated steam bubble region

in the core although natural circulation may preclude this. Although the

pressure instrumentation would still indicate actual core pressure, it

definitely would not be representative of core temperature under these conditions and thus, should not be used as a measure of reactor coolant temperature. Therefore, when considering the probability of hydrogen production,

pressure should be compared against other parameters such as temperature and

reactor vessel water level.

4.4.3.4 Reactor Vessel Water Level. To ensure that the probability of hydrogen production is minimized, reactor vessel water level must be maintained

sufficiently high to provide adequate core cooling. To monitor this, the

reactor vessel water level instrumentation is used. However, during an accident condition this level instrumentation may become inaccurate. One problem

encountered with the reactor vessel level instrumentation in older BWRs during

post-accident use is related to the physical location of the heated reference

column. 4 .15 Differences between measured and actual vessel level can result

when large changes in drywell temperature occur as a result of a DBA-LOCA, due

to the fact that at most plants the heated reference leg is located outside

the reactor vessel as shown for the Yarway-type instrument in Figure 4-18.

This effect could also be encountered during a steam line break inside the

drywell. As a large increase in drywell temperature occurs, the reference leg

heats up. As the temperature of the reference leg increases, the density of

the water in it decreases.

Since actual level measurement is a function of differential pressure (Ap), a

density decrease in the reference leg would be sensed as a decreasing pressure

and, therefore, would indicate an increasing vessel level. 4 - 1 6 The magnitude of the false level increase would be a function of three factors; (a)

the temperature transient in the drywell, (b) the thermal response time of the

reference leg, and (c) the total length of the reference leg. It has been

calculated that the maximum level error while assuming the worst possible conditions would result in 12.7% level error. A maximum level error of 12.7% x

227 inches or +29 inches results. (The calculation is considered conservative

since it assumed an equilibrium maximum drywell temperature and instantaneous

4-42
Figure 4-18. Typical Heated Reference Leg Level Instrument

Inside Drywell (Referred to as a Yarway Instrument)

4-43
thermal response of the reference leg, as previously stated.) This level

error means that the indicated level would be 29 inches higher than the actual

level. This error could give an operator a false sense of security about

reactor vessel level. This calculation was performed assuming the existence

of the maximum expected drywell temperature, and instantaneous thermal

response of the reference leg, and a 227 inch reference leg. The level indication changes resulting from increasing drywell temperature occur slowly

since the thermal time constant of the Yarway level instrument reference leg

in on the order of 20 to 30 minutes.

One solution to this problem is to use level instrumentation without a reference leg inside the drywell, as shown in Figure 4-19. This method is used on

newer BWRs. Such instruments should not be adversely affected by drywell

accident conditions.4-15

In the final analysis, reactor vessel water level alone is not a sufficient

indication of the presence of hydrogen. Because the reactor vessel water

level indications could be erroneous during an accident condition, other

instrumentation should be consulted to ensure adequate reactor core cooling

exists so as to minimize the possibility of hydrogen production. However, it

should be emphasized that, since an uncovered core is a necessary condition

for hydrogen production, reactor vessel water level is an extremely important

indication.

4.4.3.5 Reactor Coolant Activity. The discussion regarding RCS activity for

PWRs is also applicable for boiling water plants. The key point is to be

aware of which radionuclides are activation products derived from the reactor

coolant itself and from its associated corrosion and erosion products, and to

differentiate these activation products from the fission products. This differentiation is necessary because it is the fission product activity in the

reactor coolant that provides a measure of fuel cladding damage. Abnormally

high reactor coolant activity can be caused by fuel cladding damage. Hence,

if cladding damage has occurred, then there is a distinct possibility that

hydrogen could have been produced.

4.4.4 Indications of Hydrogen Production External to the Reactor Coolant System of a BWR*

4.4.4.1 Drywell/Containment Pressure. An increase in drywell/containment

pressure as a result of a LOCA was discussed in section 4.2. The pressure

increases resulting from the presence of hydrogen that might be expected for

each primary containment type were shown in Figure 4-2 and tabulated in Table

4-2.

* The term "drywell/containment" has two somewhat different connotations in

the discussion that follows:

o Mark I or Mark II designs - It refers to the drywell or as it is

sometimes termed, the primary containment.

o Mark III design - It refers to both the drywell and the surrounding

containment structure, which become one and the same (because they

communicate with each other during a post-LOCA environment).

4-44
DRYWELL DRYWELL WALL

REACTOR

PRESSURE

VESSEL

LEVEL MEASURING

INSTRUMENTS

b

Figure 4-19. Typical Cold Reference Leg Level Instrument

4-45
The pressure increase caused by liberation of the hydrogen into the drywell

containment is not a singularly sufficient indicator of the presence of hydrogen. It should be used in conjunction with other Reactor Coolant System data

to evaluate the possibility for hydrogen production.

4.4.4.2 Drywell/Containment Temperature. Drywell/containment instrumentation

does not provide indications of actual core damage. Post-accident use of this

instrumentation does, however, provide indications that can be used to observe

changing plant conditions to identify if the possibility for hydrogen production existed. Increasing drywell/containment temperatures and pressures can

be used in conjunction with reactor vessel instruments to identify energyrelease-type accidents as they occur, as discussed in section 4.3. Postaccident use of these instruments provides indications of the turning point of

the transient, and indicates whether safety systems are functioning properly

to control the transient. Proper functioning of the safety systems is necessary to minimize the probability of hydrogen production.

4.4.4.3 Drywell/Containment Humidity. Typically, the drywell/containment

contains a high relative humidity under normal operating conditions. If a

LOCA occurred, the humidity would naturally increase to 100%. However, this

marginal increase tends not to be very significant when viewed at the main

control board. Hence, as for PWRs, the increase in containment humidity can

be added to the lengthening list of indications that could indicate the

existence of an ICC condition where hydrogen could be generated, but that

cannot be relied upon exclusively to indicate such a condition.

Drywell/containment humidity must be considered in conjunction with other

available indications to determine the possibility for hydrogen generation.

4.4.4.4 Drywell/Containment Sampling. Post-accident liquid and gas sampling

can determine both the extent of reactor core damage and the extent of hydrogen gas production during the accident.

Liquid samples from the drywell or suppression pool which disclose high fission product activity are, in fact, a direct clue to the onset of nuclear fuel

damage. (A review of fission products, listed in the order of decreasing

escape rate coefficients, was presented earlier in this chapter.) It is, of

course, this fuel damage that may be an early clue to possible hydrogen production in the reactor core.

BWR facilities typically employ a Hydrogen Analyzing System that monitors and

records the hydrogen concentration in the primary and secondary containments

following a postulated LOCA. The Hydrogen Analyzing System generally is considered to be one of the subsystems that comprise the Combustible Gas Control

System. The Hydrogen Analyzing System typically provides control room indication of the hydrogen concentration, and alarms when the concentration limit is

reached or exceeded. A warmup time will be associated with the use of these

systems.

As the name implies, the Post-Accident Sampling System can be used for liquid

and gaseous sampling in a post-accident condition. For example, a gaseous

sample may be taken from the primay containment to determine the existing concentration.

4-46
4.4.4.5 Steam Line Radiation Monitoring. Steam line radiation monitoring is

one of the functions of the Process Radiation Monitoring System at a BWR

facility. The main steam line radiation monitoring subsystem, typically, consists of four identical gamma monitoring channels. Each channel monitors the

gross gamma radiation level of all four main steam lines at a point inside the

steam tunnel, close to the containment, normally in proximity to the outboard

main steam isolation valve (MSIV). (The Reactor Coolant System for a BWR ends

at the outside of the MSIV.) The radiation level is sensed by monitoring

channels that control the trip circuits that provide inputs to the Reactor

Protection System.

A high radiation level signal from the main steam line radiation monitoring

subsystem can indicate the possibility of hydrogen production due to',the onset

of fuel rod damage. The presence of high steam line radiation in- con-junction

with other confirmatory data could indicate hydrogen production.

Note that once a reactor SCRAM has occurred, the steam line radiation monitor

is isolated on most plants. Hence, core damage following a SCRAM ordinarily

would not be detected by these monitors. As a result, their usefulness is

limited to times of power operation. 4 - 1 7

4.4.4.6 Gross Radiation Level. Another possible indication of hydrogen production is the presence of high radiation, as indicated by reactor coolant or

drywell samples. As discussed previously in the section for PWRs, an

unusually high radioactivity in a reactor coolant or drywell sample, or a high

radiation level in the drywell can be an indication of degraded reactor core

conditions.

It should be emphasized that high radiation level indications do not in themselves indicate a hydrogen presence, but, instead, denote a potentially

damaging operating condition. Other vital instrumentation for the Reactor

Coolant System and containment should be consulted to verify or rule out the

presence of hydrogen.

4.4.4.7 Sump Leak Detection. Typically, the drywell floor in a BWR facility

has two sumps for the collection of potentially radioactive wastes in the drywell. Normally, these are of low capacity (200 to 300 gallons each), and are

fed by sources such as:

o Vent cooler drains

o Control rod drive flange leakage

o Chilled water drains

o Cooling water drains

o Floor drains

o Overflow from the drywell equipment drain tank4 - 1 8

Each sump contains level detectors that provide control board indication, with

an associated level alarm. Typically, each drywell sump has two AC motor

driven pumps for transferring collected wastewater to the liquid radwaste

(LWR) collection tanks.

High sump levels in the drywell are potential indications of RCS leakage. A

high sump level alarm could be an early indication of a potentially damaging

4-47
condition for the reactor core due to a loss of coolant. It is the coolant

loss that could lead to a degraded core condition that could result in

hydrogen production. Therefore, if high sump levels exist, other vital

instrumentation should be consulted to ensure that adequate reactor core

cooling exists.

Water from this sump can be transferred to the LRW collection tanks outside

the drywell, therefore, a sample of this liquid could be drawn to check for

indications of possible core damage.

4.4.4.8 Suppression Pool Temperature. The pressure suppression pool provides

an adequate heat sink in the event of a design basis LOCA. Suppression pool

water temperature is monitored during normal operations to ensure that this

temperature is maintained within prescribed limits. (A typical temperature

limitation during normal operation is 100°F although it may be much higher

during an accident.4- 1 9 ) If the suppression pool temperature exceeds the

normal operating limit, the reactor must be scrammed, and operation may not be

resumed until pool temperature is reduced to below the maximum allowable

operational limit prescribed in the technical specifications. (This pool

temperature is normally less than 90 0 F.)

Typically, RTDs are installed at several locations in the suppression chamber

water to provide signals for temperature indicators and recorders in the control room.

A sudden rise in suppression pool temperature can result from a LOCA condition. This is another indication of a potentially damaging operating condition. Other vital instrumentation should be monitored to verify the presence

and seriousness of the emergency condition. It should be emphasized again

that it is the LOCA condition that can degenerate into a degraded cooling condition for the reactor core, and it is the degraded core condition that can

result in hydrogen production through the metal-steam reaction with the BWR

fuel bundles.

4.5 HYDROGEN DETECTION

Several methods are employed to reduce the risks associated with high hydrogen

concentrations, however, proper implementation requires an accurate measurement of the concentration; a variety of hydrogen detectors currently are being

marketed for use in nuclear power plants, each of which has its own relative

strengths and weaknesses. The purpose of this section is to discuss the criteria that must be met for a detector to be adequate in a LOCA situation, and

to identify the characteristics of some of the more promising detector designs.

Reference 4-20 lists nine desirable characteristics for remote hydrogen sensing in the containment:

(1) Insensitivity to ambient pressure, temperature, and humidity

(2) Reliability and stability

(3) High sensitivity

(4) High specificity (i.e., insensitivity to the presence of other gases)

(5) Not an ignition source

(6) Suitability for remote monitoring

4-48
(7) Not affected by nuclear radiation

(8) Rapid response and recovery

(9) Ability to measure large ranges of hydrogen concentration 4 - 2 0

The list explicitly mentions only these nine items, but a tenth entry is also

implied: reasonable cost.

The importance of each of these criteria can easily be seen. However, there

are situations in which trade-offs between desirable characteristics can

become particularly crucial in the selection of a detector. One of these

situations is the conflict involving detector sensitivity. Usually, the

higher the minimum detectable hydrogen concentration (for any type of sensor),

the less expensive, more durable, and faster responding that sensor will be.

Although a relatively high minimum detectable limit can be advantageous in

these respects, the limit must, obviously, be low enough that the detector can

identify hydrogen levels in the appropriate range. An example of this is the

case where deliberate ignition is employed as a means of hydrogen control. If

the minimum detectable limit of the sensor is greater than the specified upper

bound for safe ignition, the detector is of little value. It is estimated

that an appropriate conservative minimum detectable limit is 1% hydrogen, with

the corresponding accuracy specification of 0.5% for LWR service.4-21

If hydrogen detectors are used in the future by operators to control ignition

systems, then there is another problem to consider. This problem related to

deliberate hydrogen ignition concerns the trade-off between the measurement

time constant of the detector and the time allowed for the decision to ignite

to be made. For a LOCA where hydrogen is being produced rapidly, the time

allowed for this decision is estimated to be about one minute. Assuming that

it is reasonable to allow no more than the first half of the time delay for

decision to be consumed with obtaining measurements, and that the measurement

must be taken twice to confirm its accuracy, the detector time constant should

be no more than one-fourth of the time delay allowed for the decision to

actuate the igniter. In the scenario involving rapid hydrogen buildup, this

amounts to 15 seconds or less for the system response to an increase in local

hydrogen concentration. To obtain such a response time, it is necessary to

locate the sensors inside contat.nment, where they must be able to survive the

high temperature, high humidity, and radiation effects present in the

post-LOCA environment.4-21 Note, however, that many of the criteria for

accurate and reliable hydrogen measurement cannot be met with currently

available equipment.

There are numerous devices on the market for the detection of hydrogen. However, most are expensive and designed specifically for laboratory use. As a

result, many are relatively useless for applications in nuclear power plants.

Those detectors that are feasible can be classified into the following major

groups: (1) combustion, (2) solid state, (3) electrochemical, (4) thermal

conductivity, and (5) absorption.

4.5.1 Combustion Detector

To date, the most widely used detector has been the combustion detector. In

this device, a hot wire, or catalyst, that forms one segment of a Wheatstone

4-49
bridge electrical network, ignites the combustible gas mixture. The heat

released during the combustion process produces a change in resistance that is

measured to determine the composition of the mixture. This method is effective because of the very high heat of combustion of hydrogen.

There are several disadvantages to the combustion detector. Since it operates

by igniting the gas, it must be separated from its surroundings by a flame

arrestor. Also, because the combustion process is dependent upon oxygen, any

disruption in the air supply can lead to erroneous readings. The facts that

calibration can be affected by exposure to radiation and that the detector can

only measure up to 7% hydrogen are other characteristics that detract from the

performance of the combustion type of detector.

4.5.2 Solid-State Detector

Solid-state detector is an all-encompassing term used to refer to any of a

multitude of hydrogen detectors that operate by using the electrical phenomena

of crystalline substances. These detectors are very much in vogue at present.

They are too numerous for all of them to be described here. There are, however, some characteristics common to all solid-state detectors that can be

mentioned: the upper limit of detectable hydrogen concentration is typically

around 10%, and the detectors are likely to experience calibration change when

subjected to nuclear radiation or a high moisture environment.

4.5.3 Electrochemical Detector

The electrochemical detector consists of two electrodes immersed in an electrolyte that dissolves hydrogen. The cell is covered by a membrane that is

relatively permeable to hydrogen. As the gas passes through the membrane, the

gas reacts with the electrolyte to produce an output current proportional to

the rate of hydrogen diffusion through the filter. In this type of detector,

the rate of sample air flow should be kept constant and the temperature of the

film must be known.

The greatest shortcoming of the electrochemical detector is its inability to

operate properly in the presence of water vapor. Its calibration may also be

affected when the detector is subjected to nuclear radiation.

4.5.4 Thermal Conductivity Detector

The high thermal conductivity of hydrogen is utilized in a device called,

appropriately, a thermal conductivity detector. In this device, the passive

elements of a Wheatstone bridge are exposed to a reference gas stream; the

sensing is done by the two active elements. This detector actually has very

poor specificity for most gases, but the thermal conductivity of hydrogen is

so great (seven times that of air -- only helium is comparable) that it is

actually quite suitable.

4.5.5 Absorption Detector

The final major type of hydrogen detector is the absorption detector. When

hydrogen dissolves in a palladium-silver alloy, it causes a volume expansion

4-50
that is easily detectable. Several methods have been developed to translate

this expansion into a corresponding hydrogen concentration. These detectors

are not currently used at nuclear reactor facilities. But, since the absorption processes will occur under harsh (i.e., post-LOCA) conditions and is virtually unaffected by steam, this type of detector is a likely candidate for

future service inside containment.

4.5.6 Detector Availability

According to a survey of all the types of detectors currently available, only

two are on the market* that are specifically tested for service in nuclear

power plants. One is a thermal conduction detector (TCD) and the other is a

diffusion-limited electrochemical cell (DEC). The latter is a type of electrochemical detector. At the time of the survey, the DEC units were undergoing tests to qualify them as safety-grade units for service inside LWR containments. The TCD units had already completed the tests.

The primary operational difference in these systems is the manner in which

they are employed. The TCD sensors are located outside containment, and

sample containment air by circulation through pipes (two per sensor) that

penetrate the containment wall. The DEC detectors, on the other hand, are

located inside containment where air sampling time can be short. The signal

processing equipment, however, is not able to withstand the environmental conditions expected after a LOCA and, therefore, is located outside containment.

Specific performance data for these detectors, as well as location diagrams

for currently employed systems, can be found in Ref. 4-21.

4.6 TRANSPORT AND MIXING OF HYDROGEN

4.6.1 Introduction

An inadequate cooling condition can create a degraded reactor core in which

hydrogen may be liberated (as described earlier in this chapter). This

degraded core would be the principal source of hydrogen that could be

liberated into the containment and transported to other buildings or structures. For example, during the TMI incident (described in Appendix 1) the

hydrogen generated, principally by the zirconium-steam reaction in the reactor

core, was transported throughout the RCS, as shown in Figure 4-20. This

figure shows a sketch of the TMI Reactor Coolant System at a time when hydrogen was most probably being generated. 4 - 2 2 The great loss of reactor

coolant inventory enabled hydrogen to spread freely throughout the system.

The lack of water inventory also made it impossible to establish single-phase

natural circulation once the reactor coolant pumps (RCPs) had been tripped.

There are many potential hydrogen release paths through components in the RCS

or through systems that interface with the RCS. For a PWR these paths

include, but are not necessarily limited to, the following:

o Reactor vessel head vent (as required by NUREG-0737).

o Through the hot leg or cold leg piping (as might occur because of a

break in one these piping sections).

* As of January 1981. See Ref. 4-21.

4-51
PRIMARY WATER

SECONDARY WATER

F'J STEAM

SSTEAM/HYDROGEN

t -2.8 hours

P--1200 psig

U, M3

LOOP A LOOP B

Figure 4-20. The TMI Reactor Coolant System Showing Hydrogen

Generation During the Inadequate Core Cooling

Condition
o By way of pressurizer and pressurizer relief tank (quench tank).

o By way of auxiliary and emergency systems that interface with the

RCS. These include:

- Chemical and Volume Control System (CVCS)

- Emergency Core Cooling System (ECCS)

- Residual Heat Removal System (RHR)

- Sampling System (SS)

These PWR release paths will be examined in section 4.6.2.

Similarly, for a BWR, a number of potential hydrogen release paths exist

including:

o Through a Reactor Cooling System break into the containment.

o By way of auxiliary, emergency, and steam systems from the drywell

to the secondary containment (or another building).

These potential bypass leakage paths include:

- Main steam lines

- Feedwater lines

- Reactor water cleanup line

- Recirculation pump seal mini-purge line

- Main steam line drains

- Suppression pool purification line

- Drywell Ventilation and Purge System

- High Pressure Coolant Injection (HPCI) lines (when there is a

suction taken from the suppression pool)

- Reactor Core Isolation Cooling (RCIC) lines (when there is a

suction taken from the suppression pool)

- Residual Heat Removal (RHR) lines

- Core Spray (CS) lines

- Drywell Reactor Building (primary-to-secondary containment)

Vacuum Breaker System

- Drywell floor and/or equipment sump to Radwaste System

- Control Rod Drive Hydraulic System

4.6.2 Hydrogen Transport Pathways in a PWR

4.6.2.1 Hydrogen Transport through the Reactor Vessel Head Vent. With

reference to Reactor Coolant System vents, the NRC has stated that:

Each applicant and licensee shall install reactor coolant system (RCS) and

reactor vessel head high point vents remotely operated from the control

room. Although the purpose of the system is to vent noncondensable gases

from the RCS which may inhibit core cooling during natural circulation,

the vents must not lead to an unacceptable increase in the probability of

a loss-of-coolant accident (LOCA) or a challenge to containment integrity. Since these vents form a part of the reactor coolant pressure

boundary, the design of the vents shall conform to the requirements of

Appendix A to 10 CFR Part 50, "General Design Criteria." The vent system

shall be designed with sufficient redundancy that assures a low probability of inadvertent or irreversible actuation. 4- 1 2

4-53
Although the exact reactor vessel head vent arrangement (installed or planned)

may vary somewhat among PWR facilities, the general arrangement is similar.

Figure 4-21 is a typical reactor vessel head vent arrangement. This figure

shows a sketch of the Reactor Vessel Head Vent System (RVHVS) for the Trojan

Nuclear Plant.*

The Trojan RVHVS is designed to remove noncondensable gases or steam from the

reactor vessel via remote manual operation from the control room. Venting

during plant startup and system venting during shutdown on post-accident mitigation of non-design-basis events are possible periods of RVHVS usage. The

Trojan RVHVS is designed to vent a volume of hydrogen, at system design pressure and temperature, approximately equivalent to one-half of the Reactor

Coolant System Volume in one hour. It discharges into a well-ventilated area

of the refueling cavity to enable good mixing within the containment building. This particular RVHVS consists of two parallel flow paths with redundant

isolation valves in each flow path. The venting operation uses only one of

the flow paths at any one time. 4 - 2 3

As of this writing, it appears that most PWR facilities do not have a

finalized procedure for operation of the reactor vessel head vents. 4 - 2 4

However, the Donald C. Cook Plant** has prepared a procedural guideline that

contains an outline of background information for Reactor Vessel Head Vent

operation.4-25 Because most of this information appears to be generic in

nature and thus has potential applicability to all PWRs, (although not for all

situations) it is presented, in part, in the rest of this section. Each

reader can determine its applicability to his or her specific plant.

The purpose of the RVHVS is to remove noncondensable gases from the reactor

vessel head. The specific design of the RVHVS includes a single connection to

the reactor vessel head, with redundant flow paths and isolation valves

extending from a common line, as shown in Figure 4-21. It seems to be

generally accepted that any venting operation should be performed only with an

accurate vessel level indication. For those PWR plants with a reactor vessel

water level detection system, the performance of the calculation in Appendix

II may provide an estimate of the total volume of gaseous voids in the RCS

(other than the pressurizer).

It is important that RCS conditions be stabilized, with a constant pressurizer

level and an adequate subcooling margin established, prior to commencing

reactor vessel venting. Further, it is possible that an adverse containment

environment can affect pressurizer level conditions. Therefore, to use pressurizer parameters to verify the existence of a stabilized RCS condition,

either the containment temperature must be at or near that for normal operating conditions, or the pressurizer parameters must be corrected to reflect

* Located In Prescott, Oregon, and operated by Portland General Electric

Company.

** Located in Bridgman, Michigan; operated by Indiana and Michigan Electric

Company. This was the only plant, of approximately ten PWRs contacted, that

had such a procedure.

4-54
FLOOR ELEVATION

1 in SOLENOID

VALVE (TYPICAL

OF FOUR)

3/4 in EXISTING HI 'MANUAL I-

"3/8 in ORIFICE FLANGE

(TYPICAL OF TWO)

CRDM SEISMIC SUPPORT PLATFORM

n VENT LINE

HEAD VENT VALVE

* REACTOR CAVITY

REACTOR VESSEL

Figure 4-21. Reactor Vessel Head Vent

4-55
possible changes resulting from containment conditions. Also, any venting

operation must be performed prior to the initiation of safety injection (SI)

flow throttling during a post-LOCA cooldown and depressurization operation.

An important consideration relative to use of the RVHVS is that it is not

designed to be, and should not be used as, the primary means to mitigate an

ICC event. The vent flow path is not sized to provide this capability, and

should only be used in conjunction with the plants ICC guidelines.

There are several symptoms denoting the possible presence of a gaseous void in

the reactor vessel head. These include:

o Peculiar pressurizer behavior due to the presence of a gaseous void

in the reactor vessel.

o High differential temperature across the reactor core which indicates that the coolant is spending too much time in the core and,

hence, is not providing the proper amount of cooling.

o The presence of superheat conditions, as determined by the core

exit thermocouples or the subcooling margin monitor.

o Greater letdown flow commensurate with a lesser charging (or makeup) flow into the RCS while maintaining a constant pressurizer

level.

Once a gaseous void is detected or suspected in the RCS, any changes being

made to the RCS should be terminated and steady-state conditions should be

established. This refers to such events as post-LOCA cooldown, normal plant

cooldown, or plant recovery from a design basis event. The intent is to allow

the RCS to stabilize so that the size and position of the void can be determined.

The first action taken to remove any gases from the RCS is to attempt to

recombine any condensable gases by increasing RCS pressure. The venting

operation will result in RCS gases being vented to the containment. Therefore, the Containment Purge and Exhaust System should be isolated to prevent

the possibility of a gaseous radioactivity release to the environment.

It is very important that the RCS not reach saturation conditions during the

venting process. Typically, this can be prevented by increasing the subcooling margin over the minimum plant-specific value and by limiting the RCS

pressure decrease as much as possible during the venting process. If these

two constraints are adhered to, the reactor coolant should remain in the subcooled condition while venting is taking place.

In an effort to keep the hydrogen concentration in containment less than three

volume percent to ensure that a flammable concentration is not created, the

allowable venting time must be determined. A general guideline for the venting time period is presented in Appendix III.

It is also advisable to maintain pressurizer level greater than about 50% during the venting process to maintain RCS mass inventory. It is suggested that

RCS letdown to the Chemical and Volume Control System (CVCS) be isolated during the venting process to ensure that presurizer level is maintained.

4-56
A possible decrease in RCS pressure during the venting process could initiate

safety injection (SI) if the venting occurred at a pressure near the low pressure SI setpoint. Generally, it would be advisable to block low pressure SI

actuation if or when the block permissive is energized to prevent an inadvertent SI initiation during the venting process.

The venting process should be terminated when the reactor vessel head is

refilled or when containment hydrogen concentration has reached a concentration of three volume percent.

4.6.2.2 Hydrogen Transport through the Hot Leg and and Cold Leg Piping. Any

time that hydrogen is produced in a PWR reactor vessel during an ICC condition, it has a tendency to be transported first to the hot legs of the RCS.

From there it can enter the pressurizer as well as the primary side of the

steam generator. A break in any of this piping or these components can result

in a hydrogen release to the containment atmosphere.

In general, the cold leg of the RCS will see the hydrogen gas last.

Naturally, a cold leg RCS break will result in a hydrogen release to the containment through the break. Figure 4-22 shows a profile view of a Reactor

Coolant System hot leg and cold leg in which the postulated break has occurred

in the cold leg. 4 - 2 6 The plant arrangement shown in this figure is typical

for Combustion Engineering and Westinghouse PWRs.

Forced circulation through the RCS tends to keep any steam/noncondensable gas

voids mixed in a nearly homogeneous manner in the RCS as water inventory is

lost through the break. However, where it becomes necessary to secure the

reactor coolant pumps, the hydrogen will have a tendency to rise to the

highest points in the system. For Babcock and Wilcox (B&W) units, the hydrogen has a tendency to rise to the top of the:

o Reactor vessel

o Pressurizer

o "Candy cane" inlet piping to the once-through steam generator (OTSG)

For example, Figures 4-23 and 4-24 show two types of RCS configurations for

the B&W stations. From a natural circulation standpoint, the lowered loop

configuration (Figure 4-23) is less desirable because a loss of RCS inventory

followed by the tripping of RCPs tends to separate the RCS water in three

places: the reactor vessel and the two steam generators.4-27 The lowered

loop arrangement is used at most B&W facilities, including TMI Units 1 and 2.

The installation of vent valves in the "candy cane" section can be useful in

venting any noncondenable such as hydrogen that could hamper the natural circulation process.

The raised loop configuration, shown in Figure 4-24, is used at the

Davis-Besse Nuclear Power Station.* This arrangement is more favorable for

natural circulation, if there is a loss of RCS inventory and RCPs must be

tripped. Here, reactor coolant has a tendency to flow back into the reactor

vessel where it is needed most to help ensure reactor core coverage, and,

* A B&W plant located in Oak Harbor, Ohio, and operated by The Toledo Edison

Company.

4-57
3HOO

NO I D3 N0I103S

H~sn~jiia

S' U llYlONMOV

)IV3H8

Figure 4-22. Cold Leg Break Steam Flow Path Schematic
PRESSURIZER

REACTOR I I

COOLANT OUTLET

PUMP NOZZLE

STEAM

GENERATOR I

NOZZLE VESS .EL

Figure 4-23. Babcock and Wilcox Reactor Coolant System Arrangement

Low Profile or Lowered Loop Configuration

4-59
Figure Wlcox 4-24. Babcock and Reactor Coolant System Arrangement

NXNN\N

Figure 4-24. Babcock and Wilcox Reactor Coolant System Arrangement High Profile or Raised Loop Configuration

4-60
thereby, avoid an ICC condition that could generate hydrogen. Combustion

Engineerin. and Westinghouse PWRs are also of the high profile or raised loop design.4-2o

4.6.2.3 Hydrogen Transport into the Pressurizer and Pressurizer Relief Tank.

Hydrogen that is generated during an ICC condition can be transported through

the RCS hot leg and into the pressurizer. As a result, the pressurizer is

another location from which noncondensable gases (including hydrogen) can be

vented to containment. Some facilities, therefore, are incorporating both a

Reactor Vessel Head Vent System such as that previously discussed, and a Pressurizer Vent System. These two venting subsystems would then comprise an

overall Reactor Coolant Vent System (RCVS) whose basic function would be to

remove noncondensable gases or steam from the reactor vessel head and the

pressurizer. 4- 2 9 The combination of these two vent paths would serve to

mitigate tan ICC condition, impaired natural circulation, or inability to

depressurize the RCS to residual heat removal initiation conditions, any of

which could result from any accumulation of noncondensable gases in the RCS.

Venting capability of the RCS hot legs is not required at Westinghouse or Combustion Engineering facilities because the hot legs are not the high point in

the system. For B&W facilities, the inlet piping to each of the once-through

steam generators does, in fact, constitute a high point in the system and is a

desirable location for a vent (see Figure 4-23 and 4-24).

A typical Pressurizer Vent System is shown in Figure 4-25. This system is

connected to the pressurizer relief line and, typically, incorporates two

valves in series in each flow path. Using two valves in series minimizes the

possibility of reactor coolant pressure boundary leakage.

In general, the Pressurizer Vent System is intended for use in venting noncondensable gases from the pressurizer vapor space. This path also may be

used as an alternate method of depressurizing the RCS if this is required by

another instruction, as when pressurizer spray and the power-operated relief

valves (PORVs) are not available.

There are a number of points that should be considered in using the Pressurizer Vent System. First, the system is not designed for, and should not be

used as, the primary means to mitigate an ICC event. The vent flowpath, shown

in Figure 4-25, is not sized to privide this capability.

In order to use this system it is necessary to obtain accurate pressurizer

level and pressure indications. Therefore, if the containment temperature is

not near normal operating temperature, it is necessary to make the appropriate

instrumentation correction.

As with the Reactor Vessel Head Vent System (RVHVS), use of the Pressurizer

Vent System should be initiated with stable plant conditions. Further, the

use of this system while safety injection is operating may result in the pressurizer's becoming water-solid, which is an undesirable condition.

A prerequisite to use of this system is that a larger than normal concentration of noncondensable gases be present in the pressurizer vapor space. It is

quite possible that variations from the normal pressurizer pressure and level

response due to normal charging and spraying operation may be observed. In

the event that noncondensable gases are present in the vapor space, spraying

4-61
TO BOTTOM OF f

REFUELING

TUNNEL

I

(I

T

1 in SOLENOID-OPERATED

ISOLATION VALVES (TYPICAL)

EXISTI / in VENT LINE

EXISTING 3/4 inVENT•

PRESSURIZER

SAFETY VALVE

PRESSURIZER

Figure 4-25. Typical PWR Pressurizer Vent System

4-62
will not condense the gases and the normal depressurization will not occur.

(Recall, from Chapter 3, the discussion regarding a hard bubble in the pressurizer.)

If noncondensable gases are present in the RCS and the reactor vessel head, it

is advisable to vent the reactor vessel head first. If the pressurizer were

vented first, the depressurization might result in the reactor vessel head gas

bubble expanding to the point where natural circulation core cooling could be

disturbed.

Some important steps that should be considered during the venting process

include (but are not necessarily limited to) the following (These steps are

excerpted from information rovided by the D. C. Cook Station on pressurizer

venting operation. 4-10, 4-39 They should not be used verbatim by other

plants without being verified for applicability.)

Note: Those steps marked by an asterisk are not applicable if the

pressurizer is being vented because large quantities of noncondensable gases are preventing an RCS depressurization.

1. Once noncondensable gases are detected or suspected in the RCS, any

changes being made to the primary system should be terminated and a

steady-state condition should be established. This step refers to

events such as a post-LOCA cooldown, normal plant cooldown, or

plant recovery from a design basis event.

2. If large amounts of gases are not detected in the vapor space,

there is no need to vent the pressurizer unless the vent system is

being used as an alternate depressurization method.

3. The venting operation will result in pressurizer gases being vented

to containment. Therefore, the containment Purge and Exhaust System should be isolated to prevent release of any radioactive gases

to the environment. All available containment air circulation

equipment should be started to prevent hydrogen from forming a gas

pocket, so that proper mixing will take place, and to ensure a

representative hydrogen concentration is obtained in step 5.

4. Increasing the reactor coolant subcooling above the minimum

plant-specific valve ensures that reactor coolant subcooling will

be maintained over the entire range of RCS operating conditions if

the venting operation is terminated following a decrease in RCS

pressure.

5. The actions of Appendix III determine the maximum allowable time

period for venting that will limit the containment hydrogen concentration to less than three volume percent. This limit is required

to prevent a potentially flammable hydrogen concentration from

being developed inside containment.

6. RCS pressure will decrease during the venting, and, if initial

pressure is near the low pressure safety injection actuation set

point, SI may be initiated automatically during the venting. The

operator should block low pressure SI actuation if the block permissive is energized, to prevent an inadvertent SI.

7. Charging flow is increased to maximum to limit the net mass depletion of the RCS during the venting period.

4-63
8. Both isolation valves in one vent flowpath must be opened to

initiate the venting operation.

9. The venting operation is terminated when enough gases have been

removed to restore normal pressurizer control or when the time

limit determined in step 5 is met.

10. Normal pressurizer pressure and level control is restored after

completion of venting.

11. If venting was terminated prior to removing enough gases to restore

normal pressurizer control or to reduce pressure to the required

condition, then the operator should return to step 4 and repeat the

venting.

Note: The hydrogen concentration could be reduced through use of

the containment hydrogen recombiners (where applicable) or the

purge and exhaust system if radioactive gas concentrations are

within limits. The new venting period will be based upon the

reduced hydrogen concentrations.

4.6.2.4 Hydrogen Transport from Containment to Other Buildings. In Chapter

3, it was discussed that hydrogen can be removed from the RCS even during normal plant operations. Much of the information on hydrogen transport paths and

mechanisms that was discussed in this connection with regard to such sytems as

the Chemical and Volume Control System (CVCS) (or Charging and Letdown System)

and the Gaseous Waste Disposal System also has general applicability during an

accident scenario.

First, one must be aware that the bulk of the hydrogen generated during an ICC

condition has its origin in the reactor core (see Chapter 2). As discussed

previously, care must be exercised in releasing the hydrogen into containment. Care is necessary because, if a combustible mixture were present, an

accidental deflagration could occur in containment, which could be undesirable. As a result, it could be more desirable to remove the hydrogen through

one of the plant auxiliary systems and to transport it to the Gaseous Waste

Disposal System for final removal from the plant. Such decisions would have

to be made on a plant specific basis and according to NRC guidance. The specific choice would be based on several factors, which include:

o Location of hydrogen

o Amount of hydrogen

o Availability of the auxiliary systems to be used as the release path

This section explores the release paths available to remove hydrogen from the

reactor containment and transport it to the Gaseous Waste Disposal System.

One of the more obvious paths for hydrogen removal is through the CVCS. #a

this case, letdown water from the RCS is sent to the volume control tank

(Westinghouse and Combustion Engineering plants) or makeup tank (Babcock and'

Wilcox plants). Here, noncondensable gases, including hydrogen, may be vented

to the waste gas decay tank (see release path #1 in Figure 4-26). (Note that

Figure 4-26 is not intended to represent any given plant, rather it denotes a

multiplicity of release path possibilities that are, in general, representative of B&W, CE and Westinghouse PWRs alike.)

4-64


All of the potential paths discussed so far would release hydrogen to the

Auxiliary Building. The possibility exits that a steam generator tube repture

would occur. For such a rupture, a potential hydrogen release path through

the failed steam generator tube(s), through the steam line, and into the main

condenser can be postulated. The hydrogen would be removed from the condenser

by either the steam jet air ejectors (SJAEs) or the Off-Gas System vacuum

pumps (often referred to as "hoggers"). It would then be release to the

turbine building (see Figure 4-26, release path #12).

4.6.2.5 Considerations to Minimize Hydrogen Transport to Other Buildings.

During the TMI-2 incident, noncondensable gases, such as radioactive krypton

and xenon, escaped the containment by way of the containment sump and were

pumped to a radioactive waste storage tank in the Auxiliary Building. These

gases ultimately were released through a blown rupture disc in this tank. The

result was an airborne radioactivity release to the environment by way of the

Auxiliary Building.

As a result, one of the lessons learned from the incident was that the containment sump pump should not have any automatic actuation features, but

should, instead, be manually controlled. This consideration for noncondensable radioactive fission products holds true for hydrogen as well, since the

potential for hydrogen release from containment by way of the containment sump

is certainly a viable one.

In addition, *a radioactivity release occured at TMI-2 via a leaking vent

header off the makeup tank. This resulted in a second release of noncondensable gases, such as xenon, krypton, and hydrogen to the Auxiliary Building

several days after the onset of the incident. From this another lesson was

learned: surveillance testing of vent headers should be incorporated to

ensure that leakage is limited to negligible amounts. If vent header leakage

contains a combustible hydrogen concentration, its subsequent leakage into

containment poses both a personnel hazard and a hazard to equipment. In the

TMI-2 case, hydrogen and other noncondensable gases were transported to the

makeup tank (of the CVCS) via the letdown line.

Any fluid system has the potential for leaks, especially in pump rooms due to

the types of system connections found there. Thus, one potential consideration is to have several hydrogen monitors in pump rooms within the Auxiliary

Building. The monitors could be placed in those areas where hydrogen could

accumulate in the event an accident occurred that was of sufficient magnitude

to generate hydrogen.

Precautions also should be exercised in the use of sampling systems, not only

because of the potential for high radioactivity but also because hydrogen

could be present in the sample or released into the sampling room itself.

Therefore, mention of the potential hydrogen hazard in these areas of the

Auxiliary Building is appropriate as part of any emergency procedure on the

use of the systems mentioned in this section. It should be emphasized that

each plant should specifically assess its own situation in this regard, since

the potential release paths and related concerns discussed here are presented

only as a representative sample of hydrogen-release possibilities for a PWR.

4-67
The only postulated release path previously discussed by which hydrogen can

enter the Turbine Building is via a steam generator tube rupture. At each

facility, the details of the interface piping between the Containment Building

and the Turbine Building should be examined with this in mind. In this

regard, it would appear appropriate to have hydrogen monitors in the Turbine

Building to ensure that no measurable quantities of hydrogen exist if a steam

generator tube rupture incident occurs.

4.6.3 General Hydrogen Transport Pathways in a BWR

4.6.3.1 Hydrogen Transport through a Reactor Coolant System Break. BWR stations employ a direct cycle design, in which steam produced by the reactor

core leaves the reactor vessel and is passed directly to the turbine, as shown

in Figure 4-27. The steam then passes through the turbine to the condenser.

From here it is ultimately pumped back to the reactor vessel as feedwater; it

is heated and its pressure is increased in the process. 4- 3 1

A second pumping system, also shown in Figure 4-27, is the recirculation system, which features two large motor-driven pumps arranged in two parallel

recirculation loops attached to the vessel. In addition, there are a series

of jet pumps that circumferentially surround the core in the shroud region.

A design basis accident (DBA) is a hypothetical accident in which a complete

and circumferential rupture of the largest pipe connected to the reactor

vessel occurs, with displacement of the ends so that blowdown from the Reactor

Coolant System occurs from both pipe segments. (Figure 4-28 shows an example

of the break location for the DBA-LOCA4 -32).*

It should be mentioned that as long as proper ECCS operation occurs, sufficient water should be pumped into the reactor core to ensure a minimum

coverage of two-thirds of the reactor core, i.e., water should be at least as

high as the jet pump suction inlet. This should ensure adequate core cooling,

although adequate core cooling can probably be maintained with somewhat lower

water levels. If an ICC condition occurred, the hydrogen produced would be

released into the drywell through this break in the system piping.4-32 If a

LOCA occurred as shown in Figure 4-28, and hydrogen was produced as a result

of inadequate core cooling, the hydrogen would be discharged into the drywell

through the break. Once hydrogen enters the drywell, it is contained in

Mark I and II BWR facilities. However, the possibility of its being released

to other buildings does exist, until' it can be purged from the drywell. Its

inadvertent release may be undesirable. For a Mark III containment, the drywell and containment building communicate in a post-LOCA condition. Hence,

hydrogen that enters the drywell has a tendency to enter the surrounding containment via the suppression pool (wetwell). The following subsection discusses the various bypass leakage paths via which the hydrogen may be released

from the drywell/containment.

* In general, the most severe nuclear system effects and the greatest release

of radioactivity to containment result from the complete circumferential break

at the pump inlet. However, the individual plant's FSAR should be consulted

for possible variations from this. 4 -6

4-68
MOISTURE SEPARATOR

AND REHEATER

IL SEPARATORS AND DRYERS CONDENSEI

a _ _ _ _ _ _ _

Figure 4-27. Direct Cycle Reactor System
ISOLATION

VALVE

WATER LEVEL S STEAM

SEPARATOR

MIXING

PLENUM

SHROUD HEAD

FEEDWATER SHRO UPPER

PLENUM

-m

0

RECIRCULATION TOP FUEL GUIDE - RECRCULAo

LOOP 3:LOOP -C 0

0

- "-

.. L e 0- co<

LU

RECIRCULATIO CR C LPUMP RCCUAINSUPPORT LPUMPSHROUDUD RECIRCULATION

SUPPORT -- -

LOWER PLENUM

Figure 4-28. Reactor Vessel Water Level and Primary System

Flows Immediately After a Loss-of-Coolant

Accident

TION

4-70
4.6.3.2 Hydrogen Transport through a Stuck Open Safety/Relief Valve to the

Suppression Pool. Each main steam line for a BWR is provided with safety/

relief and spring-loaded safety valves to relieve any overpressure condition

and prevent a possible failure of the reactor coolant pressure boundary.

Most BWR facilities employ four main steam lines that go directly to the high

pressure turbine. Each steam line has two kinds of valves located inside the

primary containment. One is a spring-loaded safety valve with a setpoint that

is independent of the backpressure. The pressure setpoint of the safety

valves is generally between 1210 and 1275 psig. The other valve is a

dual-purpose, safety/relief valve.

The main safety/relief valve section is a hydraulically-operated,

reverse-seated, globe valve that, when activated by the pilot valve, provides

the pressure relief function. These safety/relief valves open at a lower

pressure than the spring-loaded safety valves. Generally, the safety/relief

valves are set to open between about 1085 and 1105 psig.4-31

If a small break occurs it should be handled by the High Pressure Coolant

Injection (HPCI) System. However, if the HPCI System malfunctions, the

safety/relief valves provide an automatic depressurization capability. This

depressurization will allow operation of the Low Pressure Coolant Injection

(LPCI) System* and the Core Spray System to protect the fuel cladding integrity.

In the event that an ICC condition is reached, hydrogen could be produced.

This hydrogen could contribute to an overpressure condition if a degraded core

condition were to develop. The release of hydrogen through a stuck-open

safety/relief valve is shown in Figure 4-29. (Figure 4-29 is a simplified

sketch of the BWR Main Steam System for a facility incorporating a Mark I

primary containment design.4-31) Note that the relief valve will discharge

to the suppression pool (often referred to as the torus for Mark I primary

containments). The safety valve would discharge either to the drywell volume,

thereby increasing the hydrogen concentration of the drywell itself, or to the

suppression pool, depending upon the containment type.

4.6.3.3 Primary Containment Leakage to the Secondary Containment (Mark I and

II BWR Designs). The primary containment is designed to maintain its functional integrity during and following any postulated LOCA. The primary containment, in combination with other accident mitigation systems, also is

designed to limit the fission product leakage during and following the postu--

lated DBA to values less than those prescribed by 10CFRI00. 4 - 3 3

The drywell is protected by the Combustible Gas Control System (CGCS), which

controls the concentration of hydrogen within the drywell and secondary containment following a LOCA. If any overpressure condition developed due to the

presence of hydrogen in the drywell, the CGCS would minimize the consequences

of the event. It should be emphasized, however, that the Combustible Gas Control System cannot handle large amounts of hydrogen, such as could be

generated during a severe accident.

* LPCI mode of the Residual Heat Removal System at some facilities.

4-71
HEAD VEN

A = AIR OPERATOR

CRW = CLEAN RADWASTE

FE = FLOW ELEMENT

H = HYDRAULIC OPERATOR

M = MOTOR OPERATOR

R = RESTRICTIVE ORIFICE

T

SAFETY/RELIEF VALVES

- SAFETY VALVES

FLOW RESTRICTOR

MAIN STEAM ISOLATION VALVES

rH TURBINE

REACTOR

VESSEL

CONDENSER

PRIMARY

CONTAINMENT CRW

Figure 4-29. Main Steam System (Mark I BWR)

4-72
The CGCS ensures that the hydrogen concentration is maintained below a level

that could endanger drywell integrity. The CGCS provides the capability to

monitor and control the concentration of hydrogen in the drywell by incorporating the following subsystems for combustible gas control: 4 - 3 3

o A subsystem to monitor the concentrations of hydrogen and oxygen

within the containment.

o A hydrogen recombiner subsystem (in some plants) to maintain the

hydrogen concentration below the lower combustible limit.

o A containment hydrogen purging system to limit the concentration of

hydrogen. This is a backup to the hydrogen recombiner system.

For Mark I and Mark II containment designs, there is no intended path for

hydrogen to take from the drywell (primary containment) to the reactor building (secondary containment). Therefore, for these two designs, leakage from

the drywell to the secondary containment could only take place via bypass

leakage paths that were discussed in a previous section. Every effort is made

to minimize the probability of an accident's proceeding to the point that drywell integrity could be breached.

Mark III BWR containment designs, on the other hand, incorporate a Drywell

Purge/Vent System that can vent the drywell to the surrounding containment

volume. This system is provided for the expressed purpose of utilizing the

full capacity of both the drywell and containment volumes in containing any

hydrogen liberated by a severe accident that resulted in a degraded reactor

core condition. (It is designed to handle the hydrogen release from a DBA

LOCA; there may be other accident scenarios for which it would be unable to

handle the release.) It forces the hydrogen from the drywell to the surrounding containment, in an effort to reduce the hydrogen concentration below flammability limits. 4 - 1 4

Figure 4-30 shows a Drywell Purge System and Post-LOCA Vacuum Relief System

for the Grand Gulf Nuclear Station, which has a Mark III containment. The

vacuum relief portion of this figure will be discussed in the next section.

4.6.3.4 Hydrogen Transport via the Drywell Purge System* and Vacuum Breaker

(Mark I and II BWRs). Another method of relieving a hydrogen gas buildup in

the drywell at a facility with a Mark I or II containment is via the drywell

hydrogen purge subsystem. A line penetrating the primary containment (or drywell) is provided with power-operated isolation valves. This particular purge

system discharges to the Standby Gas Treatment System (SGTS) recirculation

supply plenum, where it is filtered and exhausted to the turbine building

exhaust vent stack. The Drywell Purge System is provided as a backup to the

Hydrogen Recombiner System at most BWR facilities. It would be used only in a

post-LOCA situation, in the unlikely event of a failure of the existing Hydrogen Recombiner Systems. (Again, it is intended to handle the release from a

*This terminology has different meaning for different plants, and these discussions may not be applicable for all plants.

4-73
PDSL = PRESSURE DIFFERENTIAL SWITCH, LOW

PDIS = PRESSURE DIFFERENTIAL INDICATING SWITCH

PDS = PRESSURE DIFFERENTIAL SWITCH

PDT = PRESSURE DIFFERENTIAL TRANSMITTER

PDR = PRESSURE DIFFERENTIAL RECORDER

A = ALARM

M = MOTOR SCREEN AIR FROM

H:1 CONTAINMENT

-.

Figure 4-30. Drywell Purge System and Post-LOCA Vacuum Relief System
DBA-LOCA; it may not be able to control the releases from some other

accidents.)

The purge system controls the hydrogen concentration by dilution of the

post-LOCA drywell atmosphere. The drywell is purged of hydrogen gas; nitrogen

is supplied to the drywell during the purging process. Calculations show that

radiation doses at theý site boundary as a result of a DBA-LOCA will not exceed

the guideline values of 10CFRIO0. 4 - 3 3

Protection of the drywell from exceeding the design maximum externai pressure

of about 2 psig is provided by a system of self-actuating swing-check vacuum

relief valves. Figure 4-31 shows a simplified Containment Ventilation and

Inserting System showing the vacuum relief valves to the suppression chamber

(torus) for a Mark I containment design. 4 - 3 2

Mark II containment vacuum relief is accomplished in much the same way. The

suppression pool, however, is directly below the reactor vessel within the

same structure, which is referred to as the drywell. Mark III containment

designs also incorporate a vacuum relief system. Figure 4-30 shows the

arrangement of this system for the Grand Gulf Nuclear Station.

In each case, the flow through the vacuum relief check valves is into the drywell, not out of it. However, if there were a failure of these check valves,

or possibly some bypass leakage, hydrogen gas contained in the drywell atmosphere could escape to the secondary containment. For the Mark III design this

is acceptable. It is not desirable in the Mark I and II designs because the

reactor building secondary containment is not designed for an elevated pressure condition.

4.6.3.5 Hydrogen Transport through the Bypass Leakage Paths from the Drywell. An important consideration examined by BWR facilities is that of

primary containment bypass leakage. If a LOCA occurs, the Standby Gas Treatment System (SGTS) is automatically activated and begins to process all air

flow streams from the secondary containment ventilation system. Therefore, if

a LOCA occurs, any airborne radioactivity and hydrogen gas that exfiltrates

the steel-lined primary containment is collected and passed through the

SGTS.* The system is designed to operate during and after a DBA-LOCA.

Although one of the principal functions of the SGTS is to maintain the

off-site radiation dose within limits prescribed by 10CFR20, it also filters

and exhausts the atmosphere from the primary containment for the purposes of

purging, ventilation, and pressure relief. The filtered exhaust is sent to

the turbine building exhaust vent stack. 4 - 3 3

* While such containment leakage is possible, its existence is considered

unlikely because of the stringent periodic testing requirements that, must be

met in this area.

4-75
TO

REACTOR BUILDING STACK

A = AIR OPERATED

RE = RADIATION ELEMENTS

PLANT F1 FLOW INDICATOR

STACK

REACTOR

BUILDING

EXHAUST

FANS SBGTS

FT = FLOW TRANSMITTER

M = MOTOR

N2 MAKEUP

SUPPLY

LIQUID N2

STORAGE

VACUUM

RELIEFS

FILTER &

CHARCOAL

FILTER

-'

A

SYSTEM REACTOR BUILDING

VENTILATION

EXHAUST

* TYPICAL OF 10

Figure 4-31. Mark I Drywell/Primary Containment Ventilation and Inerting


4.6.4 Air Handling Fans

Following a LOCA that results in the release of hydrogen to the containment

(for a PWR) or drywell (for a BWR), measures must be provided to assure that

the hydrogen mixes throughout the volume and does not "pocket" in dangerous

concentrations. The transport and mixing of hydrogen is assisted by cooling

and recirculating fans in containment. The degree of mixing achieved is

dependent upon fan size (or compressors) and hydrogen release rate.

Some BWR facilities have a hydrogen mixing system, that consists of drywell

purge compressors that obtain suction from the drywell and exhaust to the

containment. A typical mixing system consists of two compressors, each with

500 SCFM capacity. Automatic valves open when drywell pressure is 0.5 psi

less than secondary containment pressure, and shut when it is 0.25 psi less

than secondary containment pressure. Initiation of the system is manual after

a 30 minute delay, and manual operation of the valves may override automatic

operation ten minutes after system initiation. Air flow through the drywell

is upward and rotary, which enhances mixing in the drywell. Mixing in the

containment may be accomplished by other fans.

Reactor building cooling fans and sprays introduce considerable turbulence to

the building atmosphere to enhance mixing. In addition, there also may be

stairwells, elevator shafts, and gratings in the building that will help to

promote good circulation. (It should be mentioned that accident scenarios may

exist in which these fans are unavailable. Such situations are not discussed

here.)

The fans and fan motors used should be designed to withstand post-LOCA

temperatures and pressures, and exposure to radiation, depending upon their

location in containment. The fans are either vane, axial, or centrifugal, and

are either belt-driven or direct-coupled to the motor shaft.

4.7 HYDROGEN COMBUSTION

4.7.1 Introduction

An inadequate core cooling condition can produce hydrogen if fuel cladding

temperatures reach 1832°F (1000°C). Combustion of this gas in the containment

building could pose a threat to safety-related equipment and, possibly, to the

containment itself. At TMI, the 28 psig (290 kPa) peak pressure pulse that

occurred was substantially less than the 60 psig (510 kPa) containment design

pressure. However, for a containment building with a smaller volume or a

lower design pressure a more severe threat could have resulted.

This section will examine the potential sources of accidental hydrogen ignition, and will review the methods and instrumentation that may be used to

determine whether a hydrogen combustion actually took place.

The combustion properties for hydrogen:air:steam mixtures on a large scale are

not well known. However, this section will examine some current work pertaining to hydrogen distribution and combustion following an accident. It also

will introduce information regarding hydrogen flame acceleration channels that

may occur in a reactor containment and some work currently being performed to

further study flame acceleration.

4-79
4.7.2 Potential Sources of Accidental Hydrogen Ignition

Accidental ignition of hydrogen could be caused by several sources in a containment structure if the hydrogen concentration in air were to reach sufficient levels. In air at standard temperature and pressure (25 0C, 1 atm), and

100% relative humidity, the lower limit for hydrogen combustion is 4.1% hydrogen concentration by volume. 4 - 1 Table 4-6 indicates the approximate hydrogen concentrations required for combustibility in air.

Table 4-6

HYDROGEN CONCENTRATION VS. POSSIBLE REACTIONS

Hydrogen Concentration in Air* Possible Reaction

0% - 4% Noncombustible

4% - 14% Combustible

14% - 59% Combustible (possibly detonable)

59% - 75% Combustible

75% - 100% Noncombustible

* These numbers are currently accepted values. Recent experiments have

indicated that the range of concentrations for which detonations may be

achieved may be wider than that indicated.

Some containment systems include intentional ignition devices, glow plugs, to

keep the hydrogen concentration in containment between 4% and 9% in the event

of a LOCA. These systems are discussed in a later section of this chapter.

Hydrogen generation, and its subsequent release to the containment structure,

is a concern only in a post-accident mode. In the event of an accident,

hydrogen will either collect in the reactor head or vent to containment

through the reactor head relief valves or a coolant pipe break. If this

happened, any unsealed electrical component or any valve movement that created

a spark could provide the necessary energy for ignition. Depending on the

location of the leakage, the vented hydrogen might pass or remain near many

possible ignition sources as it left the RCS.

If hydrogen is vented from the reactor vessel head, the many motors and valves

near it could provide the necessary spark for ignition. The control rod drive

motors (in a PWR) and power-operated relief valve motors (in both PWRs and

BWRs) are located near the reactor vessel head relief valves. In addition, in

a PWR, there are the control rod drive mechanism (CRDM) cooling fans.

Solenoids, which actuate many motors, generally are not considered to be a

probable ignition source because most solenoids are sealed, thus preventing

exposure of any sparks to the vented hydrogen. A motor, however, is not completely sealed and can be an ignition source.

4-80
Hydrogen releases to the containment atmosphere from the pressurizer vessel

could be exposed to sparks from PORVs and PORV motors at the vessel head.

Hydrogen venting from the pressurizer to the containment atmosphere is not

probable, however, because the pressurizer would vent to the pressurizer

relief tank (PRT) first. This is a closed venting system (i.e., it is not

open to the atmosphere) and, therefore, no oxygen would be present for combustion.

In the event of a pipe rupture in any system directly connected to the reactor

vessel, or pressurizer (in a PWR), hydrogen could be introduced anywhere

inside the containment structure. There are many pumps, motors, and fans

located inside containment, all of which could provide sparks to ignite the

hydrogen. Depending upon local hydrogen concentrations and the strength of

the spark, the hydrogen could either deflagrate or detonate.

It is most probable that ignition would be caused by a spark rather than by

spontaneous combustion on a hot surface. The reason for this is that for jets

or plumes of hydrogen:steam mixtures, a temperature of at least 959 0 F (515 0 C)

is required for spontaneous combustion autoignition. 4 - 3 5 It is highly

unlikely, even in an accident mode, that any surface inside the containment or

drywell would reach this temperature.*

Once the hydrogen concentration in the containment atmosphere is over 4%, a

spark anywhere in the containment structure could initiate combustion.

Depending upon the hydrogen concentration, a global hydrogen combustion could

cause a sharp increase in containment pressure. If the initial hydrogen concentration were high enough, this pressure increase could challenge the integrity of the containment.

In a related context, there have been instances of unplanned hydrogen combustion in the off-gas systems of BWR plants. These events have been caused, in

many cases, by motors sparking, and also by welding sparks, by lightning

strikin? the exhaust stack, 4 - 3 6 and by improperly grounded equipment 4 -3 4-38 in the Off-Gas System. (Hydrogen in BWR off-gas systems was

discussed in Chapter 3.)

4.7.3 Evidence of Hydrogen Combustion in PWRs

In the event of a hydrogen deflagration or detonation, rapid changes in containment temperature and pressure can occur. Data from the TMI-2 event disclose that a hydrogen deflagration occurred approximately ten hours after the

onset of the LOCA. From the data obtained from this incident it was learned

that some instrumentation (e.g., steam generator pressure) responded to the

hydrogen combustion process.

Additional sampling of the containment atmosphere two days after this event

also showed that a hydrogen combustion had taken place.

This section will consider various methods that may be employed to determine

whether a hydrogen combustion has occurred.

*A possible exception would be at a break location where high temperature

steam and hydrogen are exiting.

4-81
4.7.3.1 Containment Pressure Effects. If a combustible concentration of

hydrogen were present in containment and an accidental ignition occurred,

creating a deflagration, then a rapid pressure rise could occur as discussed

in Chapter 2 and depicted in Figure 2-10. The containment pressure detectors

would sense the deflagration. For example, Figure 4-33 shows a containment

pressure vs. time graph from one of the trend recorders in the TMI-2 control

room during the incident. It shows that there was a pressure change, in the

TMI-2 containment, from-2 psig (115 kPa) to -28 psig (294 kPa) (a differential pressure of 26 psig) and then back down again. This was seen as a pressure spike on the control board recorder. The whole process lasted about 200

seconds. This "peculiar" behavior confused personnel in the control room

because there was, literally, no emergency or accident condition analyzed in

the Final Safety Analysis Report (FSAR) or discussed in their training that

postulated a containment pressure behavior such as this. As a result,

personnnel in the control room thought that it might have been caused by an

electrical transient. After the indicated spike, everything appeared to be

"normal." A key feature of the pressure spike was that all three containment

pressure meters on the control board showed the same pressure behavior as the

recorder. This was another indication that a deflagration had occurred. That

this behavior could have been caused by an electrical transient is virtually

impossible because the instrument power supplies for each pressure detector

utilize separate electrical power sources. Therefore, an almost simultaneous

rapid pressure rise on all three pressure channels must be believed as being a

genuine pressure increase, 4 - 8 as opposed to some sort of electrical transient.

4.7.3.2 Pressurizer Pressure Effects. If a hydrogen deflagration (or

possibly a detonation) occurred in the reactor containment, any pressure sensor or differential pressure device that measures pressure relative to the

pressure in containment will be affected, i.e., if the reference pressure of

the sensor is that of the containment atmosphere, then any change in this

pressure will effect the indicated system pressure that registers in the control room.

For example, from Figure 4-9 it can be seen that the pressure transmitter for

the pressurizer senses the pressurizer on one side and the containment volume

on the other side. 4 - 8 That is, from a pressure sensing point-of-view, it

interfaces with both the pressurizer and the reactor containment. The actual

pressure monitored by this instrument is the differential pressure between the

pressurizer and the reactor containment. Therefore, if the containment pressure were to rise suddenly (as a result of a hydrogen deflagration for

example), the pressurizer pressure detector would show a rapid drop in pressurizer pressure. This sudden deviation from the normal pressurizer pressure

behavior could be compared with the behavior of other parameters such as containment pressure, containment temperature, or steam generator pressure to

determine whether the possibility of a hydrogen ignition in containment exists.

4.7.3.3 Steam Generator Pressure Effects. The previous discussion for the

pressurizer applies to the steam generators as well. Pressure transmitters

monitoring steam pressure for the steam generators are also present in the

containment building. Hence, a sudden increase in containment pressure can

4-82
Z)

w

0~

D

0

C-,

32

28

24

20

16

12

8

4

0

HYDROGEN BURN

I I I I I I -

-4 I I I I I i

0 2 4 6 8 10

TIME AFTER TURBINE TRIP (HOURS)

12 14

Figure 4-33. Reactor Building Pressure vs. Time

4-83
manifest itself in a sudden drop in the indicated steam generator pressure.

Actual steam generator pressure data are presented in Figure 4-34.4-8 Further discussion of this point is presented in Appendix I.

As can be seen in Figure 4-34, the sharp drop in steam generator pressure that

occurred during the TMI incident occurred at about 1350 hours on March 28,

1979. The incident started at 0400 hours that morning. At 9 hours and 50

minutes into the incident (at 1350 hours) there was a sharp pressure spike

noted on the containment pressure detectors. 4 - 8 The rapid rise in containment pressure (about 26 psid; see Figure 4-33) was matched by the rapid drop

in steam generator pressure (see Figure 4-34).

4.7.3.4 Containment Temperature Effects. If hydrogen is created within the

reactor core by a fuel cladding-steam reaction and subsequently released to

the containment, it would be impossible to detect its presence from temperature effects alone. However, if the hydrogen concentration increased to a

level that could be ignited, a hydrogen combustion would definitely be detected

from the temperature effects. This was discussed in Chapter 2 and depicted in

Figure 2-11. For example, during the TMI incident, the hydrogen deflagration

that occurred at 1350 hours caused a rapid temperature rise on most of the

temperature monitors in the containment, as shown in Figure 4-35.4-8 This

suddenly rising temperature, in conjunction with changes in other parameters

such as containment pressure, pressurizer pressure, and steam generator pressure could be used to determine that a hydrogen combustion had taken place.

The temperature in containment is typically measured by RTDs which have a slow

response time. Therefore, temperature data should not be relied on exclusively; rather it should be considered carefully in conjunction with other

available information. (Refer to Appendix I for further information regarding

the TMI-2 incident.)

4.7.3.5 Containment Gaseous Sampling. In section 4.4.3.4, it was pointed out

that a containment gas sample can provide a direct indication of the presence

of hydrogen.

If a hydrogen combustion takes place, the oxygen concentration must decrease.

The post-accident sampling of the TMI-2 containment atmosphere (dry gas

sample) showed that the oxygen concentration dropped by approximately 4.8%.

This oxygen was consumed by a chemical reaction. Such a drop in oxygen concentration could be another clue that a hydrogen combustion had taken place;

however, the possibility must also be considered that the oxygen was consumed

in reactions with substances other than hydrogen (although these reactions are

generally long term).

4.7.4 Evidence of Hydrogen Combustion in BWRs

If a hydrogen deflagration or detonation occurred, rapid temperature and pressure changes would occur in the primary containment. Some of the same instruments that provide indications of hydrogen production will also provide key

indications of hydrogen combustion.

4.7.4.1 Drywell/Containment Pressure Effects. Table 4-2 gave some general

pressure effects caused by hydrogen for each containment type. These pressure

effects included estimated final pressures that might be expected if a hydrogen combustion occurred. These pressures were presented as a function of the

4-84
270 -5

0

265 - o OTSG "A" 0 e OTSG "S

260 0

0 0

0

255 0 10

0 10 25 

0 

0

0

I~00

S250 0 15 <

00

0 ,

I-O

•a20 0- 0 1

245 I0 200 0 o0

240 25

235 30

II I I I

13:50:20 13:50:40 13:51:00 13:51:20

TIME

Figure 4-34. Effect of Hydrogen Ignition on Measured Steam Pressures

4-85
5

6

7

8

9

Supply air

Supply air

Ambient steam and feedwater penetration

Ambient sump area

Ambient letdown cooler area

10 Ambient drain tank area

11 Ambient elevation 353-1

12 Ambient elevation 353-2

13 Ambient elevation 330-1

14 Ambient elevation 330-2

190

180

170

160

150

140

"w 130

1- 120

"w 110

100

90

80

70

1300 1400

TIME

1500

Note: The variation In response time for the various

Instrumented regions is due, in part, to ther

different elelvations and specific locations in

containment. Further, these data were sketched

from recorder data showing poinr-boiynt

temperature readings. This graph Is Intended

to show general temperature trernds only.

Figure 4-35. Reactor Building Temperature During Hydrogen

Ignition at Three Mile Island Unit 2

4-86
percent metal-water reaction. This table assumed that all of the hydrogen was

liberated and that a single global deflagration occurred.

For a BWR Mark III containment where no inerting is used, other methods of

controlling hydrogen behavior can be employed to ensure that containment

integrity is not threatened. (The anticipated pressure increase for a global

hydrogen combustion for the complete range of hydrogen concentrations in containment was shown in Chapter 2.) As for PWRs, the pressure increase caused

by the liberation of hydrogen into the containment is not a singularly sufficient indicator of the presence of hydrogen. However, global deflagrations

are evidenced by sharp pressure spikes, such as those in Figure 4-36. Local

deflagrations will also cause sharp pressure spikes; however, the pressure

rises will be lower in magnitude due to volumetric expansion of gases in the

burned region into the unburned region (see Figure 4-38). Continuous burning

of a steam:hydrogen jet could cause a steady pressure rise, as shown in

Figure 4-40. (Note that Figures 4-36 to 4-41 should be treated as qualitative rather than precise quantitative examples.)

4.7.4.2 Drywell/Containment Temperature Effects. There has never been a

hydrogen ignition in a BWR drywell/containment as of this writing. One should

be aware of the TMI containment temperature results previously discussed for

PWRs, since this sort of temperature behavior might be possible in a BWR containment that is air-filled. For nitrogen-inerted Mark I and II drywells, the

possibility of oxygen production by radiolysis must also be considered during

a severe accident. An indication of the temperature effects due to hydrogen

combustion is given in Figs. 4-37, 4-39 and 4-41, which show the temperature

response to deflagrations.

The temperature spikes shown in Fig. 4-37 would result from successive global

deflagrations. Local deflagrations could produce locally high temperatures

(not far below the temperatures from global deflagrations), as shown in

Fig. 4-39. Regions not adjacent to local burns would see much smaller

temperature rises. Figure 4-41 shows a gradual rise in temperature due to

burning of a steam:hydrogen jet. Regions close to the jet may see a much more

rapid and severe temperature rise.

4.7.4.3 Drywell/Containment Gas Samples. For those BWR facilities whose drywell/containments are not inerted, the possibility exists for hydrogen ignition to occur. If the hydrogen concentration exceeds the flammability limit

of 4% discussed in Chapter 2, it can be ignited either by a Hydrogen Igniter

System (HIS) 4 - 3 9 or by other ignition sources in the primary containment.

If part of the hydrogen is burned, the oxygen concentration will drop. Hence,

a sudden drop in oxygen concentration (dry gas sample) could be indicative of

a hydrogen combustion. (It could also be due to reactions with substances

other than hydrogen.) Verification that a hydrogen combustion has occurred

would require comparison of this indication with other potential indications

of hydrogen combustion being examined in this section. Maintenance of good

records of oxygen concentration in a non-inerted drywell would be necessary

for this indication to be noticed.

4.7.5 Possible Flame Acceleration Channels

Every effort is made to minimize the probability of the hydrogen concentration

reaching the flammability limit. However, if the hydrogen concentration in

4-87
400

300

"200

C,)

100

0

1600 2800 4000 5200

TIME (s)

Figure 4-36. Pressure Response to Global Burns.

1400 1 1

1200

1000

L-

( 800

S600

I--

400

200

1600 2800 4000 5200

TIME (s)

Figure 4-37. Temperature Response to Global Bums.

4-88
450

400

300

350

w

250

0200

150

100

50

I ~ I I I I I I I I I I~

I I II I I I I I

0 1200 2400 3600 4800

TIME (s)

Figure 4-38. Pressure Response to Local BunsL

Figure 4-38. Pressure Response to Local Burns

1400

1200 -

2 1000

800

cc0.

S600 w

400

200

I I I I I I I I I I I

I I I I I I I I I I I

0 1200 2400

TIME (s)

3600 4800

Figure 4-39. Temperature Response to Local Burns

4-89
300

a.

LU

200

LU

100

1200 2400 3600 4800

TIME (s)

Figure 4-40. Pressure Response to Continuous Burns

600 1 1 i 1 1 1 1 i i 1 1

500

2 400 LUI,-

300 I I I I I

1200 2400 3600 4800

TIME (s)

Figure 4-41. Temperature Response to Continuous Burns

4-90
containment reached a combustible level, a deflagration could occur. If a

hydrogen deflagration takes places, the ability of the flame velocity to cause

possible shock damage to systems or components in containment becomes a concern.

If the hydrogen has had time to completely mix with the containment atmosphere

before combustion, the combustion will be a premixed flame or, possibly, a

detonation, depending upon the hydrogen concentration.4- 1 The actual speed

of the combustion front may be as slow as 1 m/s for a laminar deflagration or

as high as 2000 m/s for a detonation. As discussed in Chapter 2, deflagrations are flames that travel at subsonic speeds relative to the unburned gas,

and propagate mainly by thermal conduction from the hot burned gas into the

unburned gas, raising the temperature high enough for a rapid exothermic

chemical reaction to take place. Detonations, on the other hand, are supersonic relative to the unburned gas and involve unsteady shock wave phenomena

in their structure. In a detonation, the unburned gas is heated primarily by

shock compression in contrast to the heat conduction operating in deflagrations.41

If the speed of the combustion front is low relative to the speed of sound,

the pressure within containment generally will rise uniformly throughout the

volume of the enclosed gas within several seconds. The pressure will decay

slowly due to heat transfer from the gas to the walls and other surfaces in

containment, with a time constant-ofa few minutes. If containment spray is

actuated, the decay of the gas temperature and pressure will be more rapid.--

For slow flames the pressure effects on the containment building are quasistatic. That is, the containment will respond principally to the magnitude of

the pressure effects. The transient pressure effects will tend not to be

important. In referring to the stresses placed on the containment, it may be

said that if the duration of a pressure pulse is short with respect to the

lowest relevant mode of vibration of a structure (its natural frequency) the

load or stress placed upon it is called impulsive. The severity of the load

is governed mainly by the impulse per unit area (the time integral of the

pressure pulse), rather than by the peak value of the pressure. When the

variation in pressure is long compared to the period of vibration of the

structure, the load is called quasi-static. The severity of the load is

governed mainly by the peak pressure; the impulse is irrelevant. When the

pressure-pulse duration and structure period are of roughly the same magnitude, the severity of the load is governed by both peak pressure and impulse.

For a detonation, however, the initial containment stresses are large and

dynamic, and will be followed by quasi-static stresses, as previously mentioned. During a detonation, the pressure seen by the containment wall will

be an intense pressure pulse followed by a series of reflected pressure pulses

due to shock wave reverberations within the containment. Once these reverberations have decayed, the residual pressure will be approximately equal to

that produced by a slow deflagration. 4 - 1

In a study performed by Sandia National Laboratories, calculations of the

pressures caused by a postulated detonation were made for various points in

the Zion containment (assuming a simplified geometry4-43). For purposes of

the calculation, it was assumed that the detonation was initiated at the center of the containment bottom, with a 20% hydrogen concentration throughout.

4-91
The detonation was assumed to propagate no faster than the Chapman-Jouguet

detonation speed (see Chapter 2). For this simplified example, the pressure

history at the top of containment is shown in Fig. 4-42. This theoretical

behavior denotes a strong initial pulse due to focussing along the axis of

symmetry, followed by other smaller pressure pulses. 4 -1,4- 4 4

Although for a postulated DBA-LOCA the hydrogen concentration in a PWR containment should not reach the detonable limit, the proposed changes to

10CFR50 4 - 5 on this matter assume that a 75% zirconium-steam reaction has

occurred. For some facilities a potentially detonable mixture (>14% hydrogen

concentration) is approached based on these revised assumptions. In an accident, however, it is much more probable that combustion will begin as a

deflagration. Experimental results indicate that deflagrations, rather than

detonations, are often observed up to hydrogen concentrations of 24% in

air. 4 - 4 2 Also, the presence of steam will make detonations less likely.

In this regard, there has been a great deal of work on the deflagration-to-detonation transition (DDT) over the past 50 years; however, the

subject is still not well understood. What is known is that a deflagration

begins in an enclosed volume. The resultant expansion of the hot burned gas

creates a compression wave of the gas ahead of the deflagration front. The

compressive heating of the unburned gas increases the flame speed, causing

further increases in compression until a shock wave is developed. If the

unburned gas behind the shock wave is heated above its autoignition temperature, a detonation can occur, assuming the hydrogen concentration is greater

than the detonation limit. 4 - 4 4 It is generally accepted today that the

transition mechanism must involve the formation of a turbulent flame and perhaps reflected shock waves.4- 4 5 ,4- 4 6 ,4- 4 7 This type of transition mechanism

has been studied in closed tubes in laboratory experiments.

There is, however, an important second mechanism to consider for a deflagration-to-detonation transition. This is the acceleration that the deflagration

flame front experiences as it passes obstacles in its path. Laboratory

experiments using tubes containing obstacles have produced detonations where,

under identical circumstances without obstacles present, there would have been

no detonation. 4 - 4 8 The fact that the plant containment will contain many

obstacles (such as pumps, piping, reactor vessel, steam generators, reactor

containment fan coolers, etc.) is important to consider with regard to a DDT

if a detonable concentration of hydrogen is ever reached in containment.

In studies currently being performed by EPRI and Sandia National Laboratories

(SNL), the topic of possible flame acceleration is being addressed. One of

the objectives of these studies is to determine the potential for the acceleration of deflagrations or for the transition to detonation in turbulent mixtures. For example, it is known that grating systems can promote turbulence

and can conceivably accelerate a burn. 4 - 4 0 The structures and equipment in

containment have the potential to create flame turbulence that could accelerate the burn. The EPRI and SNL studies will examine these phenomena to

determine their possible effects. 4 - 4 9

It, therefore, is advisable to take measures to maintain hydrogen concentrations as low as practicable during an accident or emergency condition so as to

minimize the consequences of combustion. Note, however, that structures and

equipment may have a substantial capacity to survive a local detonation

4-92
12.0

11.0

10.0

9.0

8.0

M7.0

w 6.0

S5.0

UJ 4.0

a. 3 .0

2.0

1.0

0.0

0.02 0.06 0.10 0.14 0.18

TIME (sec)

Figure 4-42. Pressure at Center of Roof

in Zion Calculation

4-93
since the pressure and temperature decay when the compression wave enters a

leaner hydrogen mixture; control means such as water sprays may sufficiently mitigate the phenomenon. (Water sprays may quench detonations and raise the

lower detonation limit.4-51

In one PWR study,* it was found that the possibility of developing uniform

hydrogen concentrations in excess of 18% (previously thought to be the

detonability limit) seems very remote, if not impossible.4- While it is

now known that detonations can occur in lower hydrogen concentrations, the

possibility of a global detonation is still remote. Local hydrogen accumulations, however, could conceivably reach detonable concentrations. The top of

the ice condenser (see Figures 4-43 and 4-44) may be such a location. The

mechanism aiding in concentrating this hydrogen is the condensation of steam

out of the steam-hydrogen mixture that could flow up an ice condenser duct

following a LOCA in which severe core damage occurred. If a deflagration was

initiated at the base of the ice condenser duct, the combination of ostacles,

along with the distinct possibility of an increasing hydrogen concentration

vertically within the duct, renders this particular arrangement a possible

candidate for DDT.

Other possible PWR locations in which hydrogen could concentrate include containment fan cooler ductwork, the cubicle area of the pressurizer relief tank

(quench tank), the compartment immediately above the reactor vessel head, or,

perhaps a reactor coolant loop cubicle, such as is present for some PWR

facilities (shown in Figure 4-45).4-52 Hydrogen could concentrate in comparable areas in BWR containments.

4.8 Residual Hydrogen (Post-Burn) Considerations in Containment

The burning of hydrogen in containment would result in large, short-duration

temperature and pressure increases. Multiple burns would result in an

increase in containment ambient temperature and pressure. Any systems and

equipment inside containment whose use may be required after a burn must be

able to survive both burn and post-burn environments. Following is a list of

systems and equipment for a BWR6/Mark III facility whose use may be required

after a burn:

o Containment isolation valves, penetrations, locks, and hatches

o Hydrogen Igniter System

o Hydrogen recombiners

o Containment Spray (CS) System

o Safety/relief valves

o Low pressure core spray, low pressure coolant injection, and residual heat removal systems

o Reactor level and pressure instruments

o Hydrogen analyzers

o Containment pressure and high-range radiation instruments

o Containment and suppression pool temperature instruments

* Performed for the Sequoyah Nuclear Power Plant, a Westinghouse plant with

an ice condenser containment, that is located in Daisy, Tennessee, and

operated by the Tennessee Valley Authority.

4-94
RCP = REACTOR COOLANT PUMP

SG = STEAM GENERATOR

Figure 4-43. Simplified Diagram of Ice Condenser Containment

4-95
RADIAL BEAM

OPERATING

DOOR PORT

\LOWER INLET DOORS

LOWER SUPPORT STRUCTURE

Figure 4-44. Cutaway View of Ice Condenser

4-96
Figure 4-45. Plan View - Cubicle Loop (Typical)

North Anna Power Station Units 1 and 2

4-97
o Drywell pressure instruments

o Associated instruments and controls

o Associated power and control cables

o Low pressure core spray, low pressure coolant injection, containment spray, residual heat removal, and containment isolation valve

position indication

The list for a PWR facility would be similar, minus the drywell equipment, and

with the addition of pressurizer and steam generator equipment and instruments.

During the TMI-2 accident, the pressurizer level transmitters, pressurizer

pressure transmitters, and RCS flow transmitters, all located at the six-foot

elevation in containment, failed when the water level rose to the seven-foot

elevation. The TMI-2 staff has recommended that any transmitters positioned

at lower elevations in the containment building be repositioned at a higher

elevation to prevent a transmitter failure by submergence in water. An alternate solution to this problem would be to enclose transmitters in watertight

casings.

Also of concern in burn and post-burn environments are radiation, pressure and

temperature effects. Although this was probably not a cause of any instrument

failure at TMI, it is certainly one of the factors to be considered in instrumentation, reliability. Up to the present time, there have been very little

data regarding the integrated dose required for given vital instrumentation to

fail. It is expected that more data will be made available regarding this

parameter in the future.

During a hydrogen burn there is a rapid temperature increase in the vicinity

of the burn. For a short duration, temperatures may exceed 1000 0 F, causing

concern over radiation heat transfer. Radiation heat transfer can be adequately controlled by shielding susceptible instrumentation with a cover

insulated on the inside.

As a result of multiple burns, the ambient containment temperature would

rise. Typically, vital instrumentation designs have been submitted to (and

have survived) test sequences that include exposures to temperatures as high

as 300 to 330°F for periods up to a few hours. Analyses have indicated that

under some circumstances severe accidents in reactor containments may produce

temperatures higher than these tests. Therefore, the survivability, i.e., the

ability to function adequately during and after such accidents, of safety

related equipment needs to be carefully evaluated. In general, the instrumentation, probably as a result of having been designed to rigorous seismic

requiremements, appears not to be threatened by the pressures expected in

reactor accidents.

4.9 METHODS OF CONTROLLING LIBERATED HYDROGEN

4.9.1 Hydrogen Recombiners

The recombiners' that now exist are capable of dealing effectively with the

relatively small amounts of hydrogen and oxygen that result from radiolysis

and corrosion following a LOCA. They are, however, incapable of handling the

4-98
hydrogen produced in an extensive zirconium-steam reaction. Current recombiners can only process gas that is approximately 4 to 5% hydrogen or less.

Higher hydrogen concentrations can be handled by diluting the mixture before

it enters the recombiner. They are also limited to about 200 SCFM input flow

per unit. 4- 1

4.9.1.1 Types. A recombiner is a device that reduces the hydrogen concentration in the containment atmosphere by combining free hydrogen and oxygen to

form water. There are three different classifications of recombiners: flame,

thermal, and catalytic. All three types perform the same function. They

differ primarily in the way that they initiate the recombination reaction.

The thermal recombiner uses radiant heat to bring about recombination, while

flame recombiners depend on a self-maintaining, exothermic combustion

process. Catalytic recombiners use a noble metal catalyst bed to promote

recombination at relatively low temperatures.

The flame recombiner has the advantage of negligible heat input, but is more

difficult to start than the other two types. In addition, it requires supplementary hydrogen and oxygen for reliable ignition and flame control. Also,

the addition of hydrogen and oxygen to the input stream makes flame arrestors

necessary. This type of recombiner has found very limited use in containment

applications.4-53

The catalytic recombiner is widely used to recombine radiolytically generated

off-gas during normal operation of BWRs. Extensive testing has indicated that

it can also be effective in the less predictable post-LOCA environment. 4 - 1

Two kinds of thermal recombiners are currently available for use in post-LOCA

situations. One is for location inside containment; it uses convective gas

flow that is regulated by the size of built-in orifices. The other is for

location outside containment; it allows control over several operating parameters. 4 - 2 1 Since the flame recombiner has limited use in containment

applications and since operation of the catalytic recombiner has already been

described in some detail in the Chapter 3 discussion of BWR off-gas recombiner

systems, only the two types of thermal recombiners will receive extended

attention here.

The first type of thermal recombiner is that employed inside the containment

building. The recombiner consists of a thermally insulated, vertical metal

duct with electric resistance heaters to heat a continuous flow of containment

air to a temperature that is sufficient to cause a reaction between hydrogen

and oxygen. It has an outer enclosure to keep out containment spray water.

The recombiner consists of an inlet preheater section, a heater-recombination

section, and a discharge mixing chamber that lowers the exit temperature of

the air (see Figures 4-46 and 4-47).

Air is drawn into the recombiner by natural convection, and passes through the

preheater section. This section consists of a shroud placed around the

central heater section; it takes advantage of heat conduction through the

walls to preheat the incoming air. This serves to reduce heat losses from the

recombiner and to preheat the air.

The warmed air passes through an orifice plate and enters the electric heater

section where it is heated, thus causing recombination to occur. Tests have

4-99
EXHAUST

COOLING'

AIR

ELECTRIC

HEATER

VERTICAL

DUCT

INTAKE

OUTER

ENCLOSURE

-PREHEATER

I

Figure 4-46. Inside-Containment Thermal Hydrogen Recombiner

4-100
o

-am_ POWER

RECOMBINER I

TEST

=----in TIC/

Figure 4-47. Schematic of Recombiner System
verified that the recombination is not a catalytic surface effect associated

with the heaters but, rather, occurs due to the increased temperature of the

process gases; therefore, catalytic poisoning is not a problem.

Catalytic poisoning is the process whereby a substance within the recombiner

unit itself inhibits the activity of the catalyst. Such poisoning has not

been demonstrated to be a problem in these thermal recombiners.

The power panel for the recombiner is located in the auxiliary building where

it is not exposed to the post-LOCA environment. The control panel is located

in the control room. To control the recombination process, the correct power

input that will bring the recombiner above the threshold temperature for

recombination is set on the controller. This power depends on containment

atmospheric conditions, and must be determined whenever recombiner operation

is required. A thermocouple readout instrument is also provided in the

control panel for monitoring temperatures in the recombiner.

The recombiner units are located in the containment such that they process a

flow of containment air containing hydrogen at a concentration that is typical

of the average concentration throughout containment. The recombiners will be

started manually after a LOCA. They are capable of continually processing a

minimum of 100 SCFM of containment air per unit. The hydrogen and oxygen in

the processed atmosphere are converted to steam, thus reducing the overall

containment hydrogen concentration. 4- 1

The other type of thermal recombiner is designed for employment outside containment (see Figures 4-48 and 4-49). This device is very similar to that

previously described; it has only a few variations. The process gas is drawn

from the containment building, into and through the recombiner system, and

back to containment by either a positive displacement blower or regenerative

blower directly driven by an induction motor. The flow rate of the containment gas through the system is measured by a flow tube. In addition to the

heater, reaction chamber, and cooler sections employed in the inside-containment type, this recombiner also uses a "trickle heater." During periods of

non-operation, it is possible for moisture to accumulate in the gas containing

piping. To preclude this, and thereby inhibit corrosion, an auxiliary heater

control system trickle heater is provided. The heaters operate continuously

to maintain heated-section temperatures at about 150OF (66 0C).

All instrumentation and control equipment is, of course, located outside containment. An adjustable timer provides for a low-alarm cutout during startup. Interlocks are provided to turn off the heater if the heater or reaction

gas temperature exceeds the normal control range. A low-flow blower and

heater cutoff, that receives its signal from the gas flow meter, completes the

safety instrumentation for the system. 4- 1

One of the concerns about the use of external thermal hydrogen recombiners is

that hydrogen control penetrations should be dedicated solely to this

purpose. For example, TMI-2 had provisions for post-accident installation and

operation of an external hydrogen recombiner for combustible gas control.

However, the design of the external recombiner hookup at TMI-2 used the

4-102
RETURN

SUCTIONO

Figure 4-48. Thermal Recombiner Package

4-103
I

0

ELECTRIC

CIRCULATING BLOWER HEATER

Figure 4-49. Schematic Representation of the Outside-Containment

Thermal Recombiner
36-inch containment penetrations for the normal Containment Purge System by

tapping 4-inch lines off the purge lines outside the containment building

between the building and outer containment isolation valves. Operation of the

hydrogen recombiners required opening of the inboard 36-inch containment

isolation valve in both a Containment Purge System inlet and outlet line.

With this design, once the hydrogen recombiner is put into operation, containment integrity is vulnerable to a single active failure. Thus, a spurious or

inadvertent opening of one of the 36-inch outboard containment isolation

valves would result in venting the containment to the environment.

As a result, a proposed amendment to IOCFR50 was prepared. 4 - 5 The purpose

of this amendment is to provide assurance that facilities with hookups for

external recombiners or post-accident purge systems that are susceptible to

single failures make design modifications to correct this situation. Systems

designed to meet these proposed requirements would not provide through-line

leakage paths between the containment atmosphere and the environment and would

eliminate the possibility of violating containment integrity through a single

active failure during hydrogen recombiner or purge system operation.

4.9.1.2 Capabilities. Hydrogen recombiners can, in general, be used from the

onset. of an accident in which severe core damage has resulted. Although they

are considered capable of handling the hydrogen resulting from a DBA-LOCA,

they appear to be ineffective for significant hydrogen generation rates. A

typical recombiner, for example, has a capacity of 100 SCFM4- 3 9 . To deal

with a 75 percent metal-water reaction, as proposed for lOCFR5O, an inordinate

number of recombiners would be required.

4.9.1.3 Positive and Negative Aspects. Tables 4-7 through 4-9 present the

positive and negative aspects of the various types of flame recombiners, thermal recombiners, and catalytic recombiners.

TABLE 4-7

FLAME RECOMBINER

Positive Negative

o There is a minimal pressure

rise in containment in conjunction

with its use

o The technology is developed

o Inadvertent actuation will

not present hazards

o It cannot control a large-scale

generation of hydrogen. (Each

recombiner is of limited

capacity.)

o Use is limited to containment

atmospheres not within the

flammability limits

(<4% H2 or <5% 02).

o Flame recombiners are difficult

to start.

o It requires supplemental hydrogen

and oxygen supplies for reliable

ignition and flame control.

4-105
TABLE 4-7 (Cont.)

FLAME RECOMBINER

Positive Negative

o It could be an ignition source for

a flammable mixture in containment.

o The necessity to use many of these

recombiners would lead to high

installation and maintenance costs.

TABLE 4-8

THERMAL RECOMBINER

Positive Negative

o -There is a minimal pressure

rise in containment in

conjunction with its use

o The technology is developed

o Inadvertent actuation would

not present hazards

o It cannot control a large-scale

generation of hydrogen. (Each

recombiner is of limited

capacity.)

o Use is limited to containment

atmospheres not within the

flammability limits

o It could be an ignition source for

a flammable mixture in containment.

o The necessity to use many of these

recombiners would lead to high

installation and maintenance costs.

4-106
TABLE 4-9

CATALYTIC RECOMBINER

Positive Negative

o Minimal pressure rise in o It is susceptible to catalytic

conjunction with use. poisoning from methyl iodide

o Inadvertent actuation would not (CH3 1).

pose hazards. o Cost is high.

o It cannot control a large-scale

generation of hydrogen.

o It could provide an ignition source

for flammable mixtures in containment.

o Use is limited to containment

atmospheres not within the flammability limits (<4% H2 or < 5%

02).

4.9.2 Deliberate Ignition of Hydrogen

4.9.2.1 Method. Another method of controlling liberated hydrogen within LWR

containments is deliberate ignition. The philosophy behind this type of mitigation scheme is very simple: keep the hydrogen concentration below levels

that would challenge the integrity of the containment. At the present time,

however, this method has only limited application. The only plants that currently employ deliberate ignition are three PWRs with ice condenser containments and one BWR with a Mark III containment; another is planning to use

deliberate ignition.

A typical Mark III BWR containment contains approximately 1.5 million cubic

feet of free air volume. If one assumes a metal-water reaction similar to the

one believed to have occurred at TMI-2, the resultant deflagration (or possible detonation) in a containment of this volume might challenge the containment integrity. Since the PWR ice condenser containment free air volume and

design pressure (about 15 psig) are similar to those of the Mark III containment, the same type of concern exists for it. Hence, for these containment

designs, the deliberate ignition concept has become an attractive scheme to

mitigate the consequences of possible metal-water reactions that could take

place during a LOCA.

4-107
One reason for the limited applicability of deliberate ignition is that in

most PWRs incorporating large dry containments it has been calculated that the

containment hydrogen concentration following a degraded core accident probably

would not threaten containment integrity (the issue of equipment survivability

for these plants is not yet resolved). For BWR Mark I and II primary containments, the volume is so small that the hydrogen problem can be readily handled

by inerting the entire drywell atmosphere with nitrogen during operation.

BWRs with Mark III containments have substantially larger drywells and, in

addition, have communication between the suppression pool and the outer containment (reactor building). This design has the distinct advantage of having

a much greater volume for steam expansion and gas dilution during a LOCA.

Those PWRs that employ ice condensers for pressure suppression in containment

are unique in that they have significantly smaller containments than other

PWRS. If a degraded-core condition (in which a major portion of the fuel

cladding reacted with steam) was reached at one of these facilities, containment integrity could be challenged if no mitigation systems were employed.

•--The volume of the ice condenser containment may not be sufficient to contain

the resultant deflagration (or detonation). Deliberate ignition is a method - that has been chosen for plants of this type. Most PWRs do not utilize deliberate ignition because their extremely large volumes (relative to the amount

of zirconium in the core) are probably sufficient to keep the hydrogen concentration below values that would challenge containment integrity. Note that

most large dry PWR containments may have a sufficient volume to handle the

hydrogen production from the oxidation of 100% of the zirconium in the core.

Large dry PWRs may have a problem if there were a high baseline pressure due

to steam before a burn. This might occur in accidents where the containment

cooling systems have failed. If it should become necessary to provide an

extra margin of safety, these containments could be retrofitted with additional systems for hydrogen control. In such a case, deliberate ignition

might be a likely candidate for use in non-ice condenser PWR containments.

Figures 4-3 and 4-5 showed simplified representations of containments in which

deliberate ignition is employed.

Although deliberate ignition is used in different types of containments, the

philosophy of operation of the system is always the same. The most important

consideration when developing a deliberate ignition scheme is to plan the

burns in such a way that the resultant pressure will not approach the failure

pressure of the containment.

Igniters should not be placed next to key safety equipment such as power supplies or electrical cable trays. In addition, they may not be as effective

when placed below solid ceilings because they may not ignite a significant

quantity of gas until the downward propagation limit of 9% hydrogen concentration is reached, as discussed in Chapter 2. A conservative estimate of pressure rises from a hydrogen deflagration can be made by assuming an adiabatic

(no heat transfer) and isochoric (constant volume) process. Refer back to

Figs. 2-10 to 2-13 for such estimates of possible pressure rises.

4-108
Notice that significantly different overpressure values could be obtained

depending on the completeness of the burn. Hydrogen burns in LWRs can be

incomplete, with the degree of combustion efficiency dependent on many factors, such as containment size and strength of ignition source. Burns arelikely to be nearly complete for hydrogen concentrations above 8%, while below

about 8% the glowplug igniters become less reliable. Note, however, that

there may be the possibility of higher hydrogen concentrations if the containment is temporarily steam inerted.

In ice condenser containments, the upper and lower compartments are separated

by paths running through the ice condensers and recirculation fans. Hydrogen

burns in the upper and lower compartments have significantly different characteristics. Burns occurring in the lower compartment can expand into the upper

compartment and, in the process, transfer large quantities of heat by cooling

and condensation in the ice condensers. This, in addition to the large volume

available for expansion in the upper compartment, greatly reduces the pressure

and temperature rises associated with the burns. For ignitions in the upper

compartment, however, pressure and temperature reductions result only from

heat transfer to the walls (and cooling sprays, if they have been preactivated) and minimal expansion through the recirculation fans. Hence, the

assumptions of adiabatic and isochoric combustion yield results that should be

fairly accurate for fast global burns in the upper compartment and overly conservative for burns in the lower compartment. It is therefore preferable to

initiate deliberate ignitions in the lower compartment of PWR ice condenser

containments.*

Referring again to Figs. 2-10 to 2-13, it can be seen that the failure pressure of an ice condenser containment (about 45 psig for Sequoyah) is reached

with about an 8% hydrogen concentration in containment -- assuming that deliberate ignition is the sole mitigation scheme. If the generation and release

of hydrogen is slow enough, the hydrogen can be consumed gradually in multiple

burns, with interim cooling of the atmosphere by heat transfer and water

sprays, thus preventing a continuous buildup of pressure. Deliberate ignition

is a mitigation scheme that is limited in the amount of hydrogen it can control for a single ignition, and limited in the rate of hydrogen it can control

for multiple ignitions with interim cooling. 4-7

Devices that have been considered for use as igniters are spark plugs and glow

plugs. These are both weak igniters and have been found to cause incomplete

combustion in large chambers at low hydrogen concentrations. Pyro-fuses could

also be used, but since they are usually intended for one-time use they are

considered impractical. One concern that has been expressed about the use of

spark plugs is the possible radio frequency interference caused by the

sparks. For this reason, glow plugs seem to be the most popular type of igniter at present. The glow plugs employed at Grand Gulf are the General Motors

AC Division model 7G plugs. 4- 1 4 Sequoyah is planning to install comparable

devices manufactured by Tayco.

* This statement may not be true if the possibility exists for flame

acceleration and deflagration-to-detonation transition in the ice condenser.

4-109
Igniters may be actuated manually or automatically, and are distributed

throughout the containment in such a way that uniform combustion can be

achieved. This is done to prevent the formation of isolated pockets with

excessive concentrations of hydrogen. It can be seen that the location of the

igniters is critical to the proper operation of the system. At present,

several igniters are planned for the region around the periphery of the containment at the top of the ice condensers. It is postulated that under certain accident conditions, the lower compartment would be inerted either by

high concentrations of steam, or by low concentration of oxygen. The inerted

gas mixture would enter the bottom of the ice condensers and emerge as an

extremely rich mixture at the top. Hydrogen concentrations is this area could

possibly exceed detonable limits, making it possibly a less than ideal location for the placement of igniters. The current state of knowledge does not

allow us to say with any certainty whether or not detonations are possible in

these geometries. Sandia recommended that these igniters be relocated higher

in the upper compartment where hydrogen concentrations will be much lower than

at the outlet of the ice condensers. 4- 7 Some consultants, however, feel

that the current placement of igniters is desirable and safe. This disagreement might arise for igniters placed at the top of the suppression pool in a

BWR.

•----In summary, deliberate ignition can be an effective method of hydrogen control

if the hydrogen can be consumed slowly enough so that neither containment

integrity nor equipment survival is jeopardized. As we mentioned, this can be

accomplished in several ways: by burning lean mixtures; by burning in the

lower compartment (in a PWR ice condenser containment); and by burning infrequently enough to prevent pressure and temperature buildup.4-7 Deliberate

hydrogen burns would occur at low enough concentrations to maintain the hydrogen below its detonable limit and to prevent containment overpressure failure./ The potential for significant pocketing of hydrogen would be reduced by:

o Utilization of distributed ignition sources

o Simultaneous operation of containment sprays

o Mixing caused by turbulence resulting from localized burns

o Use of air handling fans

Ignition may be initiated by manual control of glow plugs from the control

room. (Glow plugs are presently preferred over spark plugs as the source of

ignition.) The number and placement of the glow plugs are dependent upon the

type of containment.

4.9.2.2 Grand Gulf Nuclear Station. The Grand Gulf Nuclear Station is a

BWR-6 employing a Mark III containment. It has a Combustible Gas Control System comprised of two 100%-capacity hydrogen recombiners (based on the

DBA-LOCA), a drywell purge subsystem, and a backup containment purge subsystem; this system provides the capability to control the hydrogen that may

be generated from a DBA. This system fully meets the current requirements in

the Code of Federal Regulations for combustible gas control. However, as a

result of the TMI-2 incident, the NRC requested (on October 30, 1980) a description of a program to improve the hydrogen control capability of Grand

Gulf. A Hydrogen Ignition System was chosen as the best method of complying

4-110
with the NRC request. The following discussion concerns this system. 4 - 1 4 ,4- 6 1

In the event of a severe LOCA resulting in a large generation of hydrogen,

hydrogen can be released directly to the BWR containment atmosphere via the

safety/relief valves that exhaust to the suppression pool. Therefore, igniter assemblies are located in a ring above the suppression pool as well as at

other locations throughout the containment. Hydrogen can also be released

directly to the drywell atmosphere via a pipe break in the drywell. Therefore, igniter assemblies will also be located through the drywell.

The Grand Gulf HIS design calls for 90 igniter assemblies located in the drywell and containment, and the use of containment sprays to ease pressure and

temperature build-up. No igniters are located between elevations 208 ft-10 in

and 262 ft-10 in because of an absence of adequate support members. This configuration should not negatively affect the functioning of the HIS for the

following reasons:

o No major structures exist in this region that would promote the

formation of hydrogen pockets. (For example, the polar crane is not

large enough to allow hydrogen to pocket.)

o The turbulence resulting from localized burns at other elevations and

the operation of the containment sprays will promote the movement of

any hydrogen in this area to areas supplied with igniters. 4- 1 4

The igniters are powered from Class bE power panels that have normal and

alternate ac power supply from offsite sources. In the event of a loss of

offsite power the igniters would be powered from the emergency diesel generators. In addition, the HIS is designed as a seismic Category I system.

The igniter assemblies will be located in all areas of the containment and

drywell so that:

o Assuming only one engineered safety feature (ESF) power distribution

panel is funtional following an accident, a maximum distance of 60

feet will exist between operable igniters.

o Assuming both ESF power distribution panels are functional following

an accident, a maximum distance of 30 feet will exist between operable igniters.

In addition, for enclosed areas inside containment, two igniter assemblies

will be located in each area, with each igniter fed from a separate ESF power

distribution panel.

The igniter assemblies will be designed to include the following:

o A welded metallic enclosure that partially encloses the igniter and

contains the transformer and associated electrical wiring

o Provisions for access to the interior of the enclosure

o A spray shield to protect the igniter from containment spray

o A copper heat shield, if required, to protect assembly components

from high temperatures

4-111
O An igniter capable of maintaining a 1700OF surface temperature for a

minimum of one week

o A transformer capable of stepping down 120 volts AC power to the

voltage necessary to achieve a minimum igniter operating temperature

of 1700 0 F.

AS mentioned before, the HIS is manually initiated from the control room.

Instrumentation for the HIS consists of two control room handswitches, one for

each of the two Class IE power division. Each handswitch energizes the igniters in its respective division.

4.9.2.3 Sequoyah Nuclear Plant. The Sequoyah Nuclear Plant is a PWR ice condenser containment facility that has proposed thermal igniters for its Permanent Hydrogen Mitigation System (PHMS). 4- 59 ,4- 6 2 The Sequoyah PHMS is

designed to operate without the use of containment sprays and fogs, in contrast to the Grand Gulf HIS, which is designed to be used in conjunction with

containment sprays.

The basic design at Sequoyah includes a total of 64 igniter assemblies in two

trains distributed throughout containment, with at least one pair of redundant

igniter assemblies in each region. The following system description is

excerpted from two reports on the Sequoya Nuclear Plant:4-59,4-62

Following a degraded core accident, any hydrogen which is produced would

be released from a break or the pressurizer relief tank into the containment in the lower compartment inside the crane wall. To cover this

source region, there will be 22 igniters (equally divided between trains)

located high in the lower compartment inside the crane wall. Eight of the

igniters will be equally distributed around the interior of the crane wall

between ice condenser inlet doors. . . Two igniters will be located at the

lower edge of each of the five steam generator and pressurizer enclosures. . . A pair of igniters will be located in the top of the pressurizer enclosure. . . Another pair of igniters will be placed above the

reactor vessel in the upper reactor cavity. . .Since there are no potential hydrogen sources in the steam generator enclosures and significant

flows into these enclosures are not expected from the rest of the lower

compartment, igniters will not be located in the top of these enclosures.

Any hydrogen not burned in the lower compartment would be carried up

through the ice condenser and into its upper plenum. Because steam would

be removed from the mixture as it passes through the ice bed, thus concentrating the hydrogen, mixtures that were nonflammable in the lower compartment would tend to become flammable in the ice condenser upper

plenum. Controlled burning in the upper plenum is preferable because

upper plenum burns involve smaller quantities of hydrogen and allow for

the expansion of the hot gases into the upper compartment, thereby reducing the peak pressure.

TVA has chosen to take advantage of the beneficial characteristics of combustion in the upper plenum by distributing 16 igniters around it. The

igniters are located on the containment shell side of the upper plenum at

16 equally spaced azimuthal locations. To handle any accumulation of

4-112
hydrogen in the upper compartment, four igniters will be located in the

upper compartment dome. Additional igniters are located at lower elevations in the upper compartment to take advantage of upward flame propogation at lower hydrogen concentrations; specifically, four igniters are

located near the top and inside the crane wall, and one is located above

each of the two air return fans. The air return fans provide recirculation flow from the upper compartment through the dead-ended volume and

back into the lower compartment. To cover the dead-ended region, there

will be a pair of igniters in each of the eight rooms through which the

recirculation flow passes.

In order to prevent system breakdown, components of a deliberate hydrogen

ignition system, whether in a BWR or PWR facility, should:

maintain their functional capability under the full range of main steam

line break and post-LOCA temperatures, pressures, humidity, radiation, and

chemical sprays present in the containment. These components of the system must survive the effects of multiple hydrogen burns and must be protected from containment spray impingement and flooding. All components of

the system outside containment must be qualified to operate in the

environment in which they are located. 4 - 5 9

The impact on operations of a thermal igniter system would be minimal.

The system poses no threat to personnel since it is not required during

normal operation and would normally be deenergized. Inadvertent actuation

of the system during any phase of plant operation presents no threat to

personnel or equipment. This would prevent reluctance by the operator to

activate the system and would enable him to activate it at a point in the

accident before hydrogen could be released to the containment. The relatively short warmup time for the thermal igniters following activation

would contribute to the high likelihood of their availability.4- 59

The cost of design and hardware should be moderate for a thermal igniter

system since the technology is proven and does not need extensive development. Installation costs should not be excessive if the work is performed

during a refueling outage instead of during a special forced outage. 4 - 5 9

4.9.2.4 Capabilities. The glowplug hydrogen igniter system is promising in

that it can burn hydrogen as it is produced from the onset of a severe accident in which significant core damage has occurred. It can be energized upon

receipt of an ECCS signal or some other suitable input (from hydrogen detectors, for example). Since the system would burn the hydrogen at or near the --

lower combustible limit, the formation of detonable concentrations of hydrogen

would, in all probability, be prevented. An added advantage of burning the

hydrogen in this manner is that the oxygen in the containment air is also

being consumed, thereby reducing the probability that a combustible mixture

exists as time progresses.

The glowplugs used in this system should be durable and reliable. Hence,

long-term use of these devices can be expected. Naturally, the deliberate

ignition system only lends itself to use for a non-inerted type of reactor

containment.

4-113
4.9.2.5 Positive and Negative Aspects. Table 4-10 outlines the positive and

negative aspects of the deliberate ignition system.

Table 4-10

DELIBERATE IGNITION

Positive XtA~~ve

o Deliberate ignition distributes

the energy addition to containment over a period of time, which

allows the pressure and temperature changes inside containment

to be less severe.

o It may control a large-scale

generation of hydrogen.

o The system is no threat to

personnel since it is not

required during normal

operation, and inadvertent

actuation would not present

a threat.

o It has a relatively short warmup

time.

o Maintenance would be minimal.

o The cost is moderate.

o The technology is already developed.

o Minimal space is required inside

containment.

o It may require additional

containment penetrations for

electrical connections.

o Each ignition will increase

containment pressure and

temperature.

o Burns may damage equipment in

containment.

4.9.3 Combination of Water Fog or Spray with Deliberate Ignition

4.9.3.1 Method . Deliberate ignition removes hydrogen through a series of

controlled burns. The effectiveness of deliberate ignition is limited

primarily by containment pressure considerations. The frequency at which

burns can be tolerated is limited by the rate at which the containment

atmosphere cools. Water fogs or sprays can serve as a pressure and temperatre suppressant. This method involves the supension of a large mass of

liquid water, in the form of droplets, in the containment atmosphere. The

drops act as a large thermal capacitance, greatly reducing the temperature

rise that otherwise would occur as a result of hydrogen combustion or steam

release from the reactor vessel. For these reasons, there may be advantages

to using deliberate ignition and water fogging together. Figures 2-28 and

2-29 and Table 4-11 show how the addition of a fog increases the hydrogen

concentration required to attain given pressures. The values in Table 4-11

were calculated for the Sequoyah Nuclear Plant and are for a 0.05% water

concentration. Although this concentration is difficult to achieve, the

values indicate the general trend of increased hydrogen concentration

necessary to produce a given pressure.

4-114
Table 4-11

HYDROGEN CONCENTRATION REQUIRED TO ATTAIN GIVEN PRESSURES

Pressure Complete Incomplete 0.05% Water

31 5.5 6-9 13.5

45 8.2 8-9 15.7

In order for fogging to reduce the pressure and temperature from a hydrogen

burn effectively, the kinetics of drop vaporization must be taken into

account. There are three major characteristics of a fog that must be considered.. The first, and most important, is water content. The use of any

fog, regardless of water content, is beneficial. However, as shown in Chapter

2, water densities between 0.01 and 0.05 volume percent are needed to produce

significant reductions in the pressure and temperature. In most cases,

especially when considering loss rate, water content is the most critical

parameter of the fog.

The second characteristic is droplet size. In order for a fog to perform correctly in the presence of hydrogen combustion, it must be produced and maintained with the droplets of optimum size -- a size that is bounded both above

and below. If the droplets are too large, they will not vaporize fast enough,

and an initial pressure overshot could occur before equilibrium is achieved as

the droplets vaporize. The overshoot could last long enough to increase the

static load on the containment structure. If the droplets are too small, they

vaporize i~nside the flame front, thereby inhibiting, or even quenching, the

flame. A droplet size (radius) typical of containment spray systems is about

200-300 microns; it is estimated that the optimum droplet size for an effective water fogging system is in the neighborhood of 10-200 microns. Small

droplets also tend to remain supended in the containment atmosphere longer

than larger drops. The production of fog with an appropriate droplet size is

technically possible and can be accomplised with air blast nozzles. With

these, a very low pressure drop is developed across the spray nozzles, resulting in a high resistance to clogging. The atomization is accomplished by a

high speed, compressed air jet.

The final characteristic, and one that is closely related to droplet size and

density, is droplet spacing. Close spacing may quench the flame while droplets placed farther apart may not provide adequate thermal capacitance.

Proper droplet sizing will automatically eliminate the problem of spacing for

the densities of interest. If the fog is made such that the great majority of

droplets are larger than 5 microns, it is not expected that droplet vaporization or droplet spacing will significantly affect the flame structure; hence

they should not influence flammability limits.

Although the high-volume production of small water drops is possible, maintaining a stable, high-density fog could be extremely difficult if there are

4-115
very large settling losses. Estimates of loss rates vary over a considerable

range of values. Large estimates of loss rates may require such high injection rates that water fogging would be impractical. For this reason, iý is

necessary to determine expected loss rates more accurately. This will inv ve

studying the mechanisms of droplet interaction in greater detail. OV

A rigorous discussion of droplet interaction mechanisms is beyond the scope of

this manual. However, there is one particular phenomenon that is extremely

important and that is the critical factor in determining the loss rate. This

phenomenon is know as gravitational coagulation. It results from the fact

that nozzles do not produce monodispersed (single droplet size) sprays, but

polydispersed sprays covering a range of drop sizes. As the fog settles,

larger drops (with higher terminal velocities) will overtake, collide with,

and coalesce with smaller ones. This process increases the mean droplet size

and, therefore, the rate of water loss, as well as the injection rate required

to maintain a particular water concentration. Several variables have been

tested to determine their effect on water loss, including: injection rate,

log-standard deviation of drop size, drop spacing, and drop size. Although

optimum values were found for these variables, it was determined that, when

considering coagulation, none of them greatly affected the water content

beyond an initial transient. Coagulation clearly dominated the dynamic behavior of the fog.

In addition to its capability for limiting pressure and temperature rises, it

has been suggested that suspended water (from either sprays or fogs) can also

suppress detonation and shock waves. The droplets act to dissipate energy

from these waves, both by mechanical action of the droplet drag and by the

thermal action of evaporation in cooling the gas. Again, however, there is

considerable lack of knowledge on the subject.

A combination of fogging and ignition appears to be very attractive with few

potential problems other than those experienced by conventional spray systems. The economics of such a system have not been adequately evaluated.

Inadvertent operation of a spray or fog system may affect electrical equipment; however, safety systems are expected to operate in the presence of

sprays. 4- 3 9 , 4-59 Another possible undesirable consequence of inadvertent

operation of the fogging system would be containment depressurization.

Although analysis of the effect of this negative pressure is still required,

it is expected that it can be avoided through pressure relief modification.

The presence of a fog should not interfere with operation of the igniters. If

the droplets are of the proper size, they will not alter the flame structure

or the flammability limits. A fog may also provide the added advantage of

creating turbulence that may enhance the effectiveness of the igniters (it

would increase flame speed).4-59 (Increasing the flame speed could also

have a negative effect since there would be less time for heat transfer to

occur.) Since a fogging system would provide all of the protection now provided by spray systems, it could serve as a complete replacement for the current system. However, if it is determined that simultaneous operation of

sprays and fogs is required, the integrated effects should be analyzed. Computer calculations by Sandia National Laboratories have shown that, although

the spray does not significantly alter the water content, it does have a

stabilizing effect on the overall fog density. 4 -7

4-116
The combination fogging/ignition system should be appropriate for use in any

plant that presently employs deliberate ignition alone. However, different

concerns do exist for different types of containments. Ice condenser and Mark

III containments are substantially smaller that those of large dry PWRs, but

have a similar or greater potential for hydrogen production. Therefore, ice

condenser and Mark III containments are much more susceptible to overpressure.

The other type of containment requiring special consideration is that which is

operated at subatmospheric pressure. The effects of negative pressure due to

inadvertent operation are of particular importance here, and require substantial investigation. Operation of the fogging system in place of, or in conjunction with, the Containment Depressurization System (CSD) is also of importance. The CDS consists of quench spray and recirculation spray subsystems.

These subsystems are used after a LOCA of main steam line break (MSLB) to

remove heat from the containment structure and restore a negative pressure.

The interaction of these subsystems with water fogs, or their replacement by

it, must also be studied in much greater detail.

In summary, the utilization of water fogging in conjunction with deliberate

ignition is potentially an extremely useful hydrogen mitigation scheme. If it

is found to be feasible, it will allow the combustion of relatively high concentrations of hydrogen at a fairly rapid rate with no challenge to containment integrity.

Production of an adequate water fog appears possible; however, maintaining

sufficient water content in the fog could be extremely difficult. Further

investigation is being conducted to determine the actual rate of water loss

that can be expected and the effects of electrically-charged droplets. The

feasibility of using water fogging as a means of protecting containment integrity is dependent upon the results of these investigations. If loss rates are

found to be so high that the required injection rate cannot be reasonably

maintained, then fogging will have no useful application. If, however, loss

rates are found to be moderate enough to be made up by reasonable injection

rates, water fogging could be a valuable aid in ensuring containment integrity

during hydrogen combustion. 4 -7

4.9.3.2 Positive and Negative Aspects. Table 4-12 lists the positive and

negative aspects for deliberate ignition used in conjunction with a water fog.

Table 4-12

DELIBERATE IGNITION WITH A WATER FOG

Positive Negative

o Deliberate ignition distributes o It requires additional containthe energy addition to containment ment penetrations for electrical

over a period of time, which connections.

allows the pressure and tempera- o It is an active system requiring

ture changes inside containment power to pump water to maintain

to be gradual. the fog.

4-117
Positive Negative

o It will control a large-scale

generation of hydrogen.

o The system is not a threat to

personnel since it is not

required during normal operation,

and inadvertent actuation would

not present a threat.

o It has a relatively short warmup

time.

o Maintenance would be minimal.

o It will condense steam, reducing

containment steam pressure during

A LOCA.

o It may prevent detonations. This

issue is not yet resolved.

o It could effectively remove fission

products and aerosols from the

containment atmosphere.

o It will reduce the pressure and

temperature increase of the

combustion caused by deliberate

ignition alone.

o If the loss rate of drops is as

high as predicted by some

aerosol codes, then the water

rate required may be impractically high.

o The technology is not fully

developed.

o Burns may damage equipment in

containment.

4.9.4 Short-and Long-Term Venting Capabilities

4.9.4.1 M It is important to be able to provide paths for venting

hydrogen from both the RCS and the containment structure to prevent or control

hydrogen combustion. Facilities must provide fail-safe methods of venting

hydrogen from unwanted systems, and treatment or recycling procedures to

handle vented hydrogen. This section discusses venting capabilities of both a

short-term (removal of hydrogen from primary systems to a secondary holding

area before treatment) and long-term (venting of hydrogen to permanenent

treatment) nature. Short-term venting is discussed for high-point vents on

the reactor vessel, pressurizer, and pressurizer relief tank (PRT). Long-term

venting is discussed for the volume control tank, PRT, and Containment Purge

System for PWRs; and Containment Atmosphere Dilution (CAD) System for BWRs.

In addition, filtered venting is described. The high-point vents proposed for

PWRs by NUREG-0737 were discussed in detail earlier in this chapter. This

section will summarize the main characteristics of the Reactor Vessel Head

Vent System (RVHVS).

In the event a metal-water reaction occurs, there is a possibility that hydrogen could collect in the reactor vessel head. In a PWR a bubble could bind

the reactor coolant flow, prohibiting flow into the RCS hot leg. As a result

of the TMI accident, the NRC proposed that a Reactor Vessel Head Vent System

(RVHVS) be installed in PWR facilities; 4 - 1 2 BWRs, on the other hand, have

been built with a remote-manual reactor head vent system constant vent.

4-118
During operation of a BWR, there is a constant vent open at the top of the

reactor vessel head that taps into the main steam line. In this way, any

stagnant steam or noncondensables at the top of the reactor vessel are vented

to the main steam line. The noncondensables are then removed from the main

condenser and vented to the Off-Gas System. This RVHVS would be capable of

handling hydrogen generated by a cladding-steam reaction.

Presently there is no way to vent noncondensable gases from the reactor vessel

head of a PWR. A typical system to meet the NRC requirement that PWRs incorporate a RVHVS is shown in Figure 4-50. This system would allow noncondensables from both the reactor and pressurizer vessel heads to be vented to

either the PRT or containment. The system consists of two parallel flow

paths, with solenoid valves that fail closed. The system would be manually

operated from the control room.

A detailed system description was presented earlier in this chapter. The main

characteristics of the proposed PWR RVHVS are:

o It provides the operator with the ability to remove noncondensable

gases from the reactor vessel head through parallel flow paths,

vented to either the pressurizer relief tank or the containment

atmosphere.

o Solenoid-operated valves in the parallel flow paths are remotely

operated from the control room, fail closed, and are powered by

different vital power supplies.

o The new system attaches to the manual head vent, used during RCS

filling, which already exists on most PWRs.

o The system piping is sized and orifice-controlled so that a break

could not cause a significant loss of coolant.

It should be emphasized that the RVHVS is not designed to be used as the

primary means to mitigate an inadequate core cooling event. The RVHVS should

be used only to vent gases from the PWR reactor vessel head once the RCS has

stabilized and the situation has been diagnosed.

Once hydrogen has been vented to the PRT or to containment atmosphere, it must

be handled properly. The PRTI will vent to the waste disposal system, or to

the containment atmosphere through a rupture disc. Hydrogen in the containment atmosphere is handled by one of the mitigation techniques discussed

earlier in Chapter 2.

There is also the possibility of hydrogen build-up in the pressurizer of a PWR

system. The consequences of the presence of hydrogen and other noncondensable

gases in the pressurizer were discussed in Chapter 3. The pressurizer will

vent to the PRT, which will then vent noncondensables for long term treatment

in the waste processing system. If the pressurizer could not vent to the PRT

(e.g., due to the pipe break or stuck valve), relief valves venting to containment are also located on the pressurizer vessel head. Any hydrogen venting from the pressurizer would be short term because hydrogen cannot be

allowed to build up either in the PRT or in containment. If the PRT could not

vent to the waste processing system, short-term venting would occur through

the rupture disc on the PRT.

4-119
VENT

LC

LC

3/4 in

TO PRESSURIZER

RELIEF SYSTEM TO CONTAINMENT

7/32 in Orifice

LC

LO = LOCKED OPEN

LC = LOCKED CLOSED

S = SOLENOID-OPERATED

P1 = PRESSURE INDICATOR

EXISTING

VESSEL HEAD

VENT

LO

3/4 in

Flanged Spoolpiece

from Vessel Head

to Cavity Wall

All piping from orifices to PRT return line

are 1 in. Bypasses around the orifices, vent,

and drain lines are 3/4 in.

RUPTURE DISC REACTOR VESSEL

Figure 4-50. Reactor Coolant System Gas Vent (PWR)

4-120
In the volume control tank (VCT) of the Chemical and Volume Control System

(CVCS) of a PWR, a small amount of hydrogen is dissolved in the coolant to

control the radiolytic decomposition of water. If there is a hydrogen buildup

in the VCT, as detected by the sampling system, the gas can be vented to the

waste processing system for long-term treatment.

The purpose of long-term treatment of the containment atmosphere is to remove

hydrogen before it reaches a flammable level. Two ways available to perform

this in a PWR are controlled recombination with oxygen in a recombiner (discussed in Chapter 3), and containment purge. The Containment Purge System* is

used periodically. It operates by exhausting contaminated air out of contain--

ment through a filtered venting system that exhausts to the atmosphere. Containment pressure is kept below atmospheric pressure to prevent leakage of

contaminated air to the environment. If the containment pressure rises to a

preset level, the purge system will actuate and remove air from containment

until the pressure is reduced. The major problem associated with containment

purge is the large volume of air inside the containment structure. A typical

PWR containment volume is about 2 x 106 ft 3 . This much air requires very

large air handling units. It should be emphasized that a containment cannot--

be vented quickly enough to mitigate a hydrogen burn.

In a Mark I or II BWR facility, the post-LOCA atmosphere is controlled

manually by the CAD System. This system utilizes nitrogen inerting to keep

oxygen concentration below five volume percent (hydrogen is not combustible in

mixtures containing less than five volume percent oxygen). The system is

redundantly piped to both the drywell and suppression pool. Effluent gases

from the drywell or suppression pool are treated by the Stand-by Gas Treatment

System (SBGTS). Vented gases from the SBGTS are safely released to the atmosphere after decontamination.

Filtered venting of contaminated containment air to the atmosphere takes place

through several stages of filters. After passing through a prefilter that

takes out large particles, the contaminated air enters a HEPA (high efficiency

particulate air) filter. This filter removes all particles down to 0.3

microns (0.01 mils); 4- 5 5 the filtrate then passes to an activated charcoal

absorption filter. This filter is cooled to prevent spontaneous combustion of

the charcoal. The exhaust gases then pass through another HEPA filter (to

remove charcoal particles), before being mixed with outside air and exhausted

to the atmosphere.

With the exception of PWR reactor vessel head vents, systems in containment

are provided with adequate hydrogen-venting capabilities. As a result of the

TMI-2 incident, the NRC has recently required that a RVHVS be designed and

fitted to PWRs. Once hydrogen has been vented out of the RCS, or other areas,

it receives long-term treatment for eventual release to the atmosphere by the

Containment Purge System and filtered venting in PWRs, or by the CAD System

and filtered venting in BWRs. These venting procedures, along with the mitigation schemes discussed earlier, provide adequate hydrogen control even for

severe conditions.

*Different systems are present in different plants, and also the terminology

varies.

4-121
4.9.4.2 Venting Times and Capabilities. In general, venting is not performed

immediately at the onset of an accident: It tends to be performed only after

the size of the noncondensable gas void in the reactor vessel or RCS has been

determined.4-39

Further, the degree or amount of venting to containment is predicated upon the

other systems that are available to deal with hydrogen once it is released to

the containment. Although, theoretically, venting can be used over the long

term, in order to do this, the hydrogen either must be burned or removed from

the containment volume if it reaches or exceeds the flammability limit of

about 4.1%.

4.9.4.3 Positive and Negative Aspects. Table 4-13 lists the positive and

negative aspects of purging or venting.

Table 4-13

PURGING OR VENTING

Positive Negative

o It does not generally require o It cannot control a large-scale

additional equipment or systems. generation of hydrogen.

o It cannot control a large pressure

rise.

o Possible increased fission product

release

4.9.5 Halon Combustion Suppressant System

4.9.5.1 Halon as a Flame-Quenching Agent. Another method of controlling

liberated hydrogen that has received considerable attention is Halon inerting. Halon is a general term used to idenLtfy any of several halogenated

hydrocarbons comprising a group of gaseous fire-extinguishing agents. Among

these, Halon 1301 (Bromotrifluoromethane, CF3Br) exhibits good flame

quenching capabilities. Currently, Halon 1301 is the most popular halon in

this country for total space flooding systems, including possible systems for

use in containments. The physical properties of Halon 1301 are listed in

Table 4-14.4-56

Table 4-14

PHYSICAL PROPERTIES OF HALON 1301 (BROMOTRIFLUOROMETHANE) 4 - 5 4

Chemical Formula CF 3 Br

Molecular Weight 149

Boiling Point -720F

Freezing Point -270°F

Critical Temperature 152.60F

Critical Pressure 575 psia

4-122
Critical Density

Heat of Vaporization

Surface Tension of Liquid

Density: Liquid

Saturated Vapor

Heat Capacity

Vapor Pressure

Thermal Conductivity

Solubility in Water

46.5 lbs/ft 3

35.5 Btu/lb @ 70 0 F

9.7 dynes/cm @ 0°F

4.5 dynes/cm @ 70OF

82.2 lbs/ft 3 @ 120°F

98.0 lbs/ft 3 @ 70°F

16.2 lbs/ft 3 @ 120°F

7.4 lbs/ft 3 @ 70°F

0.257 Btu/lb-°F @ 120°F

0.205 Btu/lb-°F @ 70°F

0.176 Btu/lb-°F @ 0°F

400.4 psia @ 120OF

213.7 psia @ 70°F

71.2 psia @ 0°F

0.025 Btu ft/hb-F-ft 2 @ 70OF

100 ppm at 15 psia and 120°F

300 ppm at 15 psia and 70°F

The extinguishing mechanism of the halogenated agents is not clearly understood. However, it undoubtedly involves a chemical reaction that interferes

with the combustion process. Halon 1301 acts by removing the active chemical

species involved in the flame chain reactions (a process known as "chain

breaking"). While all the halogens are active in this way, bromine, which is

contained in Halon 1301, is much more effective than either chlorine or

fluorine.4-57

A number of possible mechanisms by which bromine inhibits combustion have been

proposed. Many research endeavors seem to indicate that in the heat of a

fire, the halogenated hydrocarbons decompose with ease into free radicals of

the particular halogen involved, and that these free radicals, through a

counterattack of their own, eliminate hydroxyl free radicals as follows:

o Bromotrifluoromethane (Halon 1301) will break down to give up a

bromine atom:

0

CF 3Br + Heat -- CF 3 + Br 0

o The Br atom can then react with an organic molecule, e.g.:

CH 4 + Br -- CH 3 + HBr

o One possible mechanism for this operation assumes the removal of H

atoms and the formulation of H2 molecules as follows:

H + HBr o. H 2 + Br

o Another proposed mechanism involves a reaction with OH radicals:

OH + HBr -P Br + H2 0

4-123
o In this way, chain carriers are removed from the system while the

inhibiting HBr is continuously generated. The net results of this

process might typically be:

CH4 + OH-- CH3 + H2 0

In the above process, it is postulated that the halogen first dehydrogenates

methane (CH4 ) (as an example), forming a free CH3 radical (that will be

further attacked by more bromine) and hydrobromic acid (HBr). The acid reacts

with the hydroxyl free radical forming water and releasing bromine for further

use in dehydrogenating CH4 , CH3 , CH2 , and CH groups. A true counterattack is launched at the "heart" of the flame, resulting in its rapid extinguishment.

A key feature of Halon, then, is that it acts by chemically interrupting the

combustion process, whereas regular inerting materials (such as nitrogen and

carbon dioxide) work by simply diluting the oxygen concentration below the

flammable limits and by providing a thermal heat sink. 4 - 5 8 For this reason,

inerting can be achieved with significantly smaller amounts of Halon than of

other materials. The concept behind Halon suppressing is to chemically inert

the containment atmosphere at some time after a serious accident begins and

before significant quantities of hydrogen are generated. The Halon would be

stored in liquid form in several storage vessels near containment and discharged, either automatically or manually, into containment. Upon introduction into containment, the liquid Halon will depressurize and immediately turn

into a gas, thereby inerting the containment atmosphere and preventing any

hydrogen combustion. 4- 5 4 The properties of Halon have been studied extensively, and it has been determined that this type of system would provide full

safety; any concerns about the feasibility of the system involve economic

(i.e., system recovery after a LOCA), rather than safety, consequences.

4.9.5.2 Halon Post-LOCA Hydrogen Suppressant System. Many operational advantages are associated with the simplicity of the Halon 1301 system: It possesses few moving parts, minimal power requirements, high reliability, relative economy, storage convenience, ease of periodic testing, and, once activated, requires little further attention. A Halon injection system typically

will consist of several Halon tanks valved independently to two manifolds.

Each tank has an associated tank of nitrogen gas to keep the Halon highly

pressurized (600 psig). Inside the containment, the piping branches to the

upper and lower compartments where the Halon is introduced into the atmosphere

by an array of spray nozzles from each manifold pipe. To ensure that the

Halon is injected as a liquid, the pressure at the discharge nozzle should

exceed the vapor pressure (434 psig at 130 0 F). A simplified diagram of a

Halon injection system proposed for the Sequoyah Nuclear Power Plant is shown

in Figure 4-51.4-56

The storage vessel, piping, and valve configuration (Figure 4-52) are based on

the principle that the system must function properly even if three independent

malfunctions occur. In the event of a LOCA, the Halon system could be activated manually or automatically; the current requirement is for total delivery

within 1000 seconds. The hydrogen and Halon concentrations would be continuously monitored during the post-LOCA period.

4-124
LIQUIFIED HALON

1301 STORAGE

AND INJECTION

SYSTEM (ONE

OF FIVE STORAGE

VESSELS SHOWN;

LOCATION CAN

BE REMOTE)

AIR TEST

CONNECTOR

FOR HALON

NOZZLES

(ONE SHOWN)

Ul

NO = NORMALLY OPEN

P PRESSURE INDICATOR

R = RESTRICTIVE ORIFICE

S SOLENOID OPERATED

Figure 4-51. Conceptual Diagram of Halon 1301 POst-LOCA

Hydrogen Suppression System for Ice Condenser
Figure 4-52. Diagram of Valving and Piping for Five Halon

Storage Vessels

4-126
Despite all the positive aspects, there are some potential problems with the

proposed Halon injection system. The primary concern is with the corrosion

that could be caused in metallic containment components by prolonged exposure

to Halon at elevated temperatures without adequate control procedures. If

clean-up does not occur within a few months of a LOCA and no attempt is made

at corrosion control, the potential exists for many problems, including

general corrosion and stress corrosion cracking, as well as extensive crevice,

pitting, and galvanic corrosion. However, there are methods to lessen the

problem of corrosion. These include:

o Addition of bromides (e.g., NaBr, KBr, LiBr) to prevent Halon

decomposition, or the addition of hydroxide (e.g., NaOH, KOH, LiOH)

to increase pH. Either of these should mitigate general corrosion

and reduce the potential for stress corrosion cracking.

o Addition of inhibitors to prevent localized corrosion. Chromates,

nitrates, borates, silicates, and zinc have been shown to be effective.

o Addition of sacrificial zinc or magnesium that could potentially

eliminate both pH depression and localized corrosion problems.

Nonmetals are not expected to be significantly affected by the

presence of Halon. 4 - 5 6

Another problem of considerable magnitude is that Halon concentrations below

that required to inert the containment atmosphere could be detrimental. Very

low concentrations (2-4 volume percent) can actually decrease the minimum

ignition energy. Furthermore, if combustion occurs in the presence of noninerting quantities of Halon, the Halon will thermally decompose into very

corrosive halogens or halogen acids, which could adversely affect the plant

and safety systems. The pressure rise caused by the addition of Halon should

also be taken into account when analyzing a suppressant system. (For the

Sequoyah plant, it was estimated that inerting the atmosphere with Halon 1301

would increase the containment pressure about 9 psig. 4 - 7 )

In June of 1981, TVA issued a report concerning the selection of a permanent

hydrogen mitigation scheme for Sequoyah. This report considered several different systems, including Halon injection. It should be noted that TVA came

to less optimistic conclusions concerning the modes of corrosion mitigation

than did McHale (Ref. 4-56). In explaining why the Halon injection option was

rejected, the report states that uncertainty about the radiolytic decomposition of Halon and subsequent metal corrosion, uncertainty concerning suitable

post-accident water chemistry control, its toxicity at the concentrations

required, and difficulty in finding room for and Installing five Halon tanks

and their associated components made it impossible for TVA to resolve the

issue consistent with the January 31, 1982, license conditions. 4 - 5 4 Despite

the problems associated with Halon inerting, it is widely employed in industry

as a fire suppressant and its use in nuclear applications promises to become

more widespread.

4-127
4.9.5.3 Halon I ection T'mes a d a bilit s. Theoretically, Halon can be

introduced into the containment volume at any time. If it is mixed at a sufficient concentration in containment, it can be very effective in preventing

hydrogen deflagrations or detonations.* However, continual release of hydrogen and Halon into the containment will increase containment pressure. For

some containments, the design pressure can be reached (or exceeded) if the

hydrogen generated by a 75% zircaloy-steam reaction in the core were to be

released to the containment.

Over the long term, Halon seems to exhibit some additional negative qualities. These include:

o Extended exposure to Halon concentrations of about 20% may be

hazardous to humans.

o If Halon compounds are exposed to temperatures above 900 0 F, they

decompose to halogenic acids and carbonyl halides, which are

extremely toxic.

o Halon and its decomposition products are also very corrosive and

could cause potential degradation to safety systems.

4.9.5.4 e andNaiv Aects. Table 4-15 lists the positive and

negative aspects for a Halon suppressant system.

Table 4-15

HALON 1301 POST-INERTING

Positive

o The technology is developed,

including large-volume (10 6 ft 3 )

systems.

o Without decomposition, a

H :aig:Halon:steam mixture

should be stable for a long time.

o The system can be designed to be

electrically passive.

o Halon can be stored conveniently

as a pressurized liquid.

o It will control a large-scale

generation of hydrogen.

o Halon decomposition, and

subsequent metal corrosion, may

by avoided by the addition of

NaBr, KBr, or LiBr.

o If Halon were to decompose, it

would cause acidic corrosion,

severe stress corrosion, crevice

and galvanic corrosion, and

pitting

o Inadvertent actuation would be

hazardous to personnel in

containment, as well as expensive.

o Halon is expensive.

o The operator may be hesitant to

use the system because of hazard

and expense.

o Addition of Halon will increase

containment pressure.

o The Halon concentration must

remain above the required inert

*Reference 4-39 states that this concentration is about 20%. Sandia National

Laboratories personnel state that 28-30% is more accurate.

4-128
Positive Negative

o Mininal space is required in level

containment, could

o It co

PWR c

conta

amouni

requi

4.9.6 Post-Accident Inertint with Carbon Dioxide

at all times or else it

aid a combustion.

uld be impractical for large

ontainments and BWR Mark III

inments because of the large

t of system equipment

red.

4.9.6.1 Method. It is impossible for a gas, most notably carbon dioxide

(C0 2 ), to be injected into the post-accident containment atmosphere in sufficient quantities to inert against a potential hydrogen combustion. Such a

system would be very similar to the Halon post-inerting system previously described. Two primary differences, however, distinguish the systems. First,

carbon dioxide is noncorrosive, thus eliminating the need for the extensive

corrosion-inhibiting mechanisms necessary with Halon injection systems.

Second, because a carbon dioxide inerts by simply increasing the mixture heat

capacity (acting as a thermal sink) instead of by chemically preventing combustion, a much greater amount (on the order of 55%) of carbon dioxide is

required to inert the containment atmosphere. The addition of this greater

volume of gas would result in a higher containment pressure. This latter difference is the major drawback associated with the carbon dioxide post-inertlng

concept. Some people feel that other hydrogen mitigation methods can adequately control combustion without producing the excessive pressures that

would result from post-inerting with carbon dioxide. 4 - 5 4

4.9.6.2 Positive and Negative Aspects. Table 4-16 lists the positive and

negative aspects of post-accident inerting with carbon dioxide.

Table 4-16

CARBON DIOXIDE POST-INERTING

Positive Negative

o Carbon dioxide will not cause

corrosion.

o It will control a large-scale

generation of hydrogen.

o The technology is developed.

o Carbon dioxide can be conveniently

stored as a pressurized liquid.

o Minimal space is required in

containment.

o The amount of carbon dioxide

necessary to suppress combustion

may cause containment overpressure.

o Cost is an important consideration

o It is untried for the large PWR and

BWR Mark III containments.

o The operator may be reluctant to

use system.

4.9.7 Pre-Inerting, Partial Pre-Inerting, and Post-Accident Inerting with

Nitrogen

4.9.7.1 Methods. Pre-inerting is a hydrogen mitigation scheme that has been

employed in BWR containments since their inception. The concept is simply to

4-129
inert the containment atmosphere with nitrogen during operation, thereby

eliminating the possibility of hydrogen combustion following a LOCA. This

method of control is particularly suited for use in early-model (Mark I and

II) BWR containments because of their smaller volumes. PWRs and later generation BWRs have not used inerting for two main reasons: First, larger containments must be accessible during operation, and accessibility is facilitated by

having a breathable atmosphere in containment. Second, the containments are

so large that maintaining a nitrogen atmosphere during normal operation is

difficult and expensive. For these reasons, the pre-inerting of large containment structures has been considered impractical and thus, has not been

employed.

There is, however, a variation of this scheme that has been considered for use

in large containments. It involves the partial pre-inerting, with nitrogen,

of the containment atmosphere during operation to about 14-15% oxygen. The

normal oxygen content of air is about 21%, so this represents a gaseous mixture that is roughly 70% air and 30% added nitrogen. An atmosphere with this

composition is breathable and, therefore, would allow access to containment

during operation. It also possesses several other advantages. If partial

pre-inerting is used in a situation where post-inerting is also employed, it

provides a significant "head start" in case of an accident. The lower oxygen

concentration also promotes slower and weaker combustion of hydrogen, which

makes partial pre-inerting a likely candidate for use in conjunction with

deliberate ignition. Note, however, that partial preinerting has never been

employed, nor is it currently proposed for use in any reactor containment.

A nitrogen post-inerting system has not been proposed for use in any plant at

the time of this writing. It appears that the inert nitrogen gas injection

could cause a significant increase in contalnment pressure. Although this

technique is feasible, determining when the gas should be injected is a problem as it is with any post-inerting scheme.

4.9.7.2 Positive and Negative Aspects. Tables 4-17 through 4-19 list the

positive and negative aspects of nitrogen pre-inerting, partial pre-inerting,

and post-inerting, respectively.

Table 4-17

NITROGEN PRE-INERTING

Positive Negative

o It will control a large-scale o Is impractical for the large

generation of hydrogen. PWR and BWR Mark III containments.

o The technology is developed. o Maintenance in containment is

o Minimal space is required inside considerably more difficult if

containment, the containment is nitrogen

o Nitrogen can be conveniently inerted during normal operations.

stored as a pressurized liquid.

o Nitrogen will not cause corrosion.

4-130
Positive Negative

o Nitrogen inerting is already in

use in most BWR Mark I and II

containments.

Table 4-18

NITROGEN PARTIAL PRE-INERTING

Positive Negative

o The atmosphere would be

breathable, thus allowing

containment entry during

normal operation.

o It provides a "head start" on

hydrogen control if an accident

occurs.

o May be of use in conjunction

with deliberate ignition.

o May be of use in large containments.

o It has never been employed in

reactor plant containments,

therefore only theoretical

data are available.

o Requires additional system

to control or mitigate H2

combustion.

Table 4-19

NITROGEN POST-INERTING

Positive Negative

o Containment atmosphere would be

breathable during normal operation, thus facilitating entry.

o Relatively inexpensive, since

nitrogen would only be used

following an accident.

o It would require some finite

period of time to inert the

containment atmosphere following

an accident.

o Overpressurization

4.9.8 Oxygen Removal By a Gas-Turbine

4.9.8.1 Theory of Operation. A gas-turbine combustor system is another proposed method for rendering a mixture of air and hydrogen nomflammable following a degraded reactor core accident. This system would

rapidly inert the containment by reducing the oxygen

level following a degraded core accident before hydrogen could be released. Such a system would involve

one or more turbines, fuel supply lines, and monitoring instrumentation and controls. It would require an

4-131
additional forced-air induction system with fans and associated ductwork. It, should also include its own supplemental

cooling to avoid impacting the containment heat removal capability. Using a representative fuel such as methane (the

reaction would be] 4 - 54

CH4 + 202 -`-C0 2 + 2H2 0

Such a system was proposed for one PWR facility*

Estimates were made of some of the combustion parameters. In

order to reduce the containment oxygen concentration from the

original 20 percent to the required level of 5 percent (conservatively neglecting the addition of C02 ), [about] two

tons of methane would be required and 82 million [Btu] would

be generated. To inert the containment within 30 minutes, an

average airflow of 54,000 scfm would be required.

The 82 million [Btu] heat load would be comparable to the

heat load from combustion of the amount of hydrogen generated

by a 75-percent metal-water reaction (1500 lbm H2 ) 4 - 5 4

A gas-turbine combustor system is shown schematically in Figure 4-53 such a

system is discussed in Ref. 4-59 and 4-60; the following description is from

Ref. 4-59,:

A duct leads from a containment penetration to an

inlet isolation valve. During operation, the air

flows through this valve and enters a separator where

entrained water is removed. The air then flows

through ducting to the inlet of a gas-turbine/ generator system. Approximately 30% of the incoming oxygen

is burned in the gas turbine and the exhaust is ducted

to a desuperheater-type spray tower where it is

quenched and cooled by a water spray system. The

exhaust then enters a second separator where entrained

water is removed. The cooling water is returned to a

large holding tank for recycling through the heat

exchanger. Two pumps are used to cycle the water

through the heat exchanger system. The cooled exhaust

gas leaves the separator and is ducted to a return

penetration in the containment. 4- 5 9

For the gas turbine system to inert the containment by

the time hydrogen could be released, it must be initiated in time to perform its function. The previous

estimate of 30 minutes to deplete the oxygen

* Tennessee Valley Authority's Sequoyah Nuclear Power Plant.

4-132
Containment

1.28 x 106 SCF

air Gas turbine tower

outlet

Pump

Containment

1.28 x 106 SCF

air

Figure 4-53. Gas Turbine Combuster System Schematic

4-133
is probably a reasonable minimum time. It would be

difficult, for all scenarios, for the operator to

determine that the event was serious enough to warrant

initiating the gas turbine that far in advance of

hydrogen release into the containment. [For an

ice-condenser containment,] the operator would

'naturally be reluctant to activate a system that would

impose such a heat load, cause ice melting, and force

a plant shutdown for several months until he was

absolutely sure it was necessary. 4 - 5 4

4.9.8.2 Positive and Negative Aspects. Table 4-20 lists the positive and

negative aspects of the gas-turbine combustor system.

Table 4-20

GAS TURBINE COMBUSTOR SYSTEM (FOR OXYGEN REMOVAL)

Positive Negative

o One turbine can serve two units

o Gas turbine is located outside

containment.

o Heat rejection is outside

containment; the gas is returned

inside containment.

o It does not compromise the

existing containment.

o Gas turbines can leak air at

their mating flanges. A

separate containment boundary

would be required for this system.

o Decreasing oxygen concentration

during use would require the fuel

supply to be reduced during system

operation.

o Installation of a gas-turbine com--

bustor system has significant

impact on existing plant systems

and features.

o Operator judgement is required for

its actuation.

o Potentially severe heat loads,

fire, and missile hazards are additional drawbacks of this system.

4.9.9 Summary of Control System Positive and Negative Aspects

There are many possible ways of mitigating hydrogen generation in containments. Table 4-21 gives an overview by summarizing the advantages and disadvantages of the schemes discussed in previous sections.

Not all of the schemes presented are practical for all containment types. For

example, it is possible to inert the large PWR and BWR Mark III containments.

However, to do so would require large amounts of inerting gas, and also would

require entering personnel to wear protective and respiratory apparatus, thus

making inerting impractical. It is possible to inert the drywells, of BWR

Mark I and TI containments because of their small volumes and because entry

into a Mark I or II containment during operation would rarely, if ever, occur.

4-134
The notes accompanying Table 4-21 should be reviewed for a more complete

understanding of the table.

4-135
Notes for Table 4-21

1. N.A. = Not applicable.

2. Inerting may be practical only for the smaller BWR Mark I and II containments.

3. Halon has a tendency to decompose, which causes severe corrosion problems. However, if bromides are added to the Halon, the decomposition

is prevented, thereby minimizing corrosion.

4. Most containments already include some type of hydrogen recombiner system designed to handle small rates of hydrogen generation.

5. Deliberate ignition with a water fog or spray will increase containment

pressure and temperature less than deliberate ignition alone.

6. Carbon dioxide, Halon, and nitrogen may be stored as liquids under

pressure.

7. Large-scale hydrogen generation would result from a severely degraded

core condition in which a metal-water reaction occurred.

8. This is true for some, but not all, cases.

9. N2 partial pre-inerting, which is not shown in the table, has many of

the same operational features as N2 pre-inerting and would be used in

conjunction with one of the other mitigation systems.

4-136




4-15. General Physics Corporation, Mitigating Reactor core Damage:

FitzPatrick (Columbia, Md.: General Physics Corp., 1981) pp. 5-31 - 5-34.

4-16. General Electric Company, "Training Manual - Abnormal Event Analysis,"

NEDO-24862, 80NED077, Class I, Aug. 1980, General Electric Co., San Jose,

Calif., pp. 11-31 - 11-32.

4-17. Edouard H. Trottier, General Physics Corporation, Personal Communication with Chester F. Kupiec, General Physics Corp., Feb. 2, 1982.

4-18. "Susquehanna Steam Electric Station System Description: Liquid Radwaste Handling System," Pennsylvania Power and Light Co., Berwick, Pa.,

pp. 38-12 - 38-16.

4-19. Niagara Mohawk Power Corporation, "Technical Specifications and Bases

for the Nine Mile Point Nuclear Station, Unit 1" (Syracuse, N.Y.: Niagara

Mohawk Power Corp.) pp. 129-130.

4-20. W. Lai, Hydrogen Monitoring Systems in Reactor Safety Assessment,

(draft report for U.S. NRC) pp. 32-33.

4-21. E. C. Neidel, J. G. Castle, Jr. and J. E. Gover, "A Review of H2

Detection in Light Water Reactor Containments," NUREG/CR-2080, SAND8I-0326,

R3, (Dec.), 1981, Sandia National Laboratories, Albuquerque, NM.

4-22. Nuclear Safety Analysis Center, "Analysis of Three Mile Island - Unit 2

Accident," NSAC 80-1, NSAC-I Revised Mar. 1980, Electric Power Research Institute, Palo Alto, Calif.

4-23. Portland General Electric Company, Transmittal Letter to the U.S. Nuclear Regulatory Commission, July 17, 1981, Attachment 1, p. 6.

4-24. Donald C. Cook Plant, "Reactor Vessel Head Vent Operation," rev. 0,

Feb. 1981, Indiana and Michigan Electric Co., New York.

4-25. Donald C. Cook Plant, "Background Information for Reactor Vessel Head

Vent Operation," rev. 0, Feb. 1981, Indiana and Michigan Electric Co.,

New York.

4-26. Power Authority of the State of New York, Indian Point Station Unit 3

Final Safety Analysis Report (Jul. 1972) fig. 14.3.2-17.

4-27. Babcock and Wilcox Company, "Nuclear Steam Supply Systems," vol. 1,

Prepared for Metropolitan Edison Company, Apr. 1974, Babcock and Wilcox Co.,

fig. PC-2.

4-28. Toledo Edison Company, Davis-Besse Nuclear Power Station Final Safety

Analysis Report, rev. 27 (Toledo, Ohio: Toledo Edison Co., Aug. 1977) ch. 5,

fig. 5-7.

4-29. Westinghouse Electric Corporation, Transmittal Letter to the Donald C.

Cook Plant, May 29, 1981.

4-141
4-30. Donald C. Cook Plant, "Pressurizer Venting Operation," rev. 0, Mar.

1981, Indiana and Michigan Electric Co., New York.

4-31. General Electric Company, "BWR Technology," NEDO-10260, Oct. 1970,

General Electric Co., pp. 1-5 - 1-8, 2-44 - 2-47.

4-32. General Physic Corporation, BWR Simulator Training Manual, vol. 1-2,

2nd ed. (Columbia, Md.: General Physics Corp., 1981) ch. 3, 8.

4-33. Pennsylvania Power and Light Company, Susquehanna Steam Electric Station Final Safety Analysis Report, vol. 8, Pennsylvania Power and Light Co.,

Berwick, Pa., sec. 6.2.

4-34. Edouard H. Trottier, General Physics Corporation, Personal Communication with Chester F. Kupiec, General Physics Corp., Mar. 4, 1982.

4-35. z. M. Shapiro and T. R. Moffette, Hydrogen Flammability Data and Application to PWR Loss-of-Coolant Accident, WAPD-SC-545, Bettis Plant (September

1957).

4-36. Bernard J. Vernal, "Off-Gas System Explosions - Part l,"Nuclear News

(Nov. 1976): 54.

4-37. William R. Casto, ed., "Selected Safety-Related Occurrences Reported in

March and April 1974," Nuclear Safety (Jul. - Aug. 1974): 479.

4-38. Nuclear Power Waste Technology, ASMB, 1978, pp. 207-208.

4-39. Mississippi Power and Light Company, Letter to the U.S. NRC,

AECM-81/139, Description of Hydrogen Control Measures, Apr. 9, 1981, pp. 3-11.

4-40. B. Lewis and G. von Elbe, Combustion, Flames and Explosions of Gases,

2nd ed. (New York: Academic Press, 1961).

4-41. W. B. Murfin, "Report of the Zion/Indian Point Study," vol. 1,

NUREG/CR-1410, SAND80-0617/1, Rl, R7, Aug. 1980, U.S. Nuclear Regulatory

Comm., Washington, D.C.

4-42. General Electric Company, "Hydrogen Flammability and Burning Characteristic in BWR Containments," NEDO-10812, 73NED49, General Electric Co.

4-43. R. K. Byers, "CSQ Calculations of H2 Detonations in the Zion and

Sequoyah Nuclear Plants," NUREG/CR-2385, SAND8I-2216, Sandia National Laboratories (July 1982).

4-44. F. E. Belles, "Detonability and Chemical Kinetics: Prediction of

Limits of Detonability in Hydrogen," 7th Symposium on Combustion, 1959,

Butterworths, London, pp. 745-751.

4-45. A. K. Oppenheim and R. A. Stern, "On the Development of Gaseous Detonation - Analysis of Wave Phenomena," 7th Symposium on Combustion, 1959,

Butterworths, London, pp. 837-856.

4-142
4-46. J. W. Meyer, P. M. Urtiew, and A. K. Oppenheim, "On the Inadequacy of

Gas Dynamic Processes for Triggering the Transition to Detonation," 1970, pp.

14:13-14:20.

4-47. J. W. Meyer and A. K. Oppenheim, "On the Shock-Induced Ignition of

Explosive Gases," 13th Symposium on Combustion, 1971, Combustion Institute,

Pittsburgh, Pa., pp. 1153-1164.

4-48. Professor John Lee, McGill University, Personal Communication with

Chester F. Kupiec, General Physics Corp., Feb. 23, 1982.

4-49. L. Thompson, "Program Plan for EPRI Hydrogen Combustion and Control

Studies," Nov. 1981, Electric Power Research Institute, Nuclear Power Division, Palo Alto, Calif., p. 6.

4-50. M. Berman, "Light Water Reactor Safety Research Program Semiannual

Report, April-September 1981," NUREG/CR-2481, SAND82-0006, Feb. 1982, Sandia

National Laboratories, Albuquerque, NM.

4-51. B. F. Kerkam and E. K. Dabora, "Effect of Water Vapor on H2-O2

Detonations," American Institute of Astronautics and Aeronautics Journal,

vol. 4, 1102, 1966.

4-52. Virginia Electric Power Company, North Anna Power Station Final Safety

Analysis Report, amend. 65 (Nov. 3, 1978) fig. 6-2-3.

4-53. J. 0. Henry, et al., "Post-LOCA Hydrogen Recombiner System for LWR Nuclear Plants," Proceedings of the American Power Conference, vol. 31, 1974, pp.

219-225.

4-54. Tennessee Valley Authority, "Selection of the Permanent Hydrogen Mitigation System for the Sequoyah Nuclear Plant" Tennessee Valley Authority, Jun.

23, 1981).

4-55. K. C. Lish, Nuclear Power Plant Systems and Equipment (New York:

Industrial Press, Inc., 1972) pp. 136-138.

4-56. Edward T. McHale, "System Feasibility Analysis of Using Halon 1301 in

an Ice Condenser Containment," ARC no. 42-6522, Feb. 1981, Atlantic Research

Corp., Allentown, Pa., p. 3, 10, 12, 41-42.

4-57. G. P. McKinnon, ed., Fire Protection Handbook, 15th ed. (Quincy,

Mass.: National Fire Protection Association, 1981) pp. 181-12 - 181-14.

4-58. Walter M. Haessler, The Extinguishment of Fire (Quincy, Mass.:

National Fire Protection Association, 1974) pp. 15-16.

4-59. H. J. Reilly, et al., "Conceptual Design of a Core Melt Mitigation System for a PWR with an Ice-Condenser Containment," EGG-PR-5633 (interim

report). Feb. 1982, EG&G Idaho, Inc., Idaho Falls, Idaho.

4-60. H. J. Reilly, "Severe qcident Mitigation Studies," 9th Water Reactor

Safety Research Information Meeting, Oct. 26-30, 1981, Gaithersburg, Md.,

Idaho National Engineering Laboratory, Idaho Falls, Idaho.

4-143
4-61. "Safety Evaluation Report Related to the Operation of Grand Gulf Nuclear Station, Units 1 and 2," NUREG-0831, July, 1982.

4-62. "Safety Evaluation Report Related to the Operation of Sequoyah Nuclear

Plant, Units 1 and 2," NUREG-0011 Draft, November 1982.

4-144
Appendix I

THE THREE MILE ISLAND UNIT 2

ACCIDENT SCENARIO*

On March 28, 1979, at approximately 4 am, the Three Mile Island Unit 2 (TMI-2)

experienced a loss of normal feedwater to its steam generators (henceforth

OTSGs-once-through steam generators). The plant had been operating at 97% of

full power, as shown in Figure I-1. A resin block had developed in a condensate polisher unit's transfer line; since the polisher outlet is operated

within 50 psig of the net positive suction head (NPSH) for the condensate

booster pumps, both of these pumps tripped by closure of the condensate

polisher outlet valves. The net result was that two condensate pumps tripped,

both feedwater pumps tripped, and then the main turbine tripped. (Figure 1-2

is a schematic of the TMI-2 plant showing the placement of these components.)

The turbine trip resulted in the pressure in the Reactor Coolant System (RCS)

rising sharply causing a reactor trip on high pressurizer pressure. During

the RCS pressure rise, the pressurizer's electromatic relief valve (also

called a power-operated relief valve, or PORV) opened (and remained stuck in

that position). The reactor trip caused the RCS pressure to drop briefly;

however, at approximately 30 seconds into the event the OTSG water level was

low enough to automatically open the emergency feedwater control valves. The

block valves between the control valves and the OTSGs were closed; RCS conditions were as shown in Figure 1-3. The block valves were opened about

8 minutes later when it was noticed that a control board tag had been obscuring the indication that these valves were closed. This event did not, however, have a significant impact on the outcome of the TMI-2 incident. As

stated in the Rogovin Report:

We have concluded, however, that the 8-minute delay in

restoring emergency flow did not directly affect the outcome of the accident - though it did serve to divert the

attention of the operators, who patently needed no more

distractions at this point.I-2

The report of the Nuclear Safety Analysis Center generally concurs with the

above comments.I- 1

As the cool feedwater entered the dry OTSGs, the hot leg temperatures

dropped. RCS pressure, however, continued to drop, since the PORV remained

open. Figure 1-4 also shows the rising pressurizer level. A control board

indicating light signalled that the PORV was closed; in fact, it merely indicated that the solenoid was actuated. The PORV itself was actually open.

*The details of the accident at Three Mile Island are still being evaluated,

and will continue to be evaluated for some time. The information presented

here represents most of the current thinking as of the summer of 1982. Additional information not received in time for incorporation into this report,

may be found in Ref. 1-4.

I-1
H

!"-

LOOP A LOOP B

TMI-2 Scenario: Initial Conditions - System Steady

at 97% Power Operating Conditions

Figure I-1.
ATMOSPHERIC

VENT VALVE&

SAFETY VALVE

H

!~A

ity) TO OTHER

STEAM GENERATOR

CONDENSATE

PUMP

Figure 1-2. Three Mile Island Unit 2 Plant Arrangment
I " II I I

HI

...... ,..-o.,° .o...,

LOOP A LOOP B

Figure 1-3. 

Liquid 

TMI-2 Scenario: System Nearly Liquid Solid. Expanding with Increasing Temperatures.
2400 .1l

0

a.

Z

.4

0

4

-j

(0

(0

0

<Iz

w

-J

0r

2300 ,OPRESSURE

SECURING PUMP AND f

INITIATE LETDOWN FLOW, /

/ HPI (OR 2 MAKE UP PUMPS) -

A•..ACCOUNTS FOR ABOUT 1/2

OF THIS RISE

I

/

I

I

22

21

u- I

a

U

I

/'•rPRESSURIZER LEVEL

I

/

I

360

320

C

-j

280 >

uJ

-j

N

240=

CA

co

200

160

2

1

1

/

I

I

/

I

I

/

I

I

I

1~

D

I ! I I I A. I

2 3 4 5 6 7 8

TRIP TIME AFTER. TURBINE TRIP (minutes)

1700

Figure 1-4. TMI-2 Scenario: Reactor Coolant Pressure and Pressurizer

Level vs. Time
Temperature readings downstream of the PORV were elevated slightly. This had

been perceived earlier and attributed to a leak of approximately 6 gpm through

one of the pressurizer relief valves. It was not considered plausible from

this evidence that the PORV could be open. In fact, the throttling of steam

through the open PORV is essentially an isenthalpic process. The rapid expansion of steam will drop the temperature and pressure of the steam to about

atmospheric pressure and the corresponding Tsat, 212 0 F. Thus, the downstream temperature is not significantly elevated even if the PORV is stuck

open.

At about 3 minutes into the incident the quench tank safety valve lifted.

Since the PORV remained open, the rupture disk on the reactor coolant drain

tank burst at about 15 minutes into the incident. Reactor coolant, therefore,

found its way to the reactor building sump (Figure 1-5) to which it continued

to flow for about 139 minutes (2.3 hours), until the block valve was closed.

At 2 minutes into the incident, safety injection automatically initiated due

to low RCS pressure. However, at about 4.5 minutes, the operator thought the

RCS was going solid because the pressurizer level was rising rapidly, as shown

previously in Figure 1-4. Because of this indication, one high pressure injection pump was turned off, and the other one was throttled back. Full high

pressure injection to the RCS was not re-initiated until 3.3 hours into the

incident.

Since the high pressure injection rate was reduced, the mass of water leaving

the RCS via the stuck-open PORV and the letdown line was greater than the mass

entering the RCS through injection. This disparity led to steam voids in the

RCS, shown in Figure 1-6, which caused the pressurizer level indication to not

be a true indication of reactor vessel inventory.

Until 73 minutes into the incident, all four reactor coolant pumps were running. Seventy-three minutes into the incident, the B-loop pumps were shut off

because of low pressure, high vibration, and low flow. This resulted in the

separation of the water-steam mixture in the B-loop, which greatly reduced flow

through the B-loop. The increased steam voids caused by this separation are

shown in Figure 1-7. (Compare to Figure 1-6, which shows the RCS before the

B-loop pumps were shut off.) The increased voiding is further evidenced by

the abrupt increase in the source range indication, shown in Figure 1-8. One

hundred minutes into the incident, the A-loop pumps were shut off, resulting

in a second increase in the source range indication, indicating further voidings, shown in Figure 1-9.

At 139 minutes into the incident, operators closed the pressurizer block valve.

Hydrogen generation had already begun from the steam:zirconium reaction, filling the RCS voids with a steam-hydrogen mixture as shown in Figure 1-10.

For the next 13 hours, operators attempted to establish a stable cooling mode

by:

o Natural or forced circulation through the RCS using the OTSGs as the heat

sink. (This was not very successful because of the many steam/hydrogen

voids in the RCS.)

o High Pressure Injection (Safety Injection) was used intermittently during

the first 16 hours of the incident

o The core flood tanks were used about 8.5 hours into the incident

o The Decay Heat Removal System which operates at a pressure of 320 psig (They

could not get the RCS down below 400 psig during the first 16 hours, therefore the Decay Heat Removal System was not used during this time frame.)

1-6
STEAM

GENERATOR

D l Ij-MAIN 

FEED PUM

CONDENSATE CON NSATE

POLISHERS PUMP

•o, REACTOR CONTAINMENT SUMP IUMP

=4:-€O0LANT PUMP • / , •

AUXILIARY BUILDING

Figure 1-5. TMI-2 Scenario: Following Bursting of the Quench Tank Rupture

Disk, Water Flowed to the Containment Sump, from which it was Pumped

to the Auxiliary Building.
: PRIMARY WATER

SSECONDARY WATER

E• STEAM

I STEAM/HYDROGEN

a t Ihour i

P a 1050 P919

ON

~ION

co*

LOOP A LOOP B

Figure 1-6. TMI-2 Scenario: Primary System Pressure and Temperatures Nearly Constant Following Secondary Steam Condition. Primary Voids Increasing.
H

LOOP A LOOP B

Figure 1-7. TMI-2 Scenario: Loop A Pumps Operating. Loop B Stagnant After

Shutdown of Loop B Pumps. Primary Voids Increasing.
6

Z -o

5)

z•

4

0 0

3

240

TURBINE TIME AFTER TURBINE TRIP (Minutes)

TRIP NORMAL POST-TRIP

SOURCE RANGE TRACE

Figure 1-8. TMI-2 Scenario: Source Range Indication

vs. Time

I-10
• I I

PRIMARY WATER

_ SECONDARY WATER

DSTEAM

I STEAM/HYDROGEN

t aE 2 hours

P A750 psig

----- ,--__--K--

LOOP A LOOP B

Figure 1-9. TMI-2 Scenario: All Pumps Off. Reactor Core Drying Out and Heating Up. Superheated Steam Flowing to Pressurizer and to One Steam Generator and Condensing.
I | [ • i

PRIMARY WATER

* SECONDARY WATER

JSTEAM

STEAM/HYDROGEN

t a 2.8 hours

P A 1200 psig

H'.

!

t,)

LOOP A LOOP B

Figure 1-10. TMI-2 Scenario: Core Dryout and Heatup Continuing. Hydrogen Generation by Steam Zirconium Reaction in Hotter Regions.
The operators attempted to restart RCP 2B 174 minutes into the incident. Flow

was indicated for a few seconds and then dropped to zero. The pump was shut

off 19 minutes later. Conditions were then as shown in Figure I-11, with an

RCS pressure of about 2050 psig.

At about 192 minutes, the operators opened the pressurizer block valve for

about 17.5 minutes, and at 200 minutes, full safety injection was manually

initiated. RCS pressure dropped to about 1500 psig by 210 minutes, but radiation levels were increasing. Figure 1-12 shows the RCS conditions at 210

minutes (3.5 hours); it shows that the core had been recovered.

The PORV block valve was again opened at about 3.7 hours into the incident; it

remained open until about 5.3 hours. During this period, the overall trend in

RCS pressure was downward; some pressure increases occurred during high pressure injections. At about 5.3 hours, the PORV block valve was closed and RCS

pressure increased. When the pressure was around 2000 psig the valve was

cycled to maintain pressure in this vicinity. Figure 1-13 shows the approximate RCS conditions at about 6 hours. This situation continued until about

7.5 hours into the incident, when a decision was made to depressurize the RCS

conditions at about 6 hours. This situation continued until about 7.5 hours

into the incident, when a decision was made to depressurize the RCS by opening

the block valve to actuate the Core Flood System. Two makeup pumps (HPI

pumps) were running during this entire period.

The operators attempted to depressurize the RCS by using the Core Flood System

at approximately 7.6 hours. The pressure reduction was also performed to

approach conditions that would allow the decay heat removal pumps to be placed

in service. RCS pressure had been reduced to about 1000 psig at about 8 hours

into the incident, as shown in Figure 1-14. The conditions necessary for

actuation of the Decay Heat Removal System were not met. The Core Flood System did actuate at approximately 8.6 hours into the incident when the RCS

pressure reached 600 psig.

During this time, hydrogen was being released through the pressurizer into

containment. It was about 9 hours, 50 minutes into the incident that a

28 psig pressure spike was recorded in containment (Figure 1-15). It was

later determined that this spike was the result of a hydrogen deflagration in

containment. By 10.5 hours, RCS pressure had been reduced to about 400 psig

(Figure 1-16), and the pressurizer temperature had reached saturation. High

pressure injection was maintained during the entire depressurization procedure.

At 13 hours conditions were as shown in Figure 1-17. RCS pressure had

increased to 600 psig, the OTSGs were blocked by hydrogen, and the reactor

vessel water level had dropped. The RCS pressure never dropped to 320 psig,

which is the necessary pressure for Decay Heat Removal System operation to

begin. Further, the RCS temperature never dropped to below 250 0 F, which is

the necessary temperature to begin operation of the Decay Heat Removal System.

By 15 hours, RCS pressure had been restored to 2300 psig by high pressure

injection. Natural circulation occurred in RCS "A" Loop with OTSG "A" steaming to the condensor; OTSG "B" was isolated at this time. Conditions at

15 hours are shown in Figure 1-18. By 16 hours, with RCS pressure at

1300 psig, forced circulation had been reestablished in the A-loop, with the

OTSG serving as the heat sink (Figure 1-19).

1-13
F-II it 1

.°......

LOOP A LOOP B

Figure I-ll. TMI-2 Scenario: Core Partially Quenched by Fluid During Loop B

Pump Start. Heatup Resumes.
ELECTROMATIC

RELIEF VALVE (ERV)

RELIEF BLOCK

VALVE

: PRIMARY WATER

SECONDARY WATER

jSTEAM

STEAM/HYDROGEN

t 3.5 hours

P 1500 psig

H XI

LOOP A LOOP

Figure 1-12. TMI-2 Safety Reactor Injection. Vessel Core Refilled Temperatures by Manual Decreasing. Initiation of

B
: PRIMARY WATER

* SECONDARY WATER

[• STEAM

I STEAM/HYDROGEN

t ak 6 hours

Pai 2100 psig

...........................

I .::

LOOP A LOOP B

Figure 1-13. TMI-2 Scenario: System Pressurized by High Pressure Injection System. Intermittent Liquid Release Through Top of Pressurizer.

Heat Removal by Heatup of Injected Water. Heat Steam Generator

Heat Transfer Blocked by Hydrogen.
II I

: PRIMARY WATER

* SECONDARY WATER

E[I STEAM

STEAM/HYDROGEN

t R- 8 hours

P i" 1000 psig

Ho

LOOP A LOE

Figure 1-14. TMI-2 Scenario: Primary System Depressurizing and

Releasing Hydrogen Through the Pressurizer into the

Containment.

)P B
321

28

24

C 20

ci,

w

•16

z

012

-J

8

0

C-

< 4

<4

cc

0

-4

HYDROGEN BURN

•Ap= 26 psi

0 2 4 6 8

TIME AFTER TURBINE TRIP (Hours)

10 12 14

Figure 1-15. TMI-2 Scenario: Reactor Building

Pressure vs. Time

1-18
THIS PAGE INTENTIONALLY LEFT BLANK

1-19
PRIMARY WATER

* SECONDARY WATER

E STEAM

STEAM/HYDROGEN

t - 10:30

P 400 psig

0 :'' , /

• .• ....... ...

•iiii~ii:,i::i::ii. .... ........ ..... "•

LOOP A LOOP B

Figure 1-16. TMI-2 Primary System Pressure Reaches a Minimum as Pressurizer

Temperature Returns to Saturated Condition. Liquid in System

Maintained During Depressurization by High Pressure Injection

and Core Flood Tanks.
I|

PRIMARY WATER

SECONDARY WATER

t a- 13:00

P i" 600 p81g

%% ... ... %

A X. ...

"IXX

%LO B.

LOO A .

Figure~~~. ScnroXta 7 enrtr .-....... lce y yrgn eco

Vessel~~~~~~~~~ Deraig.rmr Level.... ytmPesr nraig

Miniml Mae-upFlow
PRIMARY WATER

SECONDARY WATER

t a 15:00 P A 2300 psig

t\3

LOOP A LOOP B

Figure 1-18. TMI-2 Scenario. System Repressurized by High Pressure Injection. Natural Circulation to Steam Genrators Blocked by Hydrogen.
ELECTROMATIC

RELIEF VALVE (ERV)

rRELIEF BLOCK

I VALVE

PRIMARY WATER

SSECONDARY WATER

[•J STEAM

STEAM/HYDROGEN

t a 16:00 P a1300 psig

... .. ..-- + U- ................ ......... .....

...

x.-

......... ...... .

LOOP A LOOP B

Figure 1-19. TMI-2 Scenario: Forced Circulation Reestablished in Loop A

with Heat Removal Via Loop A Steam Generator
The reactor coolant that escaped into the TMI-2 containment through the blown

rupture disk in the reactor coolant draft tank released both hydrogen and

radioactive fission products into the building, as shown in Figure 1-20. The

TMI-2 facility incorporated two containment sump pumps with automatic start

features which pumped water in the containment sump to the Auxiliary Building

Miscellaneous Waste Holdup Tank. The sump pumps started operating automatically because of an increasing sump level in the Reactor Building. This

radioactive RCS water was then pumped to the miscellaneous waste holdup tank

in the Auxiliary Building. The transfer line from this tank is lined up to

the Auxiliary Building sump tank which, unfortunately, had a blown rupture

disk. Hence, the holdup tank was filled and the water was transferred to the

Auxiliary Building sump tank. This RCS water was added to that water which

was initially in the sump (mainly from packing leakage from pumps that supply

river water, for cooling purposes, to the Reactor Building). This, then, was

the path for radioactive fission products initially released to the Auxiliary

Building from the Reactor Building at approximately 38 minutes into the

incident.

Shortly after 6:30 am (2.5 hours into the incident) radiation readings up to

about 1 Roentgen/hour (up from an initial 5 milli-Roentgens/hour) were

received in the area of the makeup tank in the Auxiliary Building. By

7:24 am, the radiation monitor on the Auxiliary Building vent stack went

off-scale; and the Reactor Building dome monitor had an indicated radiation

level of 8 REN/hour; therefore at this time, the Manager-Generation Station

Nuclear declared a General Emergency. It was at this point that the public

was notified about the incident at TMI-2.

As previously discussed, the majority of the hydrogen was produced between

about 1.5 hours and 3.5 hours into the incident. Temperature data from the

core exit thermocouples disclosed that sections of the core had temperatures

sufficiently high to liberate hydrogen by means of the zircaloy-steam reaction.

At 9 hours and 50 minutes into the incident a hydrogen deflagration took place

in the containment. Although it is not known exactly what initiated the

hydrogen ignition, one point is clear: A 28 psi pressure spike occurred in

containment. This spike was sensed by several types of instrumentation.

Figure 1-15 showed the pressure pulse in containment as it appeared on a trend

recorder in the TMI-2 control room. Note that pressure increased to 28 psig.

The pressure rise and subsequent pressure drop took place over about a

200 second time-frame.

Concurrent with this pressure rise was a simultaneous temperature increase on

most of the temperature monitors in the containment, as shown in Figure 1-21.

It should be emphasized that the temperature data were taken once every

6 minutes by RTDs having a slow response time in air (or the order of about

500 seconds). Therefore, the smooth curves shown here are somewhat misleading

with regard to the actual Reactor Building temperatures; these curves only

show general trends.

Further, the OTSGs experienced an indicated pressure decrease at the same

time. The OTSGs have pressure sensors that are referenced to the containment

atmosphere pressure. If the containment pressure changes, this will, in turn,

affect the OTSG pressure. Both OTSGs experienced approximately a 24 psid

pressure drop at the same time that containment pressure increased as shown in

Figure 1-22.

1-24
H STEAM Bi L•[ ' °NG

t__COR GENERATORi io _-I Li . .

C RE AC O 

.. ?v•

Figure 1-20. TMI-2.Scenario: Radioactive RCS Water Pumped from Conta inment

to the Auxiliary Building
5

6

7

8

9

Supply air

Supply air

Ambient steam and feedwater penetration

Ambient sump area

Ambient letdown cooler area

10 Ambient drain tank area

11 Ambient elevation 353-1

12 Ambient elevation 353-2

13 Ambient elevation 330-1

14 Ambient elevation 330-2

190

180

170

160

150

140

uj 130

D

I- 120

Ir

w 110 CL

u. 100

90

80

70

1300 1400

TIME

1500

Figure 1-21. TMI-2 Scenario: Reactor Building

Temperatures During Hydrogen

Ignition.

1-26
270 -5

265 o OTSG A 0

* OTSG "B"

260 0 5

0

0 0

255 0 - 10

0

250 0 15

0 0

245 0 20

240 25

235 30

I I I I

13:50:20 13:50:40 13:51:00 13:51:20

TIME

Figure 1-22. TMI-2 Scenario: Effect Hydrogen

Ignition on Measured Steam Pressures

1-27
It has been postulated that the average hydrogen concentration in the TMI-2

containment was approximately 8% when the deflagration took place. From

Figure 1-23, it can be seen that for this concentration, combustion might have

been fairly complete.

By applying an understanding of the source range detector response to void

formation, basic thermal-hydraulic principles, and the established sequence of

events, it is possible to develop an interpretation of the source-range

recording, shown in Figure 1-28. The relevant features of the recording are

designated by letters and are referenced in the commentary that follows:

A For the first 20 minutes, source-range instrument behavior was consistent

with a normal post-trip decay rate of about one-third decade per minute.

B After approximately 20 to 30 minutes, the source count rate should be

decreasing through the 600-700 counts per second (cps) range. Instead,

the curve leveled out at about 50000 cps due to the buildup of voids

(steam bubbles) in the downcomer and core regions. This is consistent

with the fact that pressure had reached saturation (approximately

6 minutes after turbine trip), and net outflow through the open electromatic relief valve continued to empty the system. Void formation is also

consistent because of the reduced pumping head produced by two-phase flow

conditions (not shown).

C Continued loss of coolant from the primary system [leads to increased

voiding] and increased detector count rates. The recording began to

exhibit noise, and phase separation characteristic of "slug flow." This

phenomenon increased with time.

D At 73-74 minutes the B reactor pumps were secured by the operator.

E At 100 minutes the A reactor coolant pumps were secured. This caused a

flow transient and separation of voids to the upper regions of the system. Voids rising to the top and coolant fill from the hot legs produced

a "solid" water condition seen at the detector. The detector count rate

abruptly dropped.

F The minimum count rate is suggestive of the fact that the downcomer water

level was at or near the top of the active core level.

G Continued release of fluid out of the relief valve began to boil off

inventory from the core and downcomer area. Makeup flow, assumed to be

in the neighborhood of 140 gallons per minute, was not sufficient to

maintain downcomer water level. The core mixture came within better view

of the detector as water levels dropped; the count rate increased.

1-28
I

*1

I

I

I

ev

0

2

.j

I0 4 a It 1i 20

HYDROGEN (percent)

Figure 1-23. TMI-2 Scenario: Pressure Rises Resulting

from Ignition of Hydrogen inrAir in 12 Foot

Diameter Sphere at 18 0 C.

1-29
REACTOR VESSEL

9 j ~ TO ELECTROMATIC

01-• RELIEF VALVE

CORE EXIT

THERMOCOUPLES

SPNDS

!r

u ........ . .. ....

.p -41i 1- ;

SPND =SELF-POWER NEUTRON DETECTOR

Figure 1-24. TMI-2 Scenario: Core Water Level--Time

Approximately 135-142 Minutes after

Turbine Trip.

1-30
-9

E

Iz

0

o 10

w

I.-

0

10-

300 500 700 900 1100

TEMPERATURE ('F)

1300 1500 1700

Figure 1-25. Approximate Thermionic Response of a

Self-Powered Neutron Detector (Typical)

1-31
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

2811 325

469

9571325

1 Ii~1I91 1 115 1

1 50-9

192E 2580 326

so 2366 2378 323 555

375 2272 177,4 1806 1875 234

260 2452 1295 2176 1852

1811 632 1760

373 1566 382 296 1774

325 2171 23271 348 252

L 1 1 413 1 1 1 1 578 12161 1 1 1

356 462 1138 308

- I 41 99.1t 1138 t 9 308-4

291

1 3521 475

1 2 3 4 5 6 7 a 9 10 11 12 13 14 1S

Figure 1-26. TMI-2 Scenario: Map of Core Exit.Temperature (9 0 F), 240-300 Minutes.

1-32
REACTOR VESSEL WALL

CORE

M/IXTURE

LEVELS

OURCE

:IANGE

)ETECTOR

6 ft -,

~7 ft

11.5 ft

TMI-2 Scenario: Source Range Neutron

Detector Field of View vs. Core Mixture

Level.

Figure 1-27.

1-33
SOURCE RANGE

6

z

0

w

0

0

UO

5,

0,

CL

4 r

3

0 60 120 180 240

TURBINE TIME AFTER TURBINE TRIP (Minutes)

TRIP

Figure 1-28. TMI-2 Scenario: Source Range

Trace During the Incident.

1-34
H The signal level continued to increase but at a slower rate as shielding

variations began to be counterbalanced by the loss of neutron source

(i.e., [H2 0]* being removed from the core region). In this period,

also, the rate of uncovery is believed to have slowed somewhat as core

boil-off tended to equilibrium with a relatively unchanging make-up flow

rate.

Over this period the count rate was decreasing as the loss of neutron

source and reduced neutron multiplication became predominant. The turnaround in detector count rate can be interpreted [as due to either] core

refill or continued recovery. However, the weight of evidence from

make-up flow estimates and other core instrumentation suggests that the

decreasing count rate was in response to continued core uncovery.

J The operator started reactor coolant pump 2B, sending a slug of cold

water into the downcomer and essentially filling it.

K Loop flow data indicate that the pump worked effectively for a very brief

period. This is corroborated by the abrupt turnaround in the source

range detector trace, as flow ceased and excess downcomer fluid moved

into the core and was boiled off; equilibrium levels were re-established.

L High pressure injection flow was initiated at 200 minutes, 8 minutes

after the electromatic relief block valve was opened by the operator.

Coolant passed into the downcomer, filling it. Detector count rates

dropped sharply.

M Continued addition of high pressure injection flow began to quench the

core. It is conjectured that the coolant first re-wetted the outer

region of the core, bypassing the hot center.

N Water entering the core eventually led to an unstable thermal-hydraulic

condition. It is speculated that major portions of the core may have

been suddenly quenched with a resulting large amount of coolant flashing

to steam, accompanied by possible core and fuel rearrangement. The jump

in detector counts may be due to the displacement of fuel and/or sustained voiding of peripheral fuel regions.I-3

Reference 1-3 says "U02 " vice "H2 0", but this appears to be an error.

1-35
REFERENCES

I-1. Nuclear Safety Analysis Center, "Analysis of Three Mile Island - Unit 2

Accident," NSAC-8--l, NSAC-l Revised Mar. 1980, Electric Power Research Institute, Palo Alto, Calif.

1-2. Three Mile Island - A Report to the Commissioners and the Public, by

Mitchell Rogovin and George T. Frampton, Jr., Volume I., 1980.

1-3. Analysis of Three Mile Island - Unit 2 Accident. NSAC-I Revised March

1980, Chapter CI-Core Instrumentation and Analysis of Coolant Level, pp 10-13.

1-4. H. W. Schutz and P. K. Nagata, "Estimated Temperatures of Organic

Materials in the TMI-2 Reactor Building During Hydrogen Burn." GEND-INF-023

(December, 1982.

1-36
Appendix II

REACTOR COOLANT SYSTEM GASEOUS VOID

DETECTION AND SIZING

Introduction

During the TMI accident, a gas bubble composed of hydrogen and steam was

present in the reactor coolant system (RCS). Calculations of the size of the

bubble varied, depending upon the assumptions used in the calculations. In

this appendix, we present a method for calculating bubble size that should be

valid for most situations encountered in PWRs. This method is taken from Ref.

II-1, and the reader should consult this reference for a more thorough treatment of the problem.

Problem Formulation

We assume that the bubble is a mixture of hydrogen and water vapor, and that

Dalton's law is obeyed. The density of water vapor in the bubble is assumed

to be the saturation density Pv(sat)(T). The total mass of water in the RCS

(exclusive of pressurizer) is given by:

RCS RCS B .P•RCS RCS B RCS

-M =(V V) I(PT )+ V.P (T )(11 w v(sat)

where

M = mass

V = volume

P = pressure

T = temperature

P = density

Subscripts I = liquid

v = vapor

w = water

Superscripts RCS = Reactor Coolant System

B = bubble

If Eq. II-1 is evaluated for two (P,T) states and the results subtracted, one

finds:

(RCS VEB (P - ) RCS B (VP RCS RCS

(P1 - 2v2 2 -1 v'I V1 (P- M) 2 - (VP1 - (II-2)

With the general notation (f is any quantity)

f ( fI + f 2 )/2 (11-3)

Af f•2 - f1 (11-4)

II-1
Equation 11-2 becomes

(P - pv ) vB ÷ - , • - IRCS AV + (I7-5)

-VRCSnPRCS + PRCS 6vRCS _ AM RCS

w

We can make the following assumptions, as discussed in Ref. II-1:

VRCS onstant(AVRCS .)

Pv << PI

-B << V-RCS

V

Equation 11-5 then reduces to:

AVB (VRCS Ap RCS -AM RCS)/PVRCS (11-6)

The mass increase in the RCS is simply the net mass introduced from any makeup

tanks and the pressurizer, reduced by the net leakage. Because the pressure

and temperature in a makeup tank change ver'y slowly, the change in its density

may be neglected, but this is not the case for the pressurizer. The resulting

expression is:

AM RCS ( I AAL)MUT A(PjV+ PvVv PZR m Leak (11-7)

W vvw

Here

VjPZR = [A(L + Lo)]PZR (11-8)

PZR PZR PZR

V = - V, (II-9)

where

A = cross-sectional area

L = level

Lo = effective height of hemispherical section of the.pressurizer

at the bottom.

AM Leak unknown leakage term w

Superscripts

MUT = Makeup Tank

PZR = Pressurizer

11-2
The hydrogen content of the bubble is:

N B = P.VB/RT (II-10) HH

where

N = moles of hydrogen in bubble

H

PH = P-Psat(T) = partial pressure of hydrogen

R = gas constant

From Chapter 2, Eq. 2-14 can be used to determine the amount of hydrogen in

solution

X = PH/H(T) (2-14)

x H = mole fraction of hydrogen

H(T) = Henry's Law Constant

We can rewrite Eq. 2-14 as follows:

HI P

x2 H

H 2 HO H(T) X2 nH2

• + n•20 HT I-l

2 2

where

n H = molar density of hydrogen in solution

H2

n H HO0= molar density of water solution

2

Because nH << nH20 we can write

H2 H P 2 2 H (11-12)

n + n n I H(T)

H2 H2 H2

11-3
or

P

n n H H (11-13) H2 H0 H (T)

2 2

If we define S(T) as

HO

S(T) 2 (11-14) H (T)

then

n H f2 S (T) PH (11-15) H2

The total number of moles of hydrogen in the RCS is now given by:

RCS B RCS B N BN + S(T)PH (V V) (11-16)

assuming that a bubble is present. If N Bis eliminated from Eq. 11-16 by using

B H

Eq. II-10, and we solve for V , the result is

nRCS RC

VB = max nH RT SRTVRcS 0 (11-17) (1l SRT)PH 1 - SRT '

where

SRT f SP H/(P H/RT) (111-18)

Equation 11-17 explicitly includes the possibility that all hydrogen is in

solution with no bubble present.

If measurements are made at two pressures, but nearly equal temperatures so

that changes in S and T may be neglected, we can solve Eq. 11-17 for NRCS

and show* H

NRCS = 1-SRT max - p2 PI B 'IvBI + SRT RCS

RT 2 1H mn 1 - SRT (I-19)

where the A notation for Eq. 11-4 has been used, and P H is the lesser of PH

and P . AVB is calculated using Eq. 11-6. Once the hmAogen content of the 1

*We~ ~ ~ ~ ~ osatdrigtemaueent.e ~ ~ ~~ asuetaOncSi 6 hyroe changing hydrogen

H2

*We assme tha NH is constant during the measurement. A changing hydrogen

content could be included with minor changes.

11-4
system has been calculated from Eq. 11-19, Eq. 11-17 may be used to calculate

the size of the bubble at any given pressure. Consider the following three

cases.

Case 1: Bubble present in both states 1 and 2

In this case, the first term in brackets in Eq. 11-19 is larger and the bubble

size in either state is given by

VB Pj H] SRT vRCS (11-20) i APH 1 - SRT

where the subscript i refers to the state at which you are calculating the

bubble volume, and the subscript j refers to the other state.

Case 2: Bubble present only at the lower pressure

In this case, the second term in brackets in Eq. 11-19 is larger and the bubble size in the ith state is given by

B [PHmin IAVP + Hmin - PHi SRT vRCS 0

3.Hi (P P Hi I-SRT

When PHi = P min' Eq. 11-21 reduces to

vB = IAVB1 (11-22) 1

and when P Hi # PHmin' Eq. 11-21 becomes

VB ; 0 (11-23)

1

Case 3: No bubble present in either state

In this case, the second term in brackets of Eq. 11-19 will yield an upper

bound on the amount of hydrogen present based upon the lower pressure

NRCS) max= (11-24) H mx=PHmin S V RCS

Equations 11-6 and 11-17 should yield results near zero for this case.

The formulations presented above are discussed in detail in Ref. I-1 and

results are presented for the case of TMI. While it is important to understand the assumptions in these calculations, the results should be good for

most regions of practical interest. These calculations include the effects of

hydrogen solubility and the differences in water densities in the makeup tank,

the pressurizer and the RCS. These effects have been neglected in other

formulations, but can significantly impact the results.

11-5
References for Appendix II

II-1. M. Rogovin and G. T. Frampton, Jr., 'Three Mile Island, A Report to the

Commissioners and to the Public," Nuclear Regulatory Commission, Vol. II,

Appendix 11.9.

11-6
Appendix III

REACTOR VESSEL HEAD VENT

VENTING TIME PERIOD

Introduction

Once a Reactor Coolant System gaseous void has been detected and an approximation made of its size (as described in Appendix II), a calculation of the

allowable venting time period can be made. The guideline which follows was

excerpted from one prepared by the Donald C. Cook Plant, which is operated by

the Indiana and Michigan Power Company. The following information includes a

discussion of the basis for the venting time period calculation plus a general

guideline for determining the venting time period itself.III-I

Basis

During a core uncovery event, the potential exists for a significant amount of

hydrogen to be generated in the core. This hydrogen could be trapped in the

reactor vessel head and released to the containment atmosphere during the

venting operation. The containment hydrogen concentration is limited to less

than four volume percent to prevent a potential combustible mixture with oxygen, therefore, the amount of hydrogen that can be vented to the containment

is restricted. A maximum allowable time period for venting can be determined

based on limiting the containment hydrogen concentration.

1. The total containment volume in cubic feet is determined first, and

then converted to standard temperature and pressure conditions. Note

that the pressure term for the conversion is only applicable to subatmospheric containments and can be deleted for the other plants.

2. The containment hydrogen concentration is then determined in volume

percent units. This value can be found by direct sampling or by

hydrogen monitors. Sufficient time should be allowed for the air

circulation equipment to mix the containment atmosphere prior to

sampling in order to determine a representative concentration. The

NOTE identifies to the operations and engineering personnel that containment hydrogen concentration will be insignificant if there has

been no leakage from the RCS to containment. In such a case, the

operator may assume the hydrogen concentration to be 0 volume percent.

3. The maximum volume of hydrogen that can be vented and still limit the

containment hydrogen concentration to less than three volume percent

is calculated. This ensures that the hydrogen concentration will

remain less than the flammable lower limit of 4%.

III-1
REACTOR VESSEL HEAD VENT GUIDELINE FOR THE VENTING TIME PERIOD

1. Convert the gaseous containment free-volume to gaseous containment volume

at standard temperature and pressure conditions.

Containment Volume @ STP = (Actual containment volume (ft 3 ) x

Containment Pressure**) 492 0 R

14.7 psia ) x (Containment Temperature*)

ft3***

* Temperature in degrees Rankine (°R=0 F + 4600).

** If containment pressure has increased above 14.7 psia, for conservatism use 14.7 psig as the pressure.

* Assuming no humidity correction in containment.

2. Determine the containment hydrogen concentration in volume percent

units. NOTE: The containment hydrogen concentration will be insignificant if there has been no leakage from the RCS to the containment.

3. Calculate the maximum hydrogen Volume that can be vented to the containment that will result in a containment hydrogen concentration of less

than or equal to three volume percent.

Maximum H2 Volume =

1100 [(3.0% Containment H Concentration -% H Concentration measured in

Step 2 x (Containment Volume @ STP)]

- _ft 3

4. From Figure III-1 (RCS Pressure vs. H2 Flow Rate) determine the allowable venting period that will limit the containment hydrogen concentration to three volume percent.

Maximum H2 Vented (from Step 3) Venting Period =2

H2 Flow Rate

min

111-2
I I I I I

2000

0.

Cn

0~

Ix

15001-

10001-

500 -

I I I

1000 2000 3000 4000 5000

HYDROGEN FLOW RATE (scfm)

Figure III-1. Reactor Coolant System Pressure vs. Hydrogen

Flow Rate.

111-3
REFERENCES

III-1. Donald C. Cook Plant, "Background Information for Reactor Vessel Head

Vent Operation," rev. 0, Feb. 1981, Indiana and Michigan Electric Co., New

York.

111-4
LIST OF ABBREVIATIONS

APSR: Axial power shaping rod

B&W: Babcock and Wilcox Company

BWR: Boiling water reactor

CAD: Containment Atmosphere Dilution System

CAS: Containment air sample

CCW: Component Cooling Water System

CDS: Containment Depressurization System

CE: Combustion Engineering, Inc.

CRDM: Control Rod Drive Mechanism

CVCS: Chemical and Volume Control System

DBA: Design basis accident

DDT: Deflagration-to-detonation transition

ECCS: Emergency Core Cooling System

EPRI: Electric Power Research Institute

ESF: Engineered safety feature

GE: General Electric Company

HEPA filter: High efficiency particulate air filter

HIS: Hydrogen Ignition System

HPCS: High Pressure Core Spray

HRSS: High Radiation Sampling System

HUT: Holdup tank

ICC: Inadequate Core Cooling

LOCA: Loss-of-coolant accident

LPCI: Low Pressure Core Injection

LPCS: Low pressure core spray

LRW: Liquid radwaste collection tank

LWR: Light-water cooled reactor

MIDS: Movable Incore Detection System

MSIV: Main steam isolation valve

MSLB: Main steam line break

OGS: Off-Gas System

OTSG: Once-through steam generator

PHMS: Permanent Hydrogen Mitigation System

PORV: Power-operated relief valve

PRA: Probabilistic risk assessment

PRT: Pressurizer relief tank

PWR: Pressurized water reactor

PZR: Pressurizer

RCIC: Reactor Core Isolation Cooling (System)

RCS: Reactor Coolant System

RCP: Reactor coolant pump

RCVS: Reactor Coolant Vent System

RHR: Residual Heat Removal (System)

RTD: Resistance temperature detector

RVHVS: Reactor Vessel Head Vent System

RWP: Radiation Work Permit

SBGTS: Standby Gas Treatment System

SCBA: Self-contained breathing apparatus

SCFM: Standard cubic feet per minute

SI: Safety Injection (System)

SJAE: Steam jet air ejector

SMM: Subcooling margin monitors

A- 1
SNL: Sandia National Laboratories

TIP: Traversing Incore Probe (System)

VCT: Volume control tank

WDS: Waste Disposal System

A- 2
GLOSSARY

Acid day tank: Small sulfuric acid batch tank in the Condensate Demineralizer

Regeneration System in BWRs. Receives acid from holding tank and feeds it to

metering pumps.

Adsorber: A surface used for adsorption.

Adsorption: A type of adhesion which takes place at the surface of a solid or

liquid in contact with another medium, resulting in an accumulation of molecules from that medium in the vicinity of the surface.

Annunciator: An illuminated indication, which is electrically controlled in

the control room, that denotes a particular plant condition. Annunciators

generally have an audible indication as well as a visual one.

Auxiliary Coolant Systems: In a PWR, the Auxiliary Coolant Systems consist of

the Residual Heat Removal System (RHR), which removes decay heat generated in

the reactor core after shutdown; the Spent Fuel Storage and Cooling System

which removes decay heat from the spent fuel storage pool; the Containment

Cooling System which is an air cooling system and a direct water spray into

the structure, both 100% capacity; the Closed-loop Cooling System which is an

intermediate heat exchanging loop between other Auxiliary Coolant Systems and

the environment; and the Service Water System, the final heat sink for all

heat loads (ocean, river, or cooling tower) except the primary loop.

In a BWR, there are the Residual Heat Removal System; the Spent Fuel Cooling

System; the Closed-loop Cooling System; the Service Water System; the Reactor

Core Isolation Cooling System (RCIC), a standby core cooling system used when

the reactor is isolated from the turbine due to closure of the main steam

isolation valve, throttle valve, or stop valve (it is not used for accidents);

the High-Pressure Core Spray System (HPCS), designed to make up water lost in

any break or rupture; and Low-Pressure Core Spray System (LPCS), a backup to

the LPIC mode of the RHR system.

Binary Fission: The most common form of nuclear fission in a nuclear reactor,

which results in two fission products. Approximately 1 fission event in

12,000 is a ternary fission event (3 fission products), otherwise fission is

generally binary fission.

Burning Velocity (Laminar): Velocity of a flame in a Lagrangian sense (i.e.,

relative to the flowing gases) at a steady burner.

Catalyst: A substance that accelerates or retards the rate of a chemical

reaction, which itself undergoes no permanent chemical change, and which may

be recovered when the reaction is completed.

Catalytic Poisoning: The process whereby a substance within a hydrogen recombiner unit itself inhibits the activity of the catalyst. Catalytic poisoning

has not presented a problem in thermal recombiners.

Charging System: The system that introduces "new" feedwater into the RCS,

from the VCT (or make-up tank) in a PWR, and from the condensate storage tank

in a BWR.

G-1
Chemical and Volume Control System (CVCS): The system that maintains a proper

volume and boric acid concentration in a PWR RCS. Boric acid is added by

pumping a concentrated solution into the PZR. The pressure in the RCS may be

lowered by spraying water from the VCT into the vapor space of the PZR. RCS

water is removed for demineralizing and filtering through the letdown line

from the RCS cold leg. Coolant may be added to the RCS cold leg from the VCT

through the charging line. The functions of the CVCS may be summarized as

follows:

1) Fills RCS.

2) Provides a source of high pressure water to perform cold hydrostatic

testing of the RCS.

3) Maintains the water level in the pressurizer when the RCS is hot.

4) Reduces the concentration of corrosion and fission products in the

reactor coolant.

5) Adjusts the boric acid concentration of the reactor coolant for

chemical shim control.

6) Provides high pressure seal water for the reactor coolant pumps.

Cold Leg: In a PWR, the RCS from the exit of the steam generator to the reactor vessel; in a BWR, the Reactor Coolant System from the feedwater containment penetration to the reactor vessel.

Combustible Gas Control System: The system in BWRs that monitors, records,

and indicates the presence of combustible gases throughout the nuclear plant.

Combustion: A rapid chemical reaction (in this text, between hydrogen and

oxygen), accompanied by the evolution of light and a rapid production of heat.

Condensate Demineralizer Regeneration System: Used to regenerate condensate

demineralizers (periodically). The system consists of two large holding

tanks, one for sulfuric acid and one for sodium hydroxide, day tanks, metering

pumps, and a water addition line. Used in BWR facilities.

Containment Depressurization System (CDS): The water spray cooling system

used to relieve pressure and temperature buildup in containment, and to

restore a negative pressure after a LOCA or MSLB.

Containment Purge and Exhaust System: The system in PWR plants that takes a

*suction on the containment atmosphere and releases it to the environment after

treatment for radiation and suspended particles.

Core Plate: One of two plates (either upper or lower) that provide support

and orientation for the fuel assemblies and also help to guide the flow entering and exiting the reactor core.

Corrosion: The wearing away of metals due to chemical or electrolytic reactions. There are several types of corrosion, including:

Crevice Corrosion - Corrosive degradation of metal parts at the crevices

left at rolled joints or from other forming procedures; common in stainless steel heat exchangers in contact with dissolved corrosives.

Galvanic Corrosion - Electrochemical corrosion associated with the current in a galvanic cell, caused by dissimilar metals in an electrolyte

because of the difference in potential (emf) of the two metals.

G-2
CRUD: Corrosion products suspended in the RCS. CRUD tends to settle out in

areas of low water velocity causing difficulty in repair and maintenance. An

acronym for "Chalk River unidentified Deposits," from the Chalk River Reactor

Facility in Canada, where it was first encountered.

Deflagration: A combustion wave that is traveling at a speed that is subsonic

relative to the unburned gas.

Detonation: A combustion wave that is traveling at a speed that is supersonic

relative to the unburned gas.

Drywell: The primary containment structure in a BWR system. The drywell

houses the reactor and recirculating loop. It provides containment in the

event of a LOCA or MSLB. Pressure built up during an accident is vented to

the pressure suppression chamber. The containment is either of the "inverted

light-bulb and torus" design, with the drywell being the "inverted light-bulb"

and the pressure suppression chamber being the "torus"; or the "over and

under" design, with the pressure suppression chamber located under the drywell.

Electrolyte: A substance that when in solution with water conducts electricity.

Emergency Core Cooling System (ECCS): Systems running in parallel, each with

100% capacity, that will provide emergency coolant to the reactor core in the

event of a LOCA. In a BWR, there are two methods for ECC. The first has high

and low pressure water spraying directly onto the core through separate

spargers. The second method consists of steam blow-off to the pressure suppression pool followed by RHR system operation when the pressure drops. In a

PWR the ECCS typically has three ranges of coolant injection into the RCS during an accident condition:

o High Head Injection - Via the charging pumps

o Medium Head Injection - Via the Safety Injection Pumps (see Safety

Injection System)

o Low Head Injection - via the Residual Heat Removal (RHR) pumps (see

Residual Heat Removal System)

Enthalpy: The sum of a substance's internal energy and the product of its

pressure and volume. Expressed in Btu/lbm.

Excore Nuclear Instrumentation System (NIS): The system that monitors the

nuclear fission process from outside the reactor at a PWR facility. -The

Excore NIS generally consists of source, intermediate, and power range channels.

Fission Chambers: Part of the Incore Nuclear Instrumentation System for all

BWRs and some PWRs. The chambers can be movable or permanently installed.

The fission chambers respond to incore radiation: the response will change

drastically if the core becomes uncovered, as might occur during an inadequate

cooling condition.

Fission Products: Radioactive products of the fission process in a nuclear

reactor. These products generally do not enter the RCS, except in the case of

a cladding rupture, thus their presence is indicative of a cladding rupture,

G-3
which, in turn, could indicate that hydrogen generation has occurred. A list

of fission products is given in Chapter 4. Fission products can be differentiated from activation products by standard counting laboratory techniques.

Flame Arrester: A device used to isolate a combustion in a BWR Off-Gas System. It operates by removing the heat from the flame and by providing

water-gas contact. In addition to limiting flame front propagation, the flame

arrester will provide additional humidity to the off-gas and will limit the

effects of pressure fluctuations. This helps further limit the catalyst and

combustion potential.

Flame Speed: Velocity of a flame in the laboratory (Eulerian) coordinate system. The laminar flame speed is the vector sum of the burning velocity and

the gas velocity. Turbulence will effectively increase the flame speed by

increasing the flame surface area and enhancing mixing.

Flammable: Capable of being ignited and propagating a flame.

Fog: A very fine spray.

Gas Chromatography: A method used to determine the constituents of a gas.

This procedure is used in PWR plants to determine gaseous constituents in containment during normal operations, and as a backup hydrogen determination

method after an accident.

Glow Plug: The preferred of two methods to provide intentional hydrogen ignition. An element of the plug is heated to and maintained at a temperature

above that necessary for combustion.

Halogen: Any element of the halogen family: fluorine, chlorine, bromine,

iodine, and astatine. Gases containing halogens are used in fire

extinguishing and fire-suppression systems. Halogen inerting or suppressing

has been proposed for controlling hydrogen in both PWR and BWR containments.

Hard Bubble Phenomenon: A condition that, generally, can be caused by overuse

of the pressurizer spray in PWR systems. A "hard bubble" occurs when the

vapor space in the pressurizer is filled with noncondensable vapor, mostly

hydrogen, which makes the pressurizer behave as if it were filled with water.

This places constraints on the use of the pressurizer to control pressure in

the RCS.

High Radiation Sampling System (HRSS): Samples the gaseous constituents in

containment during routine operations and in a post-accident mode.

Holdup Tank (HUT): Part of the CVCS in a PWR plant. It is used to hold letdown from the RCS before demineralizing and filtering when it is necessary to

reprocess RCS water.

Hot Leg: In a PWR, the RCS from the reactor vessel, past the pressurizer to

the entrance of the steam generator; in a BWR, the Reactor Coolant System from

the reactor vessel to the penetration exiting containment.

G-4
Hydrogen Analyzing System: The system in a BWR that monitors and records the

hydrogen concentration in the drywell and the secondary containment following

a LOCA. Part of the Combustible Gas Control System.

Hydrogen Igniter System (HIS): The system used to intentionally burn hydrogen

in the containment structure before the hydrogen concentration reaches dangerous levels. Generally, it utilizes glow plugs.

Ice Condenser: A containment system for PWRs in which, during an accident,

steam is directed through the ice condensers to a containment compartment

separate from all energy sources. The ice cools and condenses the steam,

decreasing its volume, therefore allowing the containment structure to be

smaller. The ice used contains boron, to poison the reaction, and sodium (in

the form of caustic soda), to remove radioactive iodine.

Ignition: The process of starting a fuel mixture burning, or the means for

such a process.

Inadequate Core Cooling (ICC): A condition which may occur during an RCS

failure which results in a heat build-up in the core. Emergency cooling is

provided by the ECCS. Although no official definition of inadequate core

cooling has been widely publicized, the NRC provided a definition of, ICC in

correspondence to utilities owning reactors designed by Babcock and Wilcox.

This definition is:

The staff considers the core to be in a state of inadequate

core cooling whenever the two phase froth level falls below

the top of the core and the core heatup is well in excess

of conditions that have been predicted for calculated small

break scenarios for which some core uncovery with successful recovery from the accident have been predicted. Possible indicators of such a condition are core exit super

heat temperature and/or the rate of coolant loss or level

drop prior to core uncovery and the extent and duration of

uncovery.*

Incore Nuclear Instrumentation System: The system which monitors the nuclear

fission process from inside the reactor, consisting of fission chambers and

thermocouples in PWRs.

Inerting: A mixture is inert if a flame cannot propagate through it. A mixture may be inert due to a lack of hydrogen or oxygen or due to an excess of a

diluent gas such as steam.

Ion Exchange: A method of demineralizing PWR primary coolant and adsorption

of positive or negative ions on a synthetic resin, where they are replaced

with either H+ or OH- ions.

* "NRC Staff Evaluation of Babcock and Wilcox Position Regarding Additional

Instrumentation for Detection of Inadequate Core Cooling for B&W Reactors,"

Enclosed in NRC letters to owners of B&W reactors, September 24, 1980.

G-5
Isenthalpic Process: A process in which the enthalpy of a substance is constant throughout the process. (A throttling process, for example, is an

isenthalpic process.)

Isotopes: Chemically identical variations of a single element with different

atomic weights. That is, atoms of the same element having different numbers

of neutrons within their respective nuclei.

Letdown: Reactor coolant removed from the RCS cold leg by means of the letdown line of the CVCS. It is reduced in pressure and temperature and sent to

the VCT, the boron recovery subsystem of CVCS, or the Waste Disposal System.

Makeup Tank: Provides a surge volume of water for makeup (or charging) pumps

in B&W PWR facilities. Equivalent to the volume control tank (VCT) in a

Westinghouse or CE facility.

Nitrogen Inerting System: Used in Mark I and II BWRs in the primary containment (or drywell) to ensure that the primary containment in conjunction with

the ECCS will withstand the effects of metal-water reactions subsequent to the

postulated design basis LOCA.

Off-Gas System (OGS): The system for handling noncondensable radioactive

wastes before releasing them to the atmosphere. The system consists mainly of

condensers, to remove any condensable wastes, gas decay tanks, where the

radioactive gases are held until radiation levels have dropped to acceptable

levels, and ventilation fans, which mix the off-gas with the atmosphere in the

exhaust stack. BWR OGSs run continuously, while PWR OGSs run on a batch basis.

Partial Preinerting: Maintaining of a depleted (but breathable) oxygen atmosphere in containment. Oxygen concentrations of 13-17 % would be required.

This method would be used in conjunction with deliberate ignition or

post-inerting.

Partial Pressure: The partial pressure of a gas in a mixture is equal to the

pressure which the gas would exert if it occupied the same volume alone at the

same temperature.

pH: A convenient method of expressing the acidity or alkalinity of solutions. The pH is the base 10 logarithm of the reciprocal of the concentration

of hydrogen ions in an aqueous solution.

Photolysis: The decomposition or dissociation of a molecule as the result of

the adsorption of light.

Polaron: A free electron in an aqueous solution.

Post-inerting: The injection of a gas into or the removal of oxygen from the

post-accident containment atmosphere to protect against hydrogen combustion.

Power Operated Relief Valve (PORV): Valves placed on tanks, operated either

electrically, hydraulically, or pneumatically, to relieve a pressure buildup

inside a tank. The relief valves are set to open before the self-actuating

safety valves in the tank.

G-6
Pre-inerting: The inerting of containment during normal operation to prevent

hydrogen combustion following a LOCA. Used extensively in Mark I and II BWR

containments. Partial pre-inerting has been proposed for BWR Mark III and PWR

containments.

Pressurizer (PZR): The pressurizer vessel which serves to control the pressure in a PWR's primary loop. The PZR is partially filled with a surge of

water, and partially with steam, and possibly other gases. If the pressure

rises, water from the VCT is sprayed into the steam space, where some of the

steam is condensed, thereby, decreasing the pressure.

Pressurizer Relief Tank (PRT): A tank that receives effluent from the RCS

from a pressure increase. If the pressure in the primary loop of a PWR

becomes so high that water sprayed into the vapor space of the PZR will not

reduce it sufficiently, relief valves open and gas is vented to the PRT. The

PRT is partially filled with quench water, which condenses the incoming

steam. The non-condensable vapors are then vented to the OGS.

Pressurizer Vent System: A system that allows venting of the PZR steam

space. If the pressure on the primary loop of a PWR becomes so high that

water sprayed into the vapor space of the PZR will not reduce it sufficiently,

relief valves open and gas is vented to the PRT. If the relief valves are

stuck closed, there are self-actuating safety valves, set at a higher pressure, which will vent directly to containment.

Process Radiation Monitoring System: The system designed to monitor radiation

levels of certain liquid and gaseous processes throughout the plant to assist

in controlling the release of radioactive wastes and provide for personnel

safety. The subsystems in the Process Radiation Monitoring System are:

1. Main Steam Line Radiation Monitoring System - Detects the release of

fission products into the main steam line, primarily as the result of

a major fuel failure.

2. Off-Gas Radiation Monitoring System - Monitors, radiation in the

Off-Gas System (see Off-Gas System).

3. Flux Tilt Radiation Monitoring System - An expanded scale device used

to help locate ruptured or failed fuel elements.

4. Off-Gas Vent Pipe Radiation Monitoring System - Used to permanently

record the gross gamma radiation discharged from the OGS to the

environment (see Off-Gas System).

5. Process Liquid Radiation Monitoring System - Monitors radiation in

the Service Water System discharge, RHR, Closed Cooling System, and

Radwaste System effluent.

6. Building Ventilation Radiation Monitoring System - Monitors radiation

in the reactor building.

Radiolysis: The decomposition of water caused by exposure to radiation. Also

called radiolytic decomposition.

Reactor Coolant Drain Tank: A tank in containment which collects drainage

from RCP seal leak-off, reactor vessel flange seal leak-off, the reactor

coolant drain header, and accumulator drains.

G-7
Reactor Protection System: The system that, when it receives a trip (or

SCRAM) signal, causes the shutdown of the reactor and possible initiation of

any emergency cooling systems that may be required.

Recombiner: A device in the OGS of a BWR that through a catalytic reaction,

recombines hydrogen and oxygen to form water.

Residual Heat Removal System (RHR): In a PWR, a system that provides the

capability for removing decay heat from the reactor core following a plant

shutdown. This system also provides low-pressure injection water as part of

the ECCS. In a BWR, the LPCI System incorporates a residual heat removal subsystem to provide LPCI in the event of a LOCA.

Resistance Temperature Detector (RTD): A temperature measuring device in

which the sensing element is a resistor, usually platinum in nuclear plants,

whose resistance is an accurately known function of temperature. Also known

as resistance thermometer and resistance pyrometer.

Safety Injection System (SI): Provides high pressure coolant injection into

the Reactor Coolant System (and, sometimes, the reactor vessel directly) to

help maintain adequate reactor core cooling. It is part of the Emergency Core

Cooling System.

Spray: A water system used to relieve pressure and temperature buildup by

steam release in the containment structure. Mean drop radius is 200-300

microns.

Spark Plug: One of two methods to provide intentional hydrogen ignition. Not

the preferred method because the sparks could cause radio frequency interference at a nuclear power station.

Steam Jet Air Ejectors (SJAEs): Remove noncondensable gases from the main

condenser and vent them to the Off-Gas System.

Subcooling Margin Monitor (SMM): Used in PWRs to monitor the margin to

saturation of the reactor vessel and RCS. The SMM receives temperature inputs

from the core exit thermocouples, and hot and cold leg RTDs, and a pressure

input from the pressurizer. With the pressure and highest temperature, the

SMM determines and indicates the margin to saturation in the reactor vessel

and RCS. The water in the RCS must be kept at or below saturation to prevent

steam from forming in the RCS.

Suppression Pool: A pool of water in the wetwell of a BWR containment which

is designed to condense steam. It vents to the wetwell during the "blowdown"

following a LOCA. By condensing the steam, the pressure inside containment is

greatly reduced in an accident.

Ternary Fission: One form of nuclear fission which results in three fission

products, one of which is sometimes hydrogen in the form of tritium. Ternary

fission occurs approximately once in every 12,000 fission events in the reactor.

Thermocouple: A temperature measuring device consisting mainly of two dissimilar metals joined together at their ends. When the two junctions are

exposed to a temperature difference (one junction at a known reference

G-8
temperature, the other at the temperature to be measured), a thermoelectric

voltage proportional to the temperature difference develops. This voltage can

be measured, and from it the unknown temperature at the junction can be determined.

Thermowell: A small protrusion into a pipe in which a resistance temperature

detector (RTD) can be installed.

Traversing Incore Probe (TIP): A vertically traveling fission chamber in a

BWR reactor core, used to measure the neutron flux along the length of the

active core. A similar system is used in many pressurized water reactors. In

the PWR the same type of system is referred to as either a Movable Incore

Detection System (MIDS) or an Incore Flux Mapping System.

Volume Control Tank (VCT): A tank that provides a surge volume of water for

makeup (or charging) pumps in Westinghouse and CE PWR plants. Equivalent to

the makeup tank in B&W plants.

Vital Power Supply: Redundant power supplies to all systems required for safe

plant operation and shutdown.

Waste Disposal System (WDS): Consists of OGS (see Off-Gas System) and liquid

and solid waste systems. The OGS prepares gases to be exhausted to the atmosphere. Liquid wastes are held in holdup tanks until they can be classified as

"clean" (pure water) or "dirty" (chemical wastes), after which they are

drummed, demineralized, and recycled in the plant, or discharged from the

plant. Solids wastes are compressed and drummed, and sent to government

burial grounds.

Wetwell: The volume of a BWR containment that holds the suppression pool.

The wetwell in a BWR Mark I contaimment is the "torus" in the "inverted lightbulb and torus"; the wetwell in a BWR Mark II contaimment is located under the

drywell; and the wetwell in a Mark III containment is located outside the drywell.

Zircaloy: An alloy consisting of approximately 98% zirconium that is used in

the fabrication of fuel assemblies (or fuel bundles) for light-water power

reactor facilities.

G-9

INDEX

air:steam:hyrdogen mixtures, 2-26.

aluminum, reactions, 1-2; 2-1, 13, 16 ; 4-4, 7.

battery room, 3-12.

bulk storage facility, 3-11.

BWRcontainment, 4-7.

hydrogen behavior and control, 3-22 to 3-27, 4-28, 29.

hydrogen, indications of, 4-41 to 4-48.

hydrogen combustion, 4-84 to 4-93

hydrogen transport pathway, 4-66 to 4-77.

carbon dioxide, 1-2; 2-11, 12, 37, 65; 4-124, 129, 136.

chemical and volume control system, 3-18.

chemistry, 3-27.

cold leg piping, 4-57.

conditions for combustion, 2-36.

containment activity, 4-23.

containment entry, 3-19, 27.

containment humidity, 4-23, 38.

containment pressure, 4-23, 38.

containment sampling, 4-39.

containment sump level, 4-23.

containment temperature, 4-23, 38.

containment bwr, 4-7.

containment pwr, 4-4.

control rod drive mechanism, 3-16.

core:concrete interactions, 1-2; 2-1, 13, 16.

corrosion, 1-2; 2-1, 13, 16, 67; 3-3, 6, 11; 4-34, 44, 98, 102,

128, 129, 130, 136, 139.

X-1
decomposition, 4-128.

deflagration-to-detonation transition, 2-48, 54; 4-92, 109.

deflagrations, 1-4; 2-41, 42, 44, 48, 51, 54, 59, 60; 4-10, 64,

81, 82, 84, 87, 91, 92, 94, 107, 108, 109, 137.

deliberate ignition, 2-60; 4-107, 114.

detonation cell size, 2-51.

detonation limits, 2-48.

detonation local, 2-55, 60.

detonation pressure, 2-54.

detonation temperature, 2-54.

detonation, 1-3; 2-28, 40, 48; 4-81, 82, 84, 87, 91, 92, 107-109

116, 137

drywell/containment temperature, 4-29.

drywell/containment pressure, 4-28.

drywell/containment activity, 4-29.

drywell/containment pressure, 4-44.

drywell/containment temperature, 4-46.

drywell/containment sampling, 4-46.

drywell/containment humidity, 4-46.

electrical generators, 3-8.

fans, 4-77 to 4-79

flame acceleration, 1-4; 2-47, 54; 4-79, 87, 92, 109.

flammability, 1-2; 2-27, 36 to 40, 42, 45, 47, 65, 68, 69; 3-19;

4-1, 87, 105,

flammability, 3-106, 115, 116, 122, 124.

flow, 4-13, 23, 30, 41.

gas chromatography, 3-12.

gas sampling, 4-87.

gaseous sampling, 4-84.

gaseous waste disposal, 3-19.

gross radiation level detection, 4-40, 117.

gross radiation level detection, 4-47.

X-2
halon, halon system, 2-37, 41, 65, 69; 4-122 to 129, 136.

high-point-vent flaring, 2-66.

hot leg piping, 4-57.

hydrogen behavior and control, normal, bwr, 3-22 to 3-27

hydrogen behavior and control, accident, pwr, 4-10 to 4-28

hydrogen behavior and control, accident, bwr, 4-28 to 4-29

hydrogen behavior and control, normal, pwr, 3-13 to 3-22.

hydrogen combustion, 2-28 to 2-59

hydrogen combustion, evidence, pwr, 4-81.

hydrogen combustion, evidence, bwr, 4-84 to 4-93

hydrogen combustion, example calculations, 2-28.

hydrogen considerations, bwr, 3-22.

hydrogen considerations, pwr, 3-13.

hydrogen considerations, pwr, bwr, 3-1 to 3-13

hydrogen control, 4-98 to 4-140.

hydrogen detection, 4-48 to 51.

hydrogen production, 2-1 to 2-16

hydrogen research, 1-2

hydrogen transport, containment to other bldg, 4-64.

hydrogen transport pathway, bwr, 4-68 to 4-77

hydrogen transport and mixing, pwr, 4-51 to 4-67

hydrogen transport and mixing, 2-19 to 2-26

hydrogen,postburn considerations, 4-94 to 4-98

indications of hydrogen, bwr, 4-41 to 4-48.

indications of hydrogen, pwr, 4-30 to 4-40.

loca, loss-of-coolant-accident, 1-2; 2-10, 16, 26, 28., 67, 68;

4-10, 13, 15, 17, 19, 22, 23, 24,

28, 32, 38, 41, 42, 44, 46, 48,

49, 51, 53, 67, 68, 74, 79, 80,

81, 92, 94, 107, 108, 111, 116,

117, 118, 124.

missile generation, 2-54, 59.

mitigation, 1-3, 4; 2-60, 61, 65, 66, 69, 70; 4-1, 4-9, 4-98 to

4-139.

mixing of hydrogen, 2-24.

X-3
nuclear instrumentation, 4-17, 28.

oxygen removal, 4-131.

off-gas system, 3-22.

partial pre-inerting, 2-65.

pathways, 4-53.

post-accident inerting, 2-65.

post-accident inerting, carbon dioxide; 2-61.

pre-, partial-, post-accident inerting with nitrogen, 4-129.

pre-accident inerting, 2-61.

pressure, 4-15, 24, 32, 42.

pressure effects, 4-82, 84.

pressurizer, 3-14, 61.

pressurizer level, 4-15, 34.

pressurizer relief tank, 4-61.

PWR

containment, 4-4,

hydrogen behavior and control, 3-13 to 3-22,4-10 to 4-28.

hydrogen, indications of, 4-30 to 4-40.

hydrogen transport and mixing, 4-51 to 4-67.

hydrogen combustion, 4-81.

radiation synthesis, 3-2, 3.

radiolysis, 1-2; 2-1, 7, 9, 10, 13, 16, 17; 3-1, 2, 3, 4, 6, 27;

4-41, 87, 98.

radiolytic decomposition, 2-7, 9, 10, 67, 68; 3-1, 14, 22, 28.

rcs leakage, 3-18.

reactant coolant activity, 4-44.

reactor coolant sampling, 4-34.

reactor coolant system, 3-14, 22.

reactor vessel water level, 4-17, 24, 34, 42.

recombiners, 4-98.

resin beds, 3-13.

X-4
solubility in hydrogen, 2-19, 24; 3-15.

steam line radiation, 4-40, 47.

steam:hydrogen jet, 1-4; 2-28, 47, 66, 87.

steam:steel reaction, 1-2; 2-1, 7, 9; 4-1, 7.

steam:zirconium reaction, 1-2; 2-1, 2, 16.

steel reactions; 2-1, 7, 11, 15.

sump leak detection, 4-47.

suppression pool temperature, 4-48.

suppression pool water level, 4-29.

temperature effects, 4-84, 87.

temperature, 4-13, 24, 30, 38, 41.

time sequence of hydrogen, 2-16.

venting, 4-113

vessel head vent, 4-53; 111-1.

void detection, II-1.

water sprays, fogs and foams, 2-61.

zirconium reactions, 1-2; 2-1, 2, 16.

zinc, zinc-based paint, 1-2; 2-1, 13, 14.

x-5

U. S. NRC Distribution Contractor (CDSI)

7300 Pearl Street

Bethesda, MD 20014

315 copies for R3

U. S. Bureau of Mines

Pittsburgh Research Center

P. 0. Box 18070

Pittsburgh, PA 15236

Attn: M. Hertzberg

U. S. Nuclear Regulatory Commission (53)

Office of Nuclear Regulatory Research

Washington, DC 20555

Attn: R. T. Curtis

J. T. Larkins (50)

P. Worthington

U. S. Nuclear Regulatory Commission (3)

Office of Nuclear Regulatory Research

Washington, DC 20555

Attn: B. S. Burson

M. Silberberg

R. W. Wright

U. S. Nuclear Regulatory Commission (6)

Office of Nuclear Reactor Regulation

Washington, DC 20555

Attn: J. K. Long

J. F. Meyer

R. Palla

K. I. Parczewski

G. Quittschreiber

D. D. Yue

U. S. Nuclear Regulatory Commission (6)

Office of Nuclear Reactor Regulation

Washington, DC 20555

Attn: V. Benaroya

W. R. Butler

G. W. Knighton

T. M. Su

Z. Rosztoczy

C. G. Tinkler

U. S. Nuclear Regulatory Commission

Phillips Building

7920 Norfolk Avenue

Bethesda, MD 20014

Attn: C. J. Anderson

DIST-I
U. S. Department of Energy

Operational Safety Division

Albuquerque Operations Office

P.O. Box 5400

Albuquerque, NM 87185

Attn: J. R. Roeder, Director

Swedish State Power Board

El-Och Vaermeteknik

Sweden

Attn: Eric Ahlstroem

Berkeley Nuclear Laboratory

Berkeley GL 139PB

Gloucestershire

United Kingdom

Attn: J. E. Antill

Gesellschaft fur Reakforsicherheit (GRS)

Postfach 101650

Glockengasse 2

5000 Koeln 1

Federal Republic of Germany

Attn: Dr. M. V. Banaschik

Battelle Institut E. V.

Am Roemerhof 35

6000 Frankfurt am Main 90

Federal Republic of Germany

Attn: Dr. Werner Baukal

UKAEA Safety & Reliability Director

Wigshaw Lane, Culcheth

Warrington WA34NE

Cheshire

United Kingdom

Attn: J. G. Collier (2)

S. F. Hall

British Nuclear Fuels, Ltd.

Building 396

Springfield Works

Salwick, Preston

Lancs

United Kingdom

Attn: W. G. Cunliffe

DIST-2
AERE Harwell

Didcot

Oxfordshire OX1l ORA

United Kingdom

Attn: J. Gittus, AETB (2)

J. R. Matthews, TPD

Kernforschungszentrum Karlsruhe

Postfach 3640

75 Karlsruhe

Federal Republic of Germany

Attn: Dr. S. Hagen (3)

Dr. J. P. Hosemann

Dr. M. Reimann

Simon Engineering Laboratory

University of Manchester

Ml39PL,

United Kingdom

Attn: Prof. W. B. Hall

Kraftwerk Union

Hammerbacher strasse 12 & 14

Postfach 3220

D-8520 Erlangen 2

Federal Republic of Germany

Attn: Dr. K. Hassman (2)

Dr. M. Peehs

Gesellschaft fur Reaktorsickerheit (GRS mbH)

8046 Garching

Federal Republic of Germany

Attn: E. F. Hicken (2)

H. L. Jahn

Technische Universitaet Muenchen

D-8046 Garching

Federal Republic of Germany

Attn: Dr. H. Karwat

McGill University

315 Querbes

Outremont, Quebec

Canada H2V 3W1

Attn: John H. S. Lee (3)

AEC, Ltd.

Whiteshell Nuclear Research Establishment

Pinawa, Manitoba, Canada

Attn: D. Liu (2)

H. Tamm

DIST-3
National Nuclear Corp. Ltd.

Cambridge Road

Whetestone, Leicester, LE83LH

United Kingdom

Attn: R. May

CNEN NUCLIT

Rome, Italy

Attn: A. Morici

Director of Research, Science & Education

CEC

Rue De La Loi 200

1049 Brussels

Belgium

Attn: B. Tolley

Bechtel Power Corporation

15740 Shady Grove Road

Gaithersburg, MD 20877

Attn: D. Ashton (2)

D. Patton

Sandia National Laboratories

Division 8523

Livermore, CA 94550

Attn: W. T. Ashurst (3)

K. D. Marx

B. R. Sanders

Northwestern University

Chemical Engineering Department

Evanston, IL 60201

Attn: S. G. Bankoff

Brookhaven National Laboratory (2)

Upton, NY 11973

Attn: R. A. Bari (2)

A. Berlad

Mississippi Power & Light

P. 0. Box 1640

Jackson, MS 39205

Attn: D. Bigbee (3)

S. H. Hobbs

J. Richardson

Westinghouse Hanford Company

P. 0. Box 1970

Richland, WA 99352

Attn: G. R. Bloom (2)

L. Muhlstein

R. D. Peak

DIST-4
Combustion Engineering Incorporated

1000 Prospect Hill Road

Windsor, CT 06095

Attn: J. D. Boyajian

Stone & Webster Engineering Corporation

245 Summer Street/9

Boston, MA 02143

Attn: G. Brown

General Public Utilities

Three Mile Island Nuclear Station

P. 0. Box 480

Middletown, PA 17057

Attn: N. Brown

Technology for Energy Corporation

10770 Dutchtown Road

Knoxville, TN 37922

Attn: J. Carter

E. L. Fuller

UCLA

Nuclear Energy Laboratory

405 Hilgard Avenue

Los Angeles, CA 90024

Attn: I. Catton

Argonne National Laboratory

9700 South Cass Avenue

Argonne, IL 60439

Attn: H. M. Chung

General Physics Corporation

1000 Century Plaza

Columbia, MD 21044

Attn,: S. B. Coon (8)

G. J. Dickleman

E. E. Huff

C. Kupiec

W. J. Newell

J. M. Sutch

E. H. Trottier

J. N. Zerbo

University of Wisconsin

Nuclear Engineering Department

1500 Johnson Drive

Madison, WI 53706

Attn: M. L. Corradini

DIST-5
Los Alamos National Laboratory

P. 0. Box 1663

Los Alamos, NM 87545

Attn: H. S. Cullingford (4)

R. Gido

J. Carson Mark

G. Schott

Battelle Columbus Laboratory

505 King Avenue

Columbus, OH 43201

Attn: P. Cybulskis (2)

R. Denning

Power Authority State of NY

10 Columbus Circle

New York, NY 10019

Attn: R. E. Deem (2)

S. S. Iyer

Pennsylvania Power and Light

Susquehanna SES

P. 0. Box 467

Berwick, PA 18603

Attn: R. DeVore

Indiana and Michigan Electric Company

P. 0. Box 458

Bridgman, MI 49106

Attn: J. Dickson

Massachusetts Institute of Technology

Room 1-276

Cambridge, MA 02139

Attn: M. N. Fardis

GPU Nuclear

100 Interpace Parkway

Parsippany, NJ 07054

Attn: J. E. Flaherty

Offshore Power System

8000 Arlington Expressway

Box 8000

Jacksonville, FL 32211

Attn: G. M. Fuls (2)

D. H. Walker

Virginia Electric & Power Company

P. 0. Box 26666

James River Plaza

Richmond, VA 23261

Attn: R. Garner

DIST-6
Electric Power Research Institute

3412 Hillview Avenue

Palo Alto, CA 94303

Attn: J. J. Haugh (5)

R. Leyse

K. A. Nilsson

G. Thomas

L. B. Thompson

Fauske & Associates

627 Executive Drive

Willowbrook, IL 60521

Attn: R. Henry

Virginia Electric & Power Company

Northanna Power Station

P. 0. Box 402

Mineral, VA 23117

Attn: A. Hogg

General Electric Co.

175 Curtner Avenue

Mail Code N 1C157

San Jose, CA 95125

Attn: K. W. Holtzclaw

Duke Power Co.

P. 0. Box 33189

Charlotte, NC 28242

Attn: F. G. Hudson (2)

A. L. Sudduth

Westinghouse Electric Corporation

Monroeville Nuclear Center

Monroeville, PA 15146

Attn: P. Lain

TVA

400 Commerce

W9C157-CD

Knoxville, TN 37902

Attn: Wang Lau

Westinghouse Corporation

P. 0. Box 355

Pittsburgh, PA 15230

Attn: N. Liparulo (3)

J. Olhoeft

V. Srinivas

Sandia National Laboratories

Division 8513

Livermore, CA 94550

Attn: W. J. McLean

DIST-7
Donald C. Cook Nuclear Station

Indiana & Michigan Electric Company P. 0. Box 458

Bridgman, MI 49106

Attn: D. Nelson

Sandia National Laboratories

Division 8214

Livermore, CA 94550

Attn: M. A. Pound

EG&G Idaho

Willow Creek Building, W-3

P. 0. Box 1625

Idaho Falls, ID 83415

Attn: Server Sadik

Zion Nuclear Power Station

Commonwealth Edison Company

Shiloh Blvd. and Lake Michigan

Zion, IL 60099

Attn: C. Schultz

NUS Corporation

4 Research Plac e

Rockville, MD 20850

Attn: R. Sherry

Department of Aerospace Engineering

University of Michigan

Ann Arbor, MI 47109

Attn: Martin Sichel

Cleveland Electric Illuminating Company

Perry Nuclear Plant

10 Center Road

North Perry, OH 44081

Attn: R. Stratman

Attn: Roger Strehlow

505 South Pine Street

Champaign, IL 61820

Applied Sciences Association, Inc.

P. 0. Box 2687

Palos Verdes Pen., CA 90274

Attn: D. Swanson

Purdue University

School of Nuclear Engineering

West Lafayette, IN 47907

Attn: T. G. Theofanous

DIST-8
Acurex Corporation

485 Clyde Avenue

Mountain View, CA 94042

Attn: R. Torok

Bechtel Power Corporation

P. 0. Box 3965

San Francisco, CA 94119

Attn: R. Tosetti

American Electric Power Service Corporation

Room 1158-D

2 Broadway

New York, NY 10004

Attn: K. Vehstedt

Institute of Nuclear Power Operations

1820 Water Place

Atlanta, GA 30339

Attn: S. Visner

Virginia Electric & Power Company

P. 0. Box 402

Mineral, VA 23117

Attn: A. K. White (2)

E. L. Wilson

Thompson Associates

639 Massachusetts Avenue

Third Floor

Cambridge, MA 02139

Attn: T. Woolf

Factory Mutual Research Corporation

P. 0. Box 688

Norwood, MA 02062

Attn: R. Zalosh

Institute of Nuclear Power Operations

1820 Water Place

Atlanta, GA 30339

Attn: E. Zebroski

DIST-9
1131 W. B. Benedick

1512 J. C. Cummings

1513 S. N. Kempka

1513 D. W. Larson

1513 A. C. Ratzel

2513 J. E. Kennedy

2513 J. E. Shepherd

2516 V. M. Loyola

9400 A. W. Snyder

9410 D. J. McCloskey

9411 A. S. Benjamin

9411 F. E. Haskin

9411 V. L. Behr

9412 J. W. Hickman

9412 R. G. Spulak

9415 D. C. Aldrich

9420 J. V. Walker

9421 J. B. Rivard

9422 A. R.-Taig

9422 D. A. Powers

9424 K. D. Bergeron

9425 W. J. Camp

9425 W. Frid

9425 A. J. Wickett

9440 D. A. Dahlgren

9441 M. Berman

9441 A. L. Camp

9441 S. E. Dingman

9441 N. A. Evans

9441 B. W. Marshall, Jr.

9441 L. S. Nelson

9441 P. G. Prassinos

9441 M. P. Sherman

9441 S. R. Tieszen

9441 R. A. Watson

9441 M. J. Wester

9442 W. A. von Riesemann

9444 S. L. Thompson

9444 R. K. Byers

9444 G. G. Weigand

9445 B. E. Bader

9445 V. J. Dandini

9445 W. H. McCulloch

9445 E. H. Richards

3141 L. J. Ericson (5)

3151 W. L. Garner

DIST-10
NRC FORM 335 1. REPORT NUMIER (Assignedby DDCJ

111-81) U.S. NUCLEAR REGULATORY COMMISSION NUREG/CR-2726

BIBLIOGRAPHIC DATA SHEET SAND82-1137

4. TITLE AND SUBTITLE (Add Volume No., if appropriate) 2. (Leave blank)

LIGHT WATER REACTOR HYDROGEN MANUAL 3. RECIPIENT'S ACCESSION NO.

7. AUTHOR(S) J. C. Cummings, A. L. Camp, M. P. 5. DATE REPORT COMPLETED

Sherman, C. F. Kupiec, R. J. Healy, J. S. Caplan, MONTH IYEAR

J. R. Sandhop, J. H. Saunders January 1983

9. PERFORMING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code) DATE REPORT ISSUED

MONTH YEAR Sandia National Laboratories June 1983

Albuquerque, NM 87185 6. (Leave blank)

8. (Leave blank)

12. SPONSORING ORGANIZATION NAME AND MAILING ADDRESS (Include Zip Code)

Division of Accident Evaluation 10. PROJECT/TASK/WORK UNIT NO.

Office of Nuclear Regulatory Research 11.FINNO.

U.S. Nuclear Regulatory Commission

Washington, DC 20555 A1246

13. TYPE OF REPORT PERIOD COVERED (Inclusive dates)

Technical I

15. SUPPLEMENTARY NOTES 14. (Leave olank)

16. ABSTRACT (200 words or less)

A manual concerning the behavior of hydrogen in light water reactors has

been prepared. Both normal operations and accident situations are addressed.

Topics considered include hydrogen generation, transport and mixing, detection,

and combustion, and mitigation. Basic physical and chemical phenomena are

described, and plant-specific examples are provided where appropriate. A wide

variety of readers, including operators, designers, and NRC staff, will find

parts of this manual useful. Different sections are written at different

levels, according to the most likely audience. The manual is not intended to

provide specific plant procedures, but rather, to provide general guidance

that may assist in the development of such procuedures.

17. KEY WORDS AND DOCUMENT ANALYSIS 17a. DESCRIPTORS

17b. IDENTIFIERS/OPEN-ENDED TERMS

18. AVAILABILITY STATEMENT 19. SECURITY CLASS (This report) 21. NO. OF PAGES

Unclassified 124

Unlimited 20. SECURITY CrASý (Thispage) 22. PRICE Unclassified s

NRC FORM 335 111-811

*U.S. GOVERNMENT PRINTING OFFICE: 1983-0-676-027/585


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