NUREG-1364

Regulatory Analysis for the

Resolution of Generic Safety

Issue 106: Piping and the Use

of Highly Combustible Gases

in Vital Areas

U.S. Nuclear Regulatory Commission

Office of Nuclear Regulatory Research

C. C. Graves
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NUREG-1364

Regulatory Analysis for the

Resolution of Generic Safety

Issue 106: Piping and the Use

of Highly Combustible Gases

in Vital Areas

Manuscript Completed: June 1993

Date Published: June 1993

C. C. Graves

Division of Safety Issue Resolution

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555
ABSTRACT

Highly combustible gases such as hydrogen, propane, and

acetylene are used at all nuclear power plants. Hydrogen

is of particular importance because it is stored in large

quantities and is distributed and used continuously in

buildings containing safety-related equipment. Large hydrogen releases at the hydrogen storage facilities or in

these buildings could lead to fires or explosions that might

result in loss of safety-related equipment. This report

gives the regulatory analysis for the resolution of Generic

Safety Issue 106, "Piping and the Use of Highly Combustible Gases in Vital Areas." Scopirig analyses showed that

the risk associated with the storage and distribution of

hydrogen for cooling electric generators at boiling-water

reactors (BWRs), the off-gas system at BWRs, the waste

gas system at pressurized-water reactors (PWRs), and

station battery rooms and portable bottles of combustible

gas used for maintenance at PWRs and BWRs is small.

On the basis of generic evaluations, the NRC staff has

concluded that several possible methods to reduce risk

could provide cost-effective safety benefits at some

plants. However, in view of the observed large differences

in plant-specific characteristics affecting the risk associated with the use of hydrogen, and the marginal generic

safety benefit that can be achieved in a cost-effective

manner, it is recommended that this generic issue be

resolved simply by making these results available in a

generic letter. This information may help licensees in

their plant evaluations recommended by Generic Letter

88-20, Supplement 4, "Individual Plant Examination of

External Events for Severe Accident Vulnerabilities,"

June 28, 1991.

iii NUREG-1364
CONTENTS

Page

Abstract .............................................................................. ii

Executive Summary..................................................................... i

1Statement Of Problem................................................................. 1

1.1 Introduction .................................................................... 1

1.2 Existing Regulatory Requirements and Guidelines ....................................... I1

1.2.1 General .................................................................. 1

1.2.2 Regulations and Regulatory Guides.............................................. 1

1.2.3 Standard Format and Content (NUREG-75/094), Standard Review

Plan (NUREG-0800), and Technical Specifications ................................. 2

1.2.4 Electric Power Research Institute Guidelines...................................... 2

1.2.5 NRC Inspection Program..................................................... 3

1.3 Scope .. ...................................................................... 3

2 Objective .......................................................................... 5

3 Alternative Resolutions..............................................................e- 7

3.1 Hydrogen System Characteristics for Volume Control Tank and Generator Applications .......... 7

3.2 Hydrogen Combustion Characteristics ................................................ 8

3.3 Design Features at Operating Plants Used To Reduce Risk From Hydrogen Systems

for the Volume Control Tank and Generator ........................................... 8

3.4 Alternatives for Volume Control Tank and Generator Hydrogen Distribution Systems

and Hydrogen Storage Facilities ..................................................... 10

4 Technical Findings.............................................. ..................... 13

4.1 Introduction.................................................................... 13

4.2 Review of U.S. Nuclear Power Plant Hydrogen Precursors ................................ 13

4.3 Method of Analysis............................................................... 14

4.3.1 General........................................................... I....... 14

4.3.2 Seismic Events............................................................. 15

4.3.3 Non-Seismic Events......................................................... 16

4.3.4 Damage Mechanisms ........................................................ 16

4.3.5 Hydrogen Explosion Methodology .............................................. 16

4.3.6 Uncertainty Analysis ........................................................ 17

4.4 Analysis of Base Case PWR Plant ................................................... 17

4.4.1 Turbine Building ........................................................... 17

4.4.2 Primary Auxiliary Building.................................................... 18

4.4.3 Hydrogen Storage Facilities................................................... 18

4.4.4 Uncertainty Analysis Results.................................................. 18

4.5 Generic Analysis................................................................. 18

4.5.1 Method.................................................. **''**'''*'**"** 18

4.5.2 Generic Analysis Results ..................................................... 19

4.6 Reductions in Core Damage Frequency for Improvement Alternatives........................ 20

4.7 Dose Consequence Analysis........................................................ 20

4.8 Cost Analysis ................................ i.................................. 20

v NUREG-1364
Page

5 Cost-Benefit A nalysis ...................................................................... 23

5.1 Alternative 1- Take No Action .. ....................................................... 23

5.2 Alternative 2-Install Low Setpoint Excess Flow Valves, Restricting Orifices, or

Check Valves in the Hydrogen Supply Line to the Generator ............................... n 23

5.3 Alternative 3-Provide Manual Makeup of Hydrogen to Generator and

Check Valve or Restricting Orifice at the Generator ........................................ 23

5.4 Alternative 4-Enclose Safety-Related Equipment Located in Turbine Building in

Blast- and Fire-Proof Structures ........................................................ 24

5.5 Alternative 5-Install Low Setpoint Excess Flow Valve or Restricting Orifice in

Hydrogen Distribution System to Volume Control Tank and Provide Hydrogen

D etectors, if N eeded ................................................................. 24

5.6 Alternative 6-Limit the Quantity of Hydrogen Normally Connected to Volume

C ontrol T ank ........................................................................ 24

5.7 Alternative 7-Provide Normally Isolated Supply With Daily Manual Makeup of

Hydrogen to Volume Control Tank ....................................................... 24

5.8 Alternative 8-Relocate Hydrogen Storage Facility To Meet Separation Distance

From Safety-R elated Structures ......................................................... 25

5.9 Alternative 9-Install Blast Deflection Shield at Hydrogen Storage Facility .................... 25

5.10 Alternative 10-Install Hydrogen Analyzer-Actuated Air Intake Louvres at

Safety-Related Air Intakes ............................................................. 25

5.11 O ther A lternatives .................................................................... 25

5.12 Life Extension Considerations .......................................................... 25

5.13 New Reactors ................................................ ...................... 25

6 Decision Rationale ........................................................................ 27

6.1 Introduction ......................................................................... 27

6.2 Relationship to Other Generic Issues .................................................... 28

6.3 Backfit Rule and Plant-Specific Considerations .......................................... 28

6.4 C onclusion .......................................................................... 28

7 R eferences .............................. .............. .................................. 29

TABLES

1 Number of Hydrogen Events at Each Plant Location ......................................... 32

2 G eneric Plant Configurations ............................................................. 32

3 Delta Core Damage Frequency per Reactor-Year for Alternatives (Calculated Mean Values) ....... 33

4 Cost of Modifications Minus Onsite Averted Costs (Point Estimates) for Remaining

Plant Life of 20 Y ears .................................................................... 34

5 Cost of Modifications Minus Onsite Averted Costs.(Point Estimates) for Remaining•

Plant Life of 40 Y ears .................................................................... 35

6 Cost-Benefit Uncertainty Results for Remaining Plant Life of 20 Years .......................... 36

7 Cost-Benefit Uncertainty Results for Remaining Plant Life of 40 Years .......................... 37

NUREG- 1364 vi
EXECUTIVE SUMMARY

This report gives a cost-benefit analysis and supporting

information for U.S. Nuclear Regulatory Commission's

(NRC's) resolution of Generic Safety Issue 106

(GSI-106), "Piping and the Use of Highly Combustible

Gases in Vital Areas." The scope of GSI-106 includes

hydrogen storage facilities and battery rooms at

pressurized-water reactors (PWRs) and boiling-water reactors (BWRs); waste gas systems at PWRs; off-gas systems at BWRs; hydrogen distribution systems for electric

generators at PWRs and BWRs and the volume control

tank (VCT) in the chemical and volume control system at

PWRs; and small, portable bottles of combustible gas

such as hydrogen, propane, and acetylene. The scope

does not include large amounts of liquified petroleum gas

at PWRs and BWRs or the gaseous and liquid hydrogen

storage and distribution systems for hydrogen water

chemistry installations at BWRs covered under Licensing

Issue 136.

Idaho National Engineering Laboratory (INEL) provided

technical assistance for resolving this issue. Scoping and

screening analyses by INEL indicated that the risk associated with the use of hydrogen for electric generators at

BWRs, battery rooms, PWR waste gas systems, BWR

off-gas systems, and portable bottles of combustible gases

was small. Therefore, the more detailed risk and costbenefit analyses by INEL were limited to the hydrogen

storage facilities and to the hydrogen distribution systems

for the VCT and generator at PWRs. These facilities and

distribution systems are not categorized as safety related.

However, because of the use of large quantities of hydrogen for these applications, there is a potential for damage

to safety-related equipment because of hydrogen deflagrations or detonations. The basic regulatory requirement pertinent to GSI-106 is General Design Criterion 3

in Appendix A to Part 50 of Title 10 of the Code of Federal

Regulations.

The hydrogen storage facilities and distribution lines to

the VCT and generator are not near the primary coolant

system or reactor pressure vessel. Hence, hydrogen

deflagrations or detonations would not lead to pipe-break

loss-of-coolant accidents (LOCAs), steam generator

tube ruptures, or anticipated-transient-without-scram sequences. The remaining core damage events in the probabilistic risk analysis for this issue were divided into transients with failure of decay heat removal (DHR) systems

(T/DHR) and transient-induced LOCAs (T/LOCAs).

The T/DHR transients involve loss of all forms of core

cooling and release of reactor coolant at high pressure

from pressurizer power-operated relief valves (PORVs)

or safety valves. The T/LOCA transients involve failure

of reactor coolant system makeup or recirculation following a consequential reactor coolant pump seal failure (as a

result of loss of seal cooling) or a PORV LOCA caused by

a stuck-open PORV or safety valve. This transient includes such events as station blackout and loss of component cooling water or service water.

The failures considered for the storage facility were (1) a

hydrogen tank rupture resulting in a detonation at the

facility and blast damage to a nearby safety-related structure and (2) a pipe failure at the facility with a large

release of unburned hydrogen and ingestion of a flammable hydrogen-air mixture at a safety-related air intake.

Postulated failures of the hydrogen distribution systems

in the auxiliary and turbine buildings were leaks or breaks

with large hydrogen releases and subsequent deflagrations or detonations or smaller undetected leaks resulting

in the buildup and subsequent detonation of large

amounts of trapped hydrogen.

The alternatives considered to reduce a vulnerability in

the storage area included (1) relocation of the storage

area, (2) installation of a blast shield to prevent unacceptable blast damage, and (3) installation of shutters actuated by hydrogen detectors to prevent ingestion of flammable hydrogen-air mixtures at safety-related air intakes.

For the turbine building, the alternatives were (1) use of

excess flow valves and check valves or restricting orifices

to limit flow from the storage facility and generator to a

break in the hydrogen supply line, (2) use of a normally

isolated hydrogen supply with periodic manual makeup

and a check valve or restricting orifice to limit back flow to

the break from the generator, and (3) modifications to

protect safety-related equipment from the consequences

of hydrogen deflagrations or detonations. For the auxiliary building, the alternatives considered were (1) use of

excess flow valves or restricting orifices to limit the flow

rate from large hydrogen supplies to the break, supple-,

mented by hydrogen detectors, if needed; (2) use of limited hydrogen supplies; and (3) use of normally isolated

hydrogen supplies. These alternatives include administrative controls and design features to prevent inadvertent bypass of the flow-limiting devices and limited supplies, to monitor for hydrogen leaks, and to isolate the

hydrogen supply following loss of normal ventilation in

the auxiliary building.

A number of hydrogen events have occurred and continue

to occur in the turbine buildings at U.S nuclear power

plants. In addition, several large fires involving hydrogen

and oil have occurred in turbine buildings at foreign

plants. Hydrogen events in the turbine building are not

expected to be significant sources of risk for most U.S.

plants because (1) vital equipment is not located in the

building or (2) recovery operations for T/DHR transients

can prevent core damage (e.g., feed-and-bleed operations

and recovery of main feedwater). These plants could

suffer significant economic losses because of damage to

plant equipment and replacement power costs, but not

vii NUREG-1364
core damage. However, some plants are considered

susceptible to core damage resulting from hydrogen

events in the turbine building that lead to T/DHR transients or T/LOCA transients (predominantly seal

LOCAs).

There have been a number of leaks but no fires, explosions, or large hydrogen releases involving the hydrogen

system supplying the VCT in the auxiliary building. The

hydrogen events considered potentially significant are

those causing loss of vital equipment and resulting in a

seal LOCA. Licensees of a number of plants have provided corrective measures (e.g., normally isolated or limited supplies, flow-limiting devices, and leak detection

equipment and procedures) to reduce the risk from this

source. However, some plants are considered to be susceptible to core damage because of a large storage facility

and the lack of protective features to prevent large hydrogen releases.

Since industry will continue to use appreciable amounts

of hydrogen to cool the generators and for water chemistry control, the risk from hydrogen fires and explosions

cannot be completely eliminated. However, a blend of

accident-prevention and -mitigation capabilities may reduce the risk from these sources to acceptably low levels.

Examples of preventive measures include the use of excess flow valves or restricting orifices to reduce the possibility of the release of large quantities of hydrogen following a piping leak or rupture and administrative controls or

hydrogen detectors to detect leaks. In regard to mitigation, standard fire protection measures can go far to reduce the consequences of a hydrogen fire or explosion.

Although the adequacy of fire protection measures is

outside the scope of GSI-106, the staff notes that these

measures can include accident-mitigation strategies for

turbine building fires such as (1) early elimination of the

hydrogen sources by isolating the storage facility and

venting and purging the generator with carbon dioxide

and (2) controlling the pumping of lubricating oil that

could spread the fire.

For the hydrogen distribution systems in the auxiliary and

turbine buildings, the generic estimates of the reduction

in core damage frequency obtained with the alternatives

for the distribution systems ranged up to 05E-5/reactoryear (RY) to 1E-5/RY. However, risk reductions at individual plants may be significantly larger than the generic

values because of the proximity of the hydrogen distribution system to vital equipment. The estimated costs for

several of the proposed alternatives are small. Hence,

when considered individually, several of the alternatives

analyzed for reducing the risk for this issue would be cost

effective in meeting the $1000/person-rem guideline.

The analyses for these alternatives indicate cost savings

when onsite averted costs are included. However, in view

of the observed large differences in plant-specific characteristics affecting the risk associated with the use of hydrogen, and the marginal generic safety benefit that can

be achieved in a cost-effective manner, it is recommended

that this generic issue be resolved simply by making these

results available in a generic letter. This information may

help licensees in their plant evaluations recommended by

Generic Letter 88-20, Supplement 4, "Individual Plant

Examination of External Events for Severe Accident Vulnerabilities," June 28, 1991.

NUREG-1364 viii
1 STATEMENT OF PROBLEM

1.1 Introduction

Combustible gases such as hydrogen, acetylene, and propane are used at all nuclear power plants. Of these gases,

hydrogen is of principal interest because it is stored in

large quantities and is distributed and used in some

safety-related buildings during normal plant operation. It

is provided as a coolant for the main electric generators at

both pressurized-water reactors (PWRs) and boilingwater reactors (BWRs). It is also fed to the volume control tank (VCT) in the chemical and volume control system of PWRs to reduce oxygen in the reactor coolant

system. The hydrogen for these purposes is usually stored

as a high-pressure gas [e.g., 1500 to 2400 pounds per

square inch gage (psig)] in large storage facilities and is

distributed to the auxiliary and turbine buildings through

small-diameter field-run piping. Failure of the piping or

bottles/cylinders at the storage area could result in flammable hydrogen-air mixtures at safety-related air intakes

or fires or detonations that could damage safety-related

structures. Hence, the storage area should be located at a

safe separation distance from these structures and intakes. The distribution piping to the electric generators in

the turbine building generally would not be near safetyrelated equipment. However, some plants have safetyrelated equipment such as motor control centers, cables,

switchgear, and diesel generators in, or adjacent to, the

turbine building. In PWRs, the auxiliary building, which

contains the VCT, also contains most of the components

of the safety-related systems at the plant. Hence, leaks'or

breaks in the piping or components of the hydrogen distribution system in the auxiliary building at PWRs or in the

turbine buildings at some PWRs and BWRs could result

in fires or explosions that represent a threat to plant

safety because of potential damage to safety-related

equipment. Capacities of individual hydrogen bottles or

cylinders at the storage facilities range from about 200 to

10,000 standard cubic feet (scf) of hydrogen, while total

amounts of hydrogen in the storage facility may be more

than 100,000 scf. This represents a significant potential

energy release. Hydrogen gas also represents, to a lesser

degree, a potential threat to safety-related equipment

because of its presence in PWR waste gas systems, BWR

off-gas systems, station battery rooms, and small bottled

supplies in plant buildings at PWRs and BWRs.

A number of events involving hydrogen have occurred at

U.S. and foreign nuclear plants. These have ranged from

detection of concentrations above the lower flammability

limit in the waste gas system and leaks in the auxiliary

building to explosions and very large fires in the turbine

building. Although no safety-related equipment apparently.has been lost to date in the United States because of

a hydrogen event, the occurrence of these precursors

requires an evaluation of the risk associated with the use

of hydrogen in nuclear plants.

1.2 Existing Regulatory Requirements

and Guidelines

1.2.1 General

Because the structures, systems, and components involved in the use of hydrogen at nuclear plants are -not

classified as safety related, they do not have to be seismic

Category I, environmentally qualified, or redundant.

However, hydrogen fires or explosions or the release of

unburned hydrogen could result in damage to nearby

safety-related equipment and should be considered in

setting design and operational requirements.

1.2.2 Regulations and Regulatory Guides

The basic regulatory requirement dealing with the storage, distribution, and use of combustible gases at nuclear

power plants is General Design Criterion (GDC) 3, "Fire

Protection," in Appendix A to Part 50 of Title 10 of the

Code of Federal Regulations (10 CFR Part 50). This criterion states, in part, that "structures, systems, and components important to safety shall be designed and located to

minimize, consistent with other safety requirements, the

probability and effect of fires and explosions.,,

Section 50.48 of 10 CFR requires that every plant have a

*fire protection plan that satisfies GDC 3. The plan should

include descriptions of special features needed to limit

damage to structures, systems, and components important to safety so that the capability to safely shut down the

plant is ensured.

Appendix R to 10 CFR Part 50 gives the fire protection

program requirements to meet GDC 3. It includes new

requirements and guidance dealing with fire protection

measures to limit the damage to systems important to safe

shutdown and the use of alternative or dedicated capability for areas where fire protection features cannot ensure

safe shutdown, should a fire occur in that area. Appendix R applies to all plants licensed to operate before

January 1, 1979, except to the extent described in 10 CFR

50.48. Revision 2 of Branch Technical Position CMEB

9.5-1 in Section 9.5.1, "Fire Protection Program," of

NUREG-0800 contains revised guidelines, which include

the acceptance criteria in Appendix R and 10 CFR 50.48,

for implementing GDC 3 for later plants.

In accordance with 10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety for

Nuclear Power Plants," non-safety-related electric equipment should be environmentally qualified if its failure

1 NUREG-1364
under postulated environmental conditions could prevent safety-related equipment from accomplishing its

safety function.

NRC Regulatory Guide 1.29, "Seismic Design Classification," states that parts of non-seismic Category I structures, systems, or components whose continued function

is not required, but whose failure could reduce the functioning of seismic Category I structures, systems, or components to an unacceptable safety level or cause incapacitating injury to control room occupants, should be

designed and constructed so that a safe shutdown earthquake would not cause such a failure.

1.2.3 Standard Format and Content

(NUREG-75/094), Standard Review

Plan (NUREG-0800), and Technical

Specifications

1.2.3.1 Standard Format and Content

(NUREG-75/094)

NUREG-75/094 does not have a separate section describing the hydrogen storage facilities and distribution

systems. Hence, most final safety analysis reports

(FSARs) do not give this information. However, the staff

has provided some guidance on acceptable approaches

for meeting GDC 3 with respect to the scope of Generic

Safety Issue (GSI) 106 in Standard Review Plan (SRP)

(NUREG-0800) Section 9.5.1, "Fire Protection Program," and in SRP Section 11.3, "Gaseous Waste Management Systems."

1.2.3.2 Standard Review Plan (NUREC-0800)

Branch Technical Position (BTP) CMEB 9.5-1, Revision 2, in SRP Section 9.5.1, Revision 2, contains some

guidance concerning

* the use of excess flow valves and other protective

features for the distribution of hydrogen in safetyrelated buildings

* alarms and annunciation for fire detection and loss

of ventilation in safety-related battery rooms

0 barrier design features and possible additional defense in depth in the turbine building to protect

against fires in the turbine oil system or the generator hydrogen cooling system

The guidance on the hydrogen distribution systems includes the use of seismic Category I piping, sleeved piping

with the outer pipe vented directly to the atmosphere, or

excess flow check valves sized so that the hydrogen concentration in affected areas does not exceed 2 volume

percent. Because these SRP revisions were published in

July 1981, the staff did not use this guidance in its review

of some plants.

SRP Section 11.3 (Revision 2) provides guidance on design features in gaseous waste management systems for

both PWRs and BWRs to satisfy GDC 3 with respect to

hydrogen explosions. For systems designed to withstand

the effects of a hydrogen explosion, SRP Section 11.3

specifies analysis of the process gas stream for potentially

explosive conditions and annunciation both locally and in

the control room. For a system not designed to withstand

the effects of the explosion, SRP Section 11.3 specifies

two independent gas analyzers operating continuously to

provide two independent measurements. The gas analyzers should annunciate alarms both locally and in the control room. Guidance also is given for systems with recombiners and for equipment testing intervals.

1.2.3.3 Technical Specifications

The technical specifications for most BWRs and PWRs

are expected to include coverage of the explosive gas

monitoring instrumentation for gaseous radioactive

waste. NRC Generic Letter 89-01, which addresses the

relocation of portions of the Radiological Effluent Technical Specifications to the Offsite Dose Calculation Manual, states that existing requirements for explosive gas

monitoring instrumentation for waste gas systems will be

retained in the technical specifications. It also provides

model specifications for retaining existing requirements

for explosive gas monitoring instrumentation that apply

on a plant-specific basis.

1.2.4 Electric Power Research Institute

Guidelines

The recent hydrogen water chemistry (HWC) installations for BWRs that were considered under Licensing

Issue 136, "Storage and Use of Large Quantities of Cryogenic Combustibles on Site," involve the storage of larger

quantities of hydrogen and higher average consumption

rates than those encountered in typical applications for

hydrogen supplied to the VCT in PWRs and the main

generator in all plants. In 1987 (letter from J. Richardson

dated July 13, 1987), the staff approved new guidelines by

the Electric Power Research Institute (EPRI, 1987) for

these HWC installations. The guidelines describe several

system design features and procedures for the prevention

or mitigation of the consequences of fires, explosions, or

unburned leaks of hydrogen that are in addition to, or

more restrictive than, those given in SRP Section 9.5.1,

Revision 3, and BTP CMEB 9.5-1, Revision 2. They include

* new relations for separation distances between the

hydrogen storage location and safety-related structures and air intakes that often give much larger

separation distances than the values from the

NUREG-1364 2
National Fire Protection Association cited in SRP

Section 9.5.1

" color-coded piping and warning signs (American National Standards Institute Standards A13.1 and

Z35.1)

* excess flow check valves, system trips, and other design features (e.g., hydrogen detectors) to mitigate

the consequences of leaks or breaks in hydrogen

lines and to perform the intended design function

with or without normal ventilation and, as a minimum, a system trouble alarm and/or annunciator in

the main control room

" periodic testing of excess flow valves used to protect

against breaks in hydrogen lines and components

In the letter of July 13, 1987, from J. Richardson, transmitting the safety evaluation report on the EPRI guidelines, the staff recommended that the guidelines be extended to include hydrogen systems supplying hydrogen

to the VCT in PWRs and for cooling the main electric

generators in PWRs and BWRs. Although EPRI has not

done so, the staff used the separation distance criteria in

EPRI's guidelines as an initial screening mechanism during plant surveys made in this study.

1.2.5 NRC Inspection Program

The NRC Light Water Reactor Inspection Program has

several inspection requirements pertinent to GSI-106.

Inspection Procedure 64704, "Fire Protection Program,"

which specifies an inspection frequency of once every

other systematic assessment of licensee performance cycle, is required for all operating plants. This procedure

includes reviews of control of combustible material, reduction of fire hazards, and fire control capabilities. Sites

for storing combustible gas and hydrogen lines in safetyrelated areas are specifically identified in this inspection

procedure. In addition to the plant and NRC inspections,

this procedure covers three audits required under the

technical specifications: (1) an annual audit by the offsite

fire protection specialist, (2) a 2-year audit by the licensee's quality assurance organization, and (3) a 3-year audit

by a consulting fire protection firm.

1.3 Scope

In 1981, the staff identified GSI-106 in NUREG-0705,

"Identification of New Unresolved Issues in U.S.

Commercial Nuclear Power Plants." The work on this

issue was directed initially at the risk associated with the

distribution of hydrogen to the VCT in the safety-related

auxiliary building of PWRs. In 1986, the staff considered

expanding the scope to include the new concerns associated with the storage of large quantities of liquid propane

and the cryogenic storage of hydrogen and oxygen at

reactor sites. Instead of expanding the scope of GSI-106,

the staff included the new concerns in Licensing Issue

136, "Storage and Use of Lirge Quantities of Cryogenic

Combustibles on Site" (NUREG-0933). Licensing Issue

136 addressed the use of large quantities of

0 hydrogen and oxygen in permanent hydrogen water

chemistry (HWC) installations being installed at

BWRs to reduce oxygen in BWR piping to control

intergranular stress corrosion cracking

0 liquified propane in, for example, proposed systems

for the incineration of radioactive waste

In 1987, the staff accepted licensing topical report EPRI

NP-5283-SR-A (EPRI, 1987), which provided guidelines

for these HWC installations. With the issuance of staff

safety evaluation reports on both concerns, Licensing

Issue 136 was closed in 1988 (see NUREG-0933).

A significant number of events involving combustible

gases have occurred at nuclear plants and ranged from

detection of flammable mixtures and unburned leaks to

explosions and fires in turbine buildings. In April 1987,

the staff issued Information Notice 87-20 to the licensees

of all plants as the result of a reported leak in the hydrogen piping in the 'auxiliary building at the Vogtle nuclear

plant; this leak was caused because a conventional globe

valve was used instead of a valve designed specifically for

hydrogen. Such notices are not requirements, but each

licensee is expected to review them for applicability to its

facility and for consideration of applicable actions.

In another instance, during a visit to the Trojan nuclear

plant in April 1989, NRC inspectors noted that the hydrogen storage facility was located on the roof of the control

building near air intakes. This increased concerns about

similar hazards at other nuclear plants. As a result, the

staff issued Information Notice 89-44. In addition, it

asked each NRC regional office to supply information on

the size of hydrogen tank farms and the separation distance from safety-related structures and air intakes at all

plants in that region.

As a result of these and other events involving combustible gases, the staff expanded the scope of GSI-106 in

1989 to include both PWRs and BWRs. The expanded

scope included risk from

* the storage and distribution of hydrogen for the

VCT in PWRs and the main generators in PWRs and

BWRs

* other sources of hydrogen such as battery rooms, the

waste gas system in PWRs, and the off-gas system in

BWRs

* small quantities of hydrogen and other combustible

gases such as propane and acetylene that would be

used for maintenance, testing, and calibration

3 NUREG-1364
The scope did not include risk from the hydrogen storage

(gaseous or liquid) and distribution systems for HWC

installations at BWRs or the larger quantities of liquified

petroleum gas that were considered under Licensing

Issue 136.

NUREG-1364 4
2 OBJECTIVE

The purpose of the Generic Safety Issue 106 program is to

evaluate the risk associated with the use of combustible

gases for certain applications at nuclear power plants and

to examine the cost effectiveness of alternative measures

for reducing this risk.

Probabilistic risk analysis techniques were used to estimate the reduction in core damage frequency (CDF) and

the cost effectiveness of the alternative actions. For Unresolved Safety Issue (USI) A-45, "Shutdown Decay Heat

Removal Requirements," the staff recommended in

NUREG-1289 that the frequency of events related to

decay heat removal failure leading to core damage should

be reduced to -such a level [about 1.OE-5/reactor-year

(RY)] that the probability of such an accident in the next

30 years would be about 0.03 based on a population of

about 110 plants. A similar objective (1.OE-5/RY) was

noted in USI A-44, "Evaluation of Station Blackout Accidents at Nuclear Power Plants," and in GSI-130, "Essential Service Water System Failures at Multi-Unit Sites."

The application of such objectives to GSI-106 was limited

to using these insights as general guidelines for the decision process described in Section 6. Rigid application of

such a quantitative objective to define an absolute requirement is discouraged. This is consistent with the policy guidance in NRC's "Safety Goals for the Operation of

Nuclear Power Plants" and in the memorandum from C.

J. Heltemes dated August 20, 1991. Similarly, the criterion for cost effectiveness was assumed to be $1000 per

person-rem averted.

5 NUREG-1364
3 ALTERNATIVE RESOLUTIONS

As the result of scoping and screening analyses, the possible significant sources of risk associated With combustible

gases within the scope of GSI-106 were reduced to the

following areas (see Section 4.1):

(1) the hydrogen distribution systems for the volume

control tank (VCT) and the electric generator at

PWRs

(2) the hydrogen storage facilities at PWRs

3.1 Hydrogen System Characteristics

for Volume Control Tank and

Generator Applications

The hydrogen distribution systems for VCT and generator applications at PWRs have several characteristics pertinent to the selection of corrective measures to reduce

risk. For both applications there is a relatively small average hydrogen consumption rate and an infrequent need

for the use of larger quantities over short intervals. In

addition, the normal operating conditions and gas volumes result in the storage of large quantities of hydrogen

in the generator, several hundred standard cubic feet (scf)

in the VCT, and negligible quantities in the piping.

The average hydrogen flow rate to the VCT over the long

term is probably less than about 0.1 scf per minute (scfm)

for plants without a recombiner in the waste gas system

and is about 1 scfm for plants with recombiners. Larger

short-term maximum flow rates occur during manual adjustments when hydrogen is added to the VCT, while

maximum local flow rates (corresponding to a postulated

loss of letdown flow from the reactor coolant system) may

be over 20 scfm for some plants. During startup from a

cold shutdown, over 700 scf of hydrogen may be needed to

purge the VCT and obtain the desired hydrogen conditions in the VCT and reactor coolant.

The hydrogen used to cool the electric generator is circulated through integral water-cooled heat exchangers by

fans located near the ends of the rotor. Shaft oil seals

prevent the entry of air and the escape of hydrogen. A

carbon dioxide system is provided to purge hydrogen from

the generator before maintenance and air from the generator before adding hydrogen after maintenance. The

average hydrogen consumption rate, which increases with

generator size, is probably less than about 0.4 scfm for

systems with small leakage. Larger short-term flow rates

will occur when hydrogen is added to a generator that is

normally isolated from the supply. The volume occupied

by the hydrogen in generators ranges from about 3500 to

6000 cubic feet and is maintained at pressures of about 85

psia. Hence, after generator maintenance, over 35,000 scf

may be required for purging carbon dioxide and reaching

the desired hydrogen purity and pressure conditions. Assuming a 6-hour period for this infrequent purging and

filling operation, an average flow rate of about 100 scfm

would be needed.

The hydrogen supply line leads through the turbine building to the final pressure regulator at a hydrogen control

station located below the generator and one or two levels

below the operating deck. This station also has controls

for venting and purging and instrumentation for monitoring generator conditions. At the bottom of the typical

generator, there are connections for about nine lines

leading to the control station (gas sample lines, carbon

dioxide and hydrogen supply lines, and drain lines). Leaks

or breaks in any of these lines would result in large releases of hydrogen, which would not be limited by the flow

restriction provided by pressure regulators. In addition,

the seal oil unit that supplies oil to the generator shaft

seals is located on one of these levels.

The low average consumption rates for both the VCT and

generator mean that monitoring consumption rates with

flow totalizers or changes in system pressure with time

(e.g., for small supplies or operation with normally isolated VEFS or generators) couldcbe a useful procedure for

detecting hydrogen leaks in some cases. This would be

supplemented by walkdowns of the systems with hydrogen detectors. Another approach is the use of permanent

hydrogen detectors with alarms.

For the VCT, the very low average consumption rates for

some plants are such that a limited amount of hydrogen

could supply the consumption needs for an appreciable

time. The low short-term maximum flow rates also indicate that small restricting orifices or excess flow valves

(e.g., excess flow check valves or valves actuated by signals

from flow elements) with low setpoints might be used to

limit the hydrogen release rate so that the average concentrations in local areas with normal ventilation are kept

well below the lower flammability limit of 4 volume percent. A value of 2 volume percent is recommended in

SRP Section 9.5.1, Revision 3 (NUREG-0800).

For generators with normal leakage, the daily consumption of hydrogen is probably less than a few percent of the

hydrogen stored in the generator. Hence, the slow reduction in generator pressure with normal hydrogen consumption would permit isolation of the hydrogen supply

except for periodic (e.g., once-a-shift) adjustments to

keep within required hydrogen conditions for the generator load. An alternative approach is to provide a small

flow-limiting device with a bypass section for use on the

7 NUREG-1364
infrequent occasions when higher flow rates are needed

(e.g., after generator maintenance).

3.2 Hydrogen Combustion

Characteristics

Immediate ignition of the hydrogen released from a leak

or break results in a diffusion flame that could damage

nearby equipment because of thermal effects. Any delay

in ignition could result in the buildup of hydrogen-air

mixtures, which could then ignite and lead to either

deflagrations or detonations. Deflagrations are premixed

flames that advance into the adjacent unburned mixture

at subsonic speeds. If the deflagration speed is much less

than sonic speed, thermal damage to equipment with

little mechanical damage could occur. However, the

flame can be accelerated (e.g., by turbulence produced by

flow over obstacles in the flame path). As noted in

NUREG/CR-5275, if the deflagration speed increases to

over 100 m/sec, shock waves are generated. If the

deflagration speed is large enough, a deflagration-todetonation transition (DDT) could occur. Hydrogen detonations, which are premixed flames advancing into the

unburned mixture at supersonic speeds, can cause thermal damage and extensive mechanical damage because of

the associated overpressures and impulses (NUREG/

CR-5275).

As noted in Technical Note 690 (National Bureau of

Standards, 1976), the wide flammability limits for

hydrogen-air mixtures (about 4 to 74 volume percent for

upward flame propagation and 9 to 73 volume percent for

downward propagation) and low ignition energies suggest

a high probability of ignition of flammable mixtures from

random ignition sources. Ignition sources such as small

sparks and flames can initiate deflagrations, whereas direct initiation of a detonation in a detonable mixture

usually requires much stronger (shock wave) ignition

sources such as a high-energy spark or explosive

(NUREG/CR-2475). The required energy source for direct initiation of a detonation is relatively low for a

stoichiometric mixture (about. 30 volume percent hydrogen in air) but increases rapidly as the concentration approaches the detonation limits. Since the presence of

high-energy sources needed to initiate detonations near

the lean limit is unlikely in the auxiliary building or at

distribution levels of the turbine building, deflagration

would be the most likely initial mode of combustion for

this range of hydrogen concentrations. Depending on

such factors as local hydrogen concentrations and compartment geometries, DDT could then be the mechanism

for initiating local detonation.

The lean detonation limit for hydrogen-air mixtures at

standard conditions is 18 volume percent for laboratory

scale tests (National Bureau of Standards, 1976). However, tests and analysis indicate lower limits for larger

volumes (e.g., NUREG-1370, NUREG/CR-2475, and

NUREG/CR-5275). NUREG/CR-5275 describes tests

on the effects of hydrogen concentration, obstacles, and

transverse venting on flame acceleration and DDT that

were conducted in the FLAME facility, a half-scale model

of the upper plenum volume of a PWR ice condenser

containment. These tests showed that flame acceleration

at 12 volume percent was negligible. DDT was first observed at 15 volume percent, with no transverse venting

but with obstacles present. However, with no obstacles

and a large degree of transverse venting, DDT did not

occur at 28 volume percent. NUREG/CR-5275 provides

a methodology for a qualitative classification of the potential for DDT, given an estimate of the local hydrogen

concentration and knowledge of local compartment

geometry. Local detonations in large, dry PWR containments are discussed in a memorandum from

E. S. Beckjord dated March 24, 1992; NUREG-1370; and

NUREG/CR-5662.

Predictions of the consequences of postulated releases

from hydrogen distribution lines are strongly dependent

on plant-specific compartment geometries and equipment locations and involve large uncertainties in predictions of such factors as local hydrogen concentrations,

ignition locations, DDT, and subsequent blast damage.

For example, inadequate mixing and stratification may

result in local detonable mixtures even though average

hydrogen concentrations are below the detonation limit.

In view of these uncertainties, the alternatives considered

for reducing risk primarily involve ways to prevent sign ificant hydrogen releases.

3.3 Design Features at Operating

Plants Used To Reduce Risk From

Hydrogen Systems for the Volume

Control Tank and Generator

Information from final safety analysis reports, supplemented by information from plant visits and surveys, indicated significant plant-to-plant differences in existing hydrogen system design features to reduce the risk from

hydrogen line leaks or breaks. Some plants have one large

storage facility to supply hydrogen for both the VCT and

the generator but do not provide excess-flow protection

(NUREG/CR-3551). Hence, in the event of a system

failure, a potential exists for discharging large amounts of

hydrogen into the auxiliary building or turbine building

before the storage facility can be isolated manually. In this

case, the maximum release rate probably is controlled by

the flow restriction provided by the pressure regulators

operating in .parallel at the storage facility. The normal

ventilation air flow rates for the building as a whole are

large. However, the hydrogen release rates as a result of

these leaks or breaks could be too large for the dilution

capability of normal ventilation in the local building areas

involved and could result in estimated local average

NUREG-1364 8
hydrogen concentrations that are well into the detonable

range, particularly if allowance is made for nonuniform

mixing. For such releases, damage to compartment walls

and blast wave and flame front propagation via ventilation ducts, fire barriers, and passageways could result in

loss of safety-related equipment.

Undetected leaks might also result in the buildup of unacceptable amounts of trapped hydrogen in overhead regions with an inverted-pocket geometry and inadequate

local ventilation because of low ventilation rates or inadequate inlet and exhaust locations. Hydrogen has a density

only about 7 percent of air density and has a large diffusion coefficient. Hence, small leaks at lower elevations of

a compartment might be expected to mix quickly with the

air and be removed with normal room ventilation. However, hydrogen from moderate releases could stratify and

collect in overhead areas. In addition, much of the hydrogen distribution piping is located in overhead areas.

As a result of a review of more than 400 industrial accidents (nuclear and non-niclear) involving hydrogen, Factory Mutual Research Corporation recommended in its

report that hydrogen safety standards emphasize the importance of hydrogen monitoring for leak detection. The

basic approach of the National Aeronautics and Space

Administration (NASA) to reducing risk from hydrogen

fires or explosions includes (1) prevention of leaks,

(2) monitoring to detect leaks quickly and take corrective

actions, (3) prevention of accumulations of leaked hydrogen by plentiful ventilation, and (4) elimination of ignition

sources, but assuming that ignition sources are present

(NASA, 1968 and 1992, and the hydrogen safety standard* to be published by NASA).

At typical gaseous hydrogen storage facilities, a pressure

control station with two pressure regulators operating in

parallel is used to decrease the hydrogen supply pressure

(typical maximum pressures from 1500 to 2400 psig) to

about 100 psig in the distribution lines to the auxiliary and

turbine buildings. Overpressure protection for these lines

is provided by relief valves discharging outside. Pressure

regulators are then used to control pressures.at about 20

psig at the VCT and 70 psig at the generator. At some

plants with a single hydrogen storage facility for one or

two units, excess flow valves are provided downstream of

the pressure control station at the storage facility. However, the excess flow valve has a high setpoint (e.g., shutoff flow rates. from 80 to 330 scfm) that was probably

selected to meet the flow rate requirement for the infrequent purging and charging operation for the electric

generator. Hence, breaks or leaks in the distribution lines

for the VCI" or the generator with flow rates up to these

shutoff values would not be stopped by this excess-flow

protection. Other plants use separate, small storage facilities that are normally connected to the VCT by means

*NSS/fP-1740.1 1.

of a pressure regulator or operate with the VCT normally

isolated from the hydrogen supply, except for periodic

(e.g., daily) manual adjustments of hydrogen conditions.

At one plant a single 200-scf hydrogen bottle is connected

to the VCT, but is isolated except for daily adjustment of

conditions in the VCT. At a number of plants, small

flow-limiting devices (maximum flow rates ranging from

about 8 to 25 scfm) are used to limit flow to the VCT.

These maximum flow rates were usually low enough so

that normal ventilation in the compartment with the leak

or break would result in an average compartment hydrogen concentration below the lower flammability limit.

One plant combines a small storage facility for the VCT

with a small restricting orifice. The configurations to limit

flow rate include excess flow check valves, restricting

orifices, and valves controlled by a flow element in the

VCT line. The valves controlled by the flow element in

the VCT line fail closed and are also closed on an auxiliary

building isolation signal when normal ventilation air flow

to the building is lost. At some plants secondary pressure

control stations are located outside the turbine and auxiliary buildings. Since normal leakage results in small rates

of decrease in generator pressure, a number of plants also

operate with periodic manual makeup to the generator.

Other features include seismic piping supports, seismic

Category I piping, or sleeved piping for portions of the

distribution system with the guard space between the

pipes vented directly outside the building. At a few plants,

the hydrogen lines had been relocated after start of commercial operation to minimize the amount of piping in the

buildings.

Color coding is useful during walkdowns for leak tests and

for avoiding inadvertent damage to hydrogen piping. Information on color coding of hydrogen piping was obtained during visits by Idaho National Engineering Laboratory (INEL) personnel to 13 plants in 1989 and from a

staff survey. Of the 36 plants covered, 20 use color coding

for the VCT and generator lines, 2 use color coding only

for the generator lines, 1 uses color coding only for a

hydrogen water chemistry (HWC) installation, and 13 do

not use color coding.

The amount of hydrogen in the hydrogen supply piping is

very small and can be neglected (e.g., 100 feet of 1-inchdiameter supply piping contains only a few standard cubic

feet of hydrogen). However, a few hundred standard cubic feet could be released from the VCT as it depressurizes, and about 15,000 to 25,000 scf could be released

from generators. The final pressure regulators may limit

backflow to breaks in the hydrogen supply line from these

sources, but could be backed up by check valves. The use

of excess flow check valves to stop flow from the hydrogen

storage facility, supplemented by check valves in the lines

near the VCT and the generator to stop the backflow of

hydrogen in these components to leaks or breaks in the

hydrogen supply lines in the auxiliary and turbine

buildings, was proposed in a recent individual plant

9 NUREG-1364
examination (IPE) for a PWR with the hydrogen control

station on the level below the generator (Yankee Atomic

Electric Company, 1989). This approach protects the supply line, reduces the contribution of the storage facility to

releases, and limits potential locations for large releases

to the generator itself (e.g., shaft oil seals) and to the

sample, drain, and other lines below the generator.

In summary, alternative design features for limiting the

consequences of larger breaks or leaks in the hydrogen

supply lines for the VCT and generator that have been

used or considered for use at operating plants and do not

require major system changes involve several basic approaches:

* Limit Supply Amount-use a limited supply normally connected to the VCT to restrict the total

amount that could be released during a single event

• Limit Flow Rate From Supply-limit the maximum

flow rate from the storage facility to a line break so

that normal ventilation would keep local average hydrogen concentrations below the lower flammability

limit

" Isolate Storage Facility-limit the available time

when discharge from the storage facility could occur

by using normally isolated storage facilities

* Limit Backflow of Contained Hydrogen-use check

valves or restricting orifices if needed to limit backflow of hydrogen to breaks in the supply lines from

the generator and possibly the VCT

These features would reduce the frequency of occurrence

and/or the consequences of events involving larger breaks

or leaks in the supply line that result in hydrogen release

rates so large that there is insufficient time for corrective

manual actions. The features also tend to reduce the

significance of buildup of trapped hydrogen because of

the low limits on hydrogen release rates or total amounts

of hydrogen available for release during an event and the

additional time available for corrective actions. In the

auxiliary building, trapped hydrogen would probably be

limited to the immediate areas containing the hydrogen

system because of the additional dilution by ventilation in

adjoining compartments.

Even with low leak rates, significant quantities of hydrogen are involved. For example, a leak rate of 10 scfm

probably results in an average concentration in rooms

with normal ventilation that is well below the lower flammability limit for hydrogen-air mixtures, but involves the

release of nearly 5000 scf per shift. Hence, any judgments

on the significance of trapped hydrogen at a particular

plant must be based on plant-specific information such as

local confirmed ventilation rates and on construction features obtained from a walkdown of the areas containing

the hydrogen piping and components.

Methods for leak detection that have been used at plants

include monitoring for abnormal consumption of hydrogen using integrating flow meters or monitoring system

pressure changes with time (for small or isolated supplies), and use of permanent and/or portable hydrogen

detectors. If normally isolated or limited hydrogen supplies are used, the rate of decrease in pressure could be

appreciable for relatively small leaks and the total

amount that could be leaked without early corrective

action would be limited. For normally isolated hydrogen

supplies, existing pressure-sensing instrumentation and

low-pressure or other alarms could be used for the VCT

and the generator. For the limited supplies, the final

pressure regulator to the VCT would maintain VCT pressure until the supply was nearly exhausted. However,

existing instrumentation and alarms could be used for

monitoring the supply pressure. For large supplies, automatic detection such as the use of permanent hydrogen

detectors with alarms to the control room may be needed

to identify significant leaks in time for corrective action.

This type of detection is covered in the EPRI guidelines

(EPRI, 1987) and the NASA approach (NASA, 1992, and

the hydrogen safety standard to be published by NASA).

3.4 Alternatives for Volume Control

Tank and Generator Hydrogen

Distribution Systems and

Hydrogen Storage Facilities

The features that have been used or proposed for use in

operating plants were considered in selecting alternatives

for the VCT and generator hydrogen systems. For the

hydrogen storage facilities, the relocation of the storage

facility to increase the separation distances was evaluated

for cases involving safety-related air intakes and structures. The addition of a blast shield was selected as a

means of reducing the consequences of a detonation at

the facility. Automatic closure of air intakes was selected

as a means of preventing the ingestion of a flammable

mixture at the intake following rupture of a hydrogen

header at the storage facility.

The following alternatives were evaluated:

Alternative 1-Take No Action

Under this alternative there Will be no new regulatory

requirements. Consistent with existing regulations, this

alternative does not preclude a licensee, or an applicant

for an operating license, from proposing to the NRC staff

design changes intended to reduce the risk associated

with the hydrogen storage and distribution systems on a

plant-specific basis.

NUREG-1364 10
Alternative 2-Install Low Setpoint Excess Flow Valves,

Restricting Orifices, or Check Valves in Hydrogen Supply

Line to the Generator

This alternative provides protection against leaks or

breaks in the hydrogen supply line from the point of entry

into the turbine building to the hydrogen control station

below the generator, including any branches from this

line to other buildings. A low setpoint excess flow valve or

restricting orifice is provided in the supply line outside the

building to limit flow from the storage facility to the leak

or break. A check valve or restricting orifice could be

provided in the supply line near the generator, if needed

to prevent backflow from the generator to the leak or

break. The alternative also limits flow from the storage

facility to leaks or breaks in the piping near the generator

and at the generator itself. Preoperational testing and

periodic retesting of the excess flow valve to ensure that it

will function properly and administrative controls or design features and training to prevent inadvertent operation with the flow-limiting device bypassed are part of this

alternative. Larger leaks near the generator would be

indicated by the reduction in generator pressure because

of the limit on makeup flow from the storage facility.

Buildup of significant amounts of trapped hydrogen from

smaller leaks in turbine buildings may not be a concern

for most PWR plants because of the open construction at

each level and between levels (e.g., open hatches, floor

grating, and stairs). However, administrative controls

should be provided for monitoring hydrogen consumption

for indication of leaks and for corrective actions.

Alternative 3-Provide Manual Makeup of Hydrogen to

Generator and Check Valve or Restricting Orifice at the

Generator

This alternative provides protection against leaks or

breaks in the hydrogen supply line from the point of entry

into the turbine building to the hydrogen control station

below the generator, including any branches from this

line to other buildings. It entails operation with the hydrogen facility normally isolated from the generator by an

isolation valve outside the building and periodic manual

adjustments of hydrogen conditions in the generator. A

check valve would be provided in the supply line near the

generator if needed to prevent backflow from the generator to leaks or breaks in the supply line. The alternative

also prevents flow from the storage facility to leaks or

breaks at or near the generator when the generator is

isolated. Reduction of generator pressure with hydrogen

release would provide warning of larger leaks or breaks,

while monitoring hydrogen consumption by monitoring

changes in generator pressure or frequency of manual

makeup would indicate the presence of smaller leaks.

Administrative controls would be used -to prevent inadvertent operation with the hydrogen supply connected.

Alternative 4--Enclose Safety-Related Equipment Located in

the Turbine Building in Blast- and Fire-Proof Structures

This alternative provides protection against the consequences of leaks or breaks in the supply line or at locations near the generator.

Alternative 5-Install Low Setpbihit Excess Flow Valve or

Restricting Orifice in Hydrogen Distribution System to VCT

and Provide Hydrogen Detectors, if Needed

This alternative entails the use of a low setpoint excess

flow valve or restricting orifice (e.g., sized for 150 percent

of maximum daily flow rate) in the low-pressure hydrogen

supply line outside the auxiliary building to limit the rate

of hydrogen flow from the storage facility to the leak or

break. The limit should be low enough so that normal

ventilation in the compartment with the leak or break

would keep the average compartment hydrogen concentration well below the lower flammability limit. This alternative includes (1) preoperational testing and periodic

retesting of the excess flow valve to ensure operability

and (2) administrative controls and features to prevent

inadvertent opening of any bypass around the excess flow

valve or restricting orifice and to isolate the supply manually if normal building ventilation is lost. In addition,

protection against leaks at flow rates up to the setpoint of

the excess flow valves, such as the use of hydrogen leak

detectors with alarms to the control room or other suitable measures, should be provided for areas where leaking hydrogen could be trapped in unacceptable quantities. Trapped hydrogen may not have a significant effect

on risk for most plants because of such factors as location

of vital equipment and adequacy of ventilation at the low

release rates. Hence, two options were considered for this

alternative. Alternative 5 costs do not include the costs

for hydrogen detectors. Alternative 5A costs include the

additional costs of permanent hydrogen detectors.

Alternative 6-Limit the Quantity of Hydrogen Normally

Connected to the VCT

This alternative entails a limit on the total amount of

hydrogen in the storage facility that is normally connected

to the VCT. The limit is such that the release and subsequent fire or detonation of the hydrogen in the supply and

the VCT would not cause unacceptable damage to safetyrelated systems in the auxiliary building. Administrative

controls, design features, and training should be provided

to prevent inadvertent operation with a larger amount of

stored hydrogen. Administrative controls should also be

provided to monitor hydrogen consumption for indication

of leaks and to prevent the buildup of unacceptable

amounts of hydrogen in areas where hydrogen could be

trapped.

I I NUREG-1364
Alternative 7-Provide Normally Isolated Supply With Daily

Manual Makeup of Hydrogen to the UCT

This option entails isolation of the hydrogen storage

facility from the VCT except for brief daily operations to

adjust VCT conditions. Administrative controls, design

features, and training should be provided to prevent

inadvertent operation without isolating the hydrogen supply. Administrative controls should be provided to monitor hydrogen consumption for indication of leaks and to

prevent the buildup of unacceptable amounts of hydrogen in areas where hydrogen could be trapped.

Alternative 8-Relocate Hydrogen Storage Facility To Meet

Separation Distance From Safety-Related Structures

Alternative 9-Install Blast Deflection Shield at Hydrogen

Storage Facility

Alternative 10-Install Hydrogen Analyzer-Actuated Air

Intake Louvres at Safety-Related Air Intakes

NUREG-1364 12
4 TECHNICAL FINDINGS

4.1 Introduction

This regulatory analysis is based in part on work performed by Idaho National Engineering Laboratory

(INEL) under a technical assistance contract and reported in INEL, 1991; INEL, 1992; and NUREG/

CR-5759. The work included the following:

" Surveys of BWR and PWR plant information pertinent to GSI-106 that included the following sources:

- final safety analysis reports (FSARs)

- probabilistic risk analyses (PRAs)

- plant information from site visits

- information from equipment manufacturers

* A review of observed combustible gas events (precursors) at U.S. nuclear power plants.

* A risk evaluation of hydrogen storage facilities at

PWRs and BWRs with respect to damage to safetyrelated buildings caused by explosions at the storage

location and line breaks at the storage location resulting in flammable hydrogen-air mixtures at

safety-related air intakes.

* A detailed PRA by INEL of the risk associated with

the use of hydrogen for the volume control tank

(VCT) and main generator during full-power operation for a representative (base case) PWR plant. A

four-loop Westinghouse plant was selected because

it was representative of a significant portion of the

PWR population, had a Level 3 PRA, and had a

completed and detailed fire analysis. The INELbase

case PRA was then supplemented by a generic

analysis based on sensitivity studies of the variation

in plant risk resulting from observed changes in locations of safety-related equipment and plant feedand-bleed (F&B) capabilities. A similar approach

was followed in a scoping PRA for BWRs of the risk

associated with hydrogen distribution to the main

generator. A BWR/4 with a Mark I containment was

selected for the BWR base case plant.

Screening analyses for the risk associated with portable bottles of combustible gas and with other

sources of hydrogen, including the (1) waste gas system at PWRs, (2) off-gas system at BWRs, and (3)

battery rooms at PWRs and BWRs.

* Cost-benefit analyses to determine possible plant

modifications to reduce risk that could be cost effective.

The scoping PRA for BWRs in EGG-NTA-9082 (INEL,

1991) indicated that the risk associated with the use of

hydrogen for cooling the electric generator was small and

did not warrant a more detailed study. This was based on

the small risk resulting from the absence of safety-related

equipment in the turbine building at the six BWR plants

reviewed in the study. The screening analyses in EGGNTA-9082 and NUREG/CR-5759 also indicated that

the risk associated with the off-gas system in BWRs, the

waste gas system in PWRs, and the station battery rooms

and portable bottles of combustible gases in both BWRs

and PWRs was very small and did not need to be considered further in this study.

The hydrogen storage facilities at PWR and BWR plants

were initially screened by comparing the actual separation distances between storage facilities and safetyrelated structures and air intakes with the separation

distances provided in the Electric Power Research Institute (EPRI) guidelines (EPRI, 1987). The EPRI separation distances for safety-related structures are the distances needed to prevent unacceptable structural damage

from postulated hydrogen detonations at the storage facility. The EPRI separation distances for s~ifety-rclated

air intakes are the distances needed to prevent the ingestion of a flammable hydrogen-air mixture at the intake

following a postulated pipe break at the facility and release of a jet of unburned hydrogen. Although a number

of plants did not pass this screening test, this does not

directly imply high risk because credit for plant-specific

mitigating features could result in a low hazard. These

mitigating features included (1) use of reinforcedconcrete storage buildings with one open side facing away

from shfety-related structures and air intakes, (2) intervening non-safety-related structures, and (3) differences

in elevation of storage area and air intakes. An informal

survey showed that some of the plants that were screened

were not configured to allow credit for such mitigating

features. Hence, more detailed, plant-specific risk estimates were also deemed necessary.

As a result of the above evaluations, the more detailed

risk and cost-benefit analyses under the scope of GSI-106

were reduced to

* hydrogen storage facilities for PWRs

0 hydrogen distribution system for the VCT in PWRs

* hydrogen distribution system for the electric generators in PWRs

4.2 Review of U.S. Nuclear Power

Plant Hydrogen Precursors

INEL conducted a literature search to identify hydrogen

events at U.S. nuclear power plants through April 1990.

Table 1 gives the number of hydrogen events for the

13 NUREG-1364
hydrogen storage facilities and the hydrogen distribution

systems for the VCT and the electric generators. A hydrogen event is identified as an unburned hydrogen leak, a

fire, or an explosion. None of the events in TFable 1 involved damage to safety-related equipment. Up to the

date of this literature search (April 1990), INEL estimated that the total number of reactor operating years

including shutdown time [reactor-years (RYs)] was 917

RYs for PWRs and 1424 RYs for PWRs and BWRs.

Shutdown time was included because some events occurred during this time.

Electrical Generator Events

Fourteen PWR events and two BWR events involved

hydrogen associated with generator cooling (including the

supply piping within the turbine-generator building). Experience from BWRs was included because the equipment and operations for generator cooling systems are

similar for both types of plants. Of these 16 events, 7

involved unburned leaks, 7 involved fires, and 2 involved

explosions. Of the nine fires or explosions (all of which

occurred in PWRs), six occurred while the plants were at

more than 90-percent power and led to a turbine and/or

reactor trip.

INEL attributed one of these nine events to leaks at the

hydrogen distribution system levels in the turbine building. The rest were associated with leaks near or at the

generator. Most of the generator leaks were at the shaft

seal and were caused by such diverse mechanisms as faults

in the electrical power to the seal oil system, a clogged

seal oil filter, loss of hydrogen cooling because of a loose

temperature sensor, and failure of an oil pressure sensing

line.

Several fires in turbine buildings at foreign plants have

been large and damaging. The event at Vandellos I in

Spain in October 1989 (memorandum from R. L. Pressard dated September 4, 1991) was caused by failure of a

high-pressure turbine and involved oil and hydrogen fires.

The oil and hydrogen fire at the Maanshan plant in Taiwan in 1985 (reported in Nucleonics Week on August 8 and

22, 1985; December 19, 1985; and February 6, 1986) apparently was caused by loss of blading in the low-pressure

turbine. Failure of lubricating oil lines because of vibration apparently caused the oil fire in the turbine building

at the plant in Muehleberg, Switzerland, in 1971 (NRC

Translation 2240). A more recent event at Chernobyl in

October 1991 was a large hydrogen fire that apparently

was caused by an electrical fault (reported in Nucleonics

Week on October 17, 1991). INEL considered the available information on hydrogen systems and events at foreign plants to be insufficient to make a meaningful evaluation of event frequency for domestic application.

Volume Control Tank System Events

A total of 11 events involved unburned hydrogen leaks

from the VCT cover-gas system of PWRs [including the

supply piping in the primary auxiliary building (PAB)].

None of these events resulted in either a fire or an explosion. Ten leaks were detected when associated gaseous

radioactivity was detected. Ten of the leaks were hardware related; one was caused because a sampling procedure was inadequate. Of the hardware-related events,

one was caused by a leaking diaphragm in the hydrogen

supply regulator, seven were valve related, and two were

caused by a leaking VCT vent header.

Storage Facility Events

Three events occurred at hydrogen storage facilities. Two

of those occurred at PWRs and one occurred at a BWR.

One of the three events involved an explosion. Although

the other two events involved fires, it is also possible that

there was: an initial explosion with a subsequent fire. No

major unburned hydrogen releases were reported. None

of the three events resulted in damage to any safetyrelated equipment or structures.

Recent Events at U.S. Nuclear Power Plants

Several hydrogen events have occurred in the turbine

buildings at U.S. nuclear plants since the cutoff date of

April 1990 that was used for this review to generate the

initiating event frequencies. A failure of a main transformer at the Maine Yankee plant in April 1991 resulted

in arcing below the generator that caused a hydrogen leak

and fire (Maine Yankee Atomic Power Company, 1991).

A turbine overspeed incident at the Salem plant in November 1991 resulted in damage to the low-pressure turbine and a hydrogen fire (Public Service Electric and Gas

Company, 1991). In October 1991, at Nine Mile Point

Unit 2 (Niagara Mohawk Power Corporation, 1991),

about 10,000 scf of hydrogen was released from a broken

sight glass below the generator. The leak was isolated and

there was no fire or explosion. In December 1991, a

15-minute release of hydrogen from the seals of the generator at the Palisades plant occurred because of blockage

of seal oil in an oil filter. There was no fire or explosion

(Consumers Power Company, 1991).

4.3 Method of Analysis

4.3.1 General

The INEL analysis in NUREG/CR-5759 of the risk

associated with the hydrogen facilities and distribution

systems for the VCT and electric generator for the base

case PWR was based on a "vital area" analysis. The plant

response, modeled by typical probabilistic risk assessment

event trees and fault trees, was used to identify vitalareas

where hydrogen fires or explosions could result in damage

NUREG-1364 14
to safety-related equipment with a significant conditional

probability for core damage. The vital area analysis for the

base case plant included the following:

* identification of the applicable accident sequences*

* determination of affected safety equipment

0 development of new accident sequences for which

hydrogen fires or explosions are the initiating events

and that include the effects of postulated losses of

safety equipment as a result of these fires or explosions

The detailed analysis by INEL is limited to events that

occur when the reactor is at full power. In NUREG/

CR-5759, INEL concluded that power operation through

hot standby (Modes 1 through 3) should be bounded by

these full-power results. This conclusion was based on

consideration of system operability requirements, decay

heat loads, reactor coolant system (RCS) coolant inventory, RCS coolant makeup capacity, containment integrity, and operability of vital auxiliary systems. INEL also

concluded that the effects of hydrogen-induced events

during hot shutdown (Mode 4), cold shutdown (Mode 5),

and refueling (Mode 6) would be insignificant. This conclusion was based on consideration of the typical absence

of hydrogen from the in-plant distribution system, the low

decay heat loads, increased coolant inventories, and lower

coolant temperatures.

The equations for the point estimates of the coredamage

frequency (CDF) for the generic analyses have the general form of an initiating event frequency for a large

hydrogen release, IF, multiplied by the probability that

the release and resulting fire or explosion damages safetyrelated equipment, P(equipment damage), multiplied by

the conditional probability that the loss of the equipment

for this scenario results in core damage, P(core damage).

That is,

CDF = IF*P(equipment damage)*P(core damage)

Large quantities of hydrogen are not present near the

reactor vessel and control rod drive motors,primary

coolant system piping, and steam generators. Hence,

pipe-break loss-of-coolant accidents (LOCAs), steam

generator tube ruptures, and anticipated-transientwithout-scram (ATWS) events should not result from

hydrogen release events. The INEL calculations were

limited to the following two types of transient-induced

core melt scenarios:

(1) transients with failure of decay heat removal (DHR)

systems (T/DHR)

(2) transient-induced LOCAs (T/LOCAs)

T/DHR transients can range from simple turbine trips to

steamline breaks. These transients involve loss of all

forms of core cooling and loss of RCS coolant inventory at

high pressure from the pressurizer power-operated relief

valves (PORVs) or safety valves. T/LOCA transients involve failure of RCS makeup or recirculation following a

reactor coolant pump (RCP) seal LOCA caused by inadequate RCP seal cooling or a LOCA caused by stuck-open

PORVs or safety valves. This category includes events

such as station blackout and loss of component cooling

water.

The initiating events considered were seismically induced

or random failures of hydrogen piping or components at

the storage facility or in the hydrogen distribution systems

in the auxiliary and turbine buildings. In the turbine building, events are considered to occur at the generator and

lines from the hydrogen control station to the generator

or at the hydrogen supply line to the control station.

4.3.2 Seismic Events

Several studies supported by the NRC (see NUREG!

CR-5759, p. 51) have shown that small-diameter piping

systems such as those used in the hydrogen systems have a

very large seismic capacity (i.e., failure unlikely for low-g

earthquakes). Although this conclusion applies to the

piping runs, connections to equipment or connecting pipe

may be vulnerable to seismic failure, particularly if there

is inadequate anchoring or flexibility. At the base case

plant, key portions of the hydrogen lines in the auxiliary

building are seismically qualified. Hence, no damage is

expected for the higher frequency, relatively low-level

earthquakes. For a severe (beyond-design-basis) earthquake (e.g., 0.8g), INEL concluded that the contribution

of seismically induced hydrogen fires or explosions should

be relatively small compared with the direct damage

caused by the earthquake itself. For example, a severe

earthquake could initiate a loss-of-offsite-power event

because of failure of ceramic insulators at the offsite

power transformer. Loss of primary cooling equipment

(needed for the bleed-and-feed function) could also occur

because of failure of either the refueling water storage

tank (RWST), PORVs, or piping (including failure of

hydrogen piping). The RWST, which has a lower seismic

capacity than the hydrogen piping, should fail before the

hydrogen piping is damaged. Hence, INEL concluded

that the core damage contribution during seismic events

associated with the seismically qualified hydrogen piping

system in the auxiliary building at the base case plant

should be small relative to that already considered in the

PRA and could be neglected.

INEL assumed that the fragility of the hydrogen gas system for the main generator at the base case plant could be

represented by that for the dry small-bore pipe with

threaded joints in the fire protection system at that plant.

INEL obtained an initialing event frequency of

15 NUREG-1i364
5.3E-5/RY for scismically induced breaks of this.piping

using the Lawrence Livermore National Laboratory

(LLNL) seismic hazard curves. For the generic study,

INEL assumed that this seismic fragility was representative of the hydrogen storage facility and the distribution

system piping and components containing hydrogen for

the auxiliary and turbine buildings.

4.3.3 Non-Seismic Events

For non-seismic events, INEL estimated the initiating

event frequencies for the VCTand main generator hydrogen distribution systems and storage facilities from the

reported numbers of pertinent hydrogen events and the

associated number of reactor-years of operation

(NUREG/CR-5759, Appendix B). The mean initiating

event frequency of a large hydrogen release involving the

VCT hydrogen system in the auxiliary building is

5.5E-4/RY. In the turbine building, the mean frequency

of a large hydrogen release is 6E-3/RY for the generator

level and I.1E-3/RY for the hydrogen distribution level.

4.3.4 Damage Mechanisms

In the evaluation of hydrogen storage facilities, INEL

assumed that the loss of safety-related equipment was

caused by detonations with resultant blast damage to

nearby safety-related buildings or by large releases of

unburned hydrogen that resulted in flammable hydrogenair mixtures at nearby safety-related air intakes. INEL

assumed loss of equipment if the separation distances

between the storage facility and the buildings or air intakes did not meet the EPRI guidelines and there were no

mitigating factors.

The EPRI calculations were made using the TNT equivalency method, which equates the available amount of

hydrogen to an amount of TNT giving the equivalent

damage. The blast wave parameters are then obtained

from relations for TNT detonations. For these postulated

detonations in open air, EPRI assumed that the TNThydrogen equivalence is 20 percent on an energy basis

(520 percent on a mass basis). On this basis, 1000 scf of

hydrogen is equivalent to 27.1 pounds of TNT. This value

of 20 percent was considered conservative for outside

detonations.

For local detonations in partially or fully enclosed volumes such as compartments and passageways in auxiliary

buildings, reflected shock waves from other surfaces

within these volumes could cause additional damage to

the target surface. Other factors to consider include the

lower expected strength of interior walls and the weakness of fire barriers and air ducts that would not be designed to withstand differential pressures occurring during a detonation. Significant hydrogen releases could

occur at some plants with large supplies and no special

features to limit hydrogen flow to the break. Hence, damage might occur to safety-related equipment in compartments with hydrogen lines or in adjoining compartments.

Large amounts of hydrogen are also available in storage

facilities to initiate or exacerbate a fire in the turbine

building at some plants if special features to reduce risk

(e.g., excess flow check valves or normally isolated supplies) are not provided. Another large source of hydrogen

is that contained in the generator. A hydrogen fire in the

turbine buildings might not normally be considered to

have the potential to directly affect nearby safety-related

equipment because of the large size and open design

typical of these buildings. However, delayed ignition of

hydrogen escaping from a large break in the hydrogen

lines or generator could result in the accumulation and

eventual ignition of large quantities of hydrogen and result in the propagation of blast waves and fire fronts that

coi~ld cause direct damage to nearby safety-related equipment. These blast waves or fire fronts could also cause oil

leaks and fires, which could then spread and damage

safety-related equipment in lower levels of the building.

Large oil fires in the turbine building have always been

considered because of the presence of large quantities of

turbine lubricating oil in the lower levels of the turbine

building. An event involving a break in the oil lines could

result in an oil fire caused by burning hydrogen or ignition

of the oil from prolonged contact with hot metal surfaces

or insulation. Burning oil from the operating level could

then cascade to lower levels and spread to other fire

zones. Early shutoff of the pumped oil could help prevent

a large fire. However, the oil supply system is designed to

be highly reliable because loss of the bearing supply could

also cause extensive damage to the turbines and generator in the absence of a fire.Design features to increase the

reliability of the oil supply include turbine shaft-driven

pumps and emergency pumps. After a turbine trip, oil

may be supplied to the break and fire for up to an hour as

the turbine coasts down. This time can be reduced by

breaking the condenser vacuum to slow the turbine and

stopping motor-driven pumps.

4.3.5 Hydrogen Explosion Methodology

The conditional probability of damage to safety-related

equipment, P(equipment damage), following a large

hydrogen release was treated as the product of (1) the

probability, P(delay), that early ignition following a large

hydrogen release would not occur and (2) the probability,

P(blast), that, given the continued accumulation and

eventual ignition of the released hydrogen, the resultant

blast wave or fire front would incapacitate safety-related

equipment.

In the NUREG/CR-5759 generic calculations, INEL

assumed that P(delay) was equal to 0.01 for large hydrogen releases at the main generator level. This value was

based on discussions with INEL combustion experts who

NUREG-1364 16
concluded that the leakage of large quantities of hydrogen into the ionized air surrounding the generator is almost certain to cause immediate ignition. For releases

into the auxiliary building and releases from the hydrogen

distribution system in .the turbine building, INEL assumed a value of 0.1 forP(delay) to reflect the presence of

significant amounts of electrical equipment, such as

pump and fan motors, that could provide ignition .sources

for deflagrations in these buildings. INEL assumed a genericvalue of 0.1 forP(blast) for the auxiliary building and

for the generator and distribution system levels in the

turbine building. This choice was based on consideration

of the spatial interactions (i.e., relative locations of hydrogen sources and safety-related equipment) and the likelihood of blast waves or fires damaging redundant safetyrelated equipment.

4.3.6 Uncertainty Analysis

INEL performed the uncertainty analyses for the base

case plant and generic analyses using the distribution

functions for random variables and the Monte Carlo sampling techniques built into the statistical @RISK computer program (Palisades Corporation, 1988). Some uncertainty information was obtained from the licensee's

PRA. For models with random event values based on data

from the review of hydrogen events at U.S. nuclear power

plants, the distribution function and its parameters were.

calculated using the methods recommended in NUREG/

CR-2300. Uncertainties in the values of P(delay) and

P(blast) were treated as statistical uncertainties. Lognormal distributions were assigned to these probabilities, and

an error factor of 10 was assigned to reflect the large

modeling uncertainty.

4.4 Analysis of Base Case PWR Plant

The base case plant has a four-loop nuclear steam supply

system provided by Westinghouse Electric Corporation.

The reactor is licensed to operate at a thermal power of

3071 megawatts-thermal, corresponding to a turbinegenerator output of 971 megawatts-electric.

4.4.1 Turbine Building

The hydrogen storage facility supplying the main generator at the base case plant is located about 135 feet west of

the turbine building. The facility has 45 storage cylinders,

each containing about 1150 scf of hydrogen at a pressure

of about 1500 psig. Eighteen cylinders are on line as the

active supply. Another 18 cylinders supply the reserve

manifold, and 9 cylinders supply the emergency reserve

manifold. The hydrogen line to the main generator is not

equipped with an excess flow valve or restricting orifice to

automatically limit the rate of hydrogen flow to a large

leak or break in the turbine building. A 1.5-inch-diameter

hydrogen supply line runs from the storage facility to the

west wall of the turbine building where it enters at the

15-foot level. It passes horizontally through fire zones in

which the hydrogen seal oil unit, sample and vent lines,

and hydrogen control panel are located and then passes

vertically through a fire zone at the 37-foot level to the

main generator at the 53-foot level. Each elevation has

one large open area that is divided into fire zones for

convenience. The fire zones on each level are not separated by any physical barriers. However, different elevations are separated by concrete floors.

None of the fire zones in the turbine building contain

safety-related equipment. The closest fire zones containing safety-related equipment are in the control building,

which is directly adjacent to the southeast corner of the

turbine building. A fire zone on the 15-foot level in the

control building contains the switchgear room in which

vital 480-V buses and power and control cables for most

safety-related pumps are located. The wall separating the

turbine and control buildings is about 100 feet from the

hydrogen lines at this level. A fire zone on the 37-foot

elevation, about 60 feet from the hydrogen lines, contains

the cable spreading room in which power and control

cables for most safety-related pumps and valves are located. A fire zone on the turbine hall floor at the 53-foot

elevation contains the control room in which the control

panels and instrumentation for most safety-related systems are located. This level has the largest open volume

in the entire plant. The roof is about 100 feet above the

operating deck, and the wall is constructed of insulated

metal sandwich panels and contains large windows for

natural lighting.

The only T/DHR event considered for the turbine building was a main steamline (MSL) break caused by a large

hydrogen explosion on the operating deck. The estimated

core damage frequency (CDF) for this event was negligible.

The T/LOCA events evaluated for the turbine building

were both random and seismically induced failures of the

hydrogen distribution lines at the 33-foot level that result

in loss of the equipment in the cable spreading room

(CSR). The CSR was considered to be the most susceptible fire zone because of the small separation distance

from the hydrogen lines and the types of fire barriers and

construction of the separating wall at the 33-foot level. A

large fire in the CSR would result in the loss of power and

control cables for most of the plant safety-related equipment (e.g., high-pressure injection pumps, component

cooling water pumps, and residual heat removal and

recirculation pumps). Assuming a value of unity for the

conditional probability of core damage, given loss of the

CSR, the point estimates of the mean CDF from nonseismic and seismically induced failures of the hydrogen

distribution system would be about 1.1E-5/RY. However,

because the susceptibility of the plant to large fires in the

CSR had been recognized, an alternate safe shutdown

1.7 NUREG-1364
system (ASSS) was installed at the base case plant in the

early 1980s. The power and control cables for the ASSS,

which performs a number of critical safety functions, are

routed independently of the CSR. INEL obtained the

probability of nonrecovery from a T/LOCA condition,

using the installed ASSS, from the original base case

plant fire PRA. The mean value of 0.046 consists of a

human error contribution (0.039) and hardware-related

failures (0.07). Hence, with credit for use of the ASSS, the

CDF for these events was estimated to be about

5E-7/RY.

4.4.2 Primary Auxiliary Building

The hydrogen supply system for the VCT at the base case

plant is independent of the supply system for the main

generator. It consists of a 12-bottle supply located next to

the primary auxiliary building (PAB). The supply contains

a maximum of about 2400 scf of hydrogen at about 2000

psig. There is no excess flow valve or restricting orifice to

limit hydrogen flow rate following a large leak or break in

the auxiliary building. A hydrogen truck skid about 200

feet away provides refilling capability through a 1-inchdiameter field-run pipe. The 12-bottle bank is used for

normal service, and the truck, which is normally isolated,

is used as a backup.

The hydrogen supply pipe enters the PAB at the 92-foot

elevation, travels horizontally for about 25 feet, enters

and travels about 20 feet through a pipe chase, and then

enters the VCT cubicle and tank at the 98-foot elevation.

In the vital area analysis for this plant, most fire zones in

the PAB were screened out either because no safetyrelated components were present or the fire zone was

located two or more levels below the zones containing the

hydrogen lines.

The only non-seismic T/DHR event considered was a

general turbine trip event caused by a small fire or explosion. The estimated CDF for this event was insignificant.

The initiating event frequency for seismically induced

failures of the hydrogen lines in the PAB was considered

negligible because of the seismic qualification of the lines.

A non-seismic T/LOCA event in the PAB was considered

because the component cooling water (CCW) heat exchangers in Fire Zone FZ-7A were located on the same

level as the VCT. However, in view of the limited hydrogen supply to the VCT, partial shielding by intervening

concrete walls, and the separation distance from the hydrogen lines, the probability that the CCW heat exchangers would be lost because of a hydrogen fire or explosion

at that level was considered to be very small. As noted

previously, seismic events were considered to be negligible contributors to risk in the PAB of the base case plant

because of the seismic qualification of the supply line to

the VCT.

4.4.3 Hydrogen Storage Facilities

INEL performed a vital area analysis for the generator

and VCT supplies and the hydrogen truck skid facility for

the VCT. The main generator supply met the EPRI criteria for safe separation distance from safety-related structures and air intakes. The VCT supply and truck skid

supply met the EPRI criteria for detonation but did not

meet the criteria for air intakes. However, consideration

of intervening buildings and differences in elevations

along possible paths from the supplies to the safetyrelated air intakes indicated a negligible likelihood that a

safety-related air intake would ingest a combustible

hydrogen-air mixture.

4.4.4 Uncertainty Analysis Results

In summary, the evaluation of the risk from hydrogen

system failures at the base case plant indicated that the

mean core damage frequency for hydrogen events at the

storage facilities and in the turbine and auxiliary buildings

is less than 1E-6/RY and is negligible when compared

with the values from other causes identified in the plant

PRA.

4.5 Generic Analysis

The generic analysis addressed the risk from hydrogen

storage facilities and distribution systems for PWRs with

design characteristics different from those of the base

case plant, such as location of hydrogen supply facilities

and distribution systems relative to vital equipment [e.g.,

auxiliary feedwater (AFW) system, diesels, electrical

switchgear, cable spreading room, essential service water

(SW) system, and component cooling water system] and

feed-and-bleed (F&B) capability. As in the base case

plant analysis, the generic analysis was based On the fact

that the hydrogen system is not near the reactor pressure

vessel and control rod drive motors, the primary coolant

piping, or the steam generators. Hence, INEL did not

consider pipe-break LOCAs, steam generator tube ruptures, and ATWS-type scenarios due to hydrogen events.

4.5.1 Method

The generic approach involved a vital area analysis in

which hydrogen release and fire or explosion scenarios

were related to specific system failure scenarios. The

generic analysis did not include the level of detail used in

a typical plant-specific vital area analysis, but was directed

at key systems used to mitigate the two categories of

transients. In particular, for transients with loss of decay

heat removal (T/DHR), attentiorn was focused on the

AFW system and systems needed for F&B cooling. For

transient-induced LOCAs (T/LOCAs), attention was focused on normal and emergency ac power and the essential SW and component cooling water systems. If this

generic approach is used, a plant-specific design feature

NUREG-1364 18
that produces a special outlier vulnerability will not be

identified.

4.5.1.1 T/DHR Transients

INEL separated the T/DHR transients into several categories according to the location of the AFW system and

the plant's F&B capability. In some plants, AFW and

F&B systems are located in separate buildings away from

the hydrogen storage facilities and distribution systems.

In these plants, no interactions would be expected between the initiating event and AFW system failure. However, in some plants, AFW systems are located in the

auxiliary or turbine buildings. For T/DHR transients in

the turbine building, INEL assumed that a hydrogen fire

or explosion sufficient to cause loss of the AFW system

would also cause loss of the main feedwater (MFW) system. Hence, actions to recover the MFW system or to

depressurize the steam generators and use the condensate system would be ineffective.

In some plants, if AFW cooling fails, operators can start a

high-pressure safety injection pump and manually open

the power-operated relief valves (PORVs) to provide

F&B cooling to the primary system. Almost all Westinghouse (W) and Babcock & Wilcox (B&W) plants have

this capability. For W and B&W plants, INEL assumed

that P(F&B failure) was equal to 0.045. This value is the

average of four different F&B failure probabilities from

different plant PRAs and depends almost exclusively on

human error probabilities and not on design considerations. Because newer Combustion Engineering (CE) reactors do not have PORVs, cooling the core using the

F&B function is not possible. INEL also concluded in

NUREG/CR-5759 that older CE reactors have marginal

F&B cooling capability and cited previous analyses

(NUREG/CR-4471 and NUREG/CR-5072) that indicated that only a short time window would be available for

initiating successful F&B recovery operations. In view of

the higher priority assigned to other recovery operators,

INEL assumed in this generic study that F&B cooling was

not a viable heat removal mechanism for CE plants.

4.5.1.2 T/LOCA Transients

The majority of PWRs probably do not have systems such

as emergency diesels and essential SW systems in buildings where large hydrogen systems are located. However,

INEL noted that in at least one PWR, a key portion of the

component cooling water (CCW) system (CCW heat exchangers) is located in the turbine building. In most

PWRs, the CCW system is located in the auxiliary building. At many PWR plants (including the base case plant),

loss of the CCW system (e.g., caused by a large hydrogen

explosion failing CCW heat exchangers) would seriously

affect the plant's capability to cool the reactor coolant

pump (RCP) seals. At many plants, cooling of the RCP

seals is performed redundantly by CCW flow to the thermal barrier heat exchangers and by RCP seal injection

(which is provided by the charging pumps). But loss of the

CCW system leads to loss of the charging pumps; therefore, both means of cooling the RCP seals are lost if the

CCW system is lost. Since the oil coolers of the highpressure safety injection pumps and the charging pumps

are cooled by CCW, loss of the CCW system could also

lead to loss of the capability to mitigate the small LOCA

caused by seal failure (NUREG/CR-5759).

4.5.2 Generic Analysis Results

4.5.2.1 Turbine Building and Auxiliary Building

Analyses

The T/DHR and T/LOCA transients are categorized according to the location of the AFW, CCW, and other vital

equipment relative to the hydrogen systems and the

plant's feed-and-bleed capability. These combinations

are covered by the configurations given in Table 2. Table 2 summarizes the mean core damage frequencies for

the specific PWR configurations considered by INEL in

evaluating the in-plant risk from the hydrogen supply and

distribution systems and the specific accident scenarios to

be considered in these generic evaluations.

4.5.2.2 Hydrogen Storage Facility Analysis

An informal survey of all plants showed that about 30

plants did not meet the EPRI criteria for separation distances for safety-related air, intakes or structures. Of

these plants, mitigating factors were insufficient at three

plants. The results of additional evaluations by INEL of

these three plants are as follows.

At Plant A, the hydrogen storage facility (with 14,400 scf

of hydrogen in two tanks) is located about 30 feet from the

main steam enclosure, which contains motor-operated

AFW valves, main feedwater (MFW) piping, and main

steam stop and safety valves. The scenario considered was

a random rupture of a hydrogen storage tank resulting in a

detonation causing loss of the MFW and AFW systems.

Recovery is made using F&B capability. Since the actual

separation distance was a few feet greater than the EPRI

separation distance criterion, the probability of loss of the

MFW and AFW systems, given a detonation, was assumed equal to 0.1. The frequency of all hydrogen fires

and explosions, based on data in licensee event reports,

was 2.5E-3/RY. From these values and a value of 0.045

for the failure probability of F&B cooling, the estimated

mean CDF from the uncertainty analysis is 1E-5/RY.

The hydrogen facility is also near the air intake for the

pumphouse containing the essential SW pumps. The airintake scenario considered was a random failure of the

hydrogen header upstream of the pressure regulators

leading to ingestion of i combustible mixture at the air

intakes and a fire or explosion causing loss of the SW

pumps and consequent loss of the motor-driven AFW

pumps. The turbine-driven AFW pump would still be

available. The mean CDF for this scenario is 2.5E-8/RY.

19 NUREG-1364
Plant B did not meet the separation criteria for either

structures or air intakes. The hydrogen storage facility

contains 85 standard hydrogen bottles (about 200 scf

each). At. least four bottles are on line. The hydrogen

supply is not seismically qualified and was assumed to

have the same fragility as that used for the hydrogen

system piping in the generic calculations for the auxiliary

and turbine buildings. The hydrogen supply is close to the

two diesel generators. A storage bay containing a large

quantity of turbine lubricating oil is located between the

hydrogen facility and the diesel generators. The scenario

considered was a seismic event causing loss of offsite

power because of failure of ceramic insulators at the

offsite power transformer and a seismically induced rupture of a hydrogen storage bottle. Since a hydrogen fire or

detonation can also cause a large fire at the adjacent

lubricating oil storage area, loss of both diesel generators

was assumed. Hence, the seismic event could result in a

station blackout. The mean values of the initiating event

frequency and the CDF for this scenario are 5.3E-5/RY.

For the air intake analysis, the concern was also the proximity of the diesel generators. The scenario considered

was a random failure of a pipe at the hydrogen storage

area during a loss of offsite power that causes loss of both

diesel generators because of ingestion of a flammable

mixture at the air intakes. The point estimate value of

CDF for this event is 6.6E-7/RY.

Plant C did not meet the EPRI separation criteria for air

intakes. The concern was the proximity to the hydrogen

storage facility of the airintake for the building containing

the 4160-V switchgear. Loss of this switchgear would

cause loss of most safety-related equipment. Important

exceptions are the turbine-driven AFW pump and the

diesel generators. The scenario considered was a random

failure of a pipe at the facility causing releases of unburned hydrogen, ingestion of a combustible mixture at

the air intakes, and an explosion resulting in loss of the

switchgear. Recovery from this event is made with the

turbine-driven AFW pump. The point estimate value of

CDF is 2.5E-6/RY.

4.6 Reductions in Core Damage

Frequency for Improvement

Alternatives

Sections 4.4 and 4.5 give estimates of the hydrogeninitiated CDF contributions for the base case plant and

for other generic PWR plant configurations before any

procedural or hardware changes are made to reduce risk.

Configuration I scenarios are characterized by a hydrogen

event at the generator floor level leading to a general

plant transient or steamline break. INEL assumed that

the contributions of the Configuration I accident scenario

Were not reduced by any of the alternatives for the turbine

building, since none of the alternatives could prevent

large releases of the hydrogen stored in the generator.

The reductions in CDF for the alternatives are given in

Table 3. The values in the table are the mean values

obtained from the uncertainty analysis.

4.7 Dose Consequence Analysis

The dose consequence analysis by INEL for this safety

issue was based on the information developed for Safety

Issue A-45 (NUREG/CR-4762). For that study, Sandia

National Laboratories used Calculation of Reactor Accident Consequences (CRAC) Version 2 computer code

results for integrated doses (in person-rem per event)

received by the population around the plant out to 50

miles. Lower bound, best-estimate,and upper bound values were calculated for each of seven release categories.

For the generic PWR analysis of NUREG/CR-4762, a

containment event tree with three containment functions

and six containment sequences was used. Each accident

sequence contributing to the CDF was mapped to one or

more of the containment accident sequences. Each containment sequence was then mapped to containment failure modes with associated probabilities of occurrence per

event and release fractions.

4.8 Cost Analysis

The cost-benefit analysis for the various alternatives followed the guidelines of NUREG/CR-3568 and NUREG/

CR-4627, Revision 2. Costs were calculated using

FORECAST 2.1 (Science & Engineering Associates,

Inc., 1990).

All plant cost estimates are given in 1991 dollars and

include implementation and recurring costs. INEL assumed that modifications would be made during normal

plant operations or scheduled shutdowns and that no

replacement energy costs Would be incurred. The cost

analyses covered the following component costs. These

costs are discussed in INEL, 1992; Science & Engineering

Associates, Inc., 1992; and NUREG/CR-5759.

" cost of equipment, material, and structures

" installation and removal costs and associated overhead

" engineering and quality assurance costs

" radiation exposure costs

* health physics support costs

* licensee costs for rewriting procedures, staff training, and other technical subtasks

" licensee recurring costs

" NRC implementation costs

" NRC recurring costs

NUREG-1364 20
t onsite averted costs representing the averted onsite

property damages, including allowances for cleanup,

repair, and replacement energy costs

Table 4 gives the point estimates of the total cost for each

alternative minus the onsite averted costs for a remaining

plant life of 20 years and a best-estimate discount rate of

0.05. Table 5 gives similar results for a remaining plant

life of 40 years to illustrate the change in values for a plant

with a license renewal for an additional 20 years. A negative value indicates a cost savings is predicted because of

the inclusion of onsite averted costs. The calculations are

described in detail in INEL, 1992, and NUREG/

CR-5759.

21 NUREG-1364
5 COST-BENEFIT ANALYSIS

The cost-benefit methodology for analyzing the various

alternatives considered for this safety issue is based on the

requirements of the backfit rule (10 CFR 50.109) and the

guidance in memoranda from E. S. Beckjord dated

May 10 and November 18,1988, and NUREG/CR-3568.

One consideration in the decision-making process is the

cost-benefit ratio for each alternative, evaluated in terms

of cost in 1991 dollars per person-rem averted, which may

be compared to a guideline such as $1000/person-rem.

The costs used in the cost-benefit ratio are (1) the total

cost of an alternative without consideration of the onsite

averted costs (OSACs), given by the sum of the first nine

component costs listed in Section 4.8, and (2) the net cost

of an alternative, which equals total cost minus the

OSACs. The other consideration in the decision-making

process is the magnitude of the risk reduction achieved by

the alternative action. In the following sections, each.

alternative is described and the results of a cost-benefit

assessment are given.

INEL used the @RISK computer program (Palisades

Corporation, 1988) to evaluate the uncertainty in the

cost-benefit analysis with and without OSACs. Input to

the program included the cost of the alternative, the

benefit in offsite person-rem averted, and OSACs. Tables

6 and 7 give the results, which were obtained from the

cumulative distributions for the cost-benefit ratio for a

remaining plant life of 20 or 40 years. These tables give

the chance that the cost-benefit ratio is more or less than

$1000/person-rem.

5.1 Alternative 1--Take No Action

Under this alternative there will be no new regulatory

requirements. Consistent with existing regulations, this

alternative does not preclude a licensee from proposing

to the NRC staff other changes intended to reduce the

risk associated with the hydrogen storage and distribution

systems on a plant-specific basis.

5.2 Alternative 2--Install Low

Setpoint Excess Flow Valves,

Restricting Orifices, or Check

Valves in the Hydrogen Supply

Line to the Generator

This alternative provides protection from large breaks in

the hydrogen supply line to the hydrogen control station

at the generator by limiting flow from the hydrogen storage facility and backflow from the generator. The alternative also limits flow from the storage facility to leaks or

breaks in the lines near the generator and at the generator itself. It applies to Configurations II, III, and IV, which

involve leaks or breaks at the hydrogen distribution system levels in the turbine building. Configuration II applies to Babcock & Wilcox (B&W) and Westinghouse (W)

plants and the loss of the auxiliary feedwater (AFW)

system located in the turbine building. Alternative 2 is not

cost effective for this configuration because of the small

delta core damage frequency (CDF) at these plants that

have feed-and-bleed (F&B) capability. For Configuration

III, involving loss of the AFW system located in the turbine building at Combustion Engineering (CE) plants,

and Configuration IV, involving loss of vital equipment in

the turbine building at all PWRs, INEL obtained a generic best-estimate value of about IE-5/RY for delta

CDF. If onsite averted costs are included, there is a cost

savings for Configurations III and IV. Table 6 shows there

is nearly a 100-percent chance that the cost-benefit ratio

is less than $1000/person-rem for these configurations.

INEL assumed that Alternative 2 did not reduce the CDF

for Configuration V, which is applicable to hydrogen releases at or near the generator.

5.3 Alternative 3--Provide Manual

Makeup of Hydrogen to Generator

and Check Valve or Restricting

Orifice at the Generator

Alternative 3 entails operation with the hydrogen facility

normally isolated from the generator, except for manual

adjustment of hydrogen conditions in the generator, and

the installation of a check valve in the hydrogen line near

the generator to prevent backflow to the hydrogen line

break. A large portion of the cost for this alternative is the

recurring costs associated with manual makeup to the

generator.

Alternative 3 applies to Configurations II, II, and IV.

INEL assumed that this alternative did not reduce the

CDF for Configuration V, which is applicable to hydrogen releases at or near-the generator. The alternative is

not cost beneficial for Configuration II (loss of the AFW

system in the turbine building for W and B&W plants)

because of the small delta CDF for these plants that have

F&B capability. For Configurations III (loss of the AFW

system in the turbine building for CE plants) and IV (loss

of vital equipment in the turbine building for all PWRs),

the generic best-estimate delta CDF is 1.OE-5/RY. If

onsite averted costs are included for these configurations,

Table 6 shows that there is nearly a 100-percent chance

that the cost-benefit ratio is less than $1000/person-rem.

23 NUREG-1364
5.4 Alternative 4-Enclose SafetyRelated Equipment Located in

Turbine Building in Blast- and

Fire-Proof Structures

This alternative, which applies to Configurations II, III,

IV, and V, entails structural modifications to protect the

vital equipment from damage by large fires or explosions.

INEL initially considered it as a possible alternative for

plants with higher risks because of safety-related equipment in the turbine building. The alternative is not cost

effective with or without onsite averted costs because of

the large costs and the generic delta CDFs estimated for

these configurations. Table 6 shows more than a

99-percent chance that the cost-benefit ratio is greater

than $1000/person-rem.

5.5 Alternative 5--Install Low

Setpoint Excess Flow Valve or

Restricting Orifice in Hydrogen

Distribution System to Volume

Control Tank and Provide

Hydrogen Detectors, if Needed

This alternative involves the use of a low setpoint excess

flow valve or restricting orifice in the hydrogen supply line

outside the auxiliary building (AB). The purpose is to

limit the rate of hydrogen flow from the storage facility to

larger breaks or leaks to a low value so that normal ventilation in the compartment with the leak or break can keep

the average hydrogen concentration well below the lower

flammability limit. Protection against the accumulation of

unacceptable amounts of trapped hydrogen from leaks at

flow rates up to this maximum flow rate would also be

provided if necessary. Trapped hydrogen may not be a

concern at most plants if the low setpoint excess flow

valve or restricting orifice is used. Hence, as discussed in

Section 3.4, the costs for this alternative were estimated

for two cases. Alternative 5 costs do not include the installation of permanent hydrogen detectors. Alternative 5A

costs include the additional costs of permanent hydrogen

leak detectors (see EPRI, 1987 and Science & Engineering Associates, Inc., 1992) that provide an input to a local

panel sending an alarm to the control room. The costs

include the costs of (1) the hydrogen detectors, (2) periodic testing and maintenance of the excess flow check

valves and hydrogen detectors, (3) administrative controls

and/or design features to prevent the bypassing of the

excess flow check valves or restricting orifices, and (4) administrative controls to provide for manual isolation of

the hydrogen supply if normal ventilation to the AB is

lost.

These alternatives apply to Configurations VI, VII, and

VIII, which involve loss of the AFW system or vital equipment in the AB (see Table 2). The alternatives with onsite

averted costs included are not cost effective for Configuration VI (loss of the AFW system in the AB for W and

B&W plants) because of the small delta CDF at plants

with F&B capability. For Configurations VII (loss of the

AFW system in the AB for CE plants) and VIII (loss of

vital equipment in the AB for all PWRs), the INEL estimate of a generic value for delta CDF is about

*0.5E-5/RY. The alternatives are cost effective for these

configurations if onsite averted costs are included. Table

6 shows that the chance that the cost-benefit ratio is less

than $1000/person-rem is about 100 percent for Alternative 5 and 88 percent for Alternative 5A.

5.6 Alternative 6--Limit the Quantity

of Hydrogen Normally Connected

to Volume Control Tank

This alternative involves a limit on the total amount of

hydrogen in the storage facility that is normally connected

to the volume control tank at any time. The limit is such

that the release and subsequent fire or detonation of the

hydrogen in the supply and the VCf" would not cause

unacceptable damage to safety-related systems in the

auxiliary building.

This alternative also applies to Configurations VI, VII,

-and VIII, which involve loss of the AFW system or vital

equipment in the auxiliary building. For Configuration VI

(loss of the AFW system in the AB for W and B&W

plants), the alternative is not cost effective if onsite

averted costs are included because of the small delta CDF

at these plants that have F&B capability. For Configurations VII (loss of the AFW system in the AB for CE

plants) and VIII (loss of vital equipment in the AB for all

plants), the generic value of delta CDF is 0.5E-5/RY.

This alternative is cost effective for these configurations if

onsite averted costs are included. Table 6 shows that

there is about a 100-percent chance that the cost-benefit

ratio is less than $1000/person-rem.

5.7 Alternative 7-Provide Normally

Isolated Supply With Daily

Manual Makeup of Hydrogen to

Volume Control Tank

This alternative involves isolation of the hydrogen storage

facility from the VCT except for brief daily operation to

adjust VCT conditions. The dominant cost for this alternative is the recurring plant cost for manual makeup.

This alternative applies to Configurations VI, VII, and

VIII, which involve loss of the AFW system or vital equipment in the auxiliary building. For Configuration VI (loss

of the AFW system in the AB for W and B&W plants),

the alternative is not cost beneficial if onsite averted costs

NUREG-1364 24
are included because of the small delta CDF for these

plants that have F&B capability. For Configurations VII

and VIII, the generic best-estimate value of delta CDF is

0.5E-5/RY. This alternative is still not cost effective because of the higher costs. Table 6 shows that there is a

51-percent chance that the cost-benefit ratio is less than

$1000/person-rem.

5.8 Alternative 8--Relocate Hydrogen

Storage Facility To Meet

Separation Distance From

Safety-Related Structures

This alternative involves the relocation of the hydrogen

storage facility to reduce the probability that a detonation

at the storage facility will damage safety-related equipment. The mean delta CDFs for this alternative are about

1.01E-5/RY for Plant A and 5.3E-5/RY for Plant B. If

onsite averted costs are included, the alternative is not

cost effective for Plant A, but is cost effective for Plant B.

Table 6 shows that the chance that the cost-benefit ratio is

less than $1000/person-rem is 6 percent for Plant A and

97 percent for Plant B.

5.9 Alternative 9-Install Blast

Deflection Shield at Hydrogen

Storage Facility

This alternative involves the addition of a blast shield to

protect safety-related equipment from a detonation at

the hydrogen storage facility. The alternative was considered only for Plant A, since a blast shield could not be

used at Plant B because of insufficient space. The alternative does not apply to Plant C, which did not meet the

separation distance criteria for air intakes. The bestestimate delta CDF for Plant A is 1.0E-5/RY. Table 6

shows that the chance that the cost-benefit ratio is less

than $1000/person-rem is about 100 percent if onsite

averted costs are included.

5.10 Alternative 10- Install Hydrogen

Analyzer-Actuated Air Intake

Louvres at Safety-Related Air

Intakes

This alternative, which involves the addition of shutters

actuated by hydrogen detectors to prevent the ingestion

of flammable hydrogen-air mixtures at safety-related air

intakes, applies to Plants A, B, and C. Since the delta

CDFs are small because of the small initial CDFs, this

alternative is not cost effective. Table 6 shows that the

chance that the cost-benefit ratio is less than

$1000/person-rem is less than 8 percent if onsite averted

costs are included.

5.11 Other Alternatives

Other alternatives are possible that could also reduce an

existing plant vulnerability at either the auxiliary building,

the turbine building, or the hydrogen storage facility. The

alternatives discussed in Sections 5.1 through 5.10 provide a perspective on a range of options and could serve as

guidance on the cost effectiveness and benefits to be

expected from other possibilities.

5.12 Life Extension Considerations

The NRC staff is developing the regulatory requirement

.for the renewal of operating licenses. A license may be

renewed for an additional 20 years if the licensee meets

the specific requirements of the license renewal rule. The

effect of license renewal on the evaluation of this safety

issue was included by repeating the calculations for a

remaining plant life of 40 years (current remaining life of

20 years plus a license renewal of 20 years). The results

are shown in Table 7. The increases in onsite averted costs

and benefits with increase in remaining plant life cause a

decrease in the cost-benefit ratio (more cost effective)

that can be offset, in part, for some alternatives by the

increased contribution of recurring costs.

5.13 New Reactors

The implementation of the resolution of GSI-106 includes a recommendation that the Standard Review Plan

(NUREG-0800) be modified to include new guidance on

hydrogen storage facilities and distribution systems for

the VCT and generator at future PWRs and BWRs.

25 NUREG-1364
6 DECISION RATIONALE

6.1 Introduction

As noted in Section 5, the estimated cost savings and

cost-benefit ratios vary significantly for the alternatives

associated with the hydrogen storage facilities and the

hydrogen distribution system for the volume control tank

(VCT) and electric generator at PWRs.

Hydrogen Storage Facilities

The estimates for the hydrogen storage facilities indicate

that Alternative 8, which involves the relocation of the

storage facility, results in a delta core damage frequency

(CDF) of about 5E-5/RY for Plant B and is cost effective

if onsite averted costs are included. For Plant A, Alternative 9, which involves the addition of a blast shield. results

in a delta CDF of about 1E-5/RY and is cost effective if

onsite averted costs are included. Alternative 10, which

involves the air intake louvres, is not cost effective because of the small values of CDF associated with the air

intakes for these plants.

Turbine Bilding

The generic estimates indicate that Alternative 2, which

involves the installation of flow-limiting devices, and Alternative 3, which involves operation with a normally

isolated generator, would be cost effective in reducing

risk for Combustion Engineering (CE) plants with the

auxiliary feedwater (AFW) system in the turbine building

or all PWRs with vital equipment in the turbine building

and hydrogen releases at the hydrogen distribution system level (Configurations III and IV of Table 2). These

alternatives result in a best-estimate delta CDF of about

1E-5/RY. Alternative 7, which involves protection of the

safety-related equipment, is not cost effective.

Auxiliary Building

For the auxiliary building, the evaluation indicates that

Alternatives 5 and 5A and Alternative 6 would be cost

effective for CE plants with the AFW system in the auxiliary building or all PWRs with vital equipment in the

auxiliary building (Configurations VII and VIII of Table

2) if onsite averted costs are included. The generic bestestimate delta CDF for the alternatives is about

0.5E-5/RY. Alternative 5 involves the use of a flow-limiting device in the supply line to the VCT. Alternative 5A

involves the use of a flow-limiting device in the supply line

to the VCT and permanent hydrogen detectors. Alternative 6 involves the use of a limited hydrogen supply to the

VCT. Alternative 7, which involves the use of a normally

isolated supply, is not cost effective. This alternative had

the same delta CDF for Configurations VII and VIII, but

much larger estimated costs because of recurring costs

associated with manual adjustment of VCI conditions.

Plant-Specilic Conditions in Auxiliary and Turbine

Buildings

A significant number of hydrogen events have occurred

and continue to occur at U.S nuclear power plants. In

recent years, most of the significant events invQlving hydrogen fires, explosions, or large hydrogen releases have

occurred in turbine buildings. However, hydrogen events

in the turbine building are not expected to be significant

sources of risk for most plants. For T/LOCA transients,

vital equipment is not expected to be in the turbine building for most plants. For T/DHR transients, the risk is

small at the Westinghouse and Babcock & Wilcox plants

because of their feed-and-bleed capabilities (additional

recovery operations include recovery of the main feedwater system or depressurization of steam generators and

the use of condensate). At most CE plants there would

also be a minimal risk from the T/DHR transient because

the AFW pumps are located (1) in a separate building or

(2) in both the auxiliary and turbine buildings. Hence, a

single hydrogen event would not be expected to result in

loss of all AFW. However, for the small number of plants

that could be susceptible to core damage resulting from

T/LOCA or possibly T/DHR transients because of events

in the turbine building, the magnitude of the generic

estimates of CDF (IE-5/RY) and cost-benefit ratio indicates that some alternatives considered in this analysis

could be warranted.

Although there have been a number of leaks, there have

been no fires, explosions, or large hydrogen releases in

the auxiliary building. However, some plants are considered to be susceptible to core damage because protective

features are lacking to prevent large hydrogen releases

or, possibly, the buildup of significant amounts of trapped

hydrogen in the auxiliary building. The hydrogen events

considered potentially significant are those resulting in

loss of vital equipment and a reactor coolant pump seal

LOCA. An appreciable number of plants have corrective

measures such as normally isolated supplies, limited supplies, flow-limiting devices, and leak detection equipment

and procedures. Therefore, a relatively small number of

plants may need changes to reduce risk. The generic CDF

and cost-benefit ratios for these events indicate that some

alternatives could be warranted for those plants that do

not have protective features.

The generic delta CDFs for the various alternatives are

based on sensitivity studies of the base case plant to better

quantify values for other existing plants that (1) have large

hydrogen facilities that are normally connected to the

VCT and generator via pressure regulators and (2) do not

have low setpoint excess flow valves or restricting orifices

27 NUREG-1364
to limit the rate of flow from the facility following a large

break in the hydrogen supply line in these buildings.

These generic calculations are characterized by a single

set of values for initiating event frequencies and for the

probability of a delay in ignition, P(delay), and the probability of blast damage to redundant safety systems,

P(blast). Depending on the relative locations of the safety

equipment and hydrogen lines, and other factors such as

use of a limited amount of stored hydrogen or excess flow

valves and leak detection, these values and, hence, the

delta CDFs for a given plant may be significantly lower or

higher than the generic values. For example, the probability of damage to component cooling water (CCW)

heat exchangers at the base case plant that are located on

the same level as the VCT was considered to be very small

because of the limited amount of hydrogen, partial shielding by several concrete walls, and a large separation distance. Other fire zones were eliminated from consideration because they contained no safety-related equipment

or were located two or more levels below zones containing hydrogen components. Damage to a seismic Category I six-inch service water line located near a short

length of hydrogen line in a pipe chase was eliminated

from consideration in the base case plant because of a

relatively large separation distance, lack of local ignition

sources, and significant ventilation.

However, other plants may have such building arrangements that the hydrogen lines are relatively close to vital

equipment considered in the risk analysis. Limited information on the location of safety-related equipment relative to the hydrogen lines and VCT in the auxiliary building was obtained from site surveys conducted early in the

program. These surveys showed that rooms containing

CCW pumps and heat exchangers were at the same level

or at levels adjacent to the level containing hydrogen lines

at six of nine plants surveyed. Motor control centers at 5

of 6 plants and switchgear rooms at 4 of 14 plants were

also at the same or adjacent levels. A survey of the location of the auxiliary feedwater (AFW) system at 14 plants

showed that the AFW pumps were in the turbine building

at 3 plants, the auxiliary building at 5 plants, and in other

buildings at 6 plants. Of the five plants with AFW pumps

in the auxiliary building, three had pumps at the same

level or levels adjacent to those containing hydrogen

lines. An additional review of one of the plants showed

that the hydrogen supply line to the VCT in the auxiliary

building was located next to the compartment containing

the CCW pumps and heat exchangers. The generic estimate of the CDF for the T/LOCA transient following loss

of the CCW system is about 0.5E-5/RY. However, the

proximity of the hydrogen supply line to the CCW components at this plant could result in a higher conditional

probability of damage to safety-related equipment and a

corresponding increase in the CDF (e.g., about

1E-5/RY).

6.2 Relationship to Other Generic

Issues

Because the T/LOCA transients in this evaluation encompass those hydrogen-induced system failures that

lead primarily to reactor coolant pump (RCP) seal

LOCAs, GI-23, "Reactor Coolant Pump Seal Failures,"

is related to GSI-106. The objective of GI-23 is to reduce

the probability of RCP seal failures and, hence, make it a

small contributor to the total CDF. GI-23 could entail

the addition of a separate and independent cooling system for the RCP seals and could provide part of the

resolution of GSI-106 because it would eliminate most of

the delta CDF for the T/LOCA scenarios.

6.3 Backfit Rule and Plant-Specific

Considerations

As discussed in Section 2, the overall objective of

GSI-106 is to ensure that the contribution from the use of

combustible gases to the total CDF is less than about

1E-5/RY. The generic calculations indicate that some

plants may have a CDF due to hydrogen events of more

than 1E-5/RY. However, it is apparent that there are

large and diverse plant-to-plant differences in'

* relative locations of hydrogen systems and safetyrelated equipment

* hydrogen storage and distribution system safety features, operating procedures, and considerations of

trapped hydrogen

0 reactor characteristics that affect risk from hydrogen

events

Hence, only plant-specific evaluations can determine the

extent to which a modification isjustified.

6.4 Conclusion

In view of the observed large differences in plant-specific

characteristics affecting the risk associated with the use of

hydrogen, and the marginal generic safety benefit that

can be achieved in a cost-effective manner, it is concluded

that this generic issue be resolved simply by making these

results available in a generic letter. This information may

help licensees in their plant evaluations recommended by

Generic Letter 88-20, Supplement 4, "Individual Plant

Examination of External Events for Severe Accident Vulnerabilities," June 28, 1991.

NUREG-1364 28
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Radiological Effluent Technical Specifications and the

Relocation of Procedural Details of RETS to the Offsite

Dose Calculation Manual or to the Process Control Program," January 31, 1989.

, Information Notice 87-20, "Hydrogen Leak in Auxiliary Building," April 20, 1987.

29 NUREG-1364
-, Information Notice 89-44, "Hydrogen Storage on

the Roof of the Control Room," April 27, 1989.

, "Notice of Solicitation of Public Comments on Generic Issue 23, 'Reactor Coolant Pump Seal Failure,' and

Draft Regulatory Guide; Issuance, Availability," Federal

Register, Vol. 56, p. 16130, April 19, 1991.

, NUREG-75/094, "Standard Format and Content of

Safety Analysis Reports for Nuclear Power Plants," October 1975.

-, NUREG-0705, "Identification of New Unresolved

Issues in U.S. Commercial Nuclear Power Plants," February 1981.

-, NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports," July 1981.

-- , NUREG-0933, "A Prioritization of Generic Safety

Issues," and amendments, initially issued in December

1983.

, NUREG-1289, "Regulatory and Backfit Analysis:

Unresolved Safety Issue A- 45, Shutdown Decay Heat

Removal Requirements," November 1988.

, NUREG-1370, "Resolution of Unresolved Safety

Issue A-48, 'Hydrogen Control Measures and Effects of

Hydrogen Burns on Safety Equipment,' " September

1989.

-- , NUREG/CR-2300, "PRA Procedures Guide-A

Guide to the Performance of Probabilistic Risk Assessments for Nuclear Power Plants," Institute of Electrical

and Electronics Engineers, January 1983.

-, NUREG/CR-2475, "Hydrogen Combustion Characteristics Related to Reactor Accidents," Brookhaven

National Laboratory, July 1983.

-, NUREG/CR-2726, "Light Water Reactor Hydrogen Manual," Sandia Laboratories, September 1983.

-, NUREG/CR-3551, "Safety Implications Associated

With In-Plant Pressurized Gas Storage and Distribution

Systems in Nuclear Power Plants," Oak Ridge National

Laboratory, May 1985.

-, NUREG/CR-3568, "A Handbook for Value-Impact

Assessment," Battelle Memorial Institute, Pacific Northwest Laboratory, December 1983.

-, NUREG/CR-4471, "Los Alamos PWR DecayHeat-Removal Studies Summary Results and Conclusions," Los Alamos. Scientific Laboratory, March 1986.

-, NUREG/CR-4627, Revision 2, "Generic Cost Estimates," Science & Engineering Associates, Inc., February 1989.

-, NUREG/CR-4762, "Shutdown Decay Heat Removal Analysis of a Westinghouse Three-Loop Pressurized Water Reactor: Case Study," Sandia National Laboratories, March 1987.

-, NUREG/CR-5072, "Decay Heat Removal Using

Feed-and-Bleed for U.S. Pressurized Water Reactors,"

Idaho National Engineering Laboratory, June 1988.

-, NUREG/CR-5275, "Flame Facility-The Effect of

Obstacles and Transverse Venting on Flame Acceleration and Transition to Detonation for Hydrogen-Air Mixtures at Large Scale," Sandia National Laboratories,

April 1989.

-, NUREG/CR-5662, "Hydrogen Combustion, Control, and Value-Impact Analysis for PWR Dry Containments," Brookhaven National Laboratory, June 1991.

, NUREG/CR-5759, "Risk Analysis of Highly Combustible Gas Storage, Supply and Distribution Systems in

Pressurized Water Reactor Plants," Idaho National Engineering Laboratory, February 1993.

, Regulatory Guide 1.29, "Seismic Design Classification," Revision 3, September 1976.

, "Safety Goals for the Operation of Nuclear Power

Plants," Policy Statement, Federal Register, Vol. 51, p.

26044, August 4, 1986.

- Translation 2240, "The Fire at the Nuclear Power

Plant Muehleberg (KKM) Switzerland," December 1989.

Yankee Atomic Electric Company, "Yankee Nuclear

Power Station Severe Accident Closure Submittal," December 1989.

NUREG-1364 30
TABLES

31 NUREG-1364
Table 1 Number of hydrogen events at each plant location

Event location Unburned

(reactor-years) Reactor Explosions Fires leaks Total

Turbine building

(1424)

Volume control tank in

primary auxiliary building

(917)

Hydrogen storage system

(1424)

BWR, PWR

PWR

BWR, PWR

2

0

2

7

0

1

7 16

11 11

0 3

Total 4 8 18 30

Source: NUREG/CR-5759.

Table 2 Generic plant configurations

Important accident Core damage

scenarios applicable frequency/ Configuration Plant applicability to configuration reactor-year

I All PWRs with auxiliary feedwater T/DHR* 3.4E-8

(AFW) and vital equipment outside T/LOCA**

turbine and auxiliary buildings

II Babcock & Wilcox and Westinghouse T/DHR 7.3E-7

plants with AFW system at turbine (feed and bleed credited)

building distribution system level

III Combustion Engineering plants with AFW T/DHR 9.4E-6

system at turbine building dis tribution (feed and bleed not credited)

system level

IV All PWRs with vital equipment at turbine T/LOCA 9.4E-6

building distribution system level [station ac blackout or loss of

component cooling water (CCW)

or service water (SW) system]

V All PWRs with vital equipment at turbine T/LOCA 5.2E-6

building generator floor level (station ac blackout or loss of CCW

or SW system)

VI Babcock & Wilcox and Westinghouse T/DHR 2.0E-7

plants with AFW system in auxiliary (feed and bleed credited)

building

VII Combustion Engineering plants with AFW T/DHR 4.7E-6

system in auxiliary building (feed and bleed not credited)

VIII All PWRs with vital equipment in auxiliary T/LOCA 4.7E-6

building (loss of CCW or SW system)

*T/DHR = transient-induced loss of decay heat removal.

**T/LOCA = transient-induced loss-of-coolant accident.

Source: NUREG/CR-5759.

NUREG-1364 32
Table 3 Delta core damage frequency per reactor-year for alternatives (calculated mean values)

Configuration Plant

Alternative

II III IV V VI VII VIII A B C

Turbine building

Alternative 2 7.0E-7 9.413-6 9.4E-6 NA NA NA NA NA NA NA

Alternative 3 7.013-7 9.413-6 9.4E-6 NA NA NA NA NA NA NA

Alternative 4 7.OE-7 9.413-6 9.4E-6 5.2E-6 NA NA NA NA NA NA

Auxiliary building

Alternative 5 NA NA NA NA 1.9E-7 4.613-6 4.6E-6 NA NA NA

Alternative 5A NA NA NA NA 1.9E-7 4.6E-6 4.6E-6 NA NA NA

Alternative 6 NA NA NA NA 1.9E-7 4.613-6 4.6E-6 NA NA NA

Alternative 7 NA NA NA NA 1.913-7 4.6E-6 4.6E-6 NA NA NA

Hydrogen storage

facility

Alternative 8 NA NA NA NA NA NA NA 1.013-5 5.3E-5 NA

Alternative 9 NA NA NA NA NA NA NA 1.013-5 NA NA

Alternative 10 NA NA NA NA NA NA NA 6.1E-8 6.913-7 2.6E-6

Note: NA = not applicable.

Source: NUREG/CR-5759.

33 NUREG-1364
Table 4 Cost of modifications minus onsite averted costs (point estimates) for remaining plant life of 20 years ($)

Configuration Plant

Alternative

II III IV V VI VII VIII A B C

Turbine building

Alternative 2 8,400 -130,000 -130,000 NA NA NA NA NA NA NA

Alternative 3 95,000 -48,000 -48,000 NA NA NA NA NA NA NA

Alternative 4 1,000,000 950,000 950,000 1,000,000 NA NA NA NA NA NA

Auxiliary building

Alternative 5 NA NA NA NA 9,200 -63,000 -63,000 NA NA NA

Alternative 5A NA NA NA NA 76,000 3,600 3,600 NA NA NA

Alternative 6 NA NA NA NA 5,700 -67,000 -67,000 NA NA NA

Alternative 7 NA NA NA NA 100,000 31,000 31,000 NA NA NA

Hydrogen storage

facility

Alternative 8 NA NA NA NA NA NA NA 340,000 -370,000 NA

Alternative 9 NA NA NA NA NA NA NA -150,000 NA NA

Alternative 10 NA NA NA NA NA NA NA 99,000 87,000 57,000

Note: NA = not applicable.

Sources: INEL, 1992, and NUREG/CR-5759.

NUREG-1364 34
Table 5 Cost of modifications minus onsite averted costs (point estimates) for remaining plant life of 40 years ($)

Configuration Plant

Alternative

II II T IV V VI VII VIII A B C

Turbine building

Alternative 2 8,600 -190,000 -190,000 NA NA NA NA NA NA NA

Alternative 3 130,000 -61,000 -61,000 NA NA NA NA NA NA NA

Alternative 4 1,100,000 890,000 890,000 980,000 NA NA NA NA NA NA

Auxiliary building

Alternative 5 NA NA NA NA 11,000 -88,000 -88,000 NA NA NA

Alternative 5A NA NA NA NA 78,000 -22,000 -22,000 NA NA NA

Alternative 6 NA NA NA NA 4,500 -95,000 -95,000 NA NA NA

Alternative 7 NA NA NA NA 150,000 47,000 47,000 NA NA NA

Hydrogen storage

facility

Alternative 8 NA NA NA NA NA NA NA 275,000 -690,000 NA

Alternative 9 NA NA NA NA NA NA NA -210,000 NA NA

Alternative 10 NA NA NA NA NA NA NA 99,000 84,000 41,000

Note: NA = not applicable.

Sources: INEL, 1992, and NUREG/CR-5759.

35 NUREG-1364
Table 6 Cost-benefit uncertainty results for remaining plant life of 20 years

With onsite Without onsite

averted costs averted costs

Percent Percent Percent Percent

probability probability probability probability

Configu. Alter- CBR < $1000/ CBR > $1000/ CBR <$1000/ CBR > $1000,

ration native person-rem person-rem person-rem person-rem

II

III

2

3

4

2

3

4

2

3

4

2

3

4

IV

V

VI

VII

VIII

5

5A

6

7

5

5A

6

7

5

5A

6

7

8

9

10

8

9

10

8

9

10

35

<1

0

100

97

<1

100

97

<1

NA

NA

<1

3

<1

4

<1

100

88

100

51

100

88

100

51

6

100

0

97

NA

<1

NA

NA

8

65

>99

100

0

3

>99

0

3

>99

NA

NA

>99

97

>99

96

>99

4

<1

0

44

13

<1

44

13

<1

NA

NA

<1

2

<1

2

<1

0

12

0

49

0

12

0

49

32

9

31

6

32

9

31

6

2

56

0

68

91

69

94

68

91

69

94

96

>99

100

56

87

>99

56

87

>99

NA

NA

>99

98

>99

98

>99

Plant A

Plant B

Plant C

94

0

100

3

NA

>99

NA

NA

92

7

NA

<1

NA

NA

1

98.

44

100

93

NA

>99

NA

NA

99

Notes: CBR = cost-benefit ratio.

NA = not applicable.

Sources: INEL, 1992, and NUREG/CR-5759.

NUREG-1364 36
Table 7 Cost-benefit uncertainty results for remaining plant life of 40 years

With onsite Without onsite

averted costs averted costs

Percent Percent Percent Percent

probability probability probability probability

Configu- Alter- CBR <$1000/ CBR > $1000/ CBR < $1000/ CBR > $1000/

ration native person-rem person-rem person-rem person-rem

II

III

2

3

4

2

3

4

2

3

4

2

3

4

IV

V

VI

VII

5

5A

6

7

5

5A

6

7

5

5A

6

7

40

<1

<1

100

91

2

100

91

2

NA

NA

<1

5

<1

14

<1

100

97

100

44

100

97

100

44

21

100

0

>99

NA

1

NA

NA

15

60

>99

>99

0

9

98

0

9

98

NA

NA

>99

95

>99

96

>99

5

<1

<1

53

16

<1

53

16

<1

NA

NA

<1

3

<1

4

<1

95

>99

>99

47

84

>99

47

84

>99

NA

NA

>99

97

>99

96

>99

0

3

0

56

0

3

0

56

VIII

39

15

44

7

39

15

44

7

6

71

0

61

85

56

93

61

85

56

93

Plant A

Plant B

Plant C

8

9

10

8

9

10

8

9

10

79

0

100

<1

NA

99

NA

NA

85

11

NA

<1

NA

NA

3

94

29

100

89

NA

99

NA

NA

97

Notes: CBR = cost-benefit ratio.

NA = not applicable.

Sources: INEL, 1992, and NUREG/CR-5759.

37 NUREG-1364
NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER (2-89) (Assigned by NRC, Add Vol., NRCM 1102, Supp., Rev., and Addendum Num3201, 3202 BIBLIOGRAPHIC DATA SHEET bers, If any.)

(See Instructions on the reverse) NUREG-1364

2. TITLE AND SUBTITLE

3. DATE REPORT PUBLISHED

Regulatory Analysis for the Resolution of Generic Safety Issue 106: Piping MONTH YEAR

and the Use of Highly Combustible Gases in Vital Areas June 1993

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

C. C. Graves Technical

7. PERIOD COVERED (Inclusive Dates)

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and

mailing address; If contractor, provide name and mailing address.)

Division of Safety Issue Resolution

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, D.C. 20555

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type "Same as above"; if contractor, provide NRC Division, Office or Region,

U.S. Nuclear Regulatory Commission, and mailing address.)

Same as above.

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

Highly combustible gases such as hydrogen, propane, and acetylene are used at all nuclear power plants. Hydrogen is of

particular importance because it is stored in large quantities and is distributed and used continuously in buildings containing safety-related equipment. Large hydrogen releases at the hydrogen storage facilities or in these buildings could lead

to fires or explosions that might result in loss of safety-related equipment. This report gives the regulatory analysis for the

resolution of Generic Safety Issue 106, "Piping and the Use of Highly Combustible Gases in Vital Areas." Scoping analyses showed that the risk associated with the storage and distribution of hydrogen for cooling electric generators at boilingwater reactors (BWRs), the off-gas system at BWRs, the waste gas system at pressurized-water reactors (PWRs), and

station battery rooms and portable bottles of combustible gas used for maintenance at PWRs and BWRs is small. On the

basis of generic evaluations, the NRC staff has concluded that several possible methods to reduce risk could provide

cost-effective safety benefits at some plants. However, in view of the observed large differences in plant-specific characteristics affecting the risk associated with the use of hydrogen, and the marginal generic safety benefit that can be

achieved in a cost-effective manner, it is recommended that this generic issue be resolved simply by making these results

available in a generic letter. This information may help licensees in their plant evaluations recommended by Generic

Letter 88-20, Supplement 4, "Individual Plant Examination of External Events for Severe Accident Vulnerabilities,"

June 28, 1991.

12. KEY WORDS/DESCRIPTORS (List words or phrases that will assist researchers In locating the report.) 13. AVAILABILITY STATEMENT

Unlimited

14. SECURITY CLASSIFICATION

combustible gases (This Page)

detonation

explosion Unclassified

generic safety issue Ucaified hydrogen Unclassified

piping 15. NUMBER OF PAGES

probabilistic risk analysis

regulatory analysis 16. PRICE

NRC FORM 335 (2-89)