NUREG/CR-5779

ORNL-6687

Vol. 1

Aging of Non-Power-Cycle

Heat Exchangers Used in

Nuclear Power Plants

Operating Experience and Failure Identification

Prepared by

Prepared by

J. C. Moyers

Oak Ridge National Laboratory

Prepared for

U.S. Nuclear Regulatory Commission
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NUREG/CR-5779

ORNL-6687

Vol. 1

RV

Aging of Non-Power-Cycle

Heat Exchangers Used in

Nuclear Power Plants

Operating Experience and Failure Identification

Manuscript Completed: July 1992

Date Published: July 1992

Prepared by

J. C. Moyers

Oak Ridge National Laboratory

Managed by Martin Marietta Energy Systems, Inc.

Oak Ridge National Laboratory

Oak Ridge, TN 37831-6285

Prepared for

Division of Engineering

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555

NRC FIN B0828

Under Contract No. DE-AC05-840R21400
Abstract

This report presents the results of an assessment of

the time-related degradation of non-power-cycle heat

exchangers used in nuclear power plants. The

assessment was sponsored by the U.S. Nuclear

Regulatory Commission's Nuclear Plant Aging

Research Program.

Heat exchanger design characteristics and applications

in the plants are described and stressors leading to

degradation are identified. Operating experience, as

identified from nuclear industry data bases, is reviewed

and failure types and causes are summarized.

Regulatory requirements for inspection and testing,

with a brief discussion of industry practices in this

area, are presented.

iii NUREG/CR-5779
Contents

Abstract ............................................................................. iii

Summary ............................................................................ vii

Acknowledgments . .................................................................... ix

1 Introduction . ....................................................................... 1

1.1 Background ..................................................................... 1

1.2 Objective . ..................................................................... 2

1.3 Project Scope ................................................................... 2

1.4 Definitions . ..................................................................... 2

2 Basic Information ................................................................... 4

2.1 Principal Uses and Types of Heat Exchangers in LWRs .................................... 4

2.1.1 Heat Exchangers in Pressurized Water Reactor Plants ................................ 4

2.1.2 Heat Exchangers in Boiling Water Reactor Plants ................................... 8

2.2 Equipment Boundaries ............................................................ 8

2.3 Functional Requirements .......................................................... 8

2.4 Materials of Construction .......................................................... 8

3 Technical Specification Requirements .................................................... 11

4 Summary of Operational Stressors .......................... ............................. 13

4.1 Electrical Stressors ............................................................... 13

4.2 Mechanical Stressors ............................................................. 13

4.3 Chemical Stressors ............................................................... 13

4.4 Environmental Stressors ........................................................... 15

5 Operating Experience ................................................................ 17

5.1 Information Sources .............................................................. 17

5.2 Summary of Failure Types and Causes ................................................. 17

5.2.1 Shell-side Flow Blockage ...................................................... 20

5.2.2 Tube-side Flow Blockage ...................................................... 20

5.2.3 External Leakage ............................................................ 20

5.2.4 Impending External Leakage ................................................... 22

5.2.5 Inter-fluid Leakage .......................................................... 22

5.2.6 Impending Inter-fluid Leakage .................................................. 23

5.2.7 Impaired Heat Transfer ....................................................... 23

5.3 Failure Types as a Function of Cooling Water ........................................... 24

5.4 Frequency of Failures ............................................................. 24

5.5 Method of Detection .............................................................. 25

6 Maintenance and Surveillance Practices ........ ................ ........................... 29

v NUREGICR-5779
6.1 Codes and Standards Requirements . .................................................. 29

6.2 Electric Power Research Institute (EPRI) Guidelines ..................................... 29

6.3 Utility Practices . .......................................................... 30

7 Aging Degradation Monitoring ......................................................... 31

7.1 Aging-Related Degradation ......................................................... 31

7.2 Degradation Monitoring .......................................................... 31

8 Summary and Recommendations ........................................................ 32

9 References .......................................................... 33

Appendix

A Heat Exchanger Problems Identified from LER Search ..................................... 35

Figures

2.1 Thermal management in PWR plants . ................................................... 5

2.2 Thermal management in BWR plants . .................................................. 9

5.1 Distribution of events by failure type, all functions .......... ............................... 20

5.2 Distribution of tube blockage by heat exchanger function ..................................... 21

5.3 Distribution of tube blockage by cause . ................................................. 21

5.4 Distribution of external leakage by heat exchanger function ................................... 21

5.5 Distribution of external leakage by cause . ................................................. 22

5.6 Distribution of internal leaks by heat exchanger function ..................................... 23

5.7 Distribution of internal leaks by cause . ................................................... 23

5.8 Detection methods, all failure types . .................................................... 26

5.9 Detection methods, tube blockage ...................................................... 26

5.10 Detection methods, external leakage ................................................... 27

5.11 Detection methods, internal leakage ................................................... 27

5.12 Detection methods, impaired heat transfer ............................................... 28

Tables

5.1 Net Types of Failures and Failure Causes from All Databases ................................. 18

5.2 Failure Types and Causes for RHR Heat Exchangers, by Reactor Type .......................... 24

NUREGICR-5779 vi
Summary

This report presents the results of a Phase I

assessment of the time-related degradation (aging) of

non-power-cycle heat exchangers used in safety-related

systems or to provide normal operating capability in

nuclear power plants. The assessment was sponsored

by the Office of Nuclear Regulatory Research, U.S.

Nuclear Regulatory Commission, as an element of the

ongoing Nuclear Plant Aging Research (NPAR)

Program. The objective of an NPAR Phase I

assessment is to review operating experience and other

information, to identify failure modes and causes

resulting from aging, and to identify measurable

parameters that might provide a better indication of

equipment condition.

The report briefly reviews the design and application

of the heat exchangers in both PWR and BWR plants.

Typical design characteristics and materials of

construction are given for the various applications.

Operational stressors are categorized and discussed.

Operating experience events reported in data bases for

nuclear power plants and in nuclear industry reports

were examined. These data bases included the

Licensee Event Report file as cataloged in the

Sequence Coding and Search System maintained by

ORNL's Nuclear Operations Analysis Center, the

Nuclear Plant Reliability Data System compiled by the

Institute for Nuclear Power Operations, Nuclear

Power Experience published by Stoller Power, Inc.,

and maintenance records for a two-unit PWR plant as

furnished by a cooperating utility. A total of 710

reported events were examined. Of these, 279 events

involved interfluid leakage, 217 involved external

leakage, 156 involved tube-side flow blockage, and

25 involved impaired heat transfer.

There are only minimal regulatory or Technical

Specification requirements for inservice inspection and

testing, limited primarily to those inspections and tests

required to maintain the integrity of the pressurecontaining boundary. The general philosophy of plant

operators regarding flow blockage and leakage is that

repairs and maintenance will be done as required.

Improvements to this philosophy that potentially

would lead to enhanced reliability are not apparent

and none is suggested in the report.

Inservice testing to determine the heat transfer

capability of the heat exchangers has normally been

done only when possible degradation was indicated

from observation of process parameters; scheduled

performance testing was not normally done. However,

largely as a result of NRC concerns for the capability

of safety-related, service-water-cooled, heat exchangers

to perform as required under accident conditions and

the resulting issuance of Generic Letter 89-13, plantspecific inservice performance testing programs are

being developed by plant owners. In addition, the

Operation and Maintenance Committee of the

American Society of Mechanical Engineers is

developing standards to address both vibration

monitoring and inservice performance testing of heat

exchangers. As a follow-on to this assessment, an

evaluation of utility experience and findings resulting

from response to Generic Letter 89-13 is

recommended. This evaluation should provide

valuable insights of as-found conditions in plant heat

exchangers, the effectiveness of maintenance practices,

and improved inservice testing methodology.

vii NUREG/CR-5779
Acknowledgments

The author gratefully acknowledges the continuing

support and counsel of the NRC Nuclear Plant Aging

Research Program manager, J. P. Vora, and project

manager, W. S. Farmer, in the planning and

implementation of this study.

The assessment was carried out under the general

guidance of D. M. Eissenberg, ORNL NPAR Program

manager; the author appreciates his encouragement

and advice. D. A. Casada of ORNL's NPAR staff was

very helpful in sharing his experience in the nuclear

plant operating environment and in searches of the

NPRDS data base.

Insights on the operating plant experience and the

procedures under development and in place at the

plants were gained from discussions with other

members of the American Society of Mechanical

Engineers' Working Group OM-21, of which the

author is a member. Additional information was

obtained from Tom Golston, Isidoro DiBiase, Bob

Ives, and Ed Craig of the Tennessee Valley Authority

and from Mike Pugh of Carolina Power and Light.

Their willingness to share this information is deeply

appreciated.

IX NUREG/CR-5779
1 Introduction

1.1 Background

The Office of Nuclear Regulatory Research of the

U.S. Nuclear Regulatory Commission (NRC) has an

ongoing program, the Nuclear Plant Aging Research

(NPAR) Program,' aimed at understanding the timerelated degradation (aging) of nuclear power plant

systems and equipment. It includes assessing the

effectiveness of methods of inspection and surveillance

that monitor such degradation and establishing

guidelines for maintenance. The program is intended

to provide technical bases for examining the ongoing

operational safety of operating plants.

This report addresses the time-related degradation of

heat exchangers used in safety-related systems or that

provide normal operating capability in nuclear power

plants. These heat exchangers usually serve as

interfaces between systems in the plant, transferring

heat to or toward the plant's normal or ultimate heat

sink to maintain desired process temperatures. Heat

exchangers that are associated with the power

conversion systems, such as steam generators, main

condensers, feedwater heaters, and turbine plant

equipment coolers are not included in this assessment.

These power conversion system exchangers are, of

course, necessary for stable power operation but are

not required to function to bring the plant to a safe

shutdown condition.

A major concern for the operational readiness of

safety related heat exchangers that reject heat to the

plant service water has resulted from numerous

reported events in which the service water sides of

these exchangers have experienced fouling or clogging

from corrosion products or from sediment, debris, or

organisms originating in the service water source. The

NRC, in 1981, issued IE Bulletin 81-032 that pointed

out an incident of blockage of flow to containment

cooling units by Asiatic clams and calling for licensees

to check for the presence of clams or mussels in the

plant vicinity and, if present, to check fire protection

and safety related systems for blockage by these

organisms or their shells and to describe methods for

detection and control of future blockage. A

summarization of the licensee responses3 to IEB 81-03

showed that approximately half the active U.S. nuclear

plants have high potential for biofouling, and many of

these had poor programs for detection and control.

In 1982, the NRC established Generic Issue 51,

Improving the Reliability of Open-Cycle Service Water

Systems, and initiated a research program to compare

alternative surveillance and control programs to

minimize the effects of fouling on plant safety.

Although the program was initially aimed at

biofouling, it was later expanded to address fouling by

silt and corrosion products. The resulting document4

presents the results of a review of surveillance and

control programs in use by utilities and provides

guidance for developing such programs.

In 1988, NRCs Office for Analysis and Evaluation of

Operational Data issued a report5 documenting and

evaluating the safety implications of service water

system failures and degradations observed in light

water reactors from 1980 to 1987. From a total of 980

events, 276 were deemed to have potential generic

safety significance. The most frequent (in 58% of

those with safety significance) system degradation

mechanism was fouling, from corrosion/erosion,

biofouling, foreign material or debris, and siltation.

Surveillance methods in use in most plants were

incapable of detecting the condition; detection was

generally only in an on-demand situation. Four

operating events reported in Ref. 5 involved serious

heat exchanger degradation due to fouling of the

exchangers. It was concluded that the safety

significance of service water system failures and

degradations is high.

As a part of NRC's NPAR Program, Pacific Northwest

Labbratory conducted a Phase I aging degradation

assessment of service water systems and published

their findings' in 1989. Conclusions from the

assessment were that a.) aging-related degradation of

service water systems is prevalent and constitutes a

valid safety concern, b.) corrosion, compounded by

biological and inorganic accumulation, is the primary

degradation mechanism, and c.) the accuracy and

completeness of failure data are insufficient to provide

the basis for root cause determination and the

assessment of time-related degradation. A Phase II

assessment to examine methods for managing aging

degradation of service water systems is currently

underway.

As a result of concern due to continuing problems

with service water systems and the heat exchangers

served by those systems, the NRC, on July 18, 1989,

issued Generic Letter 89-13.7 The Letter points out

1 NUREG/CR-5779
Introduction

the statutory requirements, under 10 CFR 50, for

a.) provision of a service water system to transfer heat

from systems and components important to safety to

the ultimate heat sink, b.) design provisions for

periodic inspection and tests to assure integrity and

capability of the cooling water system, and

c.) establishment of a test program, with written test

procedures, to demonstrate that the systems and

components will perform satisfactorily in service. The

Letter requested that licensees perform the following

actions (or explain why the actions are not needed) to

ensure that the service water system and any

intermediate systems used to transfer heat from safetyrelated items to the ultimate heat sink are in

compliance with 10 CFR Part 50.

a. Implement and maintain an ongoing surveillance

and control program to significantly reduce the

incidence of biofouling flow blockage.

b. Implement a test program that includes both

initial and periodic tests to verify the heat transfer

capability of all safety-related heat exchangers

cooled by service water.

c. Implement a routine inspection and maintenance

program for open cycle service water system

components to ensure that any of various fouling

agents cannot degrade the performance of safetyrelated systems supplied by service water to a level

below the safety function requirements during the

interval between inspections.

d. Confirm that the service water system will perform

its intended function in accordance with the

licensing basis for the plant.

e. Confirm that maintenance practices, operating and

emergency procedures, and training involving the

service water system are adequate to ensure

system functionality and operator effectiveness.

In addition to problems with flow blockage and

fouling in heat exchangers served directly by service

water, numerous instances of external and inter-fluid

leakage have occurred in various heat exchangers.

Although minor leakage in many cases may not

compromise the ability of the operators to bring the

reactor to a safe shutdown condition, leakage can

result in cross-contamination of systems or in releases

to the environment.

1.2 Objective

The objective of this NPAR Phase I assessment is to

review operating experience, to identify failure modes

and causes resulting from aging of non-power system

heat exchangers in nuclear plant service, and to

identify measurable parameters which, if tracked in

improved inspection, surveillance, and monitoring

procedures, might result in improved system reliability.

1.3 Project Scope

This assessment covers the following information for

non-power-system heat exchangers used in nuclear

power plants.

1. Background information on heat exchangers -

boundary of equipment to be studied, types, uses,

requirements, and materials of construction.

2. Review of regulatory requirements, guides, and

standards.

3. Summary of operational and environmental

stressors.

4. Summary of operating experience.

5. State-of-the-art aging monitoring and assessment.

1.4 Definitions

For the purposes of this report, the following

definitions apply:

Failure type - one element of a systematic

categorization of the various ways in which a

component does not perform a function for which it

was designed.

Failure cause - the mechanism or agent that is

responsible for the degradation present in a given

component at a given time.

Aging - the combined cumulative effects over time of

internal and external stressors acting on a component,

leading to time-related degradation of the component.

Measurable parameters - physical or chemical

characteristics of a component that can be described

or measured directly or indirectly and that can be

correlated with aging. Useful measurable parameters

are those that can be used to establish trends of the

magnitude of aging associated with each failure cause,

NLTREG/CR-5779 2
Introduction

that have well-defined criteria for quantifying the

approach to failure, and that are able to discriminate

between the degradation that leads to failure and

other degradation.

Inspection, surveillance, and condition monitoring

(OSCM) - the spectrum of methods for obtaining

qualitative or quantitative values of a measurable

parameter of a component. The methods may be

periodic or continuous, and may involve dynamic or

static measurements.

3 NUREG/CR-5779
2 Basic Information

2.1 Principal Uses and Types of Heat

Exchangers in LWRs

Numerous heat exchangers are utilized in pressurized

water and boiling water nuclear power plants, usually

serving as interfaces between plant systems while

transferring heat to or toward the normal or ultimate

heat sink to establish or maintain desired process or

equipment temperatures. With the exception of

containment or room coolers, which are finned coil

types with air on the outside of the tubes, the

predominant heat exchanger type is shell-and-tube.

Normally, to permit effective cleaning in a shell-andtube exchanger, the stream most likely to promote

fouling is on the tube side.

2.1.1 Heat Exchangers in Pressurized Water

Reactor Plants

Typical thermal management in pressurized water

reactor (PWR) plants is represented schematically in

Fig. 2.1. Due to variations in plant designs, the

immediate heat sink for certain heat exchangers differs

as indicated by dashed lines in the figure. The

function and typical descriptions of the various

principal exchangers follow.

Residual Heat Removal (RHR) Heat Exchangers.

These exchangers are used in the second phase of

shutdown cooling, to reduce reactor coolant

temperature to and maintain it at the refueling

temperature. (The first phase of shutdown cooling, to

a coolant temperature of approximately 350'F, is

accomplished by the main steam and feedwater

systems.) They may also provide cooling for

recirculating containment sump water for core cooling

and for containment spray following a loss-of-coolant

accident (LOCA). The usual heat sink for the RHR

heat exchangers is the Component Cooling Water

System. During normal plant operation, the RHR

exchangers are idle.

The RHR heat exchangers are classified as safetyrelated.

Typical RHR heat exchanger design characteristics, as

used in an 1100 MWe plant, are:

Shell side (component cooling water)

flow 2.5 x 10' lb/hr, 95 - 108.81F

material carbon steel

design 150 psig/2501F

Tube side (reactor coolant)

flow 1.5 x 10' lb/hr, 137 - 1141F

material austenitic stainless steel

design 600 psig/4001F

Tubesheet carbon steel w/stainless overlay

Component Cooling Water (CCW) Heat Exchangers.

The Component Cooling Water System functions as

an intermediate barrier between systems and

equipment that are potentially contaminated and the

external environment. Corrosion-inhibited

demineralized water is recirculated through various

source heat exchangers and coolers to the Component

Cooling Water heat exchangers. These latter

exchangers transfer heat from the Component Cooling

Water System to the Service Water System. The CCW

heat exchangers are classified as safety related.

CCW heat exchangers are specified by the plant

engineering firm and, as a result, often differ in

characteristics between plants having the same reactor

supplier and nominal rating. Typical CCW heat

exchanger design characteristics, for an 1100 MWe

plant, are:

HX type Shell-and-straight-tube, with

rolled tube/tubesheet joints (also

plate type)

Shell side (component cooling water)

flow 3.4 x 106 lb/hr, 107.9 - 950F

material carbon steel

design 150 psig/2001F

Tube side (service water)

flow 5.0 x 10' lb/hr, 85 - 93.90F

material admiralty, 90-10 Cu-Ni,

aluminum-brass, or titanium

design 150 psig/200 0F

Containment Spray Heat Exchangers. These heat

exchangers can be used for post-accident containment

cooling to avoid excessive containment pressure

buildup. Water is pumped from the containment HX type Shell-and-U-tube, with welded

tube/tubesheet joints

NUREGICR-57794 4
Basic Information

Purnp & Motor Coolers:

Charging

RH-R

Safety Injection

Letdown HX

Sample Coolers

Seal Water Coolers

Spent Fuel Pool HXs

Reactor Cooldown

Emergency Core Cooling

RHR HXs I

Atmosphere Coolers:

Containment

Control Rod Drive I Water

Pumn & Motor Coolers:

Reactor Coolant

Recirculation Spray HiXs

cCw

Atmosphere Coolers: L.

.~~~~~~~~~~~~~~~~~~~~~. 1 L ...~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

g: ILn rvJ..

It Cool no

system

HXs

Pump & Motor Coolers:

Contairnent Spray

Emergency Diesel HXs

F p

Figure 2.1 Thermal management in PWR plants

5 NUREG/CR-5779
Basic Information

sump through the exchangers to spray headers located

high in the containment vessel.

Air temp. 120 - 103.21F (normal)

264 - 257.30F (accident)

Typical containment spray heat exchanger design

characteristics for an 1100 MWe plant are:

Water flow

Water temp.

Heat load

HX type Shell-and-U-tube, with welded

tube-to-tubesheet joints

1200 gpm (both conditions)

100 - 101.80F (normal)

100 - 206.41F (accident)

1.0 Mbtu/hr (normal)

Shell side (essential raw cooling water) 61.6 MBtu/hr (accident)

flow 5000 gpm, 83 - 109'F

material carbon steel

design 150 psig/2000F

Tube side (spray water)

flow

material

design

4750 gpm, 135.8 - 108.50F

austenititc stainless steel

300 psig/300'F

Containment Atmosphere Coolers. These fan-coil

units are used to maintain containment air

temperature at desired levels during normal operation

and to assist in limiting containment temperature and

pressure during accident conditions. Design and

application of these coolers vary considerably from

plant to plant. The units usually utilize coils having

horizontal tubes with vertical fins on the air side and

may be cooled with service water, emergency raw

water, component cooling water, or chilled water.

Tube materials are selected based on cooling water

characteristics; tube materials used in various plants

include copper, copper-nickel, austenitic stainless steel,

superaustenitic stainless steel, or admiralty metal.

Two-speed fan motors are used in some cases, with

high-speed operation during normal plant operation

and low-speed operation under accident conditions.

Containment atmosphere coolers, are classified as

safety related.

The following complement of containment atmosphere

coolers is included to illustrate a "typical' application

for an 810 MWe unit.

Four fan coil units, cooled by component cooling

water.

(Three are used during normal plant operation;

two units plus one of two containment spray

systems are adequate for design basis accident

conditions.) Values given are for each unit.

Air flow 60,000 acfm (normal, high fan speed)

40,000 acfm (accident, low speed)

Regenerative Heat Exchanger. The regenerative heat

exchanger is a component of the Chemical and

Volume Control System (CVCS), serving to partially

cool the reactor coolant letdown stream by

regeneratively extracting heat from the letdown stream

and transferring it to the reactor coolant charging

stream. To minimize the potential for external

leakage, all-welded construction is typical. Both the

shell side and the tube side of the exchanger are

fabricated from austenitic stainless steel. Since both

shell-side and tube-side streams are reactor coolant at

high pressure, there is no strong preference for one or

the other stream being on the shell side; either

arrangement is used.

Design characteristics of a typical regenerative heat

exchanger, for an 1100-MWe unit, are:

HX type Shell-and-tube, all welded,

designed for >2,000 shell-side

temperature step changes from

130 to 5501F

Shell side (reactor coolant letdown)

flow 37,050 lblhr, 545 2900F

design 2485 psig/6501F

Tube side (reactor coolant charging)

flow 27,170 lb/hr, 130 -495 0F

design 2735 psig/650°F

Letdown Heat Exchanger. The letdown heat

exchanger (also referred to as the nonregenerative

heat exchanger) is a component of the CVCS and

follows the regenerative heat exchanger in the reactor

coolant letdown stream, cooling the letdown stream to

a temperature suitable for demineralizer operation.

Because of a pressure reducing orifice in the letdown

circuit between the regenerative heat exchanger and

the letdown heat exchanger, the latter exchanger is

NUREGICR-5779 6
Basic Information

exposed to a pressure intermediate to those of the

reactor coolant system and the demineralizer.

Design characteristics of a typical letdown heat

exchanger, as used for an 1100 MWe unit, are as

follows:

Design characteristics of a typical seal water heat

exchanger, as used in an 1100 MWe unit, follow.

HX type Shell-and-tube

HX type Shell-and-tube

Shell side (component cooling water)

flow 203,000 lb/hr, 95 - 1251F

design 150 psig/2500 F

material carbon steel

Tube side (reactor coolant letdown)

flow 37,050 lb/hr, 290 - 1270F

design 600 psig/400OF

material austenitic stainless steel

Excess Letdown Heat Exchanger. During reactor

startup, when the reactor coolant volume is increasing

because of rising temperature, the letdown stream flow

is greater than can be effectively cooled in the

regenerative heat exchanger (i.e., there is insufficient

charging flow to absorb the heat). The excess letdown

heat exchanger, a component of the CVCS, essentially

parallels the regenerative and letdown heat exchangers

to provide additional cooling capacity for the letdown

stream while in this mode of operation.

Design characteristics of an excess letdown heat

exchanger for an 1100 MWe unit follow.

Shell side (component cooling water)

flow 99,500 lb/hr, 95 - 1201F

design 150 psig/250'F

material carbon steel

Tube side (reactor coolant)

flow 160,500 lb/hr, 144 - 1270F

design 150 psig/2501F

material austenitic stainless steel

Spent Fuel Pool Coolers. The spent fuel pool coolers

are designed to remove the decay heat from the spent

fuel elements stored in the pool. System design

usually considers that a complete core loading may be

placed in the pool to permit reactor vessel inspection

or maintenance when there is already 1/3 of a core

loading from each reactor at the site in the pool. The

spent fuel cooling system normally can maintain the

pool temperature at less than 1200 F when only 1/3 of

a core from each reactor is present; when an

additional full core is added to the pool, the pool

temperature can be maintained at approximately

1501F.

Design characteristics of a typical spent fuel pool

cooler, as used in an 1100 MWe unit, are as follows:

HX type Shell-and-U-tube, with welded

HX type Shell-and-tube tube/tubesheet joints

Shell side (component cooling water)

flow 115,000 lb/hr, 95 -. 1351F

design 150 psig/2500F

material carbon steel

Shell side (component cooling water)

flow 1.5 x 106 lb/hr, 95 - 1030F

material carbon steel

design 150 psig/200'F

Tube side (reactor coolant letdown)

flow 12,380 lb/hr, 545 -- 1951F

design 2485 psig/65 01F

material austenitic stainless steel

Tube side (fuel pool water)

flow 1.1 x 106 lb/hr, 120 - 109.5 0F

material austenitic stainless steel

design 150 psig/2000F

Seal Water Heat Exchanger. The seal water heat

exchanger, also a component of the CVCS, cools the

portion of reactor coolant pump injection flow that

has cooled and lubricated the pump radial bearing and

exited the pump above the lower seal. The cooled seal

water is then returned to the charging pump suction.

Pump Coolers. Small heat exchangers are employed

to cool the lubricating oil for the reactor coolant,

RHR, main and auxiliary feed, charging, containment

spray, safety injection, and service water pumps. In

addition, coolers to prevent excessive temperatures in

the seal regions of the reactor coolant and main

feedwater pumps are provided as integral parts of

7 7 ~~~~~NUJREG/CR-5
Basic Information

these pumps. Either the Component Cooling Water

System or the Service Water System serves as the heat

sink for the pump coolers.

Equipment Room Coolers. Equipment room coolers,

used to cool enclosures housing safety related

equipment to protect the operability of that

equipment, consist of fan-coil units that may be cooled

by service water, component cooling water, or chilled

water. Air-side filters are provided in some cases to

remove particulates from the recirculating air stream.

The coils are constructed from finned tubes, with

materials selection based on the cooling water

characteristics. Because they serve to protect safety

related equipment, the coolers themselves are

classified as safety related.

Emereencv Diesel Generator Heat Exchangers. The

emergency diesel generators are served by a shell-andtube heat exchanger for each engine that extracts heat

from the engine coolant and transfers it to the

Emergency or Standby Service Water System, or by an

air-cooled radiator. Engine coolant serves as the heat

sink for the engine lubricating oil cooler.

2.1.2 Heat Exchangers in Boiling

Water Reactor Plants

Typical thermal management in boiling water reactor

(BWR) plants is represented schematically in Fig. 2.2.

The functions served by the complement of heat

exchangers in BWR plants are similar to those in

PWR plants as discussed in the preceding section, and

the designs are similar, also. Those functions that are

served by the Component Cooling Water System in

PWRs generally are fulfilled by the Reactor Building

Closed Cooling Water System in BWRs. Upon loss of

offsite power, critical cooling loads are shifted from

the Service Water System to the Emergency

Equipment Cooling Water System, as indicated by the

dashed lines in the figure.

Noteworthy differences in BWR plants are the

multiple functions of the RHR heat exchangers and

the heat sink for these exchangers. In addition to

providing for shutdown cooling and containment spray

cooling as in PWRs, the BWR RHR exchangers may

be used, depending upon individual plant design, to

condense reactor-generated steam during reactor core

isolation conditions, to cool the suppression pool

water, and for augmented fuel pool cooling. While

the RHR exchangers in PWRs are usually cooled by

the component cooling water system, service water is

often used in BWRs. As in PWRs, the RHR

exchangers are idle during normal operation.

2.2 Equipment Boundaries

For purposes of this report, the heat exchangers are

defined to include the following:

1. For shell and tube heat exchangers, the shell

and its nozzles for piping attachment, the

channel head(s) and its (their) nozzles for

piping attachment, the heat exchange tubes,

the tubesheet(s), and, if used, the floating

head.

2. For air-to-water heat exchangers, the tube

bundles and their associated headers.

Associated blowers, air-flow-directing ducting

and unit housings are not included.

2.3 Functional Requirements

The general functional requirements of the heat

exchangers are to transfer the design heat load from

the source system or component to either an

intermediate system or to the normal or ultimate heat

sink, while maintaining fluid isolation between the

source and the intermediate or final sink. (An

exception is the regenerative heat exchanger in PWR

Chemical and Volume Control Systems and in BWR

Reactor Water Cleanup Systems, where heat is

regeneratively transferred from the reactor coolant

letdown stream to the reactor coolant charging

stream.) In certain applications, the heat exchanger is

specified and designed to transfer heat at a given rate

when under specified conditions (e.g., RHR

exchangers under design basis conditions). Other

applications require only that the temperature of a

component or subsystem (e.g., pump lubricating oil)

be maintained at or below a specified temperature

under specified conditions.

2.4 Materials of Construction

Typical materials of construction for certain of the

heat exchangers used in PWR plants were given in

Sect. 2.1.1. Generally, in PWRs, austenitic stainless

steel (type 304 or 316) is used for the side (shell or

tube) of a heat exchanger that is in contact with

NUREG/CR-5779 8
Basic Information

Fuel Pool Cooling HXs

Recirc. Pump & Motor Coolers

Drywell Atmosphere Coolers

React Bldg Equlpt Sump Cooler

Drywell Equipt Sump Cooler

Sample Coolers

RWCU Pump Cooler

Nonregenerative HX

Drywell Control Air Compressor

CR0 Pump Coolers

Shutdown Cooling

Containment Spray

Suppression Pool Cooling

Augmented Fuel Pool Cooling

RCIC Steam Condensing

I RHR HX I

l Core Isolation Cooling

Pump Room Cooler

Core Spray Room Cooler

Core Spray Pump Cooler

RHR Pump & Motor Coolers

EDG HXs

mergency qupment

Cooling Waler

ystem

Figure 2.2 Thermal management in BWR plants

9 9 ~~~~~NUREG/CR-57
Basic Information

reactor coolant. In BWRs, because of rigid

specifications for the chemistry of the reactor water,

carbon steel or copper-nickel alloy is used in some

components in contact with the reactor water. The

side of a heat exchanger contacting the water in a

closed, corrosion inhibited, cooling water system (e.g.,

the shell sides of CCW or PWR RHR heat

exchangers) is usually constructed of carbon steel. In

heat exchangers that reject heat to service water, the

material used in the side exposed to service water

(usually the tube side, to facilitate cleaning) is selected

for compatibility with that water. Materials used for

this application include copper-nickel, aluminum-brass,

admiralty alloy, austenitic stainless steel (type 304 or

316), copper, and superaustenitic stainless steel.

NIJREG/CR-5779 10
3 Technical Specification Requirements

The Technical Specifications for each nuclear power

plant specify Limiting Conditions of Operation (LCO)

that establish requirements for certain system and

component operability' during various operational

modes for the plant. Surveillance requirements are

included in the Technical Specifications that verify

that the LCOs are satisfied. When an LCO is not

met, action requirements for correcting the situation

or for bringing the plant to an operating mode closer

to cold shutdown within a specified time period must

be followed.

Surveillance requirements for inservice inspection and

testing of American Society of Mechanical Engineers

(ASME) Code Class 1,2, and 3 components are to be

performed in accordance with the ASME Boiler and

Pressure Vessel Code, Section XI, unless relief has

been granted by the NRC. Section XI includes

inservice testing provisions for pumps and valves only,

inservice inspection of heat exchangers is limited

primarily to that necessary to assure the integrity of

the pressure-containing capability of the exchangers.

Neither the Technical Specifications nor ASME

Section XI includes requirements for inservice testing

to determine heat exchanger thermal performance or

limiting values for that performance.

As an example of Technical Specification requirements

pertaining to heat exchangers for one PWR plant, the

following summary is presented.

a. In hot shutdown, at least two loops consisting of

any combination of reactor coolant loops or the

RHR loops shall be operable and at least one of

these shall be in operation. If less than the

required complement are operable, immediate

corrective action is to be taken to return the

required loops to operable status, and if the

remaining operable loop is an RHR loop, the

plant shall be in cold shutdown in 24 hours.

Surveillance requirements are that at least one

coolant or RHR loop be verified in operation and

circulating reactor coolant at least once per

12 hours.

A system or component is defined in the Technical

Specifications as being operable or having operability when it is

capable of performing its specified function, and when all necessary

system auxiliaries are also capable of performing their support

functions.

b. In cold shutdown, two RHR loops shall be

operable and at least one shall be in operation,

with proper operation verified at least once per

12 hours.

c. To provide for emergency core cooling, one (when

Tas <350 °F) or two (when T.,6 23500F)

independent ECCS subsystems shall be operable.

One operable RHR heat exchanger and one RHR

pump are included in each operable ECCS

subsystem. Verification procedures for the

operability of the RHR exchangers are not

specified.

d. During refueling operations, one (with high water

level) or two (with low water level) independent

RHR loops shall be operable and at least one

shall be in operation. Proper operation shall be

verified at least once per 12 hours.

e. Two independent containment spray systems shall

be operable during operational modes 1, 2, and 3,

capable of taking suction from the refueling water

storage tank and transferring suction to the

containment sump.

f. Two independent component cooling water loops

shall be operable during operational modes 1, 2,

and 3.

Operability is to be demonstrated by a.) verifying

that each valve is in its correct position once per

31 days and b.) verifying, every 18 months, that

each automatic valve goes to its correct position

upon test signal and that each CCW pump starts

on safety injection test signal.

g. Four containmentfan coolers shall be operable,

with one of two fans per unit capable of operation

at low speed. Operability shall be verified by

a.) once every 31 days, operating fans for

15 minutes and verifying cooling water flow to

each cooler is adequate and b.) once every

18 months, verifying that fans start automatically

upon injection signal.

h. Area temperatures, in tabulated equipment areas

(including rooms for CCW pumps, auxiliary

feedwater pumps, charging pumps, RHR pumps,

containment spray pumps, and others) shall not

exceed specified values by more than 301F or for

11 NUREG/CR-5779
Technical Specification

more than 8 hours. If the area temperature

exceeds the specified value by more than 301F, the

temperature is to be restored to the specified

value within four hours or the affected equipment

shall be declared inoperable.

i. Primary containment average air temperature shall

not exceed 1201F. To verify, average of

temperatures at three levels in containment shall

be determined once per 24 hours.

Technical Specification requirements for BWR plants

generally are similar to those for PWRs, except for

additional requirements for suppression pool spray

and cooling functions. Example requirements for

these functions include:

a. The RHR system shall have two independent

loops operable in the suppression pool spray mode

during plant operating conditions 1, 2, and 3.

Each loop consists of one operable RHR pump

and an operable flow path capable of recirculating

water from the suppression chamber through an

RHR heat exchanger and the suppression pool

spargers.

Surveillance requirements include a once-in-31-

days verification that each valve is in the correct

position and verifying, per ASME Section XI, that

each of the required RHR pumps develops the

specified flow through the heat exchanger and

spray sparger.

b. Two independent loops of the RHR system shall

be operable in the suppression pool cooling mode

during operating conditions 1, 2, and 3. Each

loop consists of one operable RHR pump and an

operable flow path capable of recirculating

suppression pool water through an RHR heat

exchanger.

Surveillance requirements include verification,

once per 31 days, that valves are in their correct

positions and, per ASME Section XI, that each

required RHR pump develops the specified flow

through the RHR heat exchanger, the suppression

pool, and the full-flow test line.

NUREG/CR-5779 12
4 Summary of Operational Stressors

During their service life in a nuclear power plant, heat

exchangers are exposed to operational stressors that

may result in functional degradation. These stressors

are described in the following subsections.

4.1 Electrical Stressors

The only electrical stressor for heat exchangers is

galvanic corrosion resulting from coupling of materials

remote from one another on the electromotive series.

The potential for galvanic corrosion can be reduced by

the use of sacrificial anodes, usually magnesium,

inserted in the fluid path of the exchanger.

4.2 Mechanical Stressors

a. Fluid pressure. Fluid pressures exert mechanical

stress on the heat exchanger shell, tubes,

tubesheet, channel heads and partitions, gaskets,

and nozzles. The exchangers are designed with

comfortable strength margins to withstand those

pressures expected to be encountered under both

normal and accident conditions. However,

exchanger damage may result from excessive

pressures from improper isolation of the

exchangers from systems undergoing hydrostatic

testing, from transient pressure excursions caused

by water hammer, or in the case of channel

partitions, from tube flow blockage.

b. Piping system reactions. Piping systems attached

to the heat exchanger nozzles exert thrusts and

moments on the heat exchangers at their nozzles

as the piping undergoes expansion and contraction

from system temperature changes or moves from

fluid forces.

c. Differential expansion. The tubes in a shell-andtube heat exchanger are often fabricated from a

metal having a different coefficient of thermal

expansion than the shell material. In addition, the

fluid temperatures in the shell and the tubes may

be quite different in steady state operation or may

undergo large variations in temperature, with

time, during cyclic operation. As a result, in fixed

tubesheet designs, tensile or compressive stresses

are imposed on the shell and tubes during

operation. Floating head or U-tube designs are

often adopted for applications having large

temperature differences to minimize differential

expansion stresses. Some exchangers have a

specified maximum lifetime number of thermal

cycles.

Differential expansion stresses may lead to

relaxation and leakage at rolled tube-to-tubesheet

joints. In recognition of this, recommended

maximum metal temperatures for various tube

materials used with carbon steel tubesheets are

given in the Heat Exchange Institute's Standard

for Power Plant Heat Exchangers.8

d. Tube vibration. Vibration of the tubes in a heat

exchanger can lead to failure due to either fatigue

of the tubes or to fretting corrosion where the

vibrating tubes contact baffles. Tube vibration can

result from excessive shell-side flow velocities

across the tubes, often in the area where shell-side

flow enters the tube bundle, and can be attributed

to improper design or to operation at flow rates

outside the design specifications.

e. Tube erosion. Tube erosion may result from

excessive tube-side velocity, excessive shell-side

velocity (especially in areas near the inlet nozzles),

or from suspended abrasive material in the

cooling water. Recommended maximum tube-side

velocities for different tube materials with clean

water are included in Ref. 8, and range from

10 ft/sec for stainless steel, nickel alloys, and

titanium, to 8.5 ft/sec for copper, admiralty alloy,

and aluminum-brass. Lower velocities should be

used with water containing erosive solids. Heat

exchangers containing erosive solids in the shell

side water require an impingement plate to

protect the tube bundle from erosion near the

shell inlet nozzle.

4.3 Chemical Stressors

Corrosion is a major form of heat exchanger

degradation and, except for galvanic corrosion caused

by electrical currents generated by the coupling of

dissimilar metals in an electrolyte, is caused by

chemical agents to which the heat exchanger materials

are exposed. These agents may be constituents of the

water flowing through the exchanger, or may be

generated or concentrated by organisms or

mechanisms within the exchanger. An excellent

summary description of the various corrosion

mechanisms applicable to heat exchangers is provided

in a draft document9 prepared by Pacific Northwest

13 NUREGICR-5779
Operational Strcssors

Laboratories and is included in the following

paragraphs.

Pitting is a localized form of corrosion that

results in small craters or holes in the metal.

Pitting is potentially one of the most

insidious forms of corrosion because it can

lead to component failure by perforation

while producing only a small loss of metal.

Because of their small size and because the

pits are often covered with corrosion

products, they can be difficult to detect.

Pitting occurs when one area of a metal

surface becomes anodic with respect to the

rest of the surface, or when highly localized

changes in the environment in contact with

the surface cause accelerated attack. Causes

of pitting include local inhomogeneities on or

beneath the metal surface, local loss of

passivity, mechanical or chemical rupture of

the protective oxide surface film, galvanic

corrosion from a relatively distant cathode,

and the formation of a metal ion or oxygen

concentration cell under a solid deposit

(crevice corrosion). The rate of penetration

into the metal by pitting may be 10 to 100

times greater than for general corrosion. The

most common causes of pitting in steels are

surface deposits that set up local

concentration cells, and dissolved halides that

produce local anodes by rupture of the

protective surface scale. With corrosion

resistant alloys, such as stainless steels, the

most common cause of pitting is the highly

localized destruction of passivity through

contact with a halide-containing environment.

Intergranular attack is preferential dissolution

of the grain boundary regions of a metal with

only slight or negligible attack of the grain

matrix. This preferential attack can be

enhanced by segregation of specific elements

or impurities, by enrichment of one of the

alloying elements in the grain boundaries, or

by the depletion of an element that imparts

corrosion resistance to the grain boundary

areas. Susceptibility to intergranular attack

usually develops during thermal processing

such as welding or heat treatments. The

susceptibility to intergranular attack can often

be corrected by redistributing alloying

elements more uniformlythrough solution

heat treatment, by modifying the alloy to

increase resistance to segregation, or by use

of a completely different alloy.

Stress corrosion cracking (SCC) is an aging

mechanism that occurs by the combined and

synergistic interaction of tensile stress, an

aggressive environment, and a susceptible

material. The material fails by slow,

environmentally-induced crack growth that

occurs with little or no attendant macroscopic

plastic deformation. The stresses required to

cause SCC are usually below the yield

strength, and are tensile in nature. These

stresses can be either applied or residual, and

may result from the fabrication process or

inservice loading of the component or

structure. Common sources of stress include

thermal processing and stress risers created

during surface finishing, fabrication, or

assembly. The length of time required to

produce SCC decreases for increasing stress

level. The minimum stress at which cracking

will occur depends on the temperature, the

composition and microstructure of the alloy,

and the environment. SCC may initiate at

pre-existing mechanical cracks or other

surface discontinuities, such as pits produced

by chemical attack. Although high tensile

stresses are not necessary for irradiationassisted SCC, they can aggravate the

phenomenon.

Microbiologically influenced corrosion occurs

when biological organisms affect corrosion

processes on metals by directly influencing

the anodic and cathodic reactions, by affecting

the protective surface scales on metals, by

producing corrosive substances, or by creating

solid deposits. These organisms include

microscopic forms, such as bacteria, and

macroscopic types, such as algae and

barnacles. Microscopic and macroscopic

organisms have been observed to live and

reproduce under broad ranges of pressure,

temperature, humidity, and pH; thus

biological organisms may influence corrosion

in a variety of environments.

Erosion-corrosion is an accelerated form of

corrosion caused by the relative motion of a

corrosive fluid with respect to a metal

NUREG/CR-5779 14
Operational Stressors

component. The corrosion process is

accelerated because of erosive destruction of

the protective oxide film.

4.4 Environmental Stressors

Heat exchangers operating with service water on one

side are exposed to environmental stressors that

depend upon the quality of the service water.

Degradation may be in the form of reduced cooling

water flow from siltation or accumulation of living

organisms or their debris, reduced heat transfer

capability from fouling of the heat transfer surfaces by

mineral scale, silt, or biological slime, or corrosion

either from the chemical nature of the water or from

the effects of accumulated silt or organisms.

Macrofouling by bivalves. Flow blockage problems by

bivalve organisms are frequently experienced in plants

using fresh water, brackish water, and seawater as

service water. The principal organisms causing

macrofouling, in fresh water systems, the Asiatic clam

and the zebra mussel. In brackish water and seawater

systems, macrofouling is caused by the blue mussel and

the American oyster. A brief discussion of these

organisms, their habitat, and their impact on heat

exchangers served by service water follow.

Asiatic clams. Asiatic clams are non-native fresh

water mollusks that were first found in the

Columbia River in 1938 and now are found in

most major river systems in the United States.

The larvae (less than 200 microns in size) are

released by the adults during the spawning season

and are swept, suspended in the water, into the

plant via the water intake. In regions of low flow

velocity (up to about 1 ft/sec), they then attach

themselves to solid surfaces and grow to

approximately 0.2 inch, at which size they lose the

ability to remain attached. (Under suitable

conditions, the adult clam may reach an average

length of about 1.4 inches.) Once unattached, the

clams or their shells may be swept deeper into the

plant and clog piping or heat exchanger tubes.

Systems that are used infrequently, with periods of

near-stagnant conditions under which the larvae

flourish, are most susceptible to clam fouling.

Continuous chlorination of the intake water

during peak spawning season appears to offer a

substantial degree of control, but can lead to

accelerated corrosion unless properly managed.

Shock chlorination is ineffective; the clams restrict

their feeding and respiratory functions or burrow

into sediments to resist the treatment. Clams are

very susceptible to heat; Ref. 2 cites TVA tests

showing 100%-mortality (at a 99% confidence

level) of larvae, young, and half-inch clams when

exposed to 120'F water for two minutes.

Zebra mussels. The zebra mussel was introduced

to North America in 1985 by a European ship

discharging ballast water into Lake St. Clair.

Since then, it has spread into Lake Erie, Lake

Ontario, and Lake Michigan and is expected to

eventually spread throughout the U.S. and

southern Canada."0 Like the Asiatic clam, zebra

mussel larvae are carried into power plants by the

raw cooling water and settle out in low-velocity

areas where they attach to hard surfaces. Unlike

the clam, they remain firmly attached and

accumulate in great numbers to form mats that

may reach a thickness of up to 12 inches. Shells

that break loose from these mats can be carried

downstream and block heat exchangers.

Corrosion enhancement due to reduced flow

velocities can occur.

Zebra mussel infestation is a relatively new

problem in the U.S., and control methodology is

still under investigation."l'Zl3 14

Blue mussels. Blue mussels are found along the

entire west coast of the U.S. and along the east

coast as far south as the Carolinas, with growth

supported by a temperature range of 34 to 790F

(Ref. 4). They settle and attach to firm, rough

substrata or to each other in regions where flow

velocity is less than about four ft/sec, forming

clusters and mussel beds. From these

communities, mussels or their shells may break

free and be carried into the heat exchangers. A

continuous flow of water is conducive to growth.

Continuous chlorination of the service water, at a

concentration of approximately 0.2 ppm and

especially during the spawning season, appears to

be effective in controlling blue mussels. Thermal

backflushing with hot water (1130F for 20

minutes) has also been found to be an effective

control method (Ref. 3).

American oysters. American oysters are found

along the entire Atlantic and Gulf coasts of the

15 NIJREG/CR-5779
Operational Stressors

U.S., with growth supported by water

temperatures between 34 and 97IF (Ref. 4). The

larvae settle and attach themselves to solid

surfaces, including the shells of dead oysters, and

proceed to grow with, some reaching a maximum

size of more than 8 in. As with the blue mussel, a

continuous flow of nutrient-containing water, at a

velocity up to 4 ft/sec, is conducive to growth.

Oysters and shells that break free create flow

blockage in heat exchangers.

Control of oysters can be achieved in the same

manner as for blue mussels.

Microbiological fouling. Microbiological fouling can

seriously degrade the performance of heat exchangers

by coating the heat transfer surface with slime and is

conducive to pitting corrosion damage.

Microbiological fouling increases rapidly at velocities

less than 3 ft/sec, but has also has been found to occur

in condenser tubes at velocities of 6 to 8 ft/sec

(Ref. 4).

Microbiological fouling may be removed from heat

exchanger tubes by pumping sponge balls through the

heat exchangers or by chemical or other mechanical

cleaning methods. However, a preferred approach is

to prevent its formation by the use of biocides, such as

chlorine.'s

NUREG/CR-5779 16
5 Operating Experience

5.1 Information Sources

Aging information for heat exchangers was obtained

from various sources of nuclear power plant operating

experience documentation. These include Licensee

Event Reports (LER), Nuclear Plant Reliability Data

System, and Nuclear Power Experience (NPE).

Maintenance records from two individual plants, one a

single-unit BWR for which maintenance records are

cataloged in the In-Plant Reliability Data System

(IPRDS) and the other a two-unit PWR plant for

which maintenance records were made available by the

owning utility, were examined but are not included in

the assessment. Very few heat exchanger related

maintenance calls were included and they provided

little additional insight to the aging process.

LERs are issued by nuclear-plant-operating utilities to

inform the NRC of plant events having significant

safety implications. ORNL's Nuclear Operations

Analysis Center (NOAC) maintains a depository of

these documents and provides a search capability

through the Sequence Coding and Search System

(SCSS); it was through this system that LERs

applicable to heat exchanger problems were identified

and retrieved. A total of 194 LERs, representing

operations during the 1980-1989 time period, were

included in this assessment. These LERs are

summarized in the Appendix.

The NPRDS, compiled by the Institute for Nuclear

Power Operations, provides a searchable data base of

safety-related events that occur in U.S. nuclear power

plants. Although the NPRDS collection usually

includes LER-reported events, many others that are of

lower safety significance are also included. A total of

510 heat exchanger related events, occurring in the

1974-1989 time frame, were identified. Of these, 470

were not covered in the LER compilation.

Nuclear Power Experience, published by Stoller

Power, Inc., is a compilation, derived from several

sources, of operating experience in light water

reactors. A search of this data base for heat exchanger

events was carried out by the NOAC, and 109 heat

exchanger related events were identified. Only 46 of

these were not included in the LER and NPRDS

compilation.

The events were categorized by heat exchanger

function, failure type, and failure cause. Function

categories include emergency diesel generators,

containment cooling, residual heat removal,

component cooling water, component coolers, and

miscellaneous. The component coolers category

includes lube oil coolers for pumps, motors, and gear

boxes, pump seal coolers, and motor coolers. The

miscellaneous category includes gland seal condensers

for pump drive turbines, sample coolers, letdown

coolers, and sump coolers. Failure types and the

causes attributed to each will be delineated in the

following section.

5.2 Summary of Failure Types

and Causes

The numbers of events identified from the operating

experience information sources, broken out by

information source, heat exchanger function, failure

type, and cause are given in Table 5.1. In examining

the number of events from each information source,

the order used in considering the sources should be

kept in mind: all of the LER-reported events are

included; only those NPRDS-reported events not

included in the LER information are included; and

only NPE-reported events not included in either the

LER or NPRDS information are included. It is

obvious, even with this ordering, that the NPRDS

provides the richest source for failure data.

The distribution of reported events by failure type for

all heat exchanger functions is shown in Fig. 5.1.

Three failure types account for more than 90% of the

total number of reported events. Internal leaks,

between the two fluid streams, is the leading failure

type at 39% of the total. External leaks is the secondmost prevalent failure type, at 30% of the total, and

tube blockage is third,-at 22% of the total. Minor

internal or external leakage often does not

compromise the safety function of a heat exchanger,

but may result in low-magnitude environmental

releases. Tube blockage is a safety-threatening event,

involving not only the affected exchanger but

indicating the potential for a common-mode failure of

other exchangers receiving flow from the same source.

Impaired heat transfer events, in which the heat

transfer surface becomes fouled to the extent that the

exchanger cannot accomplish its intended function,

account for less than 4% of the total. This paucity of

reported events may be due to limited application of

performance testing programs needed to detect the

degradation of heat transfer capabilities.

17 17 ~~~~~NURIEG/CR-57
0

Table 5.1 Net Types of Failures and Failure Causes from All Databases

Failure Type and Cause DIES CONT RHR CCW COMP MISC TOTAL

A BC T A BC T A BC T A BC T ABCT ABCT A B C T ~ '~Shell-side flow blockage, total 0 0 11 300 3'0 00 0 010 10 00 00 0 00 3 11 5

Scale buildup 0 0 11 2 00 2 00 00 00 00 00 00 00 0 02 0 13

Other debris 0 0 00 1 00 10 00 00 00 00 00 0 00 00 1 0 01

Coating failure 0 0 00 000 00 00 00 10 10 00 00 0 00 0 10 1

Tube-side flow blockage, total 2 15 5 22 10 9 0 19 6 4 0 10 9 73 2 84 8 13 0 21 0 0 0 0 35 114 7 156

Unspecified 0 2 02 00 00 00 0 04 408 01 01 00 0 04 7 011

Scale buildup 1 2 140 00 00 00 00 00 00 00 00 0 00 1 2 14

Silt buildup 0 3 03 6 3 09 02 02 013 0133 6 09 00 0 0927 036

Biological growth 0 7 310 4 40 82 1 032 10 3 140 50 0 00 9 17 329

Biological debris 1 0 12 01 0 13 0 03 235 2393 0 030 0 00 9 36 348

Other debris 0 1 01 010 10 10 1 114 0150 10 10 0 00 1 18 019

Shcll/head/nozzle corrosion/erosion 0 0 00 0 00 00 00 00 0 00 1 00 10 0 00 1 00 1

Coating failure 0 0 00 0 00 01 00 1 06 060 00 00 0 00 1 6 07

00 Other 0 0 00 0 00 00 00 00 0 00 0 1 01 0 0 00 0 1 0 1

External leakage, total 6 20 1 27 56 24 0 80 0 30 1 31 3 30 1 34 15 12 229 12 4 0 16 92 120 5 217

Unspecified 2 1 0324 3 027 01 01 00 0 030 03 00 0 029 5034

Tube failure, corrosion 0 0 00 8 8 0160 00 00 00 0 01 120 0 00 8 9 118

Tube failure, erosion/wear 0 3 03 21 2 023 00 00 00 0 060 17 00 0 027 51 33

Tube failure, fatigue/mech. stress 0 0 11 0 6 060 00 00 00 00 00 00 0 00 0 6 17

Shellflhead/nozzle corrosion/erosion 23 05 0 00 00 0 11 111 1132 1 030 0 00 5 15 222

Weld failure 0 1 01 0 10 1 02 02 22 042 0 0200 0 04 6 010

Coating failure 0 0 00 000 00 00 00 10 10 00 00 0 00 0 10 1

Gasket failure 0 9 09 010 1 018 018 013 0131 8 09 11 4 01512 53 065

Other 2 3 05 33 06 09 09 03 03 12 031 0 01 7 20 027

Impending external leakage, total 1 0 01 00 00 00 0 02 16 0180 00 00 0 00 3 16 019

Shelllhead/nozzle corrosion/erosion 1 0 01 0 00 00 0 00 1 10 0110 00 00 0 00 2 10 012

Coating failure 0 0 00 000 00 00 0 06 060 00 00 0 00 0 6 06

Weld failure 0 0 00 000 00 00 01 00 10 0 000 0 00 1 0 01
Table 5.1 Net Types of Failures and Failure Causes from All Databases (continued)

Failure TMpe and Cause DIES CONT RHR CCW COMP MISC TOTAL

A B C T A B C T A B C T A BC T A B C T A B C T A B C T

Inter-fluid leakage, total 1122 235 1 0 2 3 20 33 13 66 5 121 6 132 1122 2 35 6 0 2 8 54 198 27 279

Unspecified 8 6 0 14 0 0 2 2 6 0 3 9 1 4 3 8 6 6 1 13 3 0 2 5 24 16 11 51

Tube failure, corrosion 1 3 1 5 1 0 0 1 3 14 2 19 2 48 0 50 4 4 0 8 0 0 0 0 11 69 3 83

Tube failure, erosion/wear 2 9 112 0 0 0 0 0 5 3 8 0 58 0 58 0 6 0 6 1 0 0 1 3 78 4 85

Tube failure, fatigue/mech. stress 0 2 0 2 0 0 0 0 1 1 1 3 2 6 3 11 0 1 0 1 1 0 0 1 4 10 4 18

Tube-to-tubesheet joint failure 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 0 1 1 0 0 1 1 1 0 2

Shell/head/nozzle corrosion/erosion 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 2 0 0 0 0 0 0 0 0 0 2 0 2

Weld failure 0 0 0 0 0 0 0 0 0 0 1 1 0 0 0 0 0 0 1 1 0 0 0 0 0 0 2 2

Gasket failure 0 0 0 0 0000 9 10 3 22 0 0 0 0 0 2 0 2 0 0 0 0 9 12 3 24

Other 0 2 0 2 0 0 0 0 1 3 0 4 0 3 0 3 1 2 0 3 0 0 0 0 2 10 0 12

Impending inter-fluid leakage, total 0 1 0 1 0 0 0 0 0 0 3 3 0 1 1 2 0 0 0 0 0 0 0 0 0 2 4 6

Tube failure, erosion/wear 0 1 0 1 0 0 0 0 0 0 1 1 0 1 0 1 0 0 0 0 0 0 0 0 0 2 1 3

vo Tube failure, fatigue/mech. stress 0 0 0 0 0 0 0 0 0 0 2 2 0 0 1 1 0 0 0 0 0 0 0 0 0 0 3 3

Impaired heat transfer, total 2 3 1 6 4 0 0 4 0 1 0 1 1 7 1 9 0 5 0 5 0 0 0 0 7 16 2 25

Unspecified 2 0 1 3 4 0 0 4 0 0 0 0 0 1 0 1 0 2 0 2 0 0 0 0 6 3 1 10

Scale buildup 0 1 0 1 0 0 0 0 0 1 0 1 0 2 0 2 0 0 0 0 0 0 0 0 0 4 0 4

Silt buildup 0 0 0 0 0 0 0 0 0 0 0 0 0 4 1 5 0 3 0 3 0 0 0 0 0 7 1 8

Biological growth 0 2 0 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 2

Fluid circuitrydamage 0 0 0 0 0 0 0 0 0 0 0 0 1 0 0 1 0 0 0 0 0 0 0 0 1 0 0 1

Other, total 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 2 0 1 0 1 0 0 0 0 0 3 0 3

GRAND TOTAL 22 61 1093 74 33 2 109 26 68 17 111 20 251 11 282 3453 4 91 18 4 2 24 194 470 46 710

A - From LER database 0

g B - From NPRDS database, exclusive of LER events

C - From NPE database, exclusive of LER and NPRDS events

T - Net total

Li
Operating Experience

Imp. Ext. Leak 2.7%

External Leak 30.5%

Imp. Int. Leak 0.8% (

Tube Blockage 21.9%

shehl Boqkage 0.7%

Impaired Ht Trn 3.8%

Internal Leak 39.2%

Figure 5.1 Distribution of events by failure type, all functions

5.2.1 Shell-side Flow Blockage

Shell-side flow blockage is a relatively infrequent type

of failure because usual practice in design is to place

the fluid with fouling or flow-blocking tendencies on

the tube side of the exchanger to facilitate cleaning.

Only one instance of shell-side blockage in a shelland-tube exchanger was reported, in a CCW heat

exchanger from failure of the coating. The other four

shell-side blockages were actually air-side blockages in

air-to-water exchangers, three in containment air

coolers which were blocked by boric acid

accumulations or repair debris and one diesel aircooled radiator with blockage from fin corrosion.

5.2.2 Tube-side Flow Blockage

Tube-side flow blockage, in which solid material

accumulates in the channel heads or in the tubes

themselves, is a problem found in the various heat

exchangers cooled by service water. The blockage may

build up with time, as biofouling, siltation, or debris

accumulation progresses, or it may occur quickly due

to an upset in the service water system that loosens

shells or silt which then are transported into the heat

exchanger.

The distribution of the 156 reported tube-side

blockage events among the various heat exchanger

functions is shown in Fig. 5.2. More than half the

events occurred in the Component Cooling Water

NUREG/CR-5779

exchangers, and about an eighth each in component

exchangers, containment atmosphere coolers, and

emergency diesel exchangers. Tube blockage events in

RHR exchangers were limited to BWR plants; in

PWR plants, the RHR exchangers are not exposed to

service water.

The distribution of blockage events by reported cause

is shown in Fig. 5.3. Half the events are attributed to

biological causes, either biological growth that occurs

in place or debris from bivalves. Blockage by silt

(23%) and debris (12%) account for most of the

remaining identified event causes.

5.2.3 Extemal Leakage

External leakage, where one of the fluids flowing

through the heat exchanger leaks to the surrounding

environment, is the second-most prevalent failure type,

with 217 reported events. External leakage results

from failure of the shell or its joints in shell-and-tube

exchangers, or from tube failure in an air cooler. It

should be noted that leakage in an air cooler might be

classified as interfluid leakage. However, since this

leakage is to the surrounding environment, it is

included here. It should be further noted that minor

external leakage may not interfere with an exchanger's

ability to fulfill its safety function.

The distribution of external leakage events by heat

exchanger function is shown in Fig. 5.4. More than

20
Operating Experience

External Leak

Imp r xt.teak

- ~ 1 ////////tComp. 13.5%

CCW 53.8%

a

Imp. Int. Leak

Tube Blockag

21.9%

\ Bh~~~~~~itall-plckage

Internal Lsak InnpardOther - - Internal Lea..' ...- ipie Ht Tmn - - -

RHR 6.4%

Cont. 12.2%

Diesel 14.1%

Figure 5.2 Distribution of tube blockage by heat exchanger function

Coating 4.5%

7 7 Debris 12.3% External Leak

p Gxt.-C.;k

Imp. Int. Leak Biological 50%

Tube Blockage

21.9%

\ ~~~~~~fteOllh2lockage NJ"'J..-' Leak In~paie& Ot hr - - _, Internal Lea ,mpedH -.-- Tm -=

Scale 2.6%

Sill 23.4%

Unspecified 7.1%

Figure 53 Distribution of tube blockage by cause

Internal Leak

Misc. 7.4%

Comp. 13.4%

CCW 15.7%

RHR 14.3%

Cont. 38.9%

Diesel 12.4%

External Leak

30.5%

Impaired Ht Tmn -

Shell Blockage m

Tube Blockage

Figure 5.4 Distribution of external leakage by heat exchanger function

21 21 ~~~~~NUREG/CR-5
Operating Experience

one third of the reported events were associated with

containment atmosphere coolers. Shell-and-tube

exchangers for the component cooling water, RHR,

component cooling, and diesel cooling functions each

account for 12-16% of the events.

Distribution of the events by cause is shown in

Fig. 5.5. Gasket and weld failures and shell corrosion,

all in shell-and-tube exchangers, account for about

45% of the total. Almost all of the cause-unspecified

failures represent tube failures in containment

atmosphere coolers; these and other tube failures

attributed to erosion, corrosion, and fatigue occurred

in air coolers, either containment atmosphere or

motor coolers. Erosion due to excessive water velocity

or entrained silt was the most-often cited cause of

tube failures. The 'Other' cause category includes a

wide variety of miscellaneous occurrences, such as

loose flange bolts, faulty fittings and plugs, and

manufacturing or design deficiencies.

5.2.4 Impending External Leakage

Impending external leakage events are those in which

inspection revealed wall thinning or pitting of the shell

or channel heads that would ultimately lead to

external leakage if corrective actions in the form of

repair or control measures were not taken. In most

instances, the cause was attributed to coating failure

(sometimes due to erosion) or to lack of proper

cathodic protection.

events. This type of failure may cause undesirable

contamination of normally low-activity systems (e.g.,

the Component Cooling Water System or the Service

Water System), possibly leading to environmental

releases, or may result in contamination of clean,

closed systems such as the Component Cooling Water

System with service water.' Inter-fluid leaks in some

component coolers may result in severe degradation of

the component's lubricating oil and lead to component

damage.

The distribution of the inter-fluid, or internal, leakage

events by heat exchanger function is shown in Fig. 5.6.

Almost half the reported events were in component

cooling water heat exchangers and almost one-quarter

were in RHR exchangers. Review of the data revealed

that 94% of the internal leakage events for RHR

exchangers occurred in BWR plants, resulting to some

extent from the practice of using service water to cool

these exchangers in those plants. Heat exchangers for

cooling components and for diesel cooling each

accounted for one-eighth of the total.

Distribution of the events by attributed cause is shown

in Fig. 5.7. Two-thirds of the events were from tube

leaks attributed to corrosion, erosion, and fatigue. In

addition, many of the cause-unspecified events were

tube leaks. Corrosion was the major cause of tube

failures in RHR exchangers and 84% of these

corrosion-caused failures occurred in BWR plants,

probably reflecting the effect of long periods of

idleness (during normal reactor operation) with

5.2.5 Inter-fluid Leakage

Inter-fluid leakage, where one of the fluids leaks into

the fluid flowing on the other side of the heat

exchanger, was the most prevalent failure type

identified in the data sources, with 279 reported

In some applications, system design establishes the differential

pressure between the two sides of the exchanger such that any

interfluid leakage will be in the desired direction (e.g., in fuel pool

coolers, any leakage will be service water into the pool water to

preclude releases of contaminated water to the environment.

___--- -.... :.. Other 12.5%

Gasket failure 30.1 %

Weld failure 4.6% .::::,:::::: eak Shell corrosion 10.2 /////////v Tube fatigue 3.2%

Tube erosion 15.3%

'4/ // ///////X Tube corrosion 8.3%

Unspecified 15.7%

Figure 55 Distribution of external leakage by cause

NUREG/CR-5779 22
Operating Experience

p Other

Shell Blockage Nf. Impaired Ht Trn - - - -

Tube Blockaoi

Other 4%

Comp. 12.5%

CCW 47.3%

RHR 23.7%

Imp. Ext. Leak Internal Leak

39.2%

External L Imp. ak Int. Leak

Figure 5.6 Distribution of internal leaks by heat exchanger function

Other

Shell Blockage Impaired Ht Trn - -

Tube Blockage

Other 7.5%

Gasket failure 7.5%

Tube fatigue 6.5%

Tube erosion 31.2%

Tube corrosion 29.0

Unspecified 18.3%

Imp. Ext. Leak Internal Leak

39.2%

External Leak~Imp. Int. Leak

Figure 5.7 Distribution of internal leaks by cause

incomplete replacement of contained service water by

demineralized water for the idle periods. In CCW

exchangers, erosion was the leading attributed tube

failure cause (49% versus 42% due to corrosion),

reflecting continuous flow of service water in these

exchangers. Most of the inter-fluid leaks attributed to

gasket failures were in RHR heat exchangers,

occurring in floating head joints.

5.2.6 Impending Inter-fluid Leakage

Impending inter-fluid leakage events consisted of the

discovery, during inspection or cleaning, of erosion or

vibration damage to tubes before actual leakage had

occurred. Only six of these events were reported, one

in a diesel glycol cooler, three in RHR exchangers,

and two in CCW exchangers.

5.2.7 Impaired Heat Transfer

Impaired heat transfer events consisted of instances

where a heat exchanger was unable to transfer the

required amount of heat because of fouling of the heat

exchange surface or fluid circuitry damage. Although

event descriptions were not definitive in all cases, it

appears that these events were not caused by flow

blockage. Of the 25 events reported, six were related

to the emergency diesel coolers, four to containment

coolers, one to RHR heat exchangers, nine to

component cooling water heat exchangers, and five to

component coolers. Eight of the events with

identified cause were attributed to silt buildup, four to

scale buildup, and two to biological fouling. Only one

was attributed to fluid circuitry damage, due to pass

partition plate deflection because of inadequate

design.

23 NUREG/CR-5779
Operating Experience

5.3 Failure Types as a Function of

Cooling Water

It has been noted previously that certain failure types

occur primarily in heat exchangers cooled by service

water. This is substantiated by the data in Table 5.2,

in which the events reported in the NPRDS data base

for RHR heat exchangers are separated by reactor

type. In PWR plants, with few exceptions, these

exchangers are cooled by component cooling water. In

BWR plants, the usual practice is to utilize raw service

water for this function. Although the population of

BWR reactors is approximately half that of PWR

reactors and the population of RHR exchangers in

BWRs is approximately 70% of that for PWRs, events

reported for BWR exchangers were higher by a factor

of 3.4.

Table 5.2 Failure Types and Causes for RHR Heat

Exchangers, by Reactor Type

Failure Type and Cause PWR BWR

External leakage events occurred in the RHR heat

exchangers of both PWR and BWR plants, due

primarily to gasket failures. Except for the propensity

for corrosion of components operating in untreated

service water, a failure cause for which there were no

reported external leakage events for either reactor

type, cooling water quality should have little influence

on this failure type.

Inter-fluid leakage events were prevalent in BWR

plant RHR heat exchangers but rare in those for

PWRs. For the BWRs, approximately 40% of these

failures were attributed to corrosion of tubes (waterquality-related) and more than 30% were attributed to

gasket failures in the floating heads of the exchangers

(probably not water-quality-related). Five events, one

in a PWR plant that uses component cooling water for

cooling the RHR exchangers and four in BWRs, were

attributed to wear (usually not further defined).

Only one impaired heat transfer event, due to fouling

of the heat exchange surface by deposit buildup, was

reported. This occurred in a PWR plant that uses raw

Tube-side flow blockage, total

Silt buildup

Biological growth

Other debris

External leakage, total

Unspecified

Weld failure

Gasket failure

Other

service water (lake water) for RHR heat exchanger 0 4 cooling.

0 2

0 1 5.4 Frequency of Failures

0 1

14 16 Data from which the frequency of heat exchanger

1 0 failures can be determined are not available from the

0 2 information sources used in this assessment. From

8 10 consideration of the operating experience data and

5 4 from the very nature of heat exchanger failures, it is

2 38 questionable whether frequency of failures, or mean

0 1 time between failures, is a meaningful index of

1 16 reliability for these components.

Inter-fluid leakage, total

Unspecified

Tube failure, corrosion

Tube failure, erosion/wear

Tube failure, fatigue/mech. stress

Gasket failure

Other

Impaired heat transfer, total

Scale buidup

GRAND TOTAL

1 4

The failures are of two basic types - impaired flow

0 13 passing or heat transfer capabilities due to fouling of 0 3 the flow passages or heat transfer surface, and leakage

either between fluid streams or to the external

1 0 environment. Impaired flow passage events were

1 0 attributed predominantly to biological growth or

17 58 debris, the development of which is not normally a

long term time-dependent phenomenon but is related

to seasonal effects and inadequacy of control methods.

v blockage Impaired heat transfer events were attributed to a

nts were variety of causes, some of which (e.g., scale and silt

,vents were buildup) are time-related, but this problem type

laneous debris accounted for less than four percent of the total

the reported events. Inter-fluid leakage was most often

attributed to tube-side corrosion and erosion/wear.

There were no instances of tube-side flow

reported for PWR plants, while four evei

reported for BWR plants. These BWR e

due to silt, biological growth, and miscell

from the raw service water used to cool I

exchangers.

NUREG/CR-5779 24
Operating Experience

Both corrosion and erosion damage are cumulative

with time.

When failures have occurred, they usually have been

attributable to plant-specific equipment designs,

materials of construction, or local water conditions or

methods of treatment. Failures from these local

situations are not amenable to the derivation of global

representations of frequency of failures.

5.5 Method of Detection

The NPRDS data base includes information

identifying how each reported failure was recognized

or brought to the attention of the plant staff. The

detection means are categorized as follows.

Operational abnormality. A failure detected from

indications received during normal operation of the

system or component by individuals assigned duties

involving the system.

Inservice inspection. A failure detected during a

scheduled inservice inspection, such as might be

required by the ASME Boiler and Pressure Vessel

Code, Section XI.

Surveillance testing. A failure detected through

routine periodic testing, as for calibration, trippoint checks, or functional checks.

Preventive maintenance. A failure detected while

performing preventive maintenance.

Special inspection. A failure detected during

the performance of an inspection not

routinely scheduled or required.

Audiovisual alarm. A failure detected by an

alarm that either can be heard or seen.

Routine observation. A failure detected as a

result of normal log taking, log review, or

daily/weekly inspections. Usually, this would

be within the normal duties or job function

performed by plant personnel.

Incidental observation. A failure detected by

casual observation or chance witnessing by

individuals not assigned duties involving the

system.

Other. A failure in which the method of

detection cannot be assigned to any of the

above categories.

The distribution of all failure types by detection

category is shown in Fig. 5.8. Detection by routine

observation during normal activities of plant personnel

was the leading means for failure recognition,

accounting for almost one-third of the total.

Detection from operational abnormalities, surveillance

testing, and special inspections each account for nearequal fractions of the total and, in combination,

accounted for half the total. Detection during

preventive maintenance activities accounted for eight

per cent of the total, and less than five per cent each

were detected by incidental observation, audiovisual

alarms, or inservice inspection.

As would be expected, the incidence of failure

discoveries by the various detection categories varies

significantly between the different failure types.

Figs. 5.9 - 5.12 present the distributions, by detection

method, for the more significant failure types.

Flow blockage failures were most often recognized by

excessive pressure differential (approximately 53% of

events). Other blockages were found during

inspections and tests (21%), by high system or

component temperatures (14%), or by low flow (12%).

The distribution, by method of detection, of tube

blockage failures as shown in Fig. 5.9 is quite similar

to that for total failures. Routine observations

account for about one-third of the total, followed by

operational abnormalities and surveillance testing at

one-fifth each. Special inspections detected about

one-eighth of the tube blockage failures, and the

remainder were detected by audiovisual alarms,

preventive maintenance, inservice inspection, and

incidental observation.

Detection of external leakage failures was distributed

among detection methods as shown in Fig. 5.10. This

type of failure often has visible effects and is more

readily observable than other failure types. As with

tube blockage failures, the dominant detection method

was routine observation, comprising 37 per cent of the

total. Special inspections detected more than onefifth, and incidental observation one-tenth of the total.

Internal leaks, between the two fluid streams, are

detectable from changes in closed system surge tank

level, from chemical or activity measurement, from

25 NUREGICR-5779
Operating Experience

C

17.4% B

2.9%

D

8.0%

15.4% 5

4

4.5%

H

30.6%

A - Operational Abnormality

B - Inservice Inspection

C - Surveillance Testing

D - Preventive Maintenance

E - Special Inspection

F - Audiovisual Alarm

H - Routine Observation

J - Incidental Observation

Figure 5.8 Detection methods, all failure types

B

C 3.0%

20.1%

0

4.98'

E

12.8'

:- ......................- gt 24%

,,,...,, .' .. ,. ,...'.'. .. '.....

....... g,..,.,... ,...

H

31.1%

A - Operational Abnormality

B - Inservice Inspection

C - Surveillance Testing

D - Preventive Maintenance

E - Special Inspection

F - Audiovisual Alarm

H - Routine Observation

J - Incidental Observation

Figure 5.9 Detection methods, tube blockage

NUREGICR-5779 262
Operating Experience

D

7.3% C

7.3%

A

7g9%

................

................

................ 10.2% ................ ................ ................

...............................

...............................

...............................

.............................. .............................

H

37.3%

A - Operational Abnormality

B - Inservice Inspection

C - Surveillance Testing

D - Preventive Maintenance

E - Special Inspection

F -Audiovisual Alarm

H - Routine Observation

J - Incidental Observation

Figure 5.10 Detection methods, external leakage

C

15.6%

B

1.2%

D

11.91

J

2.0%

E

13.1%

F --~ * * ~ A - -- H

4.5% 29.1%

A -Operational Abnormality

B - Inservice Inspection

C - Surveillance Testing

D- Preventive Maintenance

E -Special Inspection

F - Audiovisual Alarm

H - Routine Observation

J - Incidental Observation

Figure 5.11 Detection methods, internal leakage

27 NUREG/CR-5779
Operating Experience

C

64.7N

A - Operational Abnormality

C - Surveillance Testing

E - Special Inspection

A

1 1.8%

F - Audiovisual Alarm

H - Routine Observation

J - Incidental Observation

Figure 5.12 Detection methods, impaired heat transfer

inspections and tests, or from visual observation (such

as water in lubricating oil). Distribution, by detection

method, of the internal leak failures is shown in

Fig. 5.11. Slightly more than half the failures were

detected by routine observations and operational

abnormalities. Surveillance testing, special

inspections, and observations during preventative

maintenance each accounted for about one-eighth of

the total.

Failures due to impaired heat transfer were detected

as shown in Fig. 5.12. Almost two-thirds were

detected during surveillance testing. Operational

abnormalities, often consisting of excessive system or

component temperatures, revealed almost 15 per cent

of the failures and special inspections, often resulting

from observance of operational abnormalities,

accounted for almost 12 per cent of the total.

NUREG/CR-5779 28
6 Maintenance and Surveillance Practices

6.1 Codes and Standards

Requirements

The Code of Federal Regulations (10 CFR Part 50)

General Design Criteria 44, 45, and 46 require

provision of a service water system to transfer heat

from systems and components important to safety to

the ultimate heat sink. They further require that the

system design permits periodic inspection and testing

of important components, such as heat exchangers, to

assure the integrity and capability of the system.

Generic Letter 89-13 (GL 89-13), issued in July 1989,

requires nuclear plant licensees and applicants to

provide assurances of compliance with 10 CFR Part 50

and that the safety functions of their service water

systems are being met. Initially, GL 89-13 requires

testing of safety-related heat exchangers at least once

per refueling cycle; after three cycles, the licensee may

modify the frequency of testing as appropriate to

assure that the equipment will perform the intended

safety function during the interval between tests. The

minimum final testing frequency should be once every

5 years.

The ASME Boiler and Pressure Vessel Code,

Section XI, the provisions of which are incorporated

by reference in plant Technical Specifications, is aimed

primarily at assuring the integrity of pressure

containing boundaries and includes requirements for

preservice inspection and subsequent periodic

reexamination of welds in pressure-containing parts of

heat exchangers. Also included are requirements for

periodic system leak and hydrostatic tests. There are

no requirements for inservice performance testing of

the exchangers.

The ASME Operation and Maintenance

Committee is in the process of developing standards

and guides that cover inservice testing of various

nuclear plant components and systems. Parts of these

that are applicable to heat exchangers are:

Part 2 - Requirements for Performance Testing

of Nuclear Power Plant Closed Cooling Water

Systems. This Part was published as a part of

the ASME OM-S/G-1990 Standard.

Requirements include tests to demonstrate

system operability at intervals of not greater

than 18 months, and tests to evaluate heat

removal capability of the system and

degradation of system components at 5-year

intervals. It is suggested that heat removal

capability be evaluated in terms of the overall heat

transfer coefficient, U, that is derived from

measured parameters, the available heat transfer

area, A (accounting for plugged tubes), and the

available log mean temperature difference. Any

heat exchanger degradation would be revealed by

monitoring the product of U and A.

Part 11 - Vibration Monitoring of Heat

Exchangers. This Part, recently accepted by

the ASME/ANSI OM approval procedures,

has not been published. The Part provides

guidance for the development of test

procedures and evaluation of data for the

measurement and evaluation of heat

exchanger vibration.

Part 21 - Inservice Performance Testing of Heat

Exchangers in LWR Plants. This Part is under

development, with presentation for first-level

balloting scheduled for late 1992. The Part

will provide performance and functional

testing criteria for auxiliary safety related heat

exchangers to assure that they meet their

intended safety functions from a thermal

performance standpoint.

The ASME O&M Part 21 will provide methodology

for selecting those heat exchangers to be included in

the inservice testing program, for selecting the types of

tests to be conducted, and for the conduct and results

analysis of the tests. In recognition of varying degrees

of difficulty associated with establishing suitable test

conditions and means for measuring test parameters, a

hierarchy of test methods ranging from heat transfer

coefficient determination to visual inspection is being

developed. Part 21 is limited to evaluation of thermal

performance; flow-induced vibration, structural

integrity, pressure boundary integrity, and

erosion/corrosion are not addressed.

6.2 Electric Power Research Institute

(EPRI) Guidelines

In recognition of the utility industry's need for

guidance in developing test programs applicable to

heat exchangers cooled by service water, EPRI has

developed and published the Heat Exchanger

Performance Monitoring Guidelines.16 Original

29 29 ~~~~~NUREGICR-57
Maintenance Practices

development of the Guidelines was carried out by two

utility engineers who later were appointed chairman

and secretary of the ASME O&M Part 21 Working

Group. As a result, the structure of the Guidelines

and early drafts of Part 21 have many similarities. The

Guidelines document provides a valuable tool to assist

the utilities in developing programs for performance

monitoring of heat exchangers subject to fouling.

6.3 Utility Practices

Inservice inspection activities conducted by plant

owners varies, depending upon operating experience at

each plant. For plants having no serious fouling

potential from the service water, inservice inspections

are often limited to those required to assure integrity

of pressure containing boundaries, as required by the

ASME Code.

Other plants that have experienced biofouling, fouling

by siltation or scale, or MIC may have regularly

scheduled inspections that consist of removing the

exchanger heads and inspecting for the presence of

fouling or MIC. One plant schedules these

inspections at 3-year intervals for shell-and-tube CCW

exchangers. This same plant has replaced some of its

shell-and-tube exchangers with plate type exchangers.

Operating experience with these exchangers is limited;

disassembly and cleaning is presently scheduled on an

annual basis until further experience is gained. In

addition, a performance test is scheduled for once per

refueling cycle. In this test, sufficient data is obtained

to permit determining the overall heat transfer

coefficient and, from this, the fouling factor is derived

for comparison with its limiting value.

The Turkey Point Nuclear Plant, owned and operated

by Florida Power and Light, utilizes a recirculating

open-loop Intake Cooling Water System to provide

cooling water for the CCW heat exchangers. Because

of the high mineral content of this water, the fouling

factor for the CCW exchangers has been observed to

increase at a rate of 0.00007 to 0.00009 hr-ftZF/Btu/day"7

. Since 1985, a heat exchanger performance

testing program has been conducted to track the

degradation of heat transfer ability and to aid in

determining the schedule for tube cleaning such that

the exchangers can meet their accident condition

performance requirements with the existing intake

cooling water temperature. As needed, tube cleaning

is accomplished by forcing cleaning plugs through the

tubes by water pressure.

NUREG/CR-5779 30
7 Aging Degradation Monitoring

7.1 Aging-Related Degradation

The results of the degradation of heat exchangers

generally are limited to flow blockage on either the

shell or tube side, leakage to the external environment

of one of the fluids flowing through the exchanger,

leakage of one of the fluids into the other, or reduced

heat transfer capability due to fouling of the heat

transfer surface. Each of these degradation types may

be time-related (although on quite different time

scales) and may, therefore, be considered a result of

aging.

7.2 Degradation Monitoring

Degradation monitoring methods were discussed

generally in an earlier section describing the methods

of detection of failures in heat exchangers, and are

summarized as follows.

Flow blockage

Direct flow measurement

Abnormal pressure differential across

exchanger

Reduced heat transfer function

Excessive temperature rise in cooling fluid

Physical inspection

External leakage

Physical observation

Fluid accumulation in sumps

Hydrostatic and leak testing

Acoustic emission testing

Radiographic or ultrasonic inspection (for

impending leakage)

Interfluid leakage

Chemical and radiolytic analysis

Surge tank level monitoring

Hydrostatic and leak testing

Acoustic emission testing

Eddy current tube testing (for impending leakage)

Observation of fluid appearance (e.g., water in oil)

Fouling of heat exchange surface

System or component temperature monitoring

Performance testing

Abnormal pressure differential across exchanger

31 NUREG/CR-5779
8 Summary and Recommendations

Nuclear power plants utilize many heat exchangers in

the non-power-cycle portion of the plants to provide

system and component cooling in both safety-related

and non-safety systems. These exchangers are exposed

to stressors that have, in numerous instances, resulted

in degraded performance or in failures of various

types.

Many of the leakage failures, either external or

internal, do not compromise the ability of the

exchangers to fulfill their safety functions but may

result in low magnitude environmental releases.

Failures of more serious consequence are those that

result in inadequate heat transfer ability for normal

operations or for meeting more stringent requirements

associated with accident conditions. These failure

types consist of blockages that prevent adequate

cooling water flow or fouled heat transfer surfaces that

degrade cooling performance. Both of these types of

failures are limited primarily to exchangers that utilize

raw cooling water as their heat sink. A major

problem is the control of biological organisms in the

raw water; biocide injection at the raw water intakes is

the most common control method, but this

increasingly is in conflict with environmental

regulations.

Flow blockage and external or interfluid leakage

problems are usually detectable through careful

monitoring of process variables and routine

observations. Detection and assessment of the severity

of fouled heat transfer surfaces are more difficult,

often requiring a special performance test and

evaluation of the acquired data. It appears that, in the

past, this was done on a sporadic basis, possibly

because there were no firm Code or Technical

Specification requirements that these tests and

evaluations be conducted. Recently, probably because

of the requirements contained in Generic Letter 89-13,

procedures for the performance tests and subsequent

analyses have been or are being developed for many

plants. Part OM-21 of the ASME Operation and

Maintenance Standards, now under development, will

formalize the requirements for and present such

procedures.

The difficulties in conducting performance tests,

assessing the results, and predicting performance at

accident conditions for certain heat exchangers are

recognized. In many cases, installed instrumentation is

not available to accurately measure the needed

parameters. Sufficient heat load to permit effective

performance testing may not be available for some

exchangers except during reactor cooldown (e.g., the

RHR exchangers), requiring that the tests be

conducted within a relatively narrow time frame. In

other cases, a system or storage tank must be

abnormally heated to provide the heat load for

exchanger testing during the return to normal

temperatures, necessitating testing under transient

conditions.

It is concluded that presently used methods for the

detection of flow blockage and leakage, either external

or interfluid, are adequate and means for improvement

are not evident. Although it appears that degradation

of heat transfer ability due to fouled heat exchange

surface has not been monitored, through inservice

performance testing, as well as it should have been,

extensive activity to establish programs in this area is

underway both by plant owners and the ASME

Operation and Maintenance Committee and

improvements should be forthcoming.

An evaluation of experience and findings resulting

from utility response to Generic Letter 89-13 is

recommended. This evaluation should provide

valuable information and insights on the as-found

conditions and capabilities of plant heat exchangers,

the effectiveness of extant and enhanced maintenance

practices, and improved inservice testing methodology.

NUREG/CR-5779 32
9 References

1. Nuclear Plant Aging Research (NPAR) Program

Plan, Components, Systems, and Structures,

NUREG-1144, Rev. 2, June, 1991.

2. NRC IE Bulletin 81-03, Flow Blockage of Cooling

Water to Safety System Components by Corbicula

Sp. (Asiatic Clam) and Mytilus Sp. (Mussel), April

10, 1981.

3. J. H. Rains, W. J. Foley and A. Hennick, Closeout

of IE Bulletin 81-03: Flow Blockage of Cooling

Water to Safety System Components by Corbicula

sp. (Asiatic Clam) and fyytlus sp. (Mussel),

NUREG/CR-3054 (PARAMETER IE-138), June

1984.

4. D. A. Neitzel and K I. Johnson, Technical

Findings Document for Generic Issue 51: Improving

the Reliability of Open-Cycle Service-Water Systems,

NUREG/CR-5210 (PNL-6623), August 1988.

5. Peter Lam and Eric Leeds, Operating Experience

Feedback Report - Service Water System Failures

and Degradations, NUREG-1275, Vol. 3,

November 1988.

6. D. B. Jarrell, et al, Nuclear Plant Service Water

System Aging Degradation Assessment, Phase I,

NUREG/CR-5379 (PNL-6560), Vol. 1, June 1989.

7. NRC Generic Letter 89-13, Service Water System

Problems Affecting Safety-Related Equipment, July

18, 1989.

8. Heat Exchange Institute, Inc., Standard for Power

Plant Heat Exchangers, First Edition, 1980.

9. Standard Review Plan for License Renewal, Draft

NUREG-1299, Pacific Northwest Laboratories,

issued for public comment on December 4, 1990.

10. R. F. McMahon and J. L. Tsou, Impact of

European Zebra Mussel Infestation to the Electric

Power Industry, Proceedings of the American

Power Conference, Chicago, 1990, pp. 988-997.

11. L. K Barton, Control of Zebra Mussels at CEI

Facilities, Proceedings of the American Power

Conference, Chicago, 1990, pp. 1001-1005.

12. R. F. McMahon, B. N. Shipman, and D. E. Erck,

Effects of Two Molluscicides on the Freshwater

Macrofouling Bivalve, Dreissena Polymorpha, the

Zebra Mussel, Proceedings of the American Power

Conference, Chicago, 1990, pp. 1006-1011.

13. L. A. Lyons, et al, New Treatment Employing a

Molluscicide for Macrofouling Control of Zebra

Mussels in Cooling Systems, Proceedings of the

American Power Conference, Chicago, 1990, pp.

1012-1021.

14. Y. G. Mussalli, Effective Control Technologies for

Zebra Mussels: Worldwide Experiences,

Proceedings of the American Power Conference,

Chicago, 1990, pp. 1022-1027.

15. G. J. Licina, Detection and Control of

Microbiologically Influenced Corrosion in Nuclear

Power Plants, EPRI NP-6815-D, Electric Power

Research Institute, Palo Alto, 1990.

16. Heat Exchanger Performance Monitoring

Guidelines, EPRI NP-7552, Electric Power

Research Institute, Palo Alto, 1991.

17. T. K H. Lum and E. M. Vaughn, Nuclear Service

Water System Heat Exchanger Evaluation Program,

Proceedings of the American Power Conference,

v52, Chicago, 1990, pp 915-920.

33 NUREG/CR-5779
Appendix A. Heat Exchanger Problems

Identified From LER Search

35 35 ~~~~~NuREG/CR-5779
Appendix A

RHR HEAT EXCHANGER PROBLEMS FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE: Tube-side Blockage

CAUSE TYPE: Biological Growth

BEAVER VALLEY 2

OYSTER CREEK

04/27/89 89-13 SERVICE WATER FLOW RESTRICTION THROUGH

RECIRCULATION SPRAY HX FROM ASIATIC CLAMS.

12/30/82 82-64 HIGH BAFFLE PLATE DELTA P DUE TO BIOFOULING IN

CONTAINMENT SPRAY HXI

CAUSE TYPE: Biological Debris

BRUNSWICK 1

BRUNSWICK 2

BRUNSWICK 2

04/19/81 81-32 BAFFLE PLATE IN CHANNEL HEAD OF 1B RHR HX WAS

DISPLACED, DUE TO EXCESSIVE PRESSURE

DIFFERENTIAL FROM BLOCKAGE BY SHELLS.

04/12/80 80-30 BAFFLE PLATE IN CHANNEL HEAD OF RHR HX WAS

DISPLACED DUE TO HIGH DIFFERENTIAL PRESSURE

FROM SHELL ACCUMULATION.

05/06/81 81-49 PARTIAL DISPLACEMENT OF CHANNEL HEAD DIVIDER

PLATE IN RHR HX DUE TO HIGH DIFFERENTIAL

PRESSURE FROM BLOCKAGE BY SHELLS.

CAUSE TYPE: Coating Failure

OYSTER CREEK 07/22/85 85-18 FRAGMENTS OF PIPE-COATING COAL TAR ENAMEL

PARTIALLY BLOCKED TUBESHEET OF CONTAINMENT

SPRAY HX, CAUSING HIGH BAFFLE PLATE DELTA P.

PROBLEM TYPE: Inter-fluid Leakage

CAUSE TYPE: Unspecified

ARKANSAS NUCLEAR 2 01/09/83 83-3 ACTIVITY IN SERVICE WATER SYSTEM DUE TO TUBE

LEAKS AND TUBE-TO-TUBESHEET WELD LEAKS IN THE

SHUTDOWN COOLING HX.

DRESDEN 3 06/20/80 80-26 THIRTEEN LEAKY TUBES WERE FOUND IN THE LPCI

HEAT EXCHANGER.

37 NUREG/CR-5779
Appendix A

RHR HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

MAINE YANKEE 09/29/82 82-32 TRANSIENT LEAKAGE IN RHR HX WAS DETECTED BY

XE-133 ACTIVITY IN SECONDARY CCW SYSTEM.

PEACH BOTTOM 2 03/28/84 84-6 CONTAMINATION IN HPSW SYSTEM FROM LEAK IN

BELLOWS PORTION OF RHR HX

PEACH BOTTOM 3 11/04/82 82-22 RADIOACTIVE LEAK TO INTAKE STRUCTURE VIA LEAK

IN RHR HX

SURRY 2 07/20/86 86-11 SERVICE WATER LEAKAGE INTO CONTAINMENT DUE TO

EIGHT LEAKING TUBES IN RECIRCULATING SPRAY HX.

CAUSE TYPE Tube Failure. Corrosion

DRESDEN 2 09/04/8

DRESDEN 3 12/15/8

0

0

80-33

8044

OYSTER CREEK 02/19/80 80-9 TI

CC

CAUSE TYPE: Tube Failure, Fatigue or Mechanical Stress

OYSTER CREEK 08/27/81 81-38 FA

CC

CAUSE TYPE: Gasket Failure

BROWNS FERRY 1 04/11/80 80-43 LI

LC

BROWNS FERRY 1 06/20/80 80-49 LIE

)RROSION-INDUCED LEAKAGE FOUND IN 46 TUBES OF

'CI HX.

)RROSION-CELL CORROSION RESULTED IN LEAKS

HAT SHOWED UP AFTER CLEANING IN 4 TUBES IN THE

'CI HX.

HE FOUR CONTAINMENT SPRAY HXS DEVELOPED

)RROSION-INDUCED LEAKS

LTIGUE-INDUCED FAILURE OF TUBES IN SHUTDOWN

)OLING HX.

EAKAGE FROM GASKET IN RHR HX DUE TO LOOSENED

)CK NUTS.

EAKAGE AT FLOATING HEAD OF RHR HX DUE TO

)OSE LOCKING AND FULL NUTS RESULTING FROM

IERMAL CYCLING AND VIBRATION.

EAKAGE AT INNER FLOATING HEAD GASKET OF RHR

X, CAUSED BY RELAXATION OF GASKETED JOINT.

,AKING GASKET ON 2B RHR HX DUE TO LOOSE

ANGE NUTS RESULTING FROM THERMAL CYCLING

ND VIBRATION.

BROWNS FERRY 1

BROWNS FERRY 2

11/28/85

08/15/80

86-4

80-33

NUREG/CR-5779 38
Appendix A

RHR HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

BROWNS FERRY 2

BROWNS FERRY 2

BROWNS FERRY 3

MONTICELLO

QUAD CITIES 1

08/15/80 80-34 GASKET LEAK ON 2C RHR HX DUE TO LOOSENED LOCK

NUTS AND FULL NUTS, RESULTING FROM THERMAL

CYCLING AND VIBRATION.

12/05/80 80-53 LEAKY INNER HEAD GASKET ON 2C RHR HX DUE TO

LOOSE FLANGE NUTS RESULTING FROM THERMAL

CYCLING AND VIBRATION.

08/15/80 80-33 LEAKING GASKET IN RHR HX DUE TO LOOSE FLANGE

NUTS, CAUSED BY THERMAL CYCLING AND VIBRATION.

05/04/82 82-6 LEAK IN RHR HEAT EXCHANGER AT FLOATING HEAD

GASKET.

01/09/83 834 MINOR LEAKAGE BETWEEN PRIMARY SYSTEM TO RHR

SERVICE WATER DUE TO INNER HEAD GASKET FAILURE

IN THE IA RHR HX.

CAUSE TYPE: Other

BROWNS FERRY 3 01/16/83 83-4 LEAK OF REACTOR COOLANT TO RHR SERVICE WATER

VIA CRACKED TUBE IN RHR HX. CAUSE WAS

MECHANICAL DAMAGE PRIOR TO TUBE INSTALLATION.

39 NUREG/CR-5779
Appendix A

CONTAINMENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE: Shell-side Blockage

CAUSE TYPE: Scale Buildup

MILLSTONE 2 04/08/88 88-8 AIR FLOW BLOCKAGE IN CEDM COOLER RESULTED IN

OVERHEATING OF CONTROL ELEMENT GRIPPER COILS

AND PREMATURE DROPPING OF CONTROL ELEMENTS.

BLOCKAGE WAS FROM BORIC ACID ACCUMULATION.

OCONEE 3 01/12/89 89-1 AIR-SIDE SERVICE-INDUCED FOULING OF REACTOR

BUILDING COOLING UNITS REDUCED PERFORMANCE

CAPABILITIES OF THE UNITS TO UNACCEPTABLE LEVEL.

(PER NPRDS, FOULING WAS BORON (BORIC ACID?))

CAUSE TYPE: Other Debris

TURKEY POINT 3 01125/86 86-4 DEBRIS FROM PREVIOUS STEAM GENERATOR REPAIR

WAS FOUND ON THE AIR SIDE OF THE CONTAINMENT

FAN COIL COOLERS.

PROBLEM TYPE. Tube-side Blockage

CAUSE TYPE: Silt Builduo

FITZPATRICK

KEWAUNEE

10/21/88 88-9 EXTENSIVE FOULING OF REACTOR BUILDING UNIT

COOLERS BY MUD AND SILT.

09/28/84 84-18 ESF EQUIPMENT AREA FAN COIL UNITS FOUND TO HAVE

SUBDESIGN AIR FLOW AND PARTIAL PLUGGING OF

WATER FLOW PASSAGES BY SILT, SUCH THAT ACCIDENT

CONDITIONS CAPABILITY WAS INADEQUATE.

SALEM 2 08/31/82 82-96 LOW SERVICE WATER FLOW THROUGH

CONTAINMENT FAN COIL UNIT #23 DUE TO SILT

BUILDUP IN COOLING COILS.

SALEM 2 09101/82 82-98 LOW SERVICE WATER FLOW THROUGH

CONTAINMENT FAN COIL UNIT #21 DUE TO

BUILDUP IN COOLING COILS.

SILT

SALEM 2 09/02/82 82-99 LOW SERVICE WATER FLOW THROUGH

CONTAINMENT FAN COIL UNIT #23, DUE TO SILT

BUILDUP IN COOLING COILS.

NUREG/CR-5779 40
Appendix A

CONTAINMENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

SALEM 2 09/08/82 82-105 REDUCED SERVICE WATER FLOW THROUGH

CONTAINMENT FAN COIL UNIT #22 DUE TO SILT

BUILDUP IN COILS.

CAUSE TYPE. Biological Growth

ARKANSAS NUCLEAR 1

ARKANSAS NUCLEAR 2

BROWNS FERRY 3

ROBINSON 2

09/16/80 80-35 LOW SERVICE WATER FLOW THROUGH REACTOR

BUILDING COOLING COILS DUE TO GROWTH OF ASIAN

CLAMS IN COOLERS.

09/03/80 80-72 SERVICE WATER FLOW RESTRICTION IN

CONTAINMENT BUILDING COOLERS DUE TO BUILDUP

OF ASIAN CLAMS GROWING IN THE COOLERS.

11/08/80 80-47 FLOW RESTRICTIONS TO CORE SPRAY ROOM COOLER

DUE TO BIOFOULING, SILT ACCUMULATION, AND

CORROSION.

09/05/88 88-19 BIOLOGICAL FOULING OF TUBE-SIDE OF

CONTAINMENT FAN COOLERS REDUCED FLOW ABILITY

TO LESS THAN REQUIRED FOR DESIGN BASIS HEAT

REMOVAL.

PROBLEM TYPE: Exterior Leakage

CAUSE TYPE: Unspecified

DAVIS-BESSE 1

INDIAN POINT 2

INDIAN POINT 2

INDIAN POINT 3

ROBINSON 2

ROBINSON 2

09/15/81 81-57 'MINOR TUBE LEAKS IN ECCS ROOM AIR COOLERS.

08/19/82 82-33 SERVICE WATER LEAK FROM MAIN COIL OF FAN

COOLER UNIT.

09/02/82 82-37 SERVICE WATER LEAK FROM COIL OF FAN COOLER

UNIT.

1205/80 80-16 TUBE LEAK IN MAIN COIL OF FAN COOLER UNIT #35.

07/04/83 83-14 SERVICE WATER LEAK FROM DEFECTIVE TUBE BUNDLE

IN CONTAINMENT FAN COOLER HVH-2.

08123/83 83-22 SERVICE WATER LEAK FROM DEFECTIVE TUBE BUNDLE

IN CONTAINMENT FAN COOLER HVH-2.

41 41 NUREG/CR-5779
Appendix A

CONTAINMENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

ROBINSON 2 09/26/83 83-25 SERVICE WATER LEAK FROM DEFECTIVE TUBE BUNDLE

IN CONTAINMENT FAN COOLER HVH-.

ROBINSON 2 11/03/83 83-27 COOLING COIL LEAKS FROM DEFECTIVE TUBE BUNDLES

IN CONTAINMENT FAN COOLERS HVH-1 AND HVH-3.

SALEM 1 08/13/81 81-72 SERVICE WATER LEAKAGE FROM COILS IN

CONTAINMENT FAN COIL UNITS #12 AND #14.

SALEM 1 08/26/81 81-74 SERVICE WATER LEAKAGE FROM FAILED BOTTOM

SECONDARY COIL IN CONTAINMENT FAN COIL UNIT #11.

SALEM 1 09/02/81 81-76 SERVICE WATER LEAKAGE FROM A SECONDARY COIL IN

CONTAINMENT FAN COIL UNIT #14.

SALEM 1 09/02/81 81-77 SERVICE WATER PINHOLE LEAK FROM A SECONDARY

COIL IN CONTAINMENT FAN COIL UNIT #11.

SALEM 1 09/03/81 81-78 SERVICE WATER LEAKAGE FROM FAILED TOP

SECONDARY COIL IN CONTAINMENT FAN COIL UNIT #11.

SALEM 1 09/28/81 81-84 SERVICE WATER LEAK FROM BOTTOM PRIMARY COIL IN

CONTAINMENT FAN COIL UNIT #11.

SALEM 1 10/28/81 81-94 SERVICE WATER LEAKAGE FROM FIFTH AND SIXTH

PRIMARY COILS OF CONTAINMENT FAN COIL UNIT #14.

SALEM 1 11/07/81 81-96 SERVICE WATER LEAKAGE FROM COILS OF

CONTAINMENT FAN COIL UNITS #11 AND #15.

SALEM 1 11/17/81 81-105 SERVICE WATER LEAK FROM HOLE IN UPPER PRIMARY

COIL OF CONTAINMENT FAN COIL UNIT #12.

SALEM 1 11/25/81 81-108 SERVICE WATER LEAKAGE FROM A PRIMARY COIL IN

CONTAINMENT FAN COIL UNIT #14.

SALEM 1 11/29/81 81-109 SERVICE WATER LEAKAGE FROM A PRIMARY COIL OF

CONTAINMENT FAN COIL UNIT #12.

NUREG/CR-5779 42
Appendix A

CONTAINMENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

SALEM 1

SALEM 1

SALEM 2

SALEM 2

SALEM 2

CAUSE TYPE: Tube Failure, C4

BIG ROCK POINT

BIG ROCK POINT

CT. YANKEE

12/08/81

12/26/81

09/13/81

09/18/81

11/27/81

orrosion

81-114

81-118

81-90

81-94

81-115

SERVICE WATER LEAKAGE FROM TOP SECONDARY COIL

OF CONTAINMENT FAN COIL UNIT #11.

SERVICE WATER LEAKAGE FROM A PRIMARY COIL OF

CONTAINMENT FAN COIL UNIT #11.

SERVICE WATER LEAK FROM A PRIMARY COIL ON

CONTAINMENT FAN COIL UNIT #22.

SERVICE WATER LEAK FROM A PRIMARY COIL IN

CONTAINMENT FAN COIL UNIT #23.

SERVICE WATER LEAK FROM A PRIMARY COIL ON

CONTAINMENT FAN COIL UNIT #24.

INDIAN POINT 2

ROBINSON 2

09/30/81 81-24 CORROSION-INDUCED LEAKS AT 'U' BENDS OF PIPEWAY

AIR COOLER.

01/28/82 82-3 CORROSION-INDUCED FAILURE OF TUBES IN PIPEWAY

AIR COOLER.

01/05/83 83-1 SERVICE WATER LEAK FROM ONE COIL OF

CONTAINMENT FAN COOLER, DUE TO CORROSION/EROSI

ON.

10/17/80 80-16 CORROSION-INDUCED LEAKAGE FROM

CONTAINMENT FAN COOLER UNITS.

04/10/83 83-3 SERVICE WATER LEAK IN CONTAINMENT FAN COOLER

HVH-3 DUE TO CORROSION/EROSION OF COOLER

TUBING.

05/12/83 83-13 SIX LEAKING TUBES IN REACTOR CONTAINMENT FAN

COOLER, DUE TO PITITING CORROSION.

12/13/83 83-45 PINHOLE LEAK IN ONE TUBE OF REACTOR

CONTAINMENT FAN COOLER, DUE TO PI1TTNG

CORROSION.

05/03/84 84-13 LEAKAGE FROM PITTED TUBES IN REACTOR

CONTAINMENT FAN COOLER COILS. GENERAL

CONDITION DETECTED BY EDDY CURRENT TESTING.

UNDER-DEPOSIT CORROSION IS CAUSE.

ZION 2

ZION 2

ZION 2

43 NUREG/CR-5779
Appendix A

CONTAINMENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

CAUSE TYPE: Tube Failure, Erosion/Wear

KEWAUNEE 12/06/83 83-34 SERVICE WATER LEAKS FROM CONTAINMENT FAN COIL

UNIT DUE TO SAND AND WATER EROSION OF TUBE

RETURN BENDS.

SALEM 2 08/09/82 82-70 SERVICE WATER LEAK FROM SILT-ERODED COIL IN

CONTAINMENT FAN COIL UNIT #24. NEW-DESIGN COILS

INSTALLED AT NEXT REFUELING.

SALEM 2 08/13/82 82-73 SERVICE WATER LEAK FROM SILT-ERODED COIL IN

CONTAINMENT FAN COIL UNIT #23. NEW-DESIGN COILS

WILL BE INSTALLED DURING NEXT REFUELING.

SALEM 2 08/13/82 82-74 SERVICE WATER LEAK FROM SILT-ERODED COIL IN

CONTAINMENT FAN COIL UNIT #25.

SALEM 2 08/14/82 82-75 SERVICE WATER LEAK FROM CONTAINMENT FAN COIL

UNIT #22. NEW-DESIGN COILS WILL BE INSTALLED

DURING NEXT REFUELING.

SALEM 2 08/18/82 82-77 LEAKAGE FROM A SECONDARY COIL OF

CONTAINMENT FAN COIL UNIT #21. CAUSE WAS

EROSION OF THE COPPER-NICKEL PIPING.

SALEM 2 08/21/82 82-80 SERVICE WATER LEAK FROM ERODED COILS IN

CONTAINMENT FAN COIL UNIT #24.

SALEM 2 08/29/82 82-84 SERVICE WATER LEAK FROM ERODED COILS IN

CONTAINMENT FAN COIL UNIT #23.

SALEM 2 08/30/82 82-89 SERVICE WATER LEAK FROM COIL IN

CONTAINMENT FAN COIL UNIT #23.

SALEM 2 09/06/82 82-91 SERVICE WATER LEAK FROM SILT-ERODED COIL IN

CONTAINMENT FAN COIL UNIT #23.

SALEM 2 09/10/82 82-93 SERVICE WATER LEAK FROM ERODED COIL IN

CONTAINMENT FAN COIL UNIT #21.

SALEM 2 09/15/82 82-100 SERVICE WATER LEAK FROM SILT-ERODED COIL IN

CONTAINMENT FAN COIL UNIT # 22.

SALEM 2 09/16/82 82-101 SERVICE WATER LEAK FROM SILT-ERODED COIL IN

CONTAINMENT FAN COIL UNIT #21.

NUREG/CR-5779 44
Appendix A

CONTAINMENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

SALEM 2

SALEM 2

SALEM 2

SALEM 2

09/23/82 82-109 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #21.

10105/82 82-113 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #22.

10/08/82 82-119 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #21.

10/11/82 82-120 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #21.

10/18/82 82-122 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #24.

10/31/82 82-128 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #23.

11/21/82 82-135 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #25.

11/24/82 82-136 SERVICE WATER LEAK FROM SILT-ERODED

CONTAINMENT FAN COIL UNIT #23.

COILS IN

COILS IN

COILS IN

COILS IN

COILS IN

COILS IN

COILS IN

COILS IN

SALEM 2

SALEM 2

SALEM 2

SALEM 2

CAUSE TYPE: Other

BROWNS FERRY 3

FT. CALHOUN 1

INDIAN POINT 2

07/01/81 81-32 LEAK FROM CRACK IN VENT NIPPLE OF RHR PUMP

ROOM COOLER.

09/24/81 81-9 LEAK OF COMPONENT COOLING WATER TO

CONTAINMENT RESULTED FROM BLOW OUT OF LOOSE

COIL END PLUG IN CONTAINMENT COOLING FAN COIL

UNIT.

10/04/85 85-13 SERVICE WATER LEAK FROM FAN COOLER UNIT, FROM

A TUBE THAT HAD BEEN CUT OUT IN EARLIER CHECK

IN 1983.

PROBLEM TYPE: Inter-fluid Leakage

CAUSE TYPE: Tube Failure. Corrosion

BIG ROCK POINT 05/25/82 82-18 CORROSION-RELATED FAILURE OF 20 TUBES IN

REACTOR BUILDING HEATING/COOLING SYSTEM HX.

45 NUREG/CR-5779
Appendix A

CONTAINMENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE: Impaired Heat Transfer

CAUSE TYPE: Unspecified

MCGUIRE 1 11/11/83 83-109 FOULING OF LOWER CONTAINMENT VENTILATION

SYSTEM AIR HANDLING UNIT COOLING COILS RESULTED

IN EXCESSIVE LOWER CONTAINMENT TEMPERATURES.

OCONEE 1 03/31/87 87-4 FOULING OF REACTOR BUILDING COOLING UNITS AND

THE DECAY HEAT (LPI) COOLERS REDUCED

POST-ACCIDENT COOLING CAPACITY TO UNACCEPTABLE

LEVELS.

OCONEE 3 08/19188 88-3 SERVICE-INDUCED FOULING OF REACTOR BUILDING

COOLING UNITS MAY HAVE REDUCED PERFORMANCE

CAPABILITY OF THE COOLERS TO UNACCEPTABLE

LIMITS.

SURRY 1 07/21185 85-13 FOULING OF SERVICE WATER SIDE OF

CONTAINMENT CHILLER RESULTED IN TRIP OF CHILLER

ON HIGH CONDENSER PRESSURE.

NUREG/CR-5779 46
Appendix A

COMPONENT COOLING WATER HEAT EXCHANGER PROBLEMS

FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE: Tube-side Blockage

CAUSE TYPE: Unspecified

MCGUIRE 1 11/25/87 87-31 EXCESSIVE DIFFERENTIAL PRESSURE ACROSS CCW HX,

DUE TO TUBE-SIDE FOULING.

MCGUIRE 1 09/12/88 88-24 DIFFERENTIAL PRESSURE ACROSS CCW HXS IN ACTION

RANGE, DUE TO TUBE-SIDE FOULING.

MCGUIRE 2 09/06/87 87-17 INADEQUATE FLOW THROUGH CCW HX, DUE TO

FOULING.

TURKEY POINT 3 12/11/86 87-20 UNEXPECTED INADEQUATE RESULTS FROM TUBE

CLEANING REDUCED ABILITY OF CCW HX TO MEET

DESIGN BASIS FLOW REQUIREMENTS.

CAUSE TYPE: Biological Growth

SAN ONOFRE 1

SAN ONOFRE 3

06/09/81 81-9 TUBES PARTIALLY BLOCKED BY GOOSENECK

BARNACLES IN CCW HX

08/04/86 86-11 RESTRICTED SALTWATER FLOW THROUGH CCW HX DUE

TO MARINE GROWTH.

CAUSE TYPE: Biological Debris

CALVERT CLIFFS 2

SAN ONOFRE 2

10/15185 85-9 PARTIAL BLOCKAGE OF SALTWATER FLOW THROUGH

SERVICE WATER HX, DUE TO SHELLS DISLODGED IN

SEAWATER SYSTEM.

07/06/83 83-72 FOULING OF SEAWATER SIDE OF CCW HX BY MARINE

DEBRIS INTRODUCED DURING TRAVELING SCREEN

INCIDENT. (SIMILAR EVENT OCCURRED IN UNIT 3).

CAUSE TYPE: Other Debris

MCGUIRE 2 09/17/88 88-11 EXCESSIVE DIFFERENTIAL PRESSURE ACROSS CCW HX,

DUE TO BUILDUP OF 'ENVIRONMENTAL DEBRIS'.

47 NUREG/CR-5779
Appendix A

COMPONENT COOLING WATER HEAT EXCHANGER PROBLEMS (cont'd)

FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME D

PROBLEM TYPE: External Leakage

ATE LER PROBLEM

CAUSE TYPE: Shell Corrosion/Erosion

TURKEY POINT 4 06/17180 80-10 LEAKAGE FROM CORROSION-INDUCED CRACK IN

CHANNEL COVER OF CCW HX.

CAUSE TYPE. Weld Failure

NINE MILE POINT 1

SAN ONOFRE 1

11/21/86 86-33 REACTOR BUILDING CLOSED LOOP COOLING HX FAILED

HYDRO TEST DUE TO CRACK IN WELD.

08/13/82 82-24 PRESSURE-TRANSIENT FAILURE OF PREVIOUSLY

LEAKING WELD IN CCW HX.

PROBLEM TYPE: Impending External Leakage

CAUSE TYPE: Shell Corrosion/Erosion

CALVERT CLIFFS 1 05/03/84 84-5 WALL THINNING AND SOME THROUGH-WALL HOLES

WERE FOUND IN CAST IRON CHANNEL HEADS OF

COMPONENT COOLING HXS AND SERVICE WATER HXS

DUE TO CORROSION.

CAUSE TYPE. Weld Failure

SAN ONOFRE 1 05/23/80 80-23 FLAW EXTENDING BELOW MINIMUM WALL THICKNESS

DETECTED IN WELD IN CCW HX.

PROBLEM TYPE: Inter-fluid Leakage

CAUSE TYPE: Unspecified

TURKEY POINT 4 06/08/87

CAUSE TYPE: Tube Failure, Corrosion

CALVERT CLIFFS 1 09/17/80

CALVERT CLIFFS 2 03/16/80

87-11 LEAK IN CCW HX TUBE.

80-52

80-17

TUBE LEAK IN SALTWATER/SERVICE WATER HI

TUBE LEAK IN SALTWATER/SERVICE WATER HXI

NUREG/CR-5779 48
Appendix A

COMPONENT COOLING WATER HEAT EXCHANGER PROBLEMS (cont'd)

FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

CAUSE TYPE: Tube Failure, Fatigue/Mechanical Stress

OYSTER CREEK

SAN ONOFRE 2

08/19181 81-39 TUBE VIBRATION DURING FLOW TRANSIENT CAUSED

TUBE FAILURES IN CCW HX.

1001/82 82-125 TUBE LEAK IN CCW HX DUE TO IMPINGEMENT OF

SEASHELLS.

PROBLEM TYPE: Impaired Heat Transfer

CAUSE TYPE: Fluid Circuitry Damage

PILGRIM 1 0828/81 81-49 DESIGN DEFICIENCY IN PASS PARTITION PLATES

CAN LEAD TO PLATE DEFORMATION AND EXCESSIVE

BYPASS.

49 NUREG/CR-5779
Appendix A

COMPONENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE: Tube-side Blockage

CAUSE TYPE: Silt Buildup

FARLEY 1 08A)1/86 86-14 GEAR OIL COOLER ON CHARGING PUMP PARTIALLY

BLOCKED BY MUD, SLUDGE, AND/OR CLAMS.

GRAND GULF 1 11/22/83 83-186 RESTRICTED COOLING WATER FLOW THROUGH

STANDBY SERVICE WATER PUMP COOLER, DUE TO

SEDIMENT BUILDUP.

TROJAN 01/27/84 84-2 SERVICE WATER FLOW BLOCKAGE IN SAFETY INJECTION

PUMP LUBE OIL COOLER DUE TO ACCUMULATION OF

SEDIMENT.

CAUSE TYPE: Biological Growth

BROWNS FERRY 3 07/30/83 83-47 FLOW RESTRICTION IN SEAL COOLER FOR RHR PUMP,

DUE TO CLAMS AND SILT.

CAUSE TYPE: Biological Debris

ARKANSAS NUCLEAR 2 01/20/82 82-3 SERVICE WATER FLOW RESTRICTION TO LPSI PUMP

SEAL COOLER, DUE TO ASIATIC CLAM SHELLS.

SALEM 2 04/09/83 83-13 SERVICE WATER FLOW TO CHARGING PUMP LUBE OIL

COOLERS WAS RESTRICTED BY OYSTER AND MOLLUSK

SHELLS, WHICH HAD BEEN RELEASED DURING SWS

MAINTENANCE.

TROJAN 09/16/88 88-29 CLAM DEBRIS WAS FOUND IN SAFETY

PUMP LUBE OIL COOLER.

INJECTION

CAUSE TYPE: Shell Corrosion/Erosion

RANCHO SECO 03/12/81 81-16 LUBE OIL COOLER FOR HPI PUMP PARTIALLY PLUGGED

BY CORROSION PRODUCTS FROM COOLER HEADS.

PROBLEM TYPE: External Leakage

CAUSE TYPE: Unspecified

INDIAN POINT 3 07/16/80 80-11 WATER LEAK FROM MOTOR COOLER ON

CONTAINMENT FAN COIL UNIT.

NUREG/CR-5779 50
Appendix A

COMPONENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

INDIAN POINT 3 12108/81 81-10 WATER LEAK FROM TUBE OF MOTOR COOLER IN FAN

COIL UNIT.

SALEM 2 11/19/81 81-114 SERVICE WATER PINHOLE LEAK IN MOTOR COOLER OF

CONTAINMENT FAN COIL UNIT #22. COOLER WAS

REPLACED.

CAUSE TYPE: Tube Failure, Erosion/Wear

OCONEE 1 02/16/80 80-4 MOTOR COOLER TUBE LEAKS ON HPSW PUMP B, DUE TO

EROSION FROM CONSTANT FLOW OF LAKE WATER.

OCONEE 1 06/01/80 80-18 TUBE LEAKS IN MOTOR COOLER FOR HPSW PUMP B DUE

TO EROSION/CORROSO19TROM CONSTANT FLOW OF

LAKE WATER.

OCONEE 1 07/07/80 80-22 LEAKAGE FROM MOTOR COOLER OF HPSW PUMP B DUE

TO EROSION/CORROSION FROM CONSTANT FLOW OF

LAKE WATER THROUGH TUBES.

OCONEE 1 08/11/80 80-26 MOTOR COOLER TUBE LEAKS IN HPSW PUMP B DUE TO

EROSION FROM CONSTANT FLOW OF LAKE WATER.

COOLER AND HOUSING REPLACED. SOLENOID VALVES

ADDED TO ALLOW FLOW ONLY WHEN PUMP IS

OPERATED.

SALEM 2 08/19/82 82-78 LEAKAGE FROM SILT-ERODED MOTOR COOLER ON

CONTAINMENT FAN COIL UNIT #25. COOLER WAS

REPLACED WITH ONE OF MORE EROSION-RESISTANT

MATERIAL.

SALEM 2 09/08/82 82-92 SERVICE WATER LEAK FROM SILT-ERODED MOTOR

COOLER FOR CONTAINMENT FAN COIL UNIT #21.

COOLER WAS REPLACED.

CAUSE TYPE: Shell Corrosion/Erosion

BRUNSWICK 2 07/31/83 83-72 DRAIN PLUG IN PUMP SHAFT SEAL COOLER FOR RHR

PUMP CAME OUT. CAUSE WAS PLUG CORROSION,

COUPLED WITH VIBRATION.

GINNA 03/OZ290 81-4 SERVICE WATER LEAK FROM CONTAINMENT FAN

COOLER MOTOR COOLER, DUE TO CORROSION OF

STEEL PLUG IN COPPER COOLER.

51 NUREGICR-5779
Appendix A

COMPONENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

CAUSE TYPE. Weld Failure

SALEM 2 08/06/81 81-64 SERVICE WATER LEAK FROM FAILED WELD ON

CONTAINMENT FAN COOLER MOTOR COOLER.

SALEM 2 05/26/82 82-39 LARGE SERVICE WATER LEAK FROM FAILED SEAM

WELD IN MOTOR COOLER OF CONTAINMENT FAN COIL

UNIT #21. COOLER REPLACED.

CAUSE TYPE: Gasket Failure

SALEM 1 03/20/85 85-6 WATER LEAK FROM FAILED MOTOR COOLER HEAD

GASKET ON CONTAINMENT FAN COIL UNIT #13.

CAUSE TYPE: Other

GINNA 04/26/81 81-11 LEAK FROM FILTING ON RHR PUMP SEAL COOLER,

DUE TO WORN THREADS.

PROBLEM TYPE: Inter-fluid Leakage

CAUSE TYPE. Unspecified

SALEM 1 06/26/80 80-38 LEAK FROM FAILED TUBE IN LUBE OIL COOLER FOR

CHARGING PUMP #12. COOLER WAS REPLACED.

SALEM 1 07/08/80 80-41 LEAKAGE FROM FAILED TUBE IN LUBE OIL COOLER

FOR SAFETY INJECTION PUMP #11.

SALEM 1 02/01/81 81-13 LEAK IN OIL COOLER FOR CHARGING PUMP #12.

COOLER REPLACED.

SURRY 1 07/06/82 82-69 WATER ENTERED LUBE OIL OF CHARGING PUMP 'A' VIA

LEAK IN ONE TUBE OF OIL COOLER. COOLER

REPLACED.

SURRY 1 09/05/82 82-91 WATER ENTERED LUBE OIL OF CHARGING PUMP 'A' VIA

LEAK IN ONE TUBE OF LUBE OIL COOLER. COOLER

REPLACED.

SURRY 2 08/04/81 81-50 WATER ADMIITED TO OIL IN CHARGING PUMP VIA

TUBE LEAK IN OIL COOLER.

NUREG/CR-5779 52
Appendix A

COMPONENT HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

CAUSE TYPE: Tube Failure, Corrosion

SALEM 1

SALEM 1

06t26/82 82.41 SERVICE WATER LEAKED INTO GEAR OIL RESERVOIR

OF CHARGING PUMP, VIA LEAKING GEAR OIL COOLER.

CAUSE WAS EROSION AND CORROSION.

08/15/83 83-48 LEAKAGE FROM FAILED TUBES IN SPEED INCREASER

LUBE OIL COOLER FOR CHARGING PUMP. FAILURE DUE

TO EROSION AND CORROSION.

09/15/82 82-86 WATER ENTERED LUBE OIL OF MOTOR ON SERVICE

WATER PUMP VIA MOTOR BEARING OIL COOLER.

CAUSE WAS ACCELERATED EROSION/CORROSION.

10/19/82 82-126 WATER ENTERED LUBE OIL IN CHARGING PUMP DUE TO

LEAK IN OIL COOLER. CAUSE WAS DISSIMILAR-METALS

CORROSION AND SILT-INDUCED EROSION.

SALEM 2

SALEM 2

CAUSE TYPE: Other

CALVERT CLIFFS 1 08/12180 80-41 FAILURE OF INSTRUMENT AIR COMPRESSOR

AFTERCOOLER INJECTED AIR INTO SERVICE WATER

SYSTEM. FAILURE DUE TO OVERROLLING ON

INSTALLATION.

53 NUREG/CR-5779
Appendix A

EDG HEAT EXCHANGER PROBLEMS FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE. Tube-side Blockage

CAUSE TYPE: Unspecified

YANKEE ROWE 07/06/81 81-16 INADEQUATE DIESEL GENERATOR COOLING DUE TO

RADIATOR PARTIALLY BLOCKED BY CORROSION

PRODUCTS AND SCALE.

CAUSE TYPE: Biological Debris

BROWNS FERRY 3 01/03/84 84-1 FLOW BLOCKAGE OF EECW FLOW TO DIESEL ENGINE

COOLERS, DUE TO CLAM SHELLS MOVING INTO

COOLERS AFTER HEAVY CHLORINATION OF INTAKE

PROBLEM TYPE: External Leakage

CAUSE TYPE: Unspecified

FT. CALHOUN 1

OYSTER CREEK

01/22/80 80-3 DIESEL GENERATOR RADIATOR TUBE LEAK

01/25/82 82-5 DIESEL GENERATOR RADIATOR TUBE LEAK

CAUSE TYPE: Shell Corrosion/Erosion

MILLSTONE 2 01/27/81 81-7 SERVICE WATER LEAK FROM DIESEL GENERATOR OIL

COOLER. SACRIFICIAL ANODE HAD CORRODED.

SALEM 2 09/28/82 82-115 SERVICE WATER LEAK FROM ERODED PIPE CAP IN

DIESEL GENERATOR OIL COOLER.

CAUSE TYPE: Other

BROWNS FERRY 3

TURKEY POINT 3

04/11/83 83-26 CRACKED HEAD ON EDG COOLER, DUE TO

MANUFACTURING DEFECT.

02/25/80 80 4 A FOREIGN OBJECT, DRIVEN BY THE FAN, CAUSED

DAMAGE TO DIESEL ENGINE RADIATOR. SUBSEQUENT

DEGRADATION DUE TO EXTERNAL ENVIRONMENT

RESULTED IN LEAK

NUREGICR-5779 54
Appendix A

EDG HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE: Impending External Leakage

CAUSE TYPE. Shell Corrosion/Erosion

RIVERBEND 1 03/21/89 89-11 CORROSION REDUCED WALL THICKNESS OF DIESEL

GENERATOR WATER COOLER TO BELOW ASME CODE

REQUIREMENTS.

PROBLEM TYPE: Inter-fluid Lea;

CAUSE TYPE: Unspecified

DRESDEN 2

INDIAN POINT 2

INDIAN POINT 2

INDIAN POINT 2

NINE MILE POINT 1

SEQUOYAH 1

SEQUOYAH 1

ZION 1

rage

07/25/80 80-27 LEAKS DEVELOPED IN TUBES OF EDG COOLING

WATER/SERVICE WATER HX.

07/05/81 81-16 LEAK IN DIESEL GENERATOR LUBE OIL COOLER

RESULTED IN WATER IN OIL.

09/16/81 81-22 LEAK IN DIESEL GENERATOR OIL COOLER RESULTED

IN WATER IN OIL. (NOT SAME ENGINE AS REPORTED

IN LER 81-16.)

09/09/88 88-11 WATER FROM THE LUBE OIL COOLER LEAKED INTO THE

DIESEL ENGINE LUBE OIL.

08/18/81 81-40 LEAK IN EDG RAW WATER/CHROMATED WATER HEAT

EXCHANGER.

05/12/83 83-70 COOLING WATER LEAK TO CRANKCASE OF D/G 1A-A.

ENGINE OIL COOLER WAS REPLACED.

10/10/83 83-137 WATER IN OIL OF DIESEL GENERATOR 2B-B DUE TO

LEAKAGE IN LUBE OIL COOLER. COOLER WAS

REPLACED.

06/13/83 83-19 TUBE LEAK IN EDG ENGINE COOLER WAS BEING

MONITORED BUT FLOODED AIR MANIFOLD AFTER

DRAIN VALVE WAS CLOSED BY CLEANING PERSONNEL

CAUSE TYPE: Tube Failure. Corrosion

KEWAUNEE 01126/83 83-2 CORROSION-INDUCED LEAKS IN DIESEL

GENERATOR COOLING SYSTEM HX.

55 NUREG/CR-5779
Appendix A

EDG HEAT EXCHANGER PROBLEMS FROM LER SEARCH (cont'd)

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

CAUSE TYPE: Tube Failure. Erosion/Wear

DRESDEN 2 01/26/80 80-8 DIESEL GENERATOR COOLING WATER HX

DEVELOPED LEAKS DUE TO NORMAL ENVIRONMENTAL

WEAR.

ZION 2 04/19/81 81-5 ERODED TUBES IN EDG OIL COOLER CAUSED LEAKAGE

OF WATER TO LUBE OIL

PROBLEM TYPE: Impaired Heat Transfer

CAUSE TYPE: Unspecified

BEAVER VALLEY 1 09/19/82 82-36 FOULING OF DIESEL GENERATOR COOLING WATER HX

CAUSED EXCESSIVE TEMPERATURES OF COOLING

WATER.

QUAD CITIES 2 10106/82 82-18 FOULING OF DIESEL GENERATOR COOLING WATER

SYSTEM HX RESULTED IN HIGH TEMPERATURE

TRIP OF DIESEL GENERATOR.

NUREG/CR-5779 56
Appendix A

MISCELLANEOUS HEAT EXCHANGER PROBLEMS FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME

PROBLEM TYPE: External Leaka

CAUSE TYPE: Gasket Failure

BROWNS FERRY 2

BROWNS FERRY 2

D

Le

ATE LER PROBLEM

BROWNS FERRY 2

BROWNS FERRY 3

COOPER

FITZPATRICK

FITZPATRICK

PEACH BOTTOM 2

PEACH BOTTOM 2

PILGRIM 1

PILGRIM 1

CAUSE TYPE: Other

PALISADES

05/07/81 81-21 LEAKING UPPER HEAD GASKET IN HPCI GLAND SEAL

CONDENSER AFTER OVERPRESSURIZATION (150 PSI VS 60

PSI).

07120/81 81-39 LEAKING UPPER HEAD GASKET IN HPCI GLAND SEAL

CONDENSER AFTER TUBE-SIDE OVERPRESSURIZATION

(150 VS 60 PSI).

09/16/81 81-45 LEAKING UPPER HEAD GASKET IN HPCI GLAND SEAL

CONDENSER AFTER TUBE-SIDE OVERPRESSURIZATION.

04/23/81 81-19 UPPER AND LOWER HPCI GLAND SEAL

CONDENSER HEAD GASKETS WERE BLOWN DUE TO

OVERPRESSURE DURING AUTOMATIC REACTOR

SHUTDOWN.

02127/86 86-5 FAILED HEAD GASKET IN HPCI GLAND STEAM

CONDENSER.

03/22/84 84-9 GASKET FAILED ON HPCI GLAND SEAL

CONDENSER.

03/25/84 84-10 GASKET FAILURE IN HPCI GLAND SEAL

CONDENSER.

09/23/81 81-41 LEAKAGE FROM FAILED GASKET ON HEAD OF HPCI

GLAND SEAL CONDENSER.

10/21/81 81-42 LEAKAGE FROM FAILED GASKET ON HEAD OF HPCI

GLAND SEAL CONDENSER.

08/13/82 82-24 HPCI GLAND SEAL CONDENSER GASKET FAILURE

CAUSED WETTING OF HPCI CONTROL CIRCUITRY.

08/30/82 82-35 HPCI GLAND SEAL CONDENSER GASKET FAILED DUE TO

OVERPRESSURE DURING STARTUP.

11/25/80 80-44 LEAK AT RETURN HEAD FLANGE OF LETDOWN HX DUE

TO IMPROPER TORQUING SEQUENCE AND CORRODED

FLANGE STUDS.

57 NUREG/CR-5779
Appendix A

MISCELLANEOUS HEAT EXCHANGER PROBLEMS FROM LER SEARCH

(BY PROBLEM TYPE AND CAUSE)

PLANT NAME DATE LER PROBLEM

PROBLEM TYPE: Inter-fluid Leakage

CAUSE TYPE: Unspecified

CRYSTAL RIVER 3

RANCHO SECO

RANCHO SECO

01/27/82 82-8 REACTOR COOLANT LEAK TO SERVICE WATER VIA

TUBE-TO-SHELL LEAK IN LETDOWN COOLER 'A'.

01/12/81 81-2 ACTIVITY IN CCW SYSTEM FROM LEAK IN LETDOWN

COOLER.

09/20/83 83-35 ACTIVITY IN CCW SYSTEM FROM APPARENT LEAK IN

LETDOWN COOLER.

CAUSE TYPE: Tube Failure, Erosion/Wear

ROBINSON 2 01/16/81 814 LEAK FROM PRIMARY SYSTEM TO CCW SYSTEM

THROUGH FAILED SAMPLE COOLER TUBE BUNDLE.

FAILURE DUE TO NORMAL OPERATIONAL WEAR.

CAUSE TYPE: Tube Failure, Fatigue/Stress

CRYSTAL RIVER 3 11/25/82 82-72 LEAK OF REACTOR COOLANT TO NSCCCS VIA LETDOWN

COOLER 'B'. LEAK APPARENTLY CAUSED BY THERMAL

SHOCK DUE TO LONG ISOLATION AND RAPID

RESTORATION TO SERVICE.

CAUSE TYPE: Tube-to-tubesheet Joint Failure

OCONEE 2 11/03/80 80-19 LEAKAGE FROM FAILED TUBE-TO- TUBESHEET WELDS

IN LETDOWN COOLER 2A.

NUREGICR-5779 58
NUREG/CR-5779

Volume 1

ORNL-6687/V1

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1-2. D. A. Casada 18. G. A. Murphy

3. D. F. Cox 19. C. E. Pugh

4. E. C. Fox 20. ORNL Patent Section

5. R. H. Greene 21. Central Research Library

6. H. D. Haynes 22. Document Reference Section

7. J. E. Jones Jr. 23-24. Laboratory Records Dept.

8-17. J. C. Moyers 25. Laboratory Records (RC)

External Distribution

26. R. P. Allen, Battelle-PNL, MS P8-10, P.O. Box 999, Richland, WA 99352

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2000, Soddy Daisy, TN 37379

28. W. S. Farmer, U. S. Nuclear Regulatory Commission, Office of Nuclear Regulatory

Research, Electrical and Mechanical Engineering Branch, 5660 Nicholson Lane,

Rockville, MD 20852

29. M. J. Jacobus, Sandia National Laboratory, P.O. Box 5800, Division 6447,

Albuquerque, NM 87815

30. H. L. Magleby, Idaho National Engineering Laboratory, MS 2406, P.O. Box 1625,

Idaho Fall, ID 83415

31. G. E. Sliter, Electric Power Research Institute, P.O. Box 10412, Palo Alto, CA 94303

32. M. Subudhi, Brookhaven National Laboratory, Bldg 130, Upton, NY 11973

33. J. W. Tills, Institute for Nuclear Power Operations, 1100 Circle 75 Parkway, Atlanta,

GA 30339-3064

34. M. Vagins, U. S. Nuclear Regulatory Commission, Office of Nuclear Regulatory

Research, Chief, Electrical and Mechanical Engineering Branch, Division of

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35. J. P. Vora, U. S. Nuclear Regulatory Commission, Office of Nuclear Regulatory

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Rockville, MD 20852

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NRCM 1102. And Addendum Numbers, if any.I

3201,1202. BIBLIOGRAPHIC DATA SHEET NUREG/CR-5779

{See inlstructions on the reverse) ORNL-6687 2. TITLE AND SUBTITLE Vol. 1

Aging of Non-Power-Cycle Heat Exchangers .

Used in Nuclear Power Plants 3. DATE REPORT PUBLISHED

MONTH | YEAR

Operating Experience and Failure Identification July I 1992

4. FIN OR GRANT NUMBER

B0828 5. AUTHOR 1S) 6. TYPE OF REPORT

J. C. Moyers Technical

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name and mailing address.)

Oak Ridge National Laboratory

Oak Ridge, TN 37831-6285

9. SPONSOR ING ORGANIZATION -NAME AND ADD RESS (If NRC, type "Same as above", if contractor. provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission,

and mailing address.)

Division of Engineering

Office of Nuclear Regulatory Research

U. S. Nuclear Regulatory Commission

Washington, DC 20555

10. SUPPLEMENTARY NOTES

11. ABSTRACT (200 words or less)

This report presents the results of an assessment of the time-related degradation

of non-power-cycle heat exchangers used in nuclear power plants. The assessment

was sponsored by the U.S. Nuclear Regulatory Commission's Nuclear Plant Aging

Research Program.

Heat exchanger design characteristics and applications in the plants are described

and stressors leading to degradation are identified. Operating experience, as

identified from nuclear industry data bases, is reviewed and failure types and

causes are summarized. Regulatory requirements for inspection and testing, with

a brief discussion of industry practices in this area, are presented.

12. KEY WO R DS/DESCR !PTORS {List words or phrases that vvill assist researchers in locating the report.) 13. AVAI LABI LITY STAT EMENT

heat exchangers nuclear power plants 14nECliRITYeCLASSIFCATION

aging NPAR J This Page)

failures operating experience Unclassified

reliability I'This Report)

maintenance Unclassified

coolers 15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (2-891
THIS DOCUMENT WAS PRINTED USING RECYCLED PAPER
NUREG/CR-5779, Vol. 1 AGING OF NON-POWER-CYCLE HEAT EXCHANGERS USED IN NUCLEAR POWER PLANTS JULY 1992

UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, D.C. 20555-0001

FIRST CLASS MAIL

POSTAGE AND FEES PAID

USNRC

PERMIT NO. G-67

OFFICIAL BUSINESS

PENALTY FOR PRIVATE USE, S300