ML20205D348

ESF Actuations at Commercial Us Nuclear Power Reactors, Jan-June 1984

ML20205D348
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Issue date:	08/31/1985
From:	Wolf T NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
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ML20204G617	List: IA-85-668, Partially Withheld Notice of Board Meeting 85-10 ML20204G611 ML20204G619 ML20204G631 ML20204G654 ML20204J205 ML20205D348 ML20205P875 ML20205P887 ML20205P901 ML20205P971 ML20205P984
References
FOIA-85-668, TASK-AE, TASK-P503 AEOD-P503, NUDOCS 8509260458
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AE00/P503 Engineered Safety Feature Actuations At Commercial United States Nuclear Power Reactors January 1 Through June 30, 1984 August 1985 Program Technology Branch Office for Analysis and Evaluation of Operational Data j

Principal Author:

r Thomas R. Wolf I

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Contributing Assistants:

Marcel R. Harper t

Kathy Higgins

.%k G *hp-b NOTE:

This report'do'cuments the results of a study by the Office for Analysis and Evaluation of Operational Data.

The findings and recommendations do not necessarily represent the position or requirements of either the responsible program office or the Nuclear Regulatory Commission.

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2 CONTENTS Page iv LIST OF FIGURES........................................................

v LIST OF TABLES.........................................................

I EXECUTIVE

SUMMARY

4

1.0 INTRODUCTION

2.0 GENERAL OBSERVATIONS..............................................

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3.0 ACTUATION TYPES...................................................

l 3.1 Valid Actuations.............................................

8 l

l 3.1.1 General Characteristics...............................

8 3.1.2 Specific Actuation Characteristics....................

8 3.2 False Actuations.............................................

14 3.2.1 General Characteristics...............................

14 3.2.2 Specific Actuation Characteristics....................

18 3.3 Conclusions and Recommendations.............................. 20 3.3.1 Conclusions...........................................

20 3.3.2 Recommendations....................................... ~21 4.0 EMERGENCY CORE COOLING SYSTEMS - SAFETY INJECTIONS................ 21 4.1 Discussion...................................................

21 4.2 Conclusions and Recommendations.............................. 22 4.2.1 Conclusions........................................... 22 4.2.2 Recommendations....................................... 22 l

5.0 FAILURES AND PROBLEMS............................................. 23 5.1 ESF Failures to Actuate Properly............................. 23 5.1.1 Brunswick 1 - Loss of High Pressure Coolant Injection (LER 84-007)........................................ 23 5.1.2 Duane Arnold - Loss of Standby Filter Units (LER 84-004)........................................

23 5.1.3 LaSalle 2 - Loss of Containment isolation Valve (LER 84-009)........................................

24 5.1.4 Sequoyah 2 - Loss of Turbine-Supplied Auxiliary Feedwater (LER 84-009).............................. 25 5.1.5 Yankee Rowe - Loss of Containment Isolation Valve (LER 84-003)........................................ 26 ii

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5.2 Associated Failures..........................................

26 5.3 Conclusions and Recomendations.............................. ~ 27 5.3.1 Conclusions.....................................:..... 27 5.3.2 Re come n da t i o n s....................................... 28 6.0

SUMMARY

OF FINDINGS, CONCLUSIONS AND RECOMMENDATIONS.............. 28 31 APPENDIX...............................................................

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's LIST OF FIGURES Page 1.

Unit Distribution of Engineered Safety Features Actuations 6

(January - June 1984)...........................................

2.

Average Monthly ESF Actuation Rate Distribution 7

(January - June 1984)...........................................

3.

Unit Distribution of Valid ESF Actuations.........................

9 4.

Measured Parameters and Associated System Functions for 10 Valid ESF Actuations............................................

5.

ESFToxicGasMonitorActuations(ValidNon-DesignBasis) 12 at San Onofre 2.................................................

6.

ESFRadiationMonitorActuations(ValidNon-DesignBasis).........

13 ESF RWCU Isolation Actuations (Valid Non-Design Basis)............

15 7.

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Unit Distribution of False ESF Actuations.........................

16 9.

False ESF Actuations Characteristics..............................

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10. ESF Radiation Monitor Actuations (False)..........................

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I LIST OF TABLES Page A.1 Number of ESF Actuations Reported By Coninercial U.S. Nuclear ~

Power Plants January 1,1984 through June 30, 1984.............. 32 A.2 ESF Actuations Reported By Commercial U.S. Nuclear Power Plants January 1, 1984 through June 30, 1984........................... 33 A.3 Valid (Design Basis) ESF Actuations............................... 40 A.4 Valid (Non-Design Basis) ESF Actuations........................... 41 A.5 ESF Actuations - Heating and Ventilation Systems.................. 45 A.6 False ESF Actuations.............................................. 46 A.7 ESF Actuations - Safety Injection Events..........................

55 A.8 ESF Actuations - As sociated Fail ures..............................

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I EXECUTIVE

SUMMARY

In order to gain an understanding of the challenges to safety systems, the Comission required that, effective January 1,1984, actuation of any Engi-neered Safety Feature (ESF) (be reported to the Nuclear Regulatory Comis as a Licensee Event Report LER).

Prior to this date, such actyations were not directly reportable.

As a consequence of this revised reporting require-ment, and as part of the AE00 trends and patterns analysis program, a study i

was initiated of ESF actuations which occurred between January 1 and June 30 1984.

The investigation was limited to those ESF actuations which occurred in systems other than the reactor protection system (RPS), which are the subject i

The objectives of this study were to: (1) gain an of a companion AEOD study.

understanding of the frequency and causes of such ESF actuations on both an individual unit and an industry-wide basis; (2) determine the significance and implications of the current rate of actuations; (3) determine if specific action by the NRC or the industry appears warranted; and (4) investigate the usefulness of ESF actuation data as a valid indicator of licensee performance.

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It was found that 501 ESF actuations occurred during the first six months of 1984, with 293 of the 1195 LERs (25%) submitted describing at least one such l

ESF actuation.

Of the 87 units eligible to issue LERs, 61 units reported at least one ESF actuation.

On a percentage basis, 30 percent of the eligible units did not report an ESF actuation during the first half of 1984, 42 percent reported between 1 and 3 actuations, 9 percent reported between 4 and 6 actuations, and 18 percent reported more than 6 actuations.

Twelve units j

(14%) reported more than ten ESF actuations.

The maximum number experienced at any one unit was 82.. Only 10 percent of all reported ESF actuatio'ns 3

involved an Emergency Core Cooling System (ECCS) and none of these occurrences About 70 were necessary to control an actual loss-of-coolant accident (LOCA).

percent of the actuations that occurred in ESF systems were associated with either an isolation function or a ventilation function.

The 501 ESF actuations were found to be the result of several causes.

In 143 4

(28%), a measured parameter reached the intended setpoint for ESF cases actuation; however, only 12 of these occurrences (2% of all ESF actuations) were considered to be valid responses in terms of providing a required ESF response for protection from an actual design basis event.

Of these 12 design-basis actuations, three resulted from loss-of-power conditions, three were from high toxic gas concentrations, and six were from high radiation levels.

The remaining 131 of the 143 actuations were considered to be valid actuations (i.e.,

the measured parameter reached the intended actuation setpoint) but did not represent a needed response to a design basis event.

Primarily, these actuations occurred because the sensor setpoints were adjusted to be very close to the background levels normally experienced during i

various unit operational ' modes.

Notable in this regard were 54 cases where the control room emergency air cleanup system (CREACUS) actuated at San Onofre 2 due to various toxic gas levels.

Over half of the remaining actuations in this category were experienced at just three units and they were due to radiation monitors exceeding their setpoints.

These actuations principally involved isolation of either the containment or the auxil.iary building.

More than 71 percent of the 501 ESF actuations, that is 358, were deemed to be invalid and unnecessary false actuations.

The primary causes for these i

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actuations were equipment faults during normal operation and personnel errors during maintenance or testing.

For example, because of either equipment faults or personnel errors, erroneous indication of a power loss accounted for ESF 2

actuations at 30 units. The engineered safety fe.atures most frequently experi-l encing false actuations were found to be associated with either the isolation or ventilation of either the containment or the control room.

l In 49 of the ESF actuations, involving 28 units, an ECCS was actuated.

Fluid was actually injected into the reactor coolant system in 23 of these events.

Nir.eteen units experienced these safety injection events, with no unit experiencing more than two injections.

None of these ECCS actuations were in response to an actual LOCA.

In eight of the safety injection cases, valid system setpoints were reached.

However, these setpoints were reached either l

following react.or scrams or during surveillance testing and not as a result of i

inventory losses due to a breach of the reactor coolant system pressure boundary.

The remaining 15 safety injection ECCS actuation cases were false actuations resulting from either personnel errors or equipment failures.

In five of the 501 ESF actuations the ESF systems failed to properly respond.

In 32 additional cases the ESF actuations performed properly but one or more failures were associated with the actuation.

There was no identifiable trend or pattern for these additional failures and these failures, including the five system level failures, had minimal impact since redundant systems were available to perform the required function.

However, four cf the cases could have been significant given different event circumstances.

These cases improper. temperature switch jumper configuration; (2) the involved: (1) an unavailability of a turbine driven auxiliary feedwater pump; (3) an erroneous pressure switch location and calibration method; and (4) an undesired system interaction between essential ESF support systems.

Based on the analysis and evaluation of these actuations, it was generally concluded that events necessitating ESF actuations, including ECCS actuations,

,j have not been individually significant and their frequency should not be a major concern.

It was also concluded that this holds true for failures and r

problems associated with the ESF actuations.

In addition, it was readily apparent that the majority of the ESF actuations were unnecessary and that the rate of these actuations could be greatly-decreased by (a) reducing the number of equipment failures during normal operation, (b) reducing the number of personnel errors during maintenance and testing, and (c) revising actuation setpoints to more appropriate protective levels.

ESF functions associated l

with isolation or ventilation should receive first priority in these regards.

ii Nine units were identified as being of potential concern, however, because they appear to be experiencing repeated unresolved actuations which could ultimately challenge continued equipment operability and proper personnel response.

These units were:

D. C. Cook 2, Ft. Calhoun, LaSalle 1 and 2, San Onofre 2 and 3, Sequoyah 1 and 2, and WPPSS 2.

It was further concluded that four problems were discovered that could be of safety significance under different circumstances.

These problems were: (1)

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(4) component cooling water system interaction.

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Finally, it was concluded that the limited number of ESF actuations, the wide variety of ESF systems, and the differences in the types of ESF actuations make comparison between units very difficult.

In cases where frequent actuations were being experienced at a unit,

however, the information associated with such actuations should be useful iri analyzing the performance of the licensees on an individual basis.

It is recormnended that AE00 continue to study ESF actuations with the goal being to verify the trends and patterns found in this initial investigation.

Additionally, these further studies should focus on the specific units found to have high actuation rates and continuing problems to verify that sufficient corrective actions are being taken.

These units are:

D. C. Cook 2, Ft.

Calhoun, Grand Gulf 1, San Onofre 2 and 3, Sequoyah 2, and WPPSS 2.

It is further reconsnended that AE00 investigate the four potentially significant problems discovered during this study:

(1) improper temperature switch jumper configttration; (2) steam supply transfer relay seal-in circuitry; (3) pressure switch location and setpoint calibration; and (4) component cooling water system interaction.

The goal of such an investigation should be to determine the generic applicability of these problems and define if further actions, whether generic or unit specific, should be required to j

properly address the concerns.

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1.0 INTRODUCTION

All licensed comercial nuclear power plants in the United States contain systems which are designed to control and mitigate any occurrence that might l

challenge the integrity of the reactor or adversely affect plant personnel or j

the general populace.

Generally known as engineered safety features (ESFs),

t these systems include those designed to control reactor core reactivity, isolate and cool containment, supply emergency cooling to the reactor fuel, remove residual decay heat, provide emergency power, assure habitability of the control room, and control radioactivity releases to the environment.

Prior to 1984, the nuclear power plant licensees were not required to routinely f

report ESF actuations. However, knowledge of such actuations was recognized as one of the essential elements needed to understand the operational performance of each reactor and to measure the type, frequency, and safety significance of l

events requiring mitigation.

Consequently, the Comission, as part of the revised reporting requirements which became effective in January of 1984, now requires the licensees to report [per 10 CFR 50.73(a)(2)(iv)]:

Any event or condition that resulted in manual or automatic actuation of Safety Feature -(ESF), including the Reactor Protection any Eng(ineered System RPS).

However, actuation of any ESF, including the RPS, that resulted from and was part of the preplanned sequence during testing.or reactor operation need not be reported.

In late 1984, AE0D began a comprehensive study of the ESF actuations reported t

under the new 10 CFR 50.73 requirements.

This investigation focused on_ actua-tions of ESF systems other than the RPS which occurred during the first six months of 1984 at all licensed comercial U.S. nuclear _ plants.*

This study i

I also used information contained in the NRC Operations Center "Significant Event Report" file.

This file is based on reports required by 10 CFR 50.72 and was utilized in this investigation to help ensure that the most complete and accurate set of ESF actuation data was obtained.

Of prime interest for this study were the concerns that frequent actuations of ESF systems may indicate continuing and perhaps serious safety problems j

associated with such factors as safety conditions, inadequate maintenance, or I

improper operations, and that these problems may warrant further attention and 2'j corrective actions.

Frequent ESF actuations may also be adversely affecting the design life of the ESF systems such that their availability to perform their intended safety functions may be compromised.

Additionally, frequent actuations of ESF systems may lead to personnel complacency such that they react inappropriately to the actual situation.

Consequently, this study was undertaken to: (1) gain an understanding of the frequency and causes of ESF actuations on both ~an individual unit and an industry-wide basis; (2) i determine the significance and implications of the current actuation rates; (3) determine if specific actions by the NRC or industry appear i

• Separate AEOD studies of RPS actuations are being conducted and documented.

For example, see AEOD report P406 " Trends and Patterns Analysis of Unplanned.

Reactor Scrams at U.S. Light Water Reactors January - March 1984," issued in 4

November 1984.

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1 warranted; and (4) investigate the usefulness of ESF actuation information as a suitable measure for indicating licensee performance.

The sections which follow document the results of this evaluation.

Included are general observations as well as discussions of specific characteristics of the events studied.

Each specific characteristics discussion includes a conclusion and recommendation section.

An overall sumary of the findings, conclusions, and recomendations is also included.

Details of all the events considered in fomulating this report are contained in the Appendix.

2.0 GENERAL OBSERVATIONS For the study period,1191 LERs were submitted per 10 CFR 50.73 requirements.

Of these, 293 LERs (25%) described events in which an ESF other than the RPS was actuated.

Discussed in these 293 LERs were 481 separate ESF actuations.

Searches of the immediate notification (i.e.,10 CFR 50.72) reports for the same period yielded an additional 20 occurrences (4%).

Thus, 501 ESF actua-tions other than RPS actuations were found to have occurred during the first six months of 1984.*

The 501 ESF actuations. occurred at 61 of the 87 reactors that were eligible for reporting per 10 CFR 50.73.

In more detail, of the 87 units eligible,-26 l

units (30%) experienced no actuations during the six month rtudy pericd, 37,

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units (42%) had between one and three actuations, 8 units (9%) had from four to six actuations, and 4_ units (4.5%) had between seven and nin~e actuations.

Twelve units (13.5%) experienced more than ten ESF actuations, with the maximum number of actuations at any one unit being 82.

Thus, on an average actuation rate basis,12 of the 87 units reported approximately 2 actuations per month.

An illustration of the distribution by unit of the 501 reported ESF actuations ll 1s shown in Figure 1.

Figure 2 shows the average monthly ESF actuation rate 4

distribution.

Table A.1 of the Appendix is a listing of the units eligible to report ESF actuations and the number of such actuations reported by each unit during the first six months on 1984.

Table A.2 of the Appendix gives details of these actuations.

In addition to the number of actuations and the corresponding monthly actuation rates, certain other dominant characteristics were observed.

These included:

(1) actuation types; (2) measured parameters, equipment actuated, and basic causes; (3) actuations leading to fluid injection into the reactor vessel; (4) failures to actuate properly; and (5) problems discovered as a r'esult of the j

actuations.

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• The auxiliary feedwater system (AFW) in reactor units supplied by Westing-house usually actuates during the nomal transient sequence which follows a reactor scram. Most licensees consider such an actuation to be a consequential part of a preplanned sequence during normal. reactor operation and, therefore, they do not consider such an actuation to be reportable as an ESF actuation.

Consequently, this study included actuations of the AFW system at Westinghouse 1

reactor units only when the licensee specifically stated that the AFW was started in an ESF operational mode.

Hence, the actuation rate of the AFW l

system at Westinghouse reactor units as noted in this study may not be indica-tive of the actual AFW actuation rate at these reactors.

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Figure 1:

Unit Distribution of Engineered Safety Features Actuations (January - June 1984) 6

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l 3.0 ACTUATION TYPE 5 One fundamental characteristic of the ESF actuations studied was whether or i

not a measured parameter actually reached its intended setpoint.

For discus-sion purposes, those cases in which a setpoint was reached were defined to be

" valid" actuations.

Actuations which resulted from something 6ther than a

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i measured parameter reaching its intended setpoint were considered to be invalid (and unnecessary), and were defined to be " false" actuations, i

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3.1.1 General Characteristics 1

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In 143 of the 501 cases studied (28%), a measured parameter reached the intend-

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j ed setpoint for ESF actuation; however, in only 12 of these 143 cases were the actuations considered needed in terms of providing a required ESF system i

response for protection from an actual decign basis event.

These 12 " design j

basis" ESF actuations represented only 2 percent of the 501 cases.

They i

occurred at a total of 5 different units and were associated with (1) three 1

cases involving the loss of offsite power, (2) three high toxic gas level conditions and (3) six high radiation events.

None of these 12 actuations.

.however, were necessary to control significant safety events such as a LOCA or a stenmline break.

In the remaining 131 cases where a setpoint was reached, the ESF actuation resulted primarily because the actuation setpoints, as governed by the technical specifications, were set very close to the parameter background levels experienced during various unit operational modes. These ESF l

actuations were considere~d to be valid but did not represent a required j

response to a design basis event.

Rather, they were actuations resulting from non-design basis conditions, such as an accumulation of radioactive trash in a

I front of a radiation monitor during refueling operations.

These valid but non-design basis actuations were primarily associated with either toxic gas monitors or radiation-related monitors. The ESF actuations which resulted from these setpoints being reached were principally associated with isolation of the l

containment or auxiliary building, or with isolation of the control room emergency ventilation.

A total of 20 units were affected by these valid non-design basis actuations.

The unit distribution of the valid actuations, both design and non-design l

bases, is shown in Figure 3.

Detailed listings of these 143 ESF actuations are given in Tables A.3 and A.4 of the Appendix.

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'3.1.2 Specific Actuation Characteristics 3

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The 143 valid ESF actuations resulted from several different types of parame-ters reaching their setpoints and involved a wide range of ESF systems.

Figure 4 shows the types of parameters measured and the associated general ESF system functions which were involved.

As can be seen in this figure, some 1

parameters were associated with more than one function.

It was determined that the use of general functional characteristics was 'necessary for ease in system comparison since there appears to be no comon definition or title for each ESF system at the various units.

For example, over 45 different systems were reported to have experienced an ESF actuation.

Of these, a total of 16 different systems were associated with a heating and ventilation function.

Consequently, for specific comparisons, the identification and composition of specific ESF systems for each unit, along with the associated measured parameters and setpoints, were required.

Such detailed information was not 8

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o haber Number 6eneral Systes Function involved

• Measured of of Heating and Energency Total Paraseter Fluid Ventilation Isolation Power Not, Defined Functions Involved Units Events (HVAC) 6 45 Radiation 11 45 56 5

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Isolation

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Energency Power = Diesel Generator (D6) u Figure 4: Measured Paraseters and Associated Systes Functions for Valid ESF Actuations 10

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e usually supplied by the licensees.

Thus, specific unit-to-unit comparisons were limited.

Table A.5 in the Appendix lists the ESF heating and ventilation systems that were reported.

Discussions of some of the more notable items which could be identified follow.

These Sequoyah 1 accounted for 6 of the 12 valid design basis actuations.

occurred over a six day period in January 1984, primarily due to radioactive releases into the auxiliary building during waste transfer operations.

The ESF systems actuated as designed to isolate the auxiliery building.

No safety i

i equipment was adversely affected but a few personr.el received minor levels of contamination (i.e., 300 counts per minute maximum from Rb-88, Xe-133 and Cs-138).

Corrective actions were instituted

• ,o help prevent further similar occurrences and no subsequent cases were observed.

The six remaining valid design basis actuations appeared to be isolated events involving four other units.

Three events involved actuation of emergency power systems as a result of the loss of normal offsite power supply due to weather or line faults.

In each case, the emergency power system operated as needed and no significant consequences occurred.

Emergency ventilation systems associated with the control room were actuated in the three other events.

These actuations were the result of either onsite releases of chlorine during chlorine transfer operations or tear gas drifting onto the plant site from an adjoining military installation.

Regarding the valid non-design basis events, over 40 percent of the 131 ESF actuations occurred at ' San Onofre Unit 2.

Because the ESF systems actuated are shared between Units 2 and 3, these events also affected San Onofre Unit

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3.

In all but two of the 56 San Onofre cases, the events involved the actua-tion of the control room emergency air cleanup system (CREACUS). These actua-tions were due to an indicated high toxic gas level.

In these cases, the technical specification setpoints for the monitors were such that minor varia-tions in the background readings resulted in the setpoint being reached.

Various corrective actions have been undertaken, including a technical speci-fication change request, to alleviate this problem; but, over the period

's studied, these changes have had only minor impact on the monthly rate of occurrence of such toxic gas events.

Figure 5 illustrates this monthly actua-tion rate.

Of notable interest, but not investigated further during this study, was the fact that no other unit reported similar valid ESF actuations as a result of toxic gas monitors reaching their setpoints.

j

'i Over half of the remaining valid non-design basis ESF actuatipns, i.e., 39 of 75, resulted from radiation monitors reaching their setpoints.

While six units experienced such actuations, they were concentrated at only three units:

Sequoyah I with 13 actuations, D. C. Cook 2 with 11, and Ft. Calhoun with 11.

The distribution of these actuations is shown in Figure 6.

The radiation monitor setpoints were reached for a variety of reasons. One of the prime reasons was that the licensees had elected to set the monitor set-points conservatively at essentially background levels experienced during certain reactor operational modes such as refueling.

Other principal contri-butors included maintenance activities such as trash removal, and refueling activities such as purging, refueling cavity water level adjustment and reactor i

internals movement.

The licensees involved have reportedly taken actions, i

i 11 i

. _ m._...

..m.....~.._g..

......_ m.

l

.m.= x.

.m...~

FIGURE 5

ESF TOXIC GAS MONITOR ACTUATIONS (Valid Non Design Basis)

San O n of re 2

=

t 1s-

[

1s- -

14-e i

b cn 12-5 Eto--

e 5'k 1

3j I

3N a-1g'=

E E ]8 15 i

e- -

.s j 3 1:E y -g 4

NN 5-E 2- -

l,3 O

~

JAN FEB MAR APR MAY JUNE MONTH (1984)

_._m.__..=_-

.E.]..,

FIGURE 6

ESF RADIATION MONITOR ACTUA-~lON S (Valid N.o n Design Basis)

LEGEND 2

M Other I:

1s- -

[I Sequoyah 1

g is-Fort Colhoun

/$

D.

C. Cook 2 I

G 12-g 5

h 10-E O<

a- -

y 2(4til E

^~ ~

a a s m

JN FEB MAR APR MAY

- JUNE MONTH (1984)

~.

principally procedural, to preclude future reportable occurrences of this type.

No clear trend is evident over the study period of the effectiveness of these actions, although a frequency baseline of about four reports per month appears to be persisting.

4 Of the 36 remaining valid non-design basis actuations, only c6e additional type of actuation occurred frequently; this being 22 isolations of the reactor water cleanup (RWCU) system.

These occurrences were reported by four units, each of which had received its operating license after 1981.

The units affected were:

Unit RWCU Isolations Operating License Date LaSalle 2 7

1984 LtSalle 1 6

1982 Grand Gulf 1 5

1982 WPPSS 2 4

1984 The monthly distribution of these actuations is shown in Figure 7.

~

These 22 isolations were the consequence of the setpoints being reached on instrumentation designed to sense RWCU pressure boundary failures.

Such detection is based on RWCU flow or environment temperatures in areas where the RWCU system is located.

The principal reason for the 14 actuations based on flow was the detector location and its resultant sensitivity to fluid density and reactor flow oscillations during various unit operational conditions.

Eight isolations were due to temperature variations associated with room ventilation system problems or conservative setpoints.

To help prevent recurrences of these RWCU isolations various modifications were being implemented.

Included in these were re-evaluation of monitor setpoints and modifications to procedures.

Based on the limited data avail-able, these changes appear to have resolved the RWCU isolation problems at j

both Grand Gulf 1 and WPPSS 2 but those at LaSalle 1 and 2 continue.

I 3.2 False Actuations i

3.2.1 General Characteristics False ESF actuations occurred in 358, or 71 percent, of the 501 occurrences studied.

These actuations were experienced by 59 units as a result of something other than a measured parameter reaching its intended setpoint.

Caused fairly equally by spurious signals, equipment failures, or problems related to personnel, these false ESF actuations principally affected systems whose functions were associated with either isolation or ventilation.

The main parameters involved with these false actuations were radiation and loss of power.

Figure 8 shows the unit distribution of these false actuations and Figure 9 illustrates some of their basic characteristics.

Table A.6 of the Appendix gives a comprehensive listing of the individual occurrences.

14

x.

-lGURE 7

ESF RWCU ISOLATION ACTUATIONS (Valid Non Design Basis)

LEGEND WPPSS 2 l

s..

LaSalle 2 7-

~

LaSalle 1 FA crane cuir,

l e-6 z s- -

9 Q

O d4 s--

l 9

)

2-1-

a O

JAN FEB MAR APR MAY JUNE MONTH (1984)

.....-. ~

e 0

10 20 30 40 50 l

i I

I I

I nPPSS 2 IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII SEQUDYAH 1 IIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII SAN ON0FRE 2 IIIIIIIIIIIIIIIIIIIIIIIIII IRJAE ARN(1.D IIIIIIIIIIIIIIIIIIIIIIIII MONTICEll0 111111111111111111111111 SEQUOYAH 2 IIIIIIIIIIIIIIIIIIII D. C. COOK 2 11111111111111 SAN ONOFRE 3 IIIIIIIIIIIIII WAW GA.F 1 IIIIIIIIIIIII LA SALLE 2 IIIIIIIIIIIII LA SALLE 1 IIIIIIIIII DIABLO CANYGt IIIIIIIII FORT CALH0lft 111111111 RWSWICK 1 IIIIIIII SUSQlEHAletA 1 IIIIIIII KEWAlfEE IIIIII MAIE YAftIE IIIIII PALISADES IIIIII ARKANSAS 2 IIIII

.BRWSWI(X 2 IIIII MCOUIRE 1 IIIII Suffer 1 IIIII BR0letS FERRY 1 IIII PEACH BOTTGt 2 IIII

.U IR0lMS FERRY 3 III N

CRYSTAL RIVER 3 III I

• TROJAN III T

TlRKEY POIhT 3 III BEAVER VALLEY II N

CALLAliAY II A

D. C. COOK 1 II M

Ile!AN POINT 3 II E

LACROSSE II MILLSTWE 2 II SALEM 1 II 9 N HApelA 2 II TMI 1 II TlRKEY POINT 4 II VERMONT Yale (EE II YAft(EE R0lE II ARKANSAS 1 I

BIG ROCK POINT I

BR0latS FERRY 2 I

CALVERT CLIFFS 2 I

COOPER I

DAVIS lESSE 1 I

FT. ST. VRAIN I

Gift lA I

E. I. HATCH 2 I

NIE MILE POINT I

f.

NETH AINA 1 I

OYSTER CREEK I

POINT BEACH 2 I

PRAIRIE ISLAND 2 I

QUAD CITIES 2-I RANCND SECO '

I ROBINSON 2 1

SAN ONOFRE 1 I

SLRRY 1 I

I I

I I

i 1

0 10 20 30 40 50 IGJMBER OF FALSE ESF ACTUATIONS Figure 8: Unit Distribution of False ESF Actuations 16

Number Number CAUSE+

FUNCT10 Net ACTIVITYe**

of of Paraseter Units Events DE EG PE SP PR OT CD UN FL HV IS PD OT CD MU MA TE OP CN UN 16 127 Radiation 17 14 89 3 4

39 82 6

31 12 81 1 2 32 81 Loss of Power 1 18 35 4 9 2 5 7 2 41532 25 3 35 20 25 1

6 29 Teeperature 1 4 8 1 6 9 7 22 2 12 15 18 25 Pressure 1 5 9 3 2 4 1 1

1 B 1 2.4 I

9 10 6 9

16 Level 1 4 5 3 1 1 1

9 1 2 1 3 4 3 9 4

1B Toxic Bas 12 3 1 2

17 1 2 2 9 5

6 8

Flos 4

2 2 8

1 3 4 1

6 Fire Detection 2

4 6

1 5

1 1

Condenser Vacuus 1

1 1

1 1

Reactor Trip 1

1 1

f 8

8 Manual 3 4 1

1 1 2 3 1 3 3 2 1

1 None 1

1 1

9 12 Coebination 1 2 1 1 5 2 1

2 5 4 3 2 7 2

3 Unknown 2

1 1

l' 1

3 14 22 Not Defined 3 7 2 2 4 4 5 4 3 1 1 7 1 7 9 5 1 358 TOTALS 3 71 85 114 20 43427 21 80 147 35 4 54 17 99 77 172 2 8

.i

• CAUSE - DE = Design

• • FUNCTION - FL = Fluid e w ACTIVITY - MA = Maintnenance EG = Equipment HV = Heating 6 Ventilation OP = Operation PE = Personnel IS = lsolation TE = Testing SP = Spurious P0 = Power CN = Construction PR = Procedure OT = Other ND = Not Defined GT = Other CD = Coebination CD = Costination MU = Multiple (Not Definedi UN = Unknown Figure 9: False ESF Actuation Characteristics 17

,e-,

3.2.2 Specific Actuation Characteristics Of the 358 false ESF actuations,127 (35%) were associated with radiation monitors at 16 units.

However, over 80 percent of these radiation actuations, (i.e.,104 of 127) occurred at only 6 units.

These units and the number of associated false actuations were:

Unit False Radiation Actuations Sequoyah 1 29 WPPSS 2

-21 1

San Onofre 2 17 D. C. Cook 2 13 Sequoyah 2 13 San Onofre 3 11 l

The monthly distribution of these actuations is shown in Figure 10.

All of the actuations at San Onofre, Sequoyah and WPPSS were associated with electrical noise sensitivity of their respective containment and control room radiation, monitoring equipment.

The results of this sensitivity were frequent spurious isolation of containment purge, or actuation of emergency control room ventilation.

The trend indicated that the actions being taken to elimi-nate these occurrences had been successful at Sequoyah but not successful at San Onofre or WPPSS.

The actuations at D. C. Cook 2 were primarily asso-ciated with radiation monitor software problems which led to isolation of containment purge.

This software problem did not appear to be generic to the other units studied.

The 23 remaining false actuations associated with radiation monitors occurred at a total of 10 units.

These events appeared to be unit specific with no clear trend or pattern or generic problem in evidence.

The only other major false actuation type, accounting for 23 percent of the ij false ESF actuation events (i.e., 81 out of 358), were associated with losses j

of power.

These actuations occurred at 32 units, primarily as a consequence l

of either equipment failures during normal operation or personnel errors during maintenance or testing.

The, principal affect of these events was the inadver-l tent actuation of an emergency power source (e.g., diesel generator) or some I

form of building isolation (e.g., primary containment).

No unit experienced more than 10 percent of these actuations and no clear pattern was evident.

The final 150 false ESF actuations (42%) were associated with 11 other defin-able parameters.

These actuations were widely distributed between 39 units, occurring fairly uniformly during operation, maintenance or testing activities.

Personnel problems were responsible for a few more occurrences than equipment failures.

The primary ESF functions affected were associated with either isolation or ventilation. While these general characteristics were evident, no l

specific trends or patterns were identified for which generic corrective i

actions could be applied.

18 l

.. -.../.,

=-

=...

FIGU RE 10 ESF RADIATION MONITOR ACTUATIONS (False)

L'EGEN D l

Other l

b D. C. Cook 2 so--

YI WPPSS 2 San Onofre_ 2&3 i

/$

Sequoyah 1&2 m5 i

E 20-E e

15--

l l

10--

.a 4 RE R e_

~

MkR APR MkY JUNE JAN FEB MONTH (1984)

w i

3.3 Conclusions and Recommendations r

3.3.1 Conclusions o

The rate for valid and necessary ESF actuations because of,oesign basis events is very low.

Only 12 such actuations, comprising just 2 percent of all reported actuations, occurred in the six month study period; and none of these was necessary to control a significant safety event such as a LOCA.

Thus, there is little indication that any unit is experiencing serious unresolved safety problems which have required mitigating ESF actuations.

o The majority of the ESF actuations are unnecessary.

These actuations could be most effectively decreased by: (1) improvements in equipment, (2) reductions in personnel errors during maintenance and testing, and (3) adjustments to conservative monitor setpoints.

The ESF systems most affected by such actuations are associated with the functions of either isolation or ventilation of either the containment or the control room, l

1 o

With few exceptions, the overall rates and types of ESF actuations do not appear to indicate that proper personnel attention and equipment response will be compromised as a result of too frequent ESF actuations.

Thus, future mitigation of severe operational events should not be jeopardized by the present ESF actuation frequency.

o While this study indicates that the reported ESF actuations do not seem to pose an industry-side or generic problem, a few specific units are experiencing frequent or unnecessary challenges.

These specific plants, however, appear to recognize the need for corrective actions and have implemented improvement programs but the effectiveness has varied.

The specific units and concerns where problems appear to persist are:

hj 1.

The frequency of occurrence of toxic gas isolations at San Onofre 2 n

is high enough to raise concerns regarding the long-term reliability of i

?

the actuated equipment, the personnel attention and response to such actuations, and the distractions of operating personnel caused by such actuations.

2.

The measures being taken to reduce the frequency of the ESF actua-tions based on radiation at San Onofre 2 and 3, and at WPPSS 2 do not appear to have been effective.

Also, the effectiveness of the measures being taken at D. C. Cook 2, Ft. Calhoun, and Sequoyah 1 and 2 are sus-pect.

Consequently,. continued operability, long-term reliability, and proper personnel response to such actuations may be compromised.

)

3.

ESF actuations associated with RWCU isolations at LaSalle 1 and 2 do not seem to have been effectively addressed.

As a result, there seems to be a relatively high challenge rate to both the ESF equipment and the operating personnel.

I i

20

In ger.eral, use of ESF actuation data in comp (aring the performances of o

licensees would be very difficult because of a). the limited number of actuations experienced at most units, (b) the wide variety of ESF systems, and -(c) the differences in the types and significance of ESF actuations being experienced.

However, especially in cases where frequent ESF actuations are being experienced, the information associated with the actuations should be useful in analyzing the licensees' programs for defining and correcting recurring problems.

3.3.2 Recommendations It.is reconsnended that AEOD continue to trend ESF actuations.

These o

future studies should also focus on the actuation trer.ds at: D. C. Cook 2, Ft. Calhoun, LaSalle 1 and 2, San Onofre 2 and 3, Sequoyah 1 and 2, and WPPSS' 2 in order to better determine the effectiveness of the corrective J

actions taken by each licensee.

Depending on the actuation trends, further actions, including thorough investigations into - the causess and corrective actions being taken, may be warranted.

4.0 EMERGEEY CORE COOLING SYSTEMS - SAFETY INJECTIONS 4

4.1 Discussion One of the most critical functions of the engineered safety fe'atures is to' provide emergency injection of fluid into the reactor vessel.

This safety injection assures reactor. fuel cooling in events wl'ere reactor coolant is lost.

The ESF systems which perform this vital function are collectively known as emergency core cooling systems (ECCSs).

Obviously, these emergency core cooling systems must work properly when called upon.

However, when these systems actuate unnecessarily, the' temperature differences between the ECCS safety injection fluid and the reactor coolant impose cyclical thermal stresses which challenge the design life of the affected ccmponents.

Thus, unnecessary safety injections are of concern from the standpoint of continued primary system integrity.

1 Frequent ECCS actuations are also of concern since they may cause the reactor operators to become accustomed to such actuations and, as a result, they,may respond to the actuations in a routine manner without fully comprehending 'the-reasons for such actuations.

Consequently, this conditioning may result in the operators prematurely terminating a necessary safety injection.

Thus, frequent ECCS actuations are of concern from the aspect of improper reactor operator response. _

Upon investigation o# the 501 ESF 6m JaU ns in this study, it was d5nnined that 49 of the occurrences (10%} iwlm ECCS actuations.

These actuations 4

were spread an:ong 28 units, with i.ne n4sity of these units experiencing one or two ECCS actuations.

Due to various factors, such as reactor pressure being higher. than the discharge pressure of the actuated ECCS pumps, o.nly 23 of the events resulted in actual injections of fluid.

These 23 injections occurred in 19 different units with no unit experiencing more than: twc,injec-tions.

Details of these 23 actual injection events are noted in Table A.7 of the Appendix.

s 21 t

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e

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,-,,-m-w,7m--

r

+,.-e,-.J

-,m-#.,-~$y m*

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~

Of these 23 actual injection events, none were needed to control an actual LOCA and none were deemed valid design basis actuations.

Eight of the events I

were considered _ valid non-design basis ESF actuations.

However, the actua-tions resulted from low water level or high steamline differential pressure experienced following reactor scrams, or low pressurizer pressure occurring during maintenance and testing.

Similarly, the 15 false safety infection actuations were primarily the result of personnel errors during maintenance and testing while the reactor was in operation or hot, pressurized conditions.

Equipment failures during nomal power operations were the secondary cause of these false actuations.

Where clearly reported, the safety injections were the result of actuation of high pressure ECCSs in 12 of the 23 cases, and actuation of low pressure ECCSs in just two cases.

In nine cases, the type (i.e., high or low pressure) of injection system was not reported by the licensees.

However, by implica+ ion, the majority of the systems were high pressure since most of these injections occurred while the reactors were in a hot, pressurized operational condition.

4.2 Conclusions and Recommendations 4.2.1 Conclusions The number and severity of safety injection events presently occurring o

does not appear to be sufficient to result in excessive thermal stress cycles on the reactor coolant system at any unit.

Thus, the present rate of safety injections does not appear to warrant any further actions.

[ Note:

This conclusion supports a related conclusion contained in NUREG-0933 "A Prioritization of Generic Safety Issues," dated September 30, 1982.

NUREG-0933 stated that thermal cycling was primarily an economic problem rather thn a major safety concern.

This was because present industrial codes adequately addressed thermal cycle design limits and any reactor operation in excess of these design limits would have to be justified to the NRC on a case-by-case basis.]

o The number of injections does not seem sufficient to support the concern that operations personnel will become so accustomed to such actuations as to dismiss them as being routine and of little significance.

o Notwithstanding NUREG-0933, it is readily apparent that improving personnel performance during maintenance and testing activities would have a significant benefit on reducing the number of ESF actuations which result in safety injections.

4.2.2 Recommendations o

Because of the limited number of safety injections being experienced, no recommendations for corrective actions to alleviate unnecessary ECCS actuations are believed necessary at this time.

i 22

5.0 FAILURES AND PROBLEMS A positive aspect of ESF actuations, whether valid or false, is that these occurrences verify that the ESF systems perform as designed so that their intended safety functions are fulfilled.

Conversely, failures of any ESF system to actuate properly requires immediate resolution.

In addition, ESF actuations can reveal failures that occur simultaneously with or subsequently to the actuation, such as an undetected failure in an essential ESF support system.

These " associated" failures may significantly affect the ability of the ESF systems to function properly or they may indicate potentially significant equipment or personnel deficiencies which need to be addressed.

5.1 ESF Failures To Actuate Properly Only in 5 of the 501 ESF events (1%) did an ESF system fail to actuate properly.

The significance of these failures to actuate. varied.

Discussions of each of these events follows.

5.1.1 Brunswick 1 - Loss of High Pressure Coolant Injection (LER 84-007)

On March 31, 1984 Brunswick Steam Electric Plant Unit 1 experienced an actuation of the high pressure coolant injection (HPCI) system as a result of j

the reactor water level transient associated with a reactor scram.

Shortly after starting, the HPCI system isolated and could not be successfully restarted.

The reactor core isolation cooling (RCIC) system, a non-ESF system, started and functioned correctly throughout the transient and was l

utilized to restore and' maintain the reactor water level.

Subsequent investigation determined that the HPCI system was lost due to a failure of the HPCI turbine speed controller.

This failure, in turn, was the result of a sensor wire which had been broken at an earlier time.

Such wire damage could have occurred relatively easily since the wire ran exposed approximately three feet from the end of a conduit run to the connector.

To help prevent recurrence, signs were posted warning of the exposed wire.

In this case the safety function of the HPCI system was lost until corrective

^

maintenance was perfonned.

The significance of this failure was minor since the RCIC system was available.

Further, the HPCI system is a single train 5

safety system that was not intended to meet the single failure criteria.

In addition, other safety systems were available, if needed, i

5.1.2 Duane Arnold - Loss of Standby Filter Unit,s (LER 84-004)

As a consequence of malfunctioning preheat coils, the Duane Arnold Energy Center experienced an automatic isolation of the control building ventilation system based on low inlet air temperature.

In responding to this ESF actua-tion, however, both trains of make-up air supply.to the standby filter units (SFUs) failed to initiate properly.

These SFUs are engineered safety features which (1) supply the control building ventilation system with treated makeup to balance the battery room exhaust, (2) minimize operator radiation exposure, (3) help provide control room personnel with a comfortable working atmospheric temperature, and (4) protect equipment from eventual freezing due to low air l

temperature.

23

^-

s 5

In this case, the improper SFU make-up air supply operation was due to fail-ures of the inlet dampers to open when commanded.

Immediate corrective action was taken to open the dampers.

This was accomplished by an operator going to the SFU room, which is imediately above the control room, and locally isolating the instrument air to the. dampers.

Both dampers then opened.

Subsequent investigation determined. that the failure of the 'danipers to open was a result of pilot solenoid valve failures in the air operators for the 1

l dampers.

The solenoid fatlts were attributed to several factors including (1) a restricting fitting en each solenoid exhaust port, (2) a contaminated instrument air supply, (3) aging [the valves had operated successfully for 10 years prior to this occurrencej, and (4) valve diaphragm stiffening due to cold air and ice formation as a result of the malfunctioning preheat coils.

j 1

Corrective actions taken to mitigate these faults included removal of the restricting

fitting, upgrading of the instrument air

system, general maintenance on the dampers and actuators, and repair of the preheat coils.

I Even though the safety function performed by the ESF was lost in this event, the safety significance was minor.

This was because, except for the capabill-ty of supplying treated make-up air, the remaining safety functions of the i

Duane Arnold control building ventilation system were still functional.

j 5.1.3 LaSalle 2 - Loss of Containment Iso.lation Valve (LER 84-009)

On March 8,1984 at LaSalle County Station Unit 2 an inadvertent containment isolation occurred which resulted in the isolation of the residual heat removal (RHR) system.

At. the time of the event, one loop of the RHR system 4

was operating in the shutdown cooling mode.

Upon receiving the ESF isolation signal, the injection valve closed but the suction valve remained open.

This sequence placed the operating RHR pump.at shutoff head conditions and, subsequently, generated a comand to open the minimum flow valve.

With the minimum flow valve open, 60 inches of reactor water were pumped from the vessel to the suppression pool.

The operator tripped the operating pump upon receipt of a low vessel level alarm, thereby terminating the event..Upon examination it was determined that the inadvertent containment isolation signal resulted from an improper jumper configuration on a newly installed leak detection temperature switch.

It was discovered that this switch, along with two others, had been supplied from the manufacturer with the wrong jumper configuration.

It had been assumed that these switches worked properly due to previous experience with similar switches and initial calibration operability

i checks.

Corrective actions taken to alleviate this problem included changing the jumper configuration, inspecting all temperature switches in storage to verify conformance with' station requirements, and reviewing procurement documentation to assure correct part ordering.

1 The suction valve failure to close was found to be the result of a personnel error.

During previous testing, the breaker for the valve operator was placed on the off position -with the valve open.

These facts were properly logged.

However, upon completion of the test, the breaker position was not changed.

Thus, when the close signal was generated, no motive power was available to the valve.

Corrective actions included counseling of the personnel involved.

i 24

~....

u.

1 Prompt operator action prevented excessive vessel fluid inventory loss.

Additionally, a separate and redundant suction isolation valve would have actuated at a level sufficient to maintain the vessel level above the top of the core.

Also, the fluid was not lost from the safety injection systems since it was delivered to the suppression pool.

Thus, this event was of minor safety significance.

5.1.4 Sequoyah 2 - Loss of Turbine-Supplied Auxiliary Feedwater (LER 84-009)

At Sequoyah Nuclear Plant Unit 2 on June 30, 1984, during startup while maintenance was being performed on a. main feedwater (MFW) pump, the running MFW pump tripped due to a loose terminal block connection.

This trip generat-ed an automatic start signal for the auxiliary feedwater (AFW) system. At the time of this occurrence, the two motor-driven AFW pumps were running and the

, turbine-driven AFW (TDAFW) pump was idle.

Upon receiving the auto-start signal, the two motor-driven pumps remained running but the TDAFW pump did not start.

Subsequent investigation determined that this failure was the result of an undetected fault which had occurred during an automatic start of the TDAFW pump during the previous shift.

In the earlier event, the TDAFW steam supply break isolation valves located in the coninon header from two steam generators to the AFW pump turbine had.been closed to prevent an automatic start of the TDAFW pump while maintenance' wa's being performed on an MFW pump.

During this maintenance, the running MFW pump was accidentally tripped, initiating an ESF start signal to the TDAFW.

Since the break isolation valves were closed and they did not get an automatic ESF open signal, the TDAFW puinp failed to start.

Sensing a low TDAFW pump dis-charge pressure, the steam supply transfer (SST) relay sealed in and initiated a transfer to the alternate steam supply line.

(Note:

The TDAFW steam supply may be fed from either of two steam generators.

One line leads from each generator to the common supply header.

Within each line from each generator is a motor-operated isolation valve.)

The transfer is accomplished by first commanding the preferred steam supply line isolation valve and the turbine trip and throttle valve (TTV) to both close.

Once the preferred steam line isolation valve is closed, the alternate supply isolation valve is commanded to open.

When the SST relay logic senses that the alternate valve is fully open, it then permits the TTV to open.

The position of the break isolation valves was not considered in the SST relay logic.

However, due to grease on a torque switch, the primary steam source isolation valve failed to close upon t

command from the SST relay but the TTV did close.

Since the primary valve had i

failed to close, the alternate valve never opened and the SST relay never dro~pped out, thus sealing in the close signal to the TTV.

This went unrecog-nized by the operators when they restored the accidentally tripped MFW pump and reopened the break isolation valves.

When the TDAFW pump received the subsequent ESF actuation signal, it was prevented from starting due to the closed TTV and seal-in of this valve position due to the previous undetected failure.

The operator subsequently opened the alternate isolation valve.

l This pennitted the SST relay to drop out and removed the close signal to the TTV.

When this was accomplished, the TDAFW pump started and performed cor-rectly.

The torque switch was subsequently cleaned, an operations order

(

explaining the event was issued, and a training letter was to - be written.

25

In this case, the loss of the TDAFW pump constituted only a degradation of the overall AFW system since the motor-driven AFW pumps were operational and were fully redundant to the turbine-driven pump.

Thus, the safety significance of this failure in this case was minor.

5.1.5 Yankee Rowe - Loss of Containment Isolation Valve (LER 84-003)

During preparation for a containment integrated leak rate test at Yankee Nuclear Power Station on April 3,1984, an ESF actuation event was experienced in which two solenoid operated isolation valves failed to actuate automatically on an increasing pressure exceeding 5 psig.

The valves were manually tripped at 6 psig to preclude damage by overpressurization of an air particulate leakage monitor located outside of containment.

Subsequent investigation of the failure revealed that the pressure switch, when valved out of the system, actuated at 4.3 psig.

In the leak test configuration being utilized, however, the switch was located in the suction line of the particulate monitor vacuum pump.

Because of this component arrangement, the i

trip point of the switch was adversely affected.

Subsequent calculations indicated that in this location, the switch would have actuated at a containment pressure of approximately 8.7 psig.

Corrective actions to pre-clude this type of event included relocating the leakage monitor from outside to inside containment.

This eliminated the possible failure of the leakage monitor outside of containment and, consequently, a breach of the containment boundary.

As in the previous cases, this event had minor safety significance.

The primary function of the pressure switch was degraded due to the higher than desired setpoint.

However, the switch was still operable and would have actuated such that the containment boundary would have been preserved.

5.2 Associated Failures During or subsequent to an ESF actuation, failures may be discovered that are not directly caused by the condition that necessitated the ESF actuation and, thus, appear to be separate random events.

A total of 32 of these types of failures were reported in 24 of the '501 ESF actuations studied.

These

" associated failures" occurred at 23 different units.

Table A.8 in the Appendix gives a detailed listing of these failures.

The associated failures reported appeared to be event-specific with no common cause.

They involved erroneous valve movement, equipment start or run problems, and instrumentation logic faults.

Because of system redundancy, however, none of these associated failures prevented the accomplishment of the safety function of the actuated i,

ESF systems.

One event, however, was notable since it involved the loss of an essential ESF support system.

In this instance, without a redundant support system, the function of the ESF system would have been lost.

This event occurred at Ft.

Calhoun in March 1984 (see LER 84-003).

As a result of a personnel error during maintenance, a partial loss of d.c. power was experienced.

One conse-quence of this power loss was the repositioning of isolation valves in the component cooling water (CCW) system, which serves' as the cooling water supply 26

=--_:

==

1 to the ESF RHR heat exchangers.

As a result of the valve repositioning, the CCW experienced an increased flow demand that, in turn, resulted in a CCW system pressure drop.

This pressure drop was sufficient to initiate opening of valves to the CCW back-up raw water system.

Because of system pressure differentials, CCW water (normally a closed loop) was lost to the raw water system.

This inventory loss was sufficient to cause the running CCW pump to begin cavitating, necessitating its shutdown (the associated. failure) before l

physical pump damage occurred.

Thus, the CCW system was lost.

Fortunately, in this case, the raw water system was designed as a safety system and it assumed the safety function of the CCW.

Therefore, the safety consequences of this associated failure systems interaction event were minimal.

5.3 Conclusions and Recommendations 4

5.3.1 Conclusions Failures are not occurring frequently when an ESF actuation is experi-I o

enced and no specific trend or pattern could be identified for the failures being experienced.

While the safety significance of the failures experienced was minor for o

the particular cases investigated, a few of the problems discovered may be significant at other units or under other circumstances.

These problems are:

1.

Improper temperature switch jumper configuration.

[Re:

LaSalle 2 l

LER 84-009.]

The miswired temperature switch as supplied by the switch manufacturer may be generic to like switches in other units.

If such faulty switches do exist' and are utilized in safety-related applications, the wiring defect may have a significant impact on the ability of the associated safety systems to function properly.

i l

l 2..

Steam supply transfer relay seal-in circuitry with potential for undetected failure leading to loss of system transfer function.

[Re:

Sequoyah 2 LER 84-009.]

This event was another example of undetected failures that have adversely affected the availability of a TDAFW pump.

The loss of TDAFW capability has been the subject of two recent AE00 reports, T416* and N402.**

As a result of the recommendations contained in N402, IE Information Notice 84-66 was issued to alert licensees of these potentially significant losses.***

However, it is not clear that this Information Notice sufficiently addressed this TDAFW problem since i

the events cited in N402 and 84-66 were unlike this failure.

Technical Review Report AE0D/T416

" Loss of ESF Auxiliary Feedwater Pump Capability at Trojan on January 22, 1983," dated August 1, 1984.

Engineering Evaluation Report AE0D/N402, " Engineering Evaluation of Events Involving Undetected Unavailability of the Turbine-Driven AFW Pump," dated i

June 15, 1984.

IE Information Notice No. 84-66:

Undetected Unavailability of the Turbine-Driven Auxiliary Feedwater Train, dated August 17, 1984.

4 27

-,...m,_.

.--,,,,,e,--,.-,,,m

..._,-,,,,-,.,rw,

,,,,.-,,m_w_,-,

,w

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

4,

-,.#,,.y..

..r

^

~~

_..r_; -

c _ m _.m.m_._ _ _ _.-_

I

~

3.

Pressure switch location and setpoint calibration.

[Re:

Yankee Rcwe LER 84-003.] Of prime concern in this case. is the potential for a breach in containment if similar switch and monitor locations are used along i

with utilizing a similar setpoint calibration technique.

4.

Com

[Re:

Ft. Calhoun LER 84-003.]ponent cooling water system interaction.

The Ft. Calhoun event is an example of a system interaction which can lead to the loss of a safety function with potentially serious consequences.

Ongoing studies of such interactions are being conducted by the NRC, including AE00.

5.3.2 Recommendations o

It is recommended that further review be conducted by AEOD into the potentially generic safety problems associated with improper temperature switch jumper configurations.

4 o

Because of the continuing problem of turbine-driven AFW pumps, it is recomended that AEOD conduct further studies of TDAFW failures to see if additional NRC actions are warranted.

o It is recomended that AEOD conduct a more detailed study of the pressure switch location and setpoint calibration situation in an attemp't to better define the generic nature of the-problem, its ' importance to safety, and steps that should be taken to mitigate the generic problems, i

if they exists.

o It is reconsnended that the component cooling water system interaction event identified in this study be factored into the other ongoing system interaction studies being conducted in AEOD, with generic or specific l

actions recommended as deemed necessary as a result of the findings of these further studies.

4 i

6.0 SUMARY OF FINDINGS, CONCLUSIONS AND RECOMMENDATIONS

(

j This study determined the type and ~ significance of ESF actuations being j

reported as a result of the revised reporting requirements of 10 CFR 50.73.

i It was found that 70 percent of the eligible U.S. comercial nuclear power

,i plants reported at least one ESF actuation other than an RPS actuation during the first six months of 1984.

In terms of LERs, approximately one quarter of all LERs submitted contained ESF actuations.

Some 30 percent of the units reported no ESF actuation', 42 percent of the units experienced between one and i

three actuations, 9 percent experienced between four and six actuations, and 18 percent experienced more than six actuations.

Only 10 percent of all 1

reported ESF actuations involved an ECCS actuation and none of these occurrences were necessary to control an actual LOCA.

The vast majority of the ESF actuations (some 70 percent) involved actuation of ESF systems associated with either an isolation or a ventilation function.

28 I

1

.__-_r

=-

In less than 30 percent of the cases were the ESF actuations the result of a monitored parameter reaching the intended actuation setpoint.

In these cases, some 90 percent were due to either toxic gas or radiation, with the toxic gas actuations concentrated at San Onofre 2 and 3, and the radiation actuations at Sequoyah 1, D. C. Cook 2, and Ft. Calhoun.

The prime reason for these actua-tions was the fact that the actuation setpoints were set very close to the normal background level experienced during various nonnal unit operational modes.

In those cases where the actuations were the result of something other than a valid setpoint being reached (i.e., false ESF actuations), the ESF_ actuations were primarily due to equipment failures during normal unit power operation, personnel errors during maintenance and testing activities, and spurious actuations at any condition.

Fifty-nine of the 61 reporting units experienced such actuations; however, over 80 percent of these false actuations were i

concentrated in six units:

D. C. Cook 2, San Onofre 2 and 3, Sequoyah 1 and 2, and WPPSS 2.

Finally, it was found that 94 percent of all of the 501 ESF actuations oc-curred without experiencing an associated failure.

For the six percent of the d

i ~ ~

actuations where such failures were experienced, the safety consequences were minor in each case since redundant systems were available to perform the tasks necessary to assure completion of the required safety function.

Based on the analysis and evaluation of these actuations, it was generally concluded that events necessitating ESF actuations, including 'ECCS actuations, have not been individually significant and their frequency should not be a 4

major concern.

It was also concluded that this holds true for failures and i

problems associated with the ESF actuations.

In addition, it was readily apparent that the majority of the ESF actuations were unnecessary and that the rate of these actuations could be greatly decreased by (a) reducing the number of equipment failures during normal operation, (b) reducing the number of personnel errors during maintenance and testing, and (c) revising actuation setpoints to more appropriate protective levels.

ESF functions associated with isolation or ventilation should receive first priority in these regards.

Nine units were identified as being of ~ potential concern, however, because 4

they appear to be experiencing repeated unresolved actuations which could ultimately challenge continued equipment operability and proper personnel response.

These units were:

D. C. Cook 2, Ft. Calhoun, LaSalle 1 and 2, San Onofre 2 and 3, Sequoyah 1 and 2, and WPPSS 2.

4 o

It was further concluded that four problems were discovered that could be of safety significance under different circumstances.

These problems were: (1) improper temperature switch configuration, (2) steam supply transfer relay seal-in circuitry, (3) pressure switch location and setpoint calibration, and (4) component cooling water system interaction.

Finally, it was concluded that the limited number of ESF actuations, the wide variety of ESF systems, and the differences in the types of ESF actuations make comparison between units very difficult.

In cases where frequent l

actuations were being experienced at a unit, however, the information associated with such actuations should be useful in analyzing the performance of the licensees on an individual basis.

29 5

- - -, ~

wv

~y---,-r-e,-

.,.--.--.-,.-..--,..,m.-,

,..,r-

.,p.,,

.-.-.-,_,-,,-...,_._,.-,..,.-#...w.-,,--.,%-,,,me.s

1 It is recomended that AE00 continue the ESF actuation study with the goal being to verify the trends and patterns found in this initial investigation.

Additionally, this further study should focus on the specific units found to have high actuation rates and continuing problems in order to verify that sufficient corrective actions are being taken.

These units are:

D. C. Cook 2, Ft. Calhoun, LaSalle 1 and 2, San Onofre 2 and 3, Sequoyah 2, and WPPSS 2.

It is further recommended that AEOD investigate the four potentially significant problems discovered during this study:

(1) improper temperature configuration; (2) steam supply transfer relay seal-in jump (er3) pressure switch location and setpoint calibration; and (4) switch circuitry; component cooling water system interaction.

The goal of such investigations should be to determine the generic applicability of these problems and define what further actions, whether generic or specific, are required to properly address the concerns.

e e

6 D

30

O m-@eth,-mas em

?

h 9

6 m

9 APPENDIX I

4 l

1 i

1 31

{

l i

TABLE A.1 NUMBER OF ESF ACTUATIONS REPORTED BY COMMERCIAL U.

S. NUCLEAR POWER PLANTS JANUARY 1, 1984 THROUGH JUNE 30, 1984 t

ESF ESF UNIT ACTUATIONS UNIT ACTUATIONS SAN ONOFRE 2 82 ARKANSAS NUCLEAR ONE 1 1

i SEQUOYAH 1 51 BIO ROCK POINT 1

4 WASHINGTON NUCLEAR 2 37 CALVERT CLIFFS 2 1

l MONTICELLO 26 COOPER 1

j D. C. COOK 2 25 DAVIS BESSE 1 1

DUANE ARNOLD 25 FT. ST. VRAIN 1

SEQUOYAH 2 21 GINNA 1

LA SALLE 2 20 E.

I. HATCH 2 1

FORT CALHOUN 20 NORTH ANNA 1 i

i GRAND GULF 1 19 OYSTER CREEK 1

LA SALLE 1 17 POINT BEACH 2 1

l SAN ONOFRE 3 14 PRAIRIE ISLAND 2 1

BRUNSWICK 1 10 QUAD CITIES 2 1

SUSQUEHANNA 1 10 RANCHO SECO 1

DIABLO CANYON 1 9

ROBINSON 2 1

MCGUIRE 1 7

SURRY 1 1

BRUNSWICK 2 6

CALVERT CLIFFS 1 O

KEWAUNEE 6

CONNECTICUT YANKEE O

MAINE YANKEE 6

DRESDEN 2 0

PALISADES 6

DRESDEN 3 0

SUMMER 1 6

FARLEY 1 0

ARKANSAS NUCLEAR ONE 2 5

FARLEY 2 O

BROWNS FERRY 1 4

E.

I. HATCH 1 0

PEACH BOTTOM 2 4

HUMBOLDT BAY O

BROWNS FERRY 3 3

INDIAN POINT 2 O

D. C. COOK 1 3

MCGUIRE 2 O

CRYSTAL RIVER 3 3

MILLSTONE 1 0

4 TROJAN 3

NORTH ANNA 2 0

l TURKEY POINT 3 3

OCONEE 1 0

]

TURKEY POINT 4 3

OCONEE 2 O

i YANKEE ROWE 3

OCONEE 3 O

BEAVER VALLEY 2

PEACH BOTTON 3 0

u BROWNS FERRY 2 2

PILGRIM 1 0

CALLAWAY 2

POINT BEACH 1 O

FITZPATRICK 2

PRAIRIE ISLAND 1 O

I INDIAN POINT 3 2

QUAD CITIES 1 O

LACROSSE 2

SALEM 2 0

j MILLSTONE 2 2

ST. LUCIE 1 0

NINE MILE POINT 2

ST. LUCIE 2 O

SALEM i 2

SURRY 2 O

l SAN ONOFRE 1 2

THREE MILE. ISLAND 2 O

i SUSQUEHANNA 2 2

ZION 2 O

I THREE MILE ISLAND 1 2

VERMONT YANKEE 2

i ZION 1 2

1 32 w--

-m-------m-4-

e~.-v--.----

-,,,w.

,rv,,,m,,,y-

,,~v,,------,,v-w,-,-,-

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

vc -

--.-*ry--,y.e-

~ ~ ~ ~ - ~

=

v

~

TABLE A.2

.I i

ESF ACTUATIONS REPORTED BY COMERCIAL 1

U. S. NUCLEAR POWER PLANTS JA10ARY 1 1984 THROUGH JAE 30. 1984 DOCXET REPORT EVENT LMIT NAE IUSER IUSER DATE / TIE REACTOR (NSSS) VE M OR REACTOR TYPE 1.

ARKANSAS NUCLEAR OE 1 50-313 84-002 840316/2243 BABC0CX & WILCOX PRESSLIRIZED LIGHT MTER 2.

ARKANSAS MXLEAR DE 2 50-368 84-003 840130/0928 COMBUSTION ENG!

50-368 84-008 840312/1321 3.

4.

50-368 84411 840507/0126 5.

50-368 84-013 840617/1249 6.

50-368 84-014 840618/1334 7.

BEAVER VALLEY 50-334 84-002 840125/0305 ESTINGHOUSE PRESSURIZED LIGHT MTER 8.

50-334 84-004 840524/0239 9.

BIG ROCK POINT 50-155 84-005 840531/0125 GDERAL ELECTRIC BOILING LIGHT WATER 10.

5toletS FEMY 1 50-259 84-001 840103/2125 GEERAL ELECTRIC BOILING LIGHT WATER 11.

50-259 84410 840203/1215 50-259 84-011 840209/0928 12.

13.

50-259 84-023 840518/1700 14.

BR0latS FERRY 2 50-260 84-002 840121/0556 00ERAL ELECTRIC BOILING LIGHT WATER 15.

50-260 84-005 840525/1155 16.

BR0lelS FERRY 3 50-296 84-002 840125/2205 GEERAL ELECTRIC BOILING LIGHT WATER 17.

50-296 84-003 840129/1633 18.

50-296 84-007 840616/1000 19.

NUISWICK 1 50-325 84-004 840131/1500 GEMRAL ElICTRIC B0lLIl8) LIGHT WATER 20.

50-325 84-004 840301/1405 21.

50-325 84-004 840302/1850 22.

50-325 84-004 840309/1751 23.

50-325 84-004 840314/2300 a

4 24.

50-325 04-005 840501/0109 25.

50-325 84-006 840331/2J08 i

26..

50-325 84-007 840331/2308 27.

50-325 84-010 640625/1048 28.

50-325 84-010 840625/2214 29.

BRladSWICK 2 50-324 84-002 840129/0648 GENERAL ELECTRIC BOILING LIGHT WATER 30.

50-324 84-003 840214/1307 i

31,

' 50-324 84-004 840222/0158 32.

50-324 84-006 840504/1800 33.

50-324 84-006 840504/2359 l

34.

50-324 (50.72) 840!!8/1100 PRES $1RIZED LIGHT WATER t

35.

CALLAWAY 50-483 84-003 840615/0027 ESTINGHOUSE 36.

50-483 84-004 840617/1418 37.

CALVERT CLIFFS 2 50-318 84-003 840415/1020 COMBUSTION ENGIEERING PRES $UR 38.

D. C. COOK 1 50-315 84-006 840617/2034 ESTIN0 HOUSE PRESSLRIZED LIGHT WATER 39.

50-315 84-012 840623/2034

=

40.

50-315 (50.72) 840331/1235 1

41.

D. C. COOK 2 50-316 84-003 840311/1149 ESTINGHOUSE PRESSLRIZED LIGHT WATER 1

42.

50-316 84-003 840311/1849

=

43.

50-316 84-003 840311/2009 50-316 84 4 03 840311/2139 4.I 44.

50-316 84403 840317/0047 i

f 45.

46.

50-316 84-003 840317/0937

, J J

47.

50-316 84406 840405/1027 48.

50-316 84-006 840414/0440 50-316 84-006 840414/2205 1.

49.

50.

50-316 84-006 840416/0630 51.

50-316 84-006 840418/1906 52.

50-316 84-006 840421/1915 50-316 84-007 840411/2006 53.

54.

50-316 84-007 840412/0116 55.

50-316 84-007 840416/1210 56.

50-316 84-007 840420/2123 50-316 84-008 840419/0000 57.

58.

50-316 84-008 840424/1310 4

59.

50-316 84-010 840429/2214 60.

50-316 84-010 840501/2218 61.

50-316 84-011 840504/0647 62.

50-316 84-012 840508/1536 63.

50-316 (50.72) 840310/2315 50-316 (50.72) 840313/0708 64.

65.

50-316 (50.72) 840313/1147 66.

COOPER 50-298 84-002 840129/1948 OENERAL ELECTRIC BOILING LIGHT WATER 67.

CRYSTAL RIVER 3 50-302 84-003 840228/1039 BABCOCK & WILCOX PRES $URIZED LIGHT WATE 50-302 84-005 840312/1120 68.

69.

50-302 84-008 840424/1040 33

TABLE A.2 (CONTDAJED)

ESF ACTUATIONS - JAMJARY TMU JLDE 1984 DOCKET REP @T EVENT UNIT NAE Mf9ER Mf9ER DATE / TIE REACTOR (NSSS) VENDOR REACTOR TYFE 70.

DAVIS BESSE 1 50-346 84-003 840302/1221 BABCOCX 1: WILCOX PRESSURIZED LIGHT WATER 71.

DIABLO CANYON 1 50-275 84-001 840106/1415 WESTINGHOUSE PRESSURIZED LIGHT WATER 72.

50-275 84-003 840116/1440 73.

50-275 84-005 840116/1440 74.

50-275 84-007 840309/1916 75.

50-275 84-008 840315/0028 76.

50-275 84-009 840315/1356 77.

50-275 84-011 840330/1000 78.

50-275 84-015 840500/1304 79.

50-275 84-016 840521/1402 80.

DUAE ARNJLD 50-331 84-001 840107/0809 GENERAL ELECTRIC BOILING LIGHT WATER 81.

50-331 84-002 840103/1516 82.

50-331 84-003 840102/ 2 83.

50-331 84-003 840104/1728 84.

50-331 84-003 840106/0000 85.

50-331 84-003 840116/0010 86.

50-331 84-004 840110/2228 50-331 84-007 840127/0909 87.

88.

50-331 84408 840123/2247 89.

50-331 84-010 840204/2200 90.

50-331 84-011 840205/1043 91.

50-331 84-014 840416/1953 92.

50-331 84-017 840504/1000 93.

50-331 84-018 840507/1602 94.

50-331 84-019 840521/0507 95.

50-331 84419 840603/1750 96.

50-331 84-019 840605/0345 97.

50-331 84419 840606/0623 98.

50-331 84-020 840617/1707 99.

50-331 84-020 840617/1725 100.

50-331 84-020 840620/1643 101.

50-331 84-022 840619/1537 102.

50-331 84-024 840630/1333 103. 331 (50.72) 840423/2319 104.

50-331 (50.72) 840425/1850 105. FITIPATRICX 50-333 84-009 840322/0744 GEERAL ELECTRIC BOILING LIGHT WATER 106.

50-333 84-010 8%325/0423 107.

FORT CALK)lN 50-285 84-003 840314/1411 COMRJSTION ENGIEERING PRESSURIZED LIGHT WATER 108.

50-285 84-005 840116/0233 109.

50-285 84-005 840126/1245 110.

50-285 84-005 840216/1144 111.

50-285 84-005 840222/0408 112.

50-285 84-005 840223/0107 113.

50-285 84-005 840304/2250 114.

50-285 84-005 840305/2324 115.

50-285 84-005 840315/1950 116.

50-285 64-005 840406/1706

!!7.

50-285 84-005 840418/1115 118.

50-285 84-005 840418/1610

119, 50-285 84-005 840424/1343 120.

50-285 84-005 84424/1853 121.

50-285 84-005 840502/1901 4

122.

50-285 84-006 840522/0931 123.

50-285 84-007 8%516/1210 124.

50-285 150.72) 840315/0445 125.

50-285 (50.72) 8%429/2000 126.

50-285 (50.72) 840521/0535 127.

FT. ST. VRAIN 50-267 84-007 840529/1135 GENERAL ATOMIC HIGH TEffERATURE GAS 128.

GIWA 50-244 84-006 840522/1023 WESTINGH3)SE FRESSURIZED LIGHT WATER 129. GRAND Glt.F 1 50-416 84-001 840103/0920 GENERALELECTRIC BOILING LIGHT WATER 130.

50-416 84-001 840106/1355 131.

50-416 84-002 840114/0910 132.

50-416 84-003 840210/1030 133.

50-416 84-005 840119/1430 134.

50-416 84-006 840120/1050 50-416 84-011 840309/1329 135.

136.

50-416 84-015 840326/1124 137.

50-416 84-016 840324/0135 130.

50-416 84417 840409/1620 139.

50-416 84-018 840414/0208 1%.

50-416 84420 840423/1230 141.

50-416 84-020 8%423/1938 34

h e

TABLE A12 (CONTINLED)

ESF ACTUATIONS - JANUARY TM U JL E 1984 DOCKET HEPORT EVENT UNIT NAE NUr9ER MBER DATE / TIE REACTOR (NSSS) VENIOR REACTOR TYPE 142. GRAND GlLF 1 50-416 84-020 8%423/2120 GENERAL ELECTRIC B0ILING LIGHT W TER 143.

50-416 84-020 840424/1430 144.

50-416 84-020 840514/1705

=

145.

50-416 84-022 840420/1345

=

146.

50-416 84-027 840503/0058 147.

50-416 84-028 840507/2045 148.

E. I. HATCH 2 50-366 84-003 840115/ NR GENERAL ELECTRIC 90lLING1.10HT WTER 149.

IPGIAN POINT 3 50-286 84-001 840125/1828 ESTINGHOUSE PRESSURIZED LIGHT WATER 150.

50-286 84-003 840128/2015 PRESStRIZED LIGHT WATER 151. KEWAUDEE 50-305 84-004 840409/1015 ESTINGHOUSE 152.

50-305 84-005 840410/2130 153.

50-305 84-007 840420/0105 50-305 84-011 SM510/2342 154.

50-305 84-011 840511/0930

=

=

155.

50-305 84-012 840628/0915 157. LACROSSE 50-409 84-001 840107/1842 ALLIS-CHALERS BOILING LIGHT WATER 156.

158.

50-409 84-003 840220/0631 159. LA SALLE 1 50-373 84-004 840118/1120 00ERAL ELECTRIC BOILING LIGHT WATER 160.

50-373 84-011 840213/0044

=

161.

50-373 84-015 840227/1353

• * =

=

162.

50-373 84-017 840300/1700 163.

50-373 84-020 840327/0244 164.

50-373 84-022 840411/1905 165.

50-373 84-023 840415/1754

=

166.

50-373 84-028 840513/1640 167.

50-373 84-030 840531/1825 168.

50-373 84-030 840601/1733

=

169.

50-373 84-031 840615/0020 170.

50-373 84-032 840612/1432

=

171.

50-373 84-033 840624/1730 172.

50-373 84-040 840625/1030 173.

50-373 84-043 SM627/0510 174.

50-373 (50.72) 840303/1017 175.

~50-373 (50.72) 840516/0609 176. LA SALLE 2 50-374 84-004 840212/0707 GENERAL ELECTRIC BOILING LIGHT WATER

=

177.

50-374 84-006 840223/2130

=

=

178.

50-374 84-007 840218/0402

=

50-374 84-006 840229/1740 179.

=

50-374 84-009 840308/1750 180.

181.

50-374 84-010 840312/0600 182.

50-374 84-010 8M313/0818 183.

50-374 84-013 840403/1615

=

=

184.

50-374 84-016 840423/0810

=

185.

50-374 84-021 840515/2026 186.

50-374 84-023 840529/0051 r

i 187.

50-374 84-023 84 2 /1045

=

=

188.

50-374 84-023 840529/ W

=

=

189.

50-374 84-023 840529/ W 190.

50-374 84-026 840609/1028

=

=

191.

50-374 84-028 8 % 617/1202 h

192.

50-374 84-029 840611/0857

=

=

193.

50-374 84-029 840611/1930

=

194.

50-374 84-031 840622/1350

=

195.

50-374 84-032 840626/0043 196. MIE YA*EE 50-309 84-005 840529/1755 COMBUSTION EMINEERING PRESSlRIZED L

=

197.

50-309 84-006 840405/1540 198.

50-309 84-007 840413/0905 199.

50-309 84-007 840413/1450 50-309 84-007 840413/1450 200.

=

201.

50-309 (50.72) 840530/1200 202. MCGUIRE 1 50-369 84-005 840302/1115 WESTINGHOUSE PRES 5tRIZED LIGHT WATER

=*

=

203.

50-369 84-006 840305/0632 204.

50-369 84-010 840328/1725 205.

50-369 84-011 840329/0401 50-369 84-012 840330/1934 206.

207.

50-369 84-014 840420/1406 208.

50-369 84-017 840523/1655 209.

MILLSTONE 2 50-336 84-001 8M106/2324 CW9USTION EE INEERING FRESSURIZED LIG 50-336 84-001 840109/0900 210.

211. MONTICELLO 50-263 84-001 840101/1333 CENERALELECTRIC BOILING LIGHT WATER 212.

50-263 84-002 8M107/0830

=

213.

50-263 84-004 8M110/0850 35

1 1

TABLE 4,2 (CONillAED) f ESF ACTUATION 6 - JANUARY Tleu JBE 1984 l

DOCXET REPORT EVENT LMIT NAE LAAGER INGER DATE /TIIE REACTOR (NSSS) VENDOR AEACTOR TYPE 214. MONTICELLO 50-263 M-005.840112/1630 GEDERAL ELECTRIC BOILING LIGHT WATER I

i 215.

50-263 84-006 840119/1003 j

216.

50-263 84-009 840207/1033 217.

50-263 84-009 840215/2330 218.

50-263 84-009 840217/0530 219.

50-263 84-009 840220/0600 50-263 84-009 840307/2345 j

220.

50-263 84410 840217/0900 221.

50-263 M-010 840217/1300 222.

50-263 84412 840313/1230 223.

50-263 84413 840318/0620

)

224.

50-263 84413 840310/2314 225.

50-263 04-014 8#322/1325 4

2M.

i 50-263 04415 040325/1130 2".30-263 84-016 840408/1007 i

223.

50-263 M417 840425/0430 i

22h 1000 5 4 1l 8404 8 /1355

230, 50-263 232.

50-M3 4t 840 j

232.

50-263 M-020 840530/1625 50-263 84421 840#4/1319 233.

50-263 84422 84%05/2252 234.

50-263 84423 840621/01 #

i 235.

50-263 84-024 840627/1350 l

236.

i 237. Nile MILE POINT 5&220 M-006 840413/1450 (E183tAL ELECTRIC BOILING L10HT MTER 50-220 84-012 840#1/1000 238.

239.

NORTH A101A 1 SF338 84-002 840118/0900 lESTIIGEUE PRESSIAt! ZED L10HT WATER i

~

240. 0YSTER CIEEK 50-219 84-017 840627/1400 CEIERAL ELECTRIC BOILING LIGHT M TER i

i 241.

PALISADES 50-255 84-002 840401/1246 ColeUSTISI ENDIIEERING PfESS15tIZED LIGHT WA

?

242.

50-255 84-004 840408/1702 f

243.

50-255 04-004 840408/1714 50-255 M-005 840512/1735 244.

245.

50-255 84-007 84M22/0727 4

+

l 24.

50-255 84-007 84M23/1434 247.

PEACH BOTTOM 2

' 50-277 84-002 840321/0130 (EIERAL ELECTRIC BOILING LIGHT WATER i

240.

50-277 84-005 840323/1547 i

i 249.

50-277 84-007 840403/0915 250.

50-277 84-009 840516/1312 i

251. POINT BEACH 2 50-301 84403 840519/0341 lESTINGHOUE PflESS15tIZED LIGHT WATER l

252.

PRAIRIE ISLAle 2 50-306 84-401 840618/0740 IESTINGHOUSE 253.

QUAD CITIES 2 50-265 84-003 840211/0718 OEERAL ELECTRIC BOILING LIGHT WATER 254.

RANCHO SECO 50-312 84-015 840319/2251 BABC0CK & WILC0X PRESSURIZED LIGHT WATER j

255. II0BINSON 2 50-261 84-006 840621/1024 IESTilGWU6E PRESEURIZED LIGHT WATER 256.

SALEM 1 50-272 84-013 840602/0354 IESTINGHOUSE PHESSURIZED LIGHT WATER 257.

50-272 84-014 840605/0551 258.

SAN ONOFE 1 50-206 84-001 840215/0730 IESTINGHOUSE PflESSt#t! ZED LIGHT WATER 50-206 M402 840309/1003 i

259, j

260. SAN ONOF E 2 50-M1 M-002 840130/%50 CGleUSTION ENGIlEERING PRES $lat!IED LIGHT WATER 50 M1 M-002 840131/0655 261.

i i

262, 50-M1 84-002 840201/0755 l

50-El 94-002 840202/0730 263.

50-M1 M-002 840203/1605

[

2M.

50-361 M-003 840122/2100 265.

I 2%.

50 M1 84-004 840116/1059 i

50-Mi 84-004 840116/1993 l

267.

50-361 84-0 % 8#203/0000 268.

50-361 84-0 % 840203/0030 1

269.

• M1 M-0% 840203/0230 l

270.

50-M1 M-0% 840204/1Zio j

271.

272.

50-361 84406 840205/0321 50-361 84-006 840207/1315 273.

50-361 M4% 8#208/ift 274.-

50-361 84-0 % 840211/0413

}

275.

i 276.

50-M1 84 4 % 840214/1127 277.

50-Mi 84-006 840217/1137 50-M1 84 4 % 8#220/1650 278.

$>M1 M-006 840223/0710 l

279.

50 361 84-006 840226/1423 1

200.

281.

50-M1 84-006 840227/1400 282.

50-361 84-007 840203/0150 l

283.

50-M1 04-007 840204/0910 50-M1 84-011 8#225/2250 284.

i 50-Mi M412 840301/M19 25.

36 l

___.-__._____~_.;_

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

i i.

TAB 12 A.2 (CONTIMED)

ESF ACTWT10NS - JANUARY TMU JLSE 1984 I

D00ET IEPORT EVENT 1Al!T NAfE M#EER lt#8ER DATE /TifE lEACTOR (NSSS) VOSOR REACTOR TYPE 286. y 20FRE 2 50-M1 M412 840304/0012 COMuSTION ENGIEERING PRESSURIZG LIGHT WTB 287.

50-M1 84412 840307/0647 a

=

=

=

=

288-50-M1 84-012 840310/1717 a

=

=

=

=

?

289.

50- % 1 84-012 840314/%34

=

=

=

J 290.

=

• 50- % 1 84-012 840317/0610 a

=

50-%1 M412 840322/04 %

• =

=

=

l 291.

=

292.

50-361 84-012 840326/1218 50-361 M-012 840327/0918 1

293.

• =

=

=

294.

50-M1 84-012 840331/1638

=

=

=

50-361 84-016' 840309/1933

=

=

=

50-M1 84-01 4/1

=

i 50- % 1 8441 1

• =

d 298=

50-361 84-021 840330/1216

=

=

=

$0-%1 M 421 840405/0230 299.

=

=

t 50-361 M-021 840405/2343

=

300.

=

• 381.

• *~

50- % 1 84-021 840407/0118

=

=

=

302.

50-M1 84-021 840410/2020

=

303.

=

• a a

50-X1 84-021 840411/1207 304.

50-361 84421 840412/2154

= *

=

=

305.

50-%1 84-021 - 840415/1015

=

e 306.

50-361 84-021 840419/2028

=

=

=

307.

50- % 1 84421 840422/0814

• =

=

=

=

=

l 300.

50-M1 84421 840423/2245

=

=

a

=

309.

50-X1 84-022 840330/0226

=

e 310.

50-X1 M-022 840410/1906

=

=

=

311.

50-X1 84-022 840410/2020

• =

=

=

312.

50-M1 M-023 840524/0952

=

313.

50 M1 84-023 840527/0102

=

a

=

a

=

314.

50-361 M-023. 840527/0159 l

315.

50-361 84423 84%20/1606

=

a e

316.

l 50-361 M-023 840621/1130

=

=

=

317.

50- % 1 M-026 840427/1300

=

318.

50-361 84-026 840427/1314

=

=

319.

• 361 M-026 840430/2223

• =

=

=

i 1

320.

l 50-M1 M-026 840506/01 %

=

a 1

321.

W 361 84426 840511/0945 a

322.

l 30-361 84-026 M0516/1434

=

=

a 323.

50-361 M426 840521/1353 e

324.

50-%1 84426 840522/0953 a

a a

4 325.

30 361 M-029 84M14/0344

=

326.

a 50-M1 84432 840528/0920

=

=

327.

a 30-3g 34 032 840530/1123

=

=

=

328.

50-M1 84-032 840530/1425 a

a

=

329.

a 50-%1 84432 840531/1330 a

a l,

330.

50-361 84-032 840603/1822

=

=

=

331.

50-361 M-032 840607/0812

=

e 4>

332 50-361 84-032 84M14/0345 e

333'.

50-361 M-032 84%14/1336

=

=

334 50-M1 84-032 840618/1300 e

=

It 335' 50 M1 84-032 840619/1320

• =

=

a ll 3M-50-361 84-032 84%23/1524

=

337.

=

=

e ii 50-X1 84435 840625/1318 338.

50-361 84-037 840627/0545

=

e 339.

=

• 50-361 M-037 84%30/1620

= "

=

i 340.

50-361 (50.72) 840530/0410

=

=

=

=

j 341.

50-361 (50.72) 840509/1553

=

i

h. y y 3 50-362 84-004 840222/1940 COPSUSTION ENGIEGING PRES $URIZG l.IGHT W T s 50-362 84-000 840310/ W

=

e 344' 50-%2 84410 840424/1035

=

=

345.'

50-362 84410 840502/2100

=

344 50-362 84-010 840509/174 347' 50- % 2 84410 840509/17 %

= *

=

348.

l 50- % 2 84-010 840509/1955

=

a e

=

i j,

We 50 % 2 84-010 840510/1830

=

a

=

350.

50-362 84-010 840510/

j 351.

a 50-%2 84-010 840512/ M

352.

l 50-362 84410 840512/0820 a

a 353.

50-362 M-024 840611/1817 354.

l l 50-362 84-026 840612/0836 355.

50-362 (50.72) 840526/0816 e

=

g g ESTj @

PRESy!!ED 1.lGHT WTG I'

$0-37

~

TABLE A.2 (CONTIMED)

ESF ACTUATIONS - JAEIARY TIEU M 1984

~

DOCXET REPORT EVENT LMIT NAE NLMEER MAGER ' DATE / TIE REACTOR (NSSS) VENDOR REACTM TYPE l

358.

SEQUOYAH 1 50-327 84-001 840108/1025 ESTilGIQUSE PRESSURIZED LIGHT idATER 359.

50-327 84-001 840112/1546 360.

50-327 84401 840117/1744 361.

50-327 84-002 840112/0700 362.

50-327 84-002 840112/1020 363.

50-327 84-002 840118/1451 364.

50-327 84-003 840120/1939 365.

50-327 84-003 840129/1015 366.

50-327 84-004 840114/0055 367.

50-327 84-004 840114/0120 368.

50-327 84-006 8#124/1550 369.

50-327 84-008 840127/1000 370.

50-327 84-006 840127/1Cr20 371.

50-327 84-008 840130/1116 372.

50-327 84-008 840130/1147

=

373.

50-327 84-009 840128/0550 374.

50-327 84-010 840128/2130 375.

50-327 84-012 840201/0900 376.

50-327 84-012 840206/0100 377.

50-327 84-014 840214/0749 378.

50-327 84-014 840220/1500 379.

50-327 84-014 840301/0850 300.

50-327 84-015 840220/0052 381.

50-327 84-015 840221/1829 382.

50-327 84-016 840225/1330 383.

50-327 84-017 840227/0600 384.

50-327 84-017 840227/1332 385.

50-327 84-020 840309/0339 386.

50-327 84-020 840726/0854 387.

50-327 84-021 840322/0225 388.

50-327 84-021 840330/0219 389.

50-327 84-021 840331/0215 390.

50-327 84-021 840401/0624 391.

50-327 84-021 840403/0731 392.

50-327 84-022 840330/0730 393.

50-327 84-022 840409/0740 394.

50-327 84-027 8%420/1642

=

395.

50-327 84427 840425/1055 396.

50-327 84-027 840425/1116 397.

50-327 84-028 840411/2358

=

398.

$0-327 84-029 840507/1205 399.

50-327 84-029 840507/2341 400.

50-327 84-029 840508/0828 401.

50-327 84-035 840521/2234 402.

50-327 84-037 8 4 531/0444

=

403.

50-327 84-037 840602/1550 404 50-327 84-037 84604/2253 405.

50-327 84-039 840527/1950 406.

50-327 84439 840611/0543 407.

SEQUOYAH 2 50-328 84-001 840110/1535 ESTINGHOUSE PRESSURIZED LIGHT WATER 408.

50-328 84-001 840115/0241

=

409.

50-328 84-001 840116/0829 410.

50-328 84-001 840117/2335 411.

50-328 84-001 840121/1950

=

412.

50-328 84-002 840127/0123 413. 328 84-002 840127/1538

=

414.

50-328 84-002 840127/2025 415.

50-328 84-002 840129/0117 416.

50-328 84-002 840201/1714

=

417.

50-328 84-002 840208/2048 418.

50-328 84-003 840227/2028 419.

50 328 84-003 840301/1915 420.

50-328 84-004 8 4 326/0854 421.

50-328 84-004 840402/1026 422.

50-328 84-004 840403/0036 423.

50-328 84-006 840406/0!!0 424.

50-328 84-006 840400/0439 425.

50-328 84-009 840630/1543 426.

50-328 84-009 840630/1820 427.

50-328 150.72) 8 4 405/0730

=

428.

SLMMER 1 50-395 84-011 840210/0537 WESTINGHOUSE PRES $URIZED LIGHT WATER 429.

50-395 84416 840301/1935 38

_ __;~.------

TA8LE A>2 (CONTIltED)

ESF ACTUATIONS - JAMJARY TMlU J2E 1984 D00ET 'llEPORT EVENT UNIT NAE MAGER NUMlER DATE / TIE REACTOR (NSSS) vel @0R llEACTOR TYPE 430. SutER 1 50-395 84-017 840329/1750 ESTINGHOUSE PfiESSURIZED LIGHT MTER 431.

50-395 84-023 840417/1025 432.

50-395 84-026 840505/1929 433.

50-395 84-028 8#629/1720 434.

SUIRY 1 50-280 84-005 840301/2135 ESTINGHOUSE PRESSutIZED LIGHT MTER 435. SUSQlEHAI9141 50-387 84-007 8#202/0530 GEERAL ELECTRIC BOILING LIGHT W TER 436.

50-387 84-011 840301/ Mt 437.

50-387 84411 840308/1000 50-387 84-014 840305/1315 438.

439.

50-387 84-019 840415/1348 50-387 84-020 840321/0240 i

440.

441.

50-387 84-028 840613/1720 442.

50-387 (50.72) 840125/0156 443.

50-387 (50.72) 840128/0920 i

444.

50-387 (50.72) 8#131/1100 j

445.

SUSQLENAlelA 2 50-388 84-004 840501/0755 COERAL ELECTRIC BOILING LIGHT WATER 50-388 84-005 840515/1450 446.

447.

THIEE MILE ISLAls 1 50-289 84-002 840603/1155 BABC0CK 1 WILCOX PRESSLRIZED LICHT MTER 50-289 84-002 840630/0524 448.

449.

TH061AN 50-344 84403 840218/0445 ESTINGHOUSE PRESSut! ZED LIGHT ETER 450.

50-344 84-007 840428/1624

- 451.

50-344 84-011 840500/1632 452. TU8EY POINT 3 50-250 84-002 840108/0735 ESTINGHOUSE PRESSLRIZED LIGHT WATER 453.

50-250 84-006 840212/0638 454.

50-250 84-007 8M216/0925 455. TUllEY POINT 4 5& 251 84-004 840307/0238 lESTINGHOUSE PRESSURIZED LIGHT WATER

~

t 456.

50-251 84-006 840505/0318 1

457.

50-251 84-013 840624/0625 l

450. VERENT YAIGEE 50-271 84-001 840105/1252 GENERAL ELECTAIC BOILING LIGHT WTER 459.

50-271 84-004 840417/0742 l

460.

WASHINGTON MXLEAR 2 50-397 84-002 8M111/0840 GEERA. ELECTRIC B0ILING LIGHT WATER 50-397 84-002 840114/0605 461.

42.

' 50-397 84-002 840206/1811 50-397 84-005 840123/1025 463.

1 50-397 84-005 840208/1600 44.

50-397 84-014 840219/0500 465.

50-397 84-015 840307/1410 466.

50-397 84-016 840317/0600 47.

50-397 84-017 840318/1045 48.

a 50-397 84418 840306/1358 469.

4 50-397 84-019 840308/0112 1

470.

50-397 84-022 840319/1415 i

471.

50-397 84-024 840317/0950 472.

50-397 84-025 840319/0610 j

473.

50-397 84-030 840412/0524 474.

54 397 84-033 840412/0213 -

475.

50-397 84-033 - 840418/0345 476.

477.

50-397 84-033 840419/1622 478.

50-397 84435 840420/0756 50-397 84-039 840426/1955 479.

480.

50-397 84-046 840520/1141 50-397 84449 840522/2105 481.

482.

50-397 84-050 840526/1845 483.

50-397 84-052 840528/1612 50-397 84-053 840528/1057 i

404.

485.

50-397 84-054 84529/1231 i

486.

50-397 84-055 840528/1057

)

467.

50-397 84-057 8%605/0034 50-397 84-057 840612/1705 488.

489.

50-397 84-058 840607/1548 i

50-397 84-063 840617/0430 490.

50-397 84-064 840623/1932 491.

50-397 84464 840623/2132 i

492.

493, 50-397 84-066 840620/1332 l

494.

50-397 84-067 840620/1810 50-397 84-068 840628/1029 495.

50-397 84-069 840628/2124 i

496.

497.

YANKEE R0WE 50- 29 84-003 840403/1056 ESTINGHOUSE PRESSURIZED LIGHT ETER

498, 50- 29 84-008 840503/1415 50- 29 84-009 840510/1010 i

499.

500.

ZION 1 50-295 84-002 840102/1539 ESTINGHOUSE PRESSut!!ED LIGHT M TER 501.

50-295 84-004 8%120/0912 39

^

-m--,e-.eg,-,--g g--+-2-g-uc-9.--vv-9.e.. * >- -

e-esi--

g-.--4-4g9-wp*,,

w,-.+-*-----+--%m m

y-

--e~y-*yw

-,-3,-

>-y+g---*'t='v'-

Tw***vM*'--#-*1w---

--*--9t'*'

w... 2.

TABLE A.3 VALID (DESIGN BASIS) ESF ACTUATIONS D00(ET NSSS REPORT EVENT EASURED ESF SYSTEM LMIT(S)

MNER VEM)0R MMIER DATE / TIE PARAETER FtMCTION*

REASON 1.

GRA E OLAF 1 50-416 GE 84-027 840503/0058 LOSS OF POER POER (DG)

STORM 2.

MCalIRE 1 (2) 50-369 EST 84-006 840305/0632 LOSS OF POER POER (DG)

LINE FALLT.

3, MC0UIE 1 50-369 EST 84-010 840328/1725 LOSS OF POER POER (DG)

STORM 4.

MONTICELLO 50-263 GE 84-010 840217/0900 T0XIC GAS IWAC (CR)

OLORIE RELEASE 5.

MONTICELLO 50-263 GE 84-010 840217/1300 TOIIC GAS HVAC (CR)

OLORIE RELEASE 6.

SAN ONOFE 1 (2.3) 50-206 EST 84-401 840215/0730 TOIICGAS HVAC (CR)

TEAR GAS 7.

SEGUDYAH 1 50-327 EST 84-006 840124/1550 RADIATION ISCLATION (AB) WASTE GAS M ING 8:, ' SEQUOYAH 1 50-327 EST 84-006 840127/1000' RADIATION ISOLATION (AB) WASTE GAS VENTING 9.

SEQUDYAH 1 50-327 EST 84-006 840127/1020 RADIATION ISOLATION (AB) WASTE GAS VENTINC 10, SEQUOYM 1 50-327 EST 84-006 840130/1116 RADIATION ISOLATION (AB) WASTE EVAPORATOR SPILL 11.

SEQUOYAH 1 50-327 EST 84-000 840130/1147 RADIATION ISCLATION (AB) WASTE EVAPORATOR SPILL 12.

SEQUOYM 1 50-327 EST 009 840128/0550 RADIATION ISOLATION (AB)

INSTRitENTATION VALVE (PRESSURIZER) LEAK W = AUIILIARY BUILDING CR = CONTROL ROOM CV = CONTA! MENT YENTILATION 00 = DIESEL GEERATOR l

l I

40

\\

TABLE A.4 YALID (NON-DESIGN BASIS) ESF ACTUATIONS DOCKET NSSS REPORT EVENT EASLRED ESF SYSTEM IMIT(S)

NLM ER VENDOR NUMBER DATE / TIE PARAETER FUNCTION

• REASON 1.

BR0lMS FERRY 2 50-260 GE 84-002 840121/0556 LEVEL FLUID UFCI) - LOW LEVEL AFTER REACTOR ISOLATION (MS)

SCRAM 2.

BRLMSWICK 1(2) 50-325 GE 84-004 840131/1500 FIRE PROTECTION HVAC (CB)

PAINTING FUES 3.

BRUNSWICX 1(2) 50-325 GE 84-004 840302/1850 FIRE PROTECTICM HVAC (CB)

COOKING FlfES 4.

BALMSWICK 1 50-325 GE 84-006 840331/2300 LEVEL FLUID OPCI)

LOW LEVEL AFTER REACTOR ISOLATION (PCIS)

SCRAM 5.

BRIMSWICK 2 50-324 GE 84-004 840222/0150 (NOT DEFIED)

FLUID OPCI)

LOW LEVEL AFTER REACTOR ISOLATION (PCIS)

SCRAN POER (DG) 6.

D. C. COOK 1 50-315 EST 84-012 S40623/2034 RADIATION ISOLATION (CV)

SETPOINT 4 BACKGROUND 7.

D. C. COOK 2 50-316 EST 84-006 840405/1027 RADIATION ISOLATION (CP)

TRASH EXT TO MONITOR i

8.

D. C. COOK 2 50-316 EST 84-006 840414/2205 RADIATION ISOLATION ( T )

UPPER INTERNALS REMOVAL 9.

D. C. COOK 2 50-316 EST 84-006 840416/0630 RADIATION ISOLATION (CP)

REFUEL PIT WATER L0ERING 10.

D. C. COOK 2 50-316 EST 84-006 840418/1906 RADIATION ISOLATION (CP)

VENTILATION OFF 11.

D. C. COOK 2 50-316 EST 84-006 840421/1915 RADIATION ISOLATION (CP)

REFLEL PIT WATER L0ERING

- 12.

D. C. COOK 2 50-316 EST 84-007 840411/2006 RADIATION ISOLATION (CP)

SETPOINT e BACKGROLM) 13.

D. C. COOK 2 50-316 EST 84-007 840412/0116 RADIATION ISOLATION (CP)

SETPOINT t BACXGROUND 14.

D. C. COOK 2 50-316 'EST 84-007 840416/1210 RADIATION ISOLATION (CP)

SETPOINT t BACKGROLN) j j

15, D. C. COOK 2 50-316 EST 84-007 840420/2123 RADIATION ISOLATION (CP)

SETPOINT t BACXGROLND i

l 16.

D. C. COOK 2 50-316 EST 84-010 840429/2214 RADIATION ISOLATION (CP)

SETPOINT t BACKGROUND 17.

D. C. COOK 2 50-316 EST 84-010 840501/2218 RADIATION ISOLATION ( 7 )

SETPOINT t BACXGROLMD 18.

FITIPATRICX 50-333 GE 84-009 840322/0744 LEVEL FLUID UPCI)

LOW LEVEL AFTER ISOLATION (PCIS)

REACTOR SCRAM 19.

FITZPATRICK 50-333 GE 84-010 840325/0423 LEVEL FLUID OfCI)

LOW LEVEL AFTER j

ISOLATION (PCIS)

REACT (R SCRAM 20.

FORT CALHOLN 50-285 E

84-005 840116/0233 RADIATION ISOLATION (CP)

ATM0$PERIC INVERSION HVAC (CR)

)

21.

FORT CALHolm 50-285 E

84-005 840126/1245 RADIATION ISOLATION (CP)

SPENT FLEL POOL HVAC (CR)

WATER TRANSFER 22.

FORT CALB0l*

50-285 E

84-005 840216/1144 RADIATION ISOLATION (CP)

ATMOSPHERIC INVERSION HVAC (CR) 23, FORT CALHOLM 50-285 E

84-005 840222/0408 RADIATION ISOLATION (CP)

ATMOSPHERIC INVERSION HVAC (CR) 24.

FORT CALN0lm 50-285 E

84-005 840223/0107 RADIATION ISOLATION (CP)

ATMOSPERIC INVERSION HVAC (CR)

L 25.

FORT CALNOLN 50-285 E

84-005 840304/2250 M)lATION ISOLATION (CP)

CONTAIMENT PURGING hVAC (CR)

DLRING REFUELING 26.

FORT CM.HOLN 50-285 E

84-005 840305/2324 RADIATION LK)LATION (CP)

CONTADfENT PlRGING HuAC (CR)

DLRING REFlELING 27.

FORT CALHOLN 50-285 E

84-005 84M15/1950 P.%IATION ISOLATION (CP)

CONTAINENT PURGING NVAC (CR)

DURING REFUELING 28.

FORT CMBOLN 50-285 84-005 840406/17 % RACIATICH ISOLATION (CP)

CONTAIMENT PlRGING HVAC (CR)

DLRING REFLELING 29.

FORT CALH0lM 50-285 E

84-005 840418/1115 RADIATION ISCLATICN (CP)

LOOSE PARTICIA.ATES HVAC KR)

DURING REFUELING 30.

FORT CMMOLN 50-285 E

84-007 840516/1210 RADIATION ISOLATION (CP)

RELIEF VALVE DISCHARGE HVAC (CR)

TOSWP 31.

GRAND CLLF 1 50-416 GE 84-020 M0423/1230 R0W ISOLATION (PWCU) FEEDWATER OSCILLATIONS 32.

GRAM)Oltf I 50-416 CE 84-020 540423/1939 FLOW ISCLATION ( W CU) FEEDhATER OSCILLATIONS 33.

GRAND OULF 1 50-416 GE 84420 640423/2120 FLOW ISOL4T10N (RWCLI) FEEDLATER OSCILLATIONS 34.

GRAM)GLLF 1 50-416 GE 84-020 840424/1430 FLOW IRILATION (PKU) FEEDWATER OSCILLATIONS 35.

GRAM) 01151 50-416 GE 84420 840514/1705 FLOW ISOLATION (RWCU) TEEDWATER OSCILLATIONS 41

m

==

t TABLE A.4 (CONTINUED)

VALID (NON-DESIGN BASIS) ESF ACTUATIONS DOCKET NSSS REPORT EVENT EASURED ESF SYSTEN LMIT(S)

EMBER VEEOR WMBER DATE / TIE PARAMETER FlNCTION+

REASON 36.

LA SALLE 1 50-373 E

84-030 840531/1825 R0W IS0lATION (RWCU) RUID ENSITY VARIATIONS 37.

LA SALLE 1 50-373 GE 84430 840601/1733 R0W ISOLATION (RWCU) RUID DENSITY VARIATIONS 38.

LA SALLE 1 50-373 GE 84-031 840615/0020 TENPERAM ISOLATION (RWCU) VENTILATION OFF 39.

LA SALLE 1 50-373 GE 84-032 840612/1432 R0W ISOLATION (RWCU) FILLING (iVENTING i

40.

LA SALLE 1 50-373 GE 84-033 840624/1730 R0W ISOLATION (RWCU) RUID DENSITY VARIATICNS 41.

LA SALLE 1 50-373 GE 84-040 84M25/1030 R0W ISOLATION (RWCU) RUID DENSITY VARIATIONS 42.

LA SALLE 1 50-373 GE (50.72) 840303/1017 CONDENSER VACULM/ ISOLATION (MSIV) HYDROSTATIC TESTING REACTOR PRESSLEE 43.

LA SALLE 2 50-374 GE 84-006 840223/2130' TEN ERA N ISOLATION (RWCU) VENTILATION CLRRENTS 44.

LA SALLE 2 50-374 GE 84-007 840218/0402 TEWERA M ISOLATION (RWCU) VENTILATION CLRRENTS l

45.

LA SALLE 2 50-374 GE 84410. 840312/0600 TEWERA M ISOLATION (RWCU) YENTILATION CLRRENTS 46.

LA SALLE 2 50-374 GE 84-010 840313/0818 TEWERATlRE ISOLATION (RWCU) VENTILATION CURRENTS 47.

LA SALLE 2 50-374 GE 84-021 840515/2026 FLOW ISOLATION (RWCU) BACXROW t MAINTENANCE C.

LA SALLE 2 50-374 GE 84-029 840611/0057 R0W ISOLATION tRWCU) RUID DENSITi VARIATIONS 49.

LA SALLE 2 50-374 GE 84-029 84%11/1930 R0W ISOLATION (RWCU) RUID DENSITY VARIATIONS 50.

NIE MILE POINT 50-220 CE 84412 84 % 01/1000 LOSS OF POER POER (DG)

VOLTAGE DRCPS DLRING BACKFEEDING 51.

SAN ONOFRE 2 50-361 CE 84-003 840122/2100 RADIATION ISOLATION (CP)

SETPOINT t BACKGROUND 52.

SAN ONOFRE 2(3) 50-361 E

84-006 840203/0008 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 53.

SAN ON0FRE 2(3) 50-361 3

84-006 840203/0030 TOI!C GAS HVAC (CR)

SETPOINT 4 BACKGROUND 54.

SAN ONOFRE 2(3) 50-361 E

84-006 840203/0220 TOIIC GAS HVAC (CR)

SETPOINT t BACKGROLM) 55.

SAN ON0FRE 2(3) 50-361 E

84-006 840204/1230 TOIIC GAS HVAC (CR)

SETPOINT t BACKGROUM) 56.

SAN ONOFRE 2(3) 50-361 E

84-006 840205/0321 T0XIC GAS HVAC (CR)

SETPOINT e BACKGROUND 57.

SAN ON0FRE 2(3) 50-361 E

84406 840207/1315 TOI!C GAS HVAC (CR)

SETPOINT 4 BACKGROUND 58.

SAN ONOFRE 2(3) 50-361 E

84-006 840208/ Mt TOIIC GAS HVAC (CR)

SETPOINT t BACKGROLN) 59.

SAN ONOFRE 2(3) 50-361 E

84-006 840211/0413 TOIlc GAS HVAC (CR)

SETPOINT e BACKGR0lND 60.

SAN ONCfRE 2(3) 50-361 E

84-006 840214/1127 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROLND 61.

SAN ON0FRE 2(3) 50-361 E

84-006 840217/1137 T0!!C GAS HVAC (CR)

SETPOINT 4 BACKGROUND 62.

SAN ONOFRE 2(3) 50-361 E

84-006 840220/1650 T0!!C GAS HVAC (CR)

SETPOINT t BACKGROLND 63.

SAN ON0FRE 2(3) 50-361 E

84-006 840223/0710 TOIIC GAS E (CR)

SETPOINT t BACKGROUND 64.

SM CN0FRE 2(3) ' 50-361 E

84-006 840226/1423 T0XIC GAS HVAC (CR)

SETPOINT t BACK0R0lN) 65.

SAN ONOFRE 2(3) 50-361 E

84-006 840227/1400 T0XICGAS WAC (CR)

SETPOINT t BACKGROUND l

66.

SAN CN0FE 2(3) 50-361 E

84-012 840301/0619 TOIICGAS HVAC(CR)

SETPOINT t BACKGROUND 67.

SAN ON0FRE 2(3) 50-361 E

84-012 840304/0012 TOIIC GAS HVAC (CR)

SETPOINT t BACKGROUND i

68.

SAN ONOFRE 2(3) 50-361 E

84-012 840307/0647 TOIICGAS HVAC (CR)

SETPOINT t BACKGROLMD 69.

SAN ON0FRE 2(3) 50-361 E

84412 840310/1717 TOIIC GAS HVAC (CR)

SETPOINT t BACKGROLMD 70.

SAN ON0FRE 2(3) 50-361 E

84412 840314/0634 T0XIC GAS HVAC (CR)

SETPOINT 4 BACKGR0lND 71.

SAN ONOFRE 2(3) 50-361 E

84-012 840317/0610 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 72.

SAN ONOFRE 2(3) 50-361 E

84-012 840322/0406 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROLN) 73.

SAN ON0FRE 2(3) 50-361 E

84-012 840326/1218 TOIIC GAS HVAC (CR)

SETPOINT t BACKGR0lND 74.

SAN ON0FRE 2(3) 50-361 E

84-012 840327/0918 T0XICGAS HVAC (CR)

SETPOINT t BACKGROUND 75.

SAN ON0FRE 2(3) 50-361 CE 84-012 840331/1638 TOIIC GAS HVAC (CR)

SETPOINT 4 BACKGROLND 76.

SAN ON0FE 2(3) 50-361 E

84421 840330/1216 TOIIC CAS

. HVAC (CR)

SETPOINT t BACKGROLND 77.

SAN ONOFE 2(3) 50-361 E

84-021 840405/0230 T0!!CCAS HVAC (01)

SETPOINT t BACKGROUM) 78.

SAN ON0FE 2(3) 50-361 E

84-021 840405/2343 T0XIC GAS HVAC (CR)

SETPOINT 4 BACKGROUND 79.

SAN ONOFE 2(3) 50-361 E

84-021 840407/0118 TOIIC GAS HVAC (CR)

SETPOINT t BACKGROUND 80.

SAN ONOFE 2(3) 50-361 E

84-021 840410/2020 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 01.

SAN ON0FRE 2(3) 50-361 E

84-021 840411/1207 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 82.

3M ONOFE 2(3) 50-361 E

84-021 840412/2154 TOIIC GAS HVAC (CR)

SETPOINT e BACKGROLN) 83, SAN (N0FRE 2(3) 50-361 E

84-021 840415/1015 T0XIC CAS HVAC (CR)

SETPOINT t BACKGROLND 42

TABLE A.4 (CONTINUED)

VALID (NON-DESIGN BASIS) ESF ACTUATIONS DOCET NSSS REPORT EVENT EASlRED ESF SYSTEM LMIT(S)

M BER VENDOR M BER DATE / TIE PARAETER FUNCTION

• REASON 84.

SM ONOFRE 2(3) 50-361 CE 84-021 840419/2028 T0XIC GAS HVAC (CR)

- SETPOINT t BACKGROUND 85.

SAN ON0FRE 2(3) 50-361 E

84-021 840422/0814 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 86.

SAN ONOFRE 2(3) 50-361 E

84421 840423/2245 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 87.

SAN ON0FRE 2(3) 50-361 E

84-026 840427/1300 T0!!C GAS HVAC (CR)

SETPOINT t BACK0ROLN) 88.

SAN ONOFRE 2(3) 50-361 E

84-026 840427/1314 TOIIC GAS HVAC (CR)

SETPOINT 4 BACKGR0tMD 89.

SAN ON0FRE 2(3) 50-361 E

84-026 840430/2223 T0XIC GAS HVAC (CR)

SETPOINT t BACK0 ROUE 90.

SM CN0FRE 2(3) 50-361 E

84426 040506/01 % TOIIC GAS WAC (CR)

SETPOINT t BACKGROUND 91.

SAN ONOFRE 2(3) 50-361 E

84-026 840511/0945 T0XIC GAS HVAC (CR)

SETPOINT t BACK0R0lMD 92.

SAN ON0FRE 2(3) 50-361 E

84-026 840516/1434 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROLND 93.

SAN ONOFRE 2(3) 50-361 E

84-026 840521/1353 TOIIC GAS HVAC (CR)

SETPOINT t BACKGROUND 94.

SAN ONOFRE 2(3) 50-361 E

84426 040522/0953 T0XICGAS HVAC (CR)

SETPOINT 4 BACKGRGMD 95.

SAN O EFRE 2(3) 50-361 E

84-032 840528/0920 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROLND 96.

SAN ONOFRE 2(3) 50-361 E

84-032 840531/1330 T0XIC GAS HVAC (CR)

SETPOINT t BACK0ROLN) 97.

SM OEFRE 2(3) 50-361 E

84-032 840603/1822 T0!!CGAS HVAC (CR)

SETPOINT t BACKGROLMD 98.

SAN ON0FE 2(3) 50-361 CE 84-032 840607/0012 T0XICGAS HVAC (CR)

SETPOINT t BACKGROLN)

- 99.

SAN ONOFRE 2(3) 50-361 E

84-032 840414/0345 TOIIC GAS HVAC (CR)

SETPOINT t BACK0ROU E 100.

SAN ONOFRE 2(3) 50-361 E

84-032 840614/1336 T0XIC GAS HVAC (CR)

SETPOINT 4 BACKGROLND 101.

SM ON0FRE 2(3) 50-361 E

84H)32 840618/1300 T011C GAS HVAC (CR)

SETPOINT t BACKGROLMD 102.

SAN ON0FRE 2(3) 50-361 E

84-032 840619/1320 T0XIC GAS HVAC (CR)

SETFOINT t BACKGROUND 103.

SAN ON0FRE 2(3) 50-361 CE 84-032 840623/1524 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 104.

SM CN0FRE 2 50-361 CE 84-035 840625/1318 RADIATION ISOLATION (CP)

STEM CENERATOR M M AY REMOVAL 105.

SAN ON0FE 2(3) 50-361 CE 84-037 840627/0545 T0XIC GAS HVAC (CR)

SETPOINT t BACKGROUND 1E SAN ONCFRE 2(3) 50-361 CE 84437 840630/1620 TOIIC GAS HVAC (CR)

SETPOINT t BACKGROUND 107.

SEQUOYAH 1 50-327 EST 84-016 840225/1330 RADIATION ISOLATION (AB)

TRASH EXT TO MONITOR 108.

SEQUOYAH 1 50-327 WEST 84-017 840227/0600 RADIATION ISOLATION (CV)

STEM CENERATOR MANWAY REMOVAL 109.

SEQUOYAH 1 50-327 WEST 84-017 840227/1332 RADIATION ISOLATION (CV)

STEM GEERATOR MANWAY REMOVAL 110.

SEQUOYAH 1 50-327 WEST 84-021 840322/0225 RADIATION ISOLATION (AB)

TRASH EXT TO MONITOR 111.

SEQUOYAH 1 50-327 WEST 84-021 840330/0219 RADIATION ISOLATION (AB)

TRASH NEIT TO MONITOR 112.

SEQUOYAH 1 50-327 WEST 84-021 840331/0215 RADIATION ISOLATION (AB)

TRASH EXT TO MONITOR 113.

SEQUOYAH 1 50-327 WEST 84-021 840401/0624 RADIATION ISCLATION (AB)

TRASH EXT TO MONITOR 114.

SEGUOYAH 1 50-327 EST 84-021 840403/0731 RADIATION ISOLATION (AB)

TRASH EXT TO MONITOR 115.

SEQLOYAH 1 50-327 WEST 84-029 840507/2341 RADIATION ISOLATION (AB)

SETPOINT t BACKGROUND 116.

SEQUOYAH 1 50-327 EST 84-029 840500/0828 RADIATION ISOLATION (AB)

SETPOINT t BACK0R0lMD 117.

SEQUOYMi 1 50-327 WEST 84-037 840531/0444 RADIATION ISOLATION (AB)

SETPOINT t BACKGROUND 118.

SEQUOYAH 1 50-327 EST 84-037 840602/1550 RADIATION ISOLATI(M (AB)

SETPOINT t BACKGR0lMD 119.

SEQUOYAH 1 50-327 WEST 84437 840604/2253 RADIATION ISOLATION (AB)

SETPOINT t BACKGROUND 120.

SEQUOYNI2 50-328 EST (50.72) 840405/0730 RADIATION ISOLATION (CV)

OECK SOURCE t MONITOR 121.

SUPfER 1 50-395 IEST 84411 840210/0537 PRESSURE MULTIPLE (ND)

HIGH STEM LIE PRESSORE FLUID (E )

FTER REACTOR SCRM 122.

SUSQUEHAPNA 1 50-387 GE 84-020 840321/0240 FLOW ISOLATION (M) EXCESSIVE Ptw FLOW 123.

SUSQUEH M A 1(2) 50-387 GE 84-028 840613/1720 LOSS OF POWER POWER (DG)

YOLTAGE TRANSIENT DUE HVAC (SBOT)

TO LIGHTNINO 124.

TUREY POINT 4 50-251 WEST 84-013 840624/ % 25 PLMP RlNi!NO FLUID (AFW)

FEEDWATER TRANSIENT 125.

WFfSS 2 50-397 E

84-033 840412/0213 TEPFEPATURE ISOLATICN (RWCU) SETPOINT t BACKGROLN) 126.

WPSS 2 50-397 GE 84-033 840418/0345 TElfERATURE ISOLATION (RWCU) SETPOINT t BACKGR0lMD 127.

WPSS 2 50-397 GE 84-033 840419/1622 TEPFERATlRE ISOLATI(N (RWCU) SETPOINT t BACKGROUND 128.

WPSS 2 50-397 CE 84-035 840420/0756 FLOW ISOLATION (RWCU) EXCESSIVE FLOW DLRINO SYSTEM REALICNENT 43

TABLE A.4 (CONTIMED)

VALID (NON-DESIGN BASIS) ESF ACTUATIONS D00(ET NSSS REPORT EVENT EASURED ESF SYSTEM LMIT(S)

IUEER VENDOR MMER DATE / TIE PARAETER RMCTIONe REASON '

129.

YAM (EE ROE 50- 29 EST 84-006 840503/1415 LOSS OF PO E POER (DG)

V0LTAGE LOSS DlRING

~

PCMER TRANSFER 130.

ZION 1 50-295 EST 84-002 840102/1539 PRESSLRE FLUID (E).

LOW PRESSLRIZER PRESSURE HYAC (RS) lDELOCKED DLRING TEST ISOLATION (M)

POER (DG) 131.

ZION 1 50-295 EST 84-004 840120/0912 PESSLRE ltLTIPLE (2)

LOW PRESSlRIZER PRESSURE FLUID ( E )

I,DELOO(ED DURING TEST

1. AB = AUIILIARY BUILDING WCI = HIGH PRESSURE C00UWT INICTION M) = NOT DEFIED CB = CONTRCL BUILDING WI = HIGH PRESSLRE INICTION PCIS = PRIMARY C0(LANT ISOLATION SYSTEM CP= CONTAllfENT PlRGE M

= MLLTIPLE IHt = ESIDUAL EAT REMOVAL CR = CONTROL ROOM MS = MIN STEAM RWCU = RAW WATER CLEAMP CV a CONTAlffENT VENTILATION MSIV = MIN STEAM ISOLATION VALVE SBOT = STAMBY GAS TREAT!ENT

_ DG = DIESEL GEERATOR e

e 44

...=..-

TABLE A.5 ESF ACTUATIONS - HEATING AND VENTILATION SYSTEMS SYSTEM NAMES AUXILIARY ~ BUILDING GAS TREATMENT AUXILIARY BUILDING SPECIAL VENT 4

l AUXILIARY BUILDING VENTILATION CONTROL BUILDING EMERGENCY AIR FILTRATION CONTROL BUILDING VENTILATION - STANDBY FILTRATION UNIT CONTROL ROOM CLEANUP AND PRESSURIZATION CONTROL ROOM EMERGENCY AIR CLEANUP CONTROL ROOM EMERGENCY AIR TREATMENT CONTROL ROOM EMERGENCY FILTRATION CONTROL ROOM EMERGENCY OUTSIDE AIR SUPPLY CONTROL ROOM FRESH AIR CONTROL ROOM HEATING, VENTILATION AND AIR CONDITIONING CONTROL ROOM VENTILATION EMERGENCY FILTRATION TRAIN (CONTROL ROOM HEATING, VENTILATION AND AIR CONDITIONING)

SHIELD BUILDING VENT STANDBY GAS TREATMENT s

9 4

a l

l 45 I.

1 TABLE A.6 l

FALSE ESF ACTUATIONS DOCKET NSSS REPORT EVENT EASWED BASIC WIT (S)

NLMBER VENDOR NUMER DATE / TIME PARAMETER FUNCTION

• CAUSE ACTIVITY 1.

ARKANSAS 1 50-313 BW 84-002 640316/2243 LN(NOWN RUID (EFW) -

LN(NOWN OPEMTION 2.

ARKANSAS 2 50-368 84-003 840130/0928 PRESSWE ISOLATION (MS)

FERSONNEL OPEMTION EQUIPENT 3.

ARKANSAS 2 50-368 E

84-008 840312/1321 LEVEL RUID (EFW)

DESIGN OPERATION 4.

ARKANSAS 2 50-368 E

84-011 840507/0126 LEVEL RUID (EFW)

PER$0MEL OPERATION 5.

ARKANSAS 2 50-368 E

84-013 840617/1249 LEVEL RUID (EFW)

(N(N0lm CPERATION 6.

ARKANSAS 2 50-368 E,84-014 840618/1334 LEVEL RUID (EFW)

MANUAL OFERATION 7.

BEAVER VALLEY 50-334 EST 84-002 840125/0305 MMJAL MLLTIFtE (ND)

FERSONNEL MINTENANL 8.

BEAVER VALLEY 50-334 EST 84-004 840524/0239 LOSS OF POER POER (DG)

(NGON OPERATICH 9.

BIG ROCK POINT 50-155 GE 84-005 840531/0125 MANUAL ISOLATION (MS)

EQUIFTENT OPEMTION 10.

BROWNS FERRY 1 50-259 GE 84-001 840103/2125 MANUAL RUID (RM)

FERSOMEL MINTENAM BROWNS FERRY 1 50-259 GE 84-010 840203/1215 RADIATION ISCLATION (PCIS)

EQUIFtENT OPEMTION 12.

BR0lMS FERRY 1 50-259 E

84-0!! 840209/0928 R0W ISG.ATION (PCIS) MAMJAL TESTING EQUIPMENT 13.

BR0lMS FERRY 1 50-259 E

84-023 8@518/1700 LOSS OF P0lER ISOLATION (PCIS)

PERS0MEL MINTENAM 14.

BROWNS FERRY 2 50-260 CE 84-005 840525/1155 (NOT DEFIED)

RUID (M)

PRO DLRE TESTING 15.

BR0lNS FERRY 3 50-296 E

84-002 8M125/2205 (NOT DEFIED)

ISOLATION (M)

EQUIPMENT OPEMTION 16.

BRC6MS FERRY 3 50-296 SE 84-003 840129/1633 LOSS OF P0lER POER (DG)

EQUIPMENT-0FEMTION 17.

BROLMS FERRY 3 50-296 E

84-007 8%616/1000 00T EFIED)

POWCR (DG)

PERSONNEL MINTENAM PROCEDURE 18.

BRLNSWICX 1(2) 50-325 GE 84-004 840301/1405 FIRE DETECTION HVAC (CB)

SPURIOUS OPEMTION 19.

BRUNSWICX 1(2) 50-325 GE 84-004 840309/1751 FIRE DETECTION HVAC (CB)

SPtRIOUS OPERATION 20.

BRlNSWICK 1(2) 50-325 GE 84-004 840314/2300 FIRE ETECTION HVAC (CB)

SPURIOUS OPEMTION 21.

BRtNSWICK 1(2) 50-325 C

84-005 840501/0109 FIRE DETECTION HVAC (CB)

EQUIPENT CPERATION 22.

BRlNSWICX 1 50-325 CJ 34-007 840331/2308 PRESSURE ISCLATION (FCIS)

LN(N0lN OPEMTION 23.

BRUNSWICX 1(2) 50-325

'A G-010 840625/1048 FIRE IETECTION HVAC (CB)

SFURIOUS MINTENAN 24.

BRtNSWICX 1(2) 50-325 E

84-010 840625/2214 FIRE DETECTION HVAC (CB)

EQUIPMENT OFERATION 25.

BRtNSWICX 2(1) 50-324 E

84-002 8#129/0648 LOSS OF POER ISOLATICN (PCIS)

PER$0MEL MINTENAN POWER (D0) 26.

ERUNSWICA ill) 50-324 E

84-003 84214/1307 LOSS OF PCMER ISOLATION (PCIS)

UENCMN TESTING P0lER (DG) 27.

BRLNSW!CX 2 50-324 E

84-006 840504/1800 LEVEL ISOLATION (PCIS)

PROCERJRE MINTENAN HVAC (SBOT)

RUID (WCI) 28.

BPNSWICX 2 50-324 GE 84 % 84 E 4/2359 LEVEL ISQ.ATION (PCIS) FECCEDEE MINTENAN HVAC (S80T) 29.

BRUN5 WICK 2 50-324 GT 450,72) 840!!8/1100 MANUAL ISOLATION (RWCU)

FERSCNEL OPEMTI0h 30.

CALLAWAY 50-483 WEST G4,03 840615/0027 RADIATION ISOLATION (M)

FERSOMEL CONSTRUCT 31.

CALLAWAY 50-483 WEST 84-004 840617/1418 RADIATION ISCLATION (M)

PER$0hNEL MINTENAh i

SPURIOUS 32.

CALVERT CLIFFS 2 50-318 E

84-003 840415/1020 LEVEL RUID (EFO FERSONNEL CFERATIOP.

33.

D. C. COOK 1 50-315 WEST 84-008 8 4 617/2034 R0W FLUID (CH)

DESIGN OFERATICh PRESSlEE EQUIPMENT 34.

D. C. COOK 1 50-315 WEST (50.72) 8%331/1235 RADIATICN HVAC (CR)

SFtRIQJS OPERATIOk 35.

D. C. COOK 2 50-316 WEST 84-003 840311/1149 RADIATION ISOLATION (CP)

EQUIPENT OPERATIOk 36 D. C. COOK 2 50-316 WEST 84-003 84311/1849 MDIATICH ISOLATICN (CP)

EQUIPMENT OPERATIOk 37.

D. C. COGC 2 50-316 EST 84-003 840311/2009 RADIATION ISOLATION (CP)

EQUIPENT OPERATIOk 38.

D. C. COOK 2

.50-316 EST 84-003 840311/2139 MDIATION ISOLATION (CP)

EQUIPMENT CFERATIOP 39.

D. C. COOK 2 50-316 WEST 84-003 640317/0047 RADIATION ISOLATICN (CP)

EQUIPENT OPERATICt 40.

D. C. COOK 2 50-316 EST 84-003 840317/0937 MDIATION ISOLATION (CP)

EQUIPMENT OPEFATIOP 46

TABLE A.6 (CONTIMJED)

FALSE ESF ACTUATIONS DOCET NSSS REF0RT EVENT EASUED BASIC LMIT(S)

NLNBER VENDOR NLN6ER DATE / TIME PARMETER FUNCTION

• CAUSE ACTIVITY 41.

D. C. COOK 2 50-316 EST 84-006 840414/0440 RADIATION ISOLATION (CP)

PERSOMEL TESTING 42.

D. C. COOK 2 50-316 EST 84-008 840419/0000 RADIATION ISOLATION (CP)

EQUIPMENT OPERATION 43.

D. C. COOK 2 50-316 EST 84-006 840424/1310 RADIATION ISOLATION (CP)

EQUIPMENT OFSATION 44.

D. C. COOK 2 50-316 EST 84-011 840504/0647 RADIATION ISCLATION (CP)

EQUIPMENT OFSATION 45.

D. C. COOK 2 50-316 EST 84-012 840508/1536 (NOT DEFIED)

ItLTIPLE (ND)

PERS0mEL TESTING 46.

D. C. COOK 2 50-316 EST (50.72) 840310/2315 RADIATION WAC (CR)

SPtRIOUS OFERATION 47.

D. C. COOK 2 50-316 EST (50.72) 840313/0708 RADIATION WAC (CR)

SPtRIOUS OFSATION 48.

D. C. COOK 2 50-316 EST (50.72) 840313/1147 RADIATION HVAC (CR)

SPURIOUS OPERATION 49.

COOPER 50-298 CE 84-002 840129/1948 PRESSLRE ISOLATION (PCIS)

EQUIPENT CPERATION LOSS OF POER POER (DG)

ENVIRONFEhT 50.

CRYSTAL RIVER 3 50-302 N

84-003 840228/1039 LOSS OF POWER RUID (M)

EQUIPENT TESTING POER (DG) 51.

CRYSTAL RIVER 3 50-302 BW 84-005 840312/1120 PRESSURE RUID (WI)

MAMJAL TESTING SPURIOUS 52.

CRYSTAL RIVER 3 50-302 BW 84-008 840424/1040 (NOT DEFINED)

RUID (M)

MAMJAL TESTING EQUIFtENT 53.

DAVIS BESSE 1 50-346 BW 84403 840302/1221 PRESSLRE ISOLATION (M)

PERS0MEL TESTING EQUIPENT MMJAL 54.

DIABLO CANYON 1 50-275 EST 84-001 840106/1415 PRESStRE RUID (CH)

PERSONNEL TESTING LOSS OF POER P0WER (00)

ISOLATION (PC) 55.

DIABLO CANYON 1 50-275 EST-84-003 840116/1440 PRESSURE RUID (M)

UM(NCNN MINTENAN LOSS OF POER POER (DG)

WAC (CN) 56.

DIAELO CANYON 1 50-275 WEST 84-005 840116/1440 LOSS OF POWER POWER (00)

PERSONEL OPEPATION 57.

DIABLO CANYCN 1 50-275 WEST 84-007 840309/1916 LOSS OF POWER WAC (M)

PERS0mEL OFSATION 58.

DIABLO CANYON 1 50-275 EST '64-000 840315/0828 PRESSlRE RUID (RM)

PERSONEL TESTING POER (DG) 59.

DIABLO CANYON 1(2) 50-275 EST 84-009 840315/1356 LOSS OF POER PCMER (00)

PER50MEL MINTENAN 60.

DIABLO CANYON 1 50-275 EST 84-011 840330/1000 LOSS OF POER POWER (DG)

PERSCteEL MINTENM 61.

DIABLO CANYON 1 50-275 WEST 84-015 840500/1304 RCW lu.TIPLE (ND)

EQUIPMENT OPERATION TEWERATlRE 62.

DIABLO CANYON 1 50-275 WEST 84-016 840521/1402 LOSS & POER

.ISQ.ATION (CV)

PERSONhEL MINTENAN 63.

DUAE ARNOLD 50-331 GE 84-001 840107/0809 LEVEL RUID (WCI)

PERS0 feel TESTING ISOLATION (PCIS)

EQUIPMENT HVAC (SBGT) 64.

DUAE ARNOLD

' 50-331 GE 84402 840103/1516 PRESSURE ISOLATION (PCIS) PERS0mEL TESTING 65.

DUANE ARNOLD 50-331 GE 84-003 840102/ 2 TENDATLRE WAC (M)

EQUIPMENT OPERATIOk EWIR0 MENT 66.

DUAE ARNCLD 50-331 GE 84-003 840104/1728 TEMPERATlRE WAC (M)

EQUIPMENT CPERATIOk EWIRONENT 67.

DUAE ARNOLD 50-331 GE 84-003 840106/0800 TEMFERATlRE HVAC (M)

EQUIFtENT OPERATICA EWIROMENT 68.

00AhE ARNCLD 50-331 GE 84-003 840116/0810 TEMPERATlRE HVAC (M)

EQUIPMENT OPERATIOP EWIROMENT 69.

DUNE ARNOLD 50-331 GE 84404 840!!0/2228 TEMPERATLEE HVAC (M)

EQUIPrfNT OFERATIOP EWIRCNPENT 70.

DUAE ARMX.D 50-331 GE 84-007 840127/0909 RADIAT!(N ISCLATION (PCIS) SFtJRIQJS MINTENM WAC (SECT) 71.

DUANEARNOLD 50-331 GE 84403 840123/2247 LEVEL ISOLATION (PCIS) EQUIPMENT WERATI0f 72.

DUANEARNOLD 50-331 GE 84-010 840204/2200 TEMPERATURE ISOLATION IMI)

SPtRIOUS WERAT10t 47

TABLE A.6 (CONTIltJED)

FALSE ESF ACTUATIONS DOCKET NSSS REPORT EVENT MEAc1 RED T9 SIC LMIT(S)

NUM3ER VENDOR NUMBER DATE /TI!E PARAETER FUNCTIONe CAUSE ACTIVITY 73.

DUANE ARNOLD 50-331 GE 84-011 840205/1043 TEMFERATLRE HVAC m)

EQUIPMENT TERATION EWIRONMENT 74.

DUAE ARNOLD 50-331 GE 84-014 840416/1953 TEMPERATlRE ISCLATICN (RE) EQUIPMENT TESTING 75.

DUAE ARNCLD 50-331 GE 84-017 840504/1000 LEVEL FLUID (WCI)

PERS0WEL TESTING 76.

DUANE ARNOLD 50-331 GE 84-018 840507/1602 PRESSLRE ISOLATION (RCIC) PERS0WEL TESTING 77.

DUAE ARNOLD 50-331 GE 84-019 840521/0507 (NOT DEFIED)

ISOLATION (RWCU) SPlRIOUS OPERATION 78.

DUAE ARNOLD 50-331 CE 84-919 840603/1750 TEWERATlRE ISOLATION (RWCU) SPURIOUS OPERATION 79.

DUAE ARNOLD 50-331 GE 84419 840605/0345 TEPPEPATlRE ISCLATION (RWCU) SPURIOUS OPERATION 90.

DUAE ARNOLD 50-331 GE Ce-019 840606/0623 TEMPERATIRE ISCLATION (RWCU) SFtJRIOUS OPERATION 81.

DUAE ARNOLD 50-331 C:

84-020 840617/1707 RADIATION HVAC (SFU)

SPlRIOUS TERATION 82.

DUAE ARNOLD 50-331 GE 84-020 840617/1725 RADIATION WAC (SFU)

SPURIOUS OPERATION 83.

DUAE ARNOLD 50-331 E

84-020 840620/1643 RADIATION HVAC (SFU)

SPURICAJS OPERATION 84.

DUANE ARNOLD 50-331 GE 84-022 840619/1537 LNKNOW ISOLATION (PCIS)

SPURIOUS OPERATION HVAC (SBGT) 85.

DUAE ARNOLD 50-331 GE 84-024 840630/1333 UENOW ISOLATION (RWCU) SFtRIOUS OPERATION 86.

DUAE ARNOLD 50-331 GE (50.72) 84423/2319 TEWERATlRE ISOLATION (RWCU)

SPURIOUS TESTING 87.

DUME ARNOLD 50-331 GE (50.72) 8M425/1850 TEMPERATURE ISOLATICN (PCIS)

UENOWN TESTING 88.

FORT CALHOUN 50-285 E

84-003 840314/1411 LOSS OF POER ISOLATION (M)

PERSONNEL MINTENANC1 89.

FORT CALHOLN 50-285 CE 84-005 840410/1610 RADIATION ISOLATION (VIAS) SPURIOUS OPERATION 90.

FORT CALHOLN 50-285 G

84-005 8%424/1343 RADIATION ISOLATION (VIAS) SPURIOUS OPERATION 91.

FE T CALHOUN 50-285 E

84-005 840424/1853 RADIATION ISOLATION (VIAS) PERSONNEL MINTEN4C 92.

FORT CALHOLN 50-285 CE 84-005 8%502/1901 RADIATION ISOLATION (VIAS) PERSONEL MINTEENC 93.

FORT CALH0UN 50-285 E 006 840522/0931 RADIATION ISCLATION (VIAS)

SPlRIOUS MINTENANC

, 94.

FORT CALHOUN 50-285 E

(50.72) 840315/0445 LOSS OF POER FCER (DG)

EQUIPENT OFERATION 95.

FM T CALHOLN 50-235 E

(50.72) 840429/2000 LOSS OF POER POWER (DG)

ENVIRONMENT OPERATION 96.

FORT CALHCON 50-285 CE (50.72) 840521/0035 LOSS OF Pt.NER POWER (DG)

EQUIPMENT OFERATICN 97.

FT. ST VRAIN 50-267 GA 84-007 840529/1135 L0f 3 0F POER ISOLATION (MI)

SPURIOUS OPERATION 98.

GIWA 50-244 EST 84-006 840522/1023 PRESSURE MULTIPLE WD)

PERSONNEL TERATION 50-416 GE 84-001 840103/0920 LCSS OF POWER FLUID (LPCI)

DESIGN MINTENANC 99.

GRAND 00LF 1 HVAC (M)

PROEDURE ISOLATICH (M)

MISCELLAECOS 100.

ORMDCLU 1 50-416 GE 84-001 840106/1355 LOSS OF POWER HVAC (CR)

UNKNOW TESTING i

101.

GRAND 01LF 1 50-416 GE 84-002 84114/0910 LOSS OF POER ISOLATION (PCIS) MANUAL MINTENANC ;

WAC (CR)

SFtRIOUS PERSONNEL MINTEENC 102.

GRAND GlLF 1 50-416 GE 84-003 84210/1030 T0XIC GAS HVAC (CR) 103.

GRAND 00LF 1 50-416 GE 84-005 8M119/1430 LOSS OF POWER HVAC (CN)

PROCEIORE TESTING 1

0 104.

ORMD GlLF 1 50-416 E

84-006 840120/1058 IWNJAL ISOLATION (AB)

FERS0tML TESTING HVAC (M)

PROCEICRE 105.

ORMD GLLF 1 56-416 GE 84-011 840309/1329 LOSS OF POWER ISOLATION (M)

EQUIFMENT MINTENAN(

PCMER (DG)

HVAC (M) 106.

GRMD OULF 1 50-416 GE 84-015 8M326/1124 (NOT DEFINED)

HVAC (CR)

PERSONNEL MAINTENAM 107.

ORMD GLLF 1 50-416 GE 84-016 840324/0135 (NOT IEFINED)

FLUID (MI)

PROCEDURE TESTING' POWER (DG)

ISOLATION (M)

HVAC (CN) 108.

ORMD ClLF 1 50-416 CE 84-017 840M9/1620 TEMFERATlRE ISOLATION (RWCU)

SFtRIOUS OFERATION !

109.

GRAND 00LF 1 50-416 E

844)18 840414/0208 TEWERATlRE ISOLATION (R M )

PER$0NNEL TESTING 110.

GRMD GlLF 1 50-416 GE 84-022 840420/1345 TEMFERATLRE ISOLATION (RWCU) PROCEDURE TESTING 111.

GRAND GLLF 1 50-416 OE 84-028 84507/2045 MANUAL ISCLATION (RWCU) ENVIRCNMENT TERATION LOSS & PCMER POWER (DG) 48 z_,

... w.

z.

2 o

TABLE A.6 (CONTINUED)

FALSE ESF ACTUATIONS DOCKET ISSS REPORT EVENT EASURED BASIC LeilT(3)

NUMBER VENDOR M ER DATE / TIE PARAPETER FlMCTIONe CAUSE ACTIVIT 112.

E. I. MTCH 2 50-366 GE 84-003 8 4115/ NR R0W ISOLATIQi GE1))

PERSONEL MAINTENA PROCEDLEF i

113.

IWIAN POINT 3 50-286 EST 84-C01 84125/1828 PRESSWE MULTIPLE (ND)

EQUIPtENT TESTING 114.

INDIAN POINT 3 50-286 EST 84-003 840128/2015 PRESSWE HA.TIPLE (2)

EQUIPENT TESTING 115.

KEWALSEE 50-305 IEST 84-004 84409/1015 (NOTDEFINED)~ HVAC (58)

PERSONNT MAINTE M ;

116.

KEWAl4EE 50-305 EST 84-005 8#410/2130 (NOT DWIED)

RUID (M)

IN(N0lm,

TESTING HW4 (CR) 117.

NEWNDEE 50-305 EST 84407 840420/0105 REACTOR TRIP POLER (DG)

PERS0leEL MAINTENA i

118.

KEWAl5EE 50- M lEST 84-011 840510/2342 (NOT DEFIED)

HVAC (SS)

PERS0f0EL OPERATIO

{

119.

KEWAUEE 50-305 IkST ' 84411 8#511/0930 (NOT DEFIED)

HVAC (SB)

(N(NOWN OPERATIO 120.

KEWAUBEE 50-305 EST 84-012 840628/0915 TEWERATURE HVAC (AB)

PERSGGEL TESTING l

121.

LACROSSE 50-409 AC 84401 84107/1842 LOSS OF POWER P0lER (DG)

PER$0f0EL OPERATIO 122.

LACROSSE 50-409 AC 8ar403 84220/0631 PRESSWE RUID (M)

EQUIPENT OPERATIO ISOLATION (PCIS) 123.

LA SALLE 1(2) 50-373 GE 84-004 840118/1120. (NOT DEFItED)

ISOLATION (M)

PERSOPDEL CONSTRUC HVAC (S8GT) 124.

LA SALLE 1(2) 50-373 E

84-011 8 # 213/0(44 TEWERATLRE RUID (RCIC)

DESIGh OPERATIO COMENSER ISOLATION (PCIS)

EGUIPPOiT VACIAM MISCEllAE00S 125.

LA SALLE 1 50-373 GE 84415 84227/1353 LOSS OF PCER ISOLATION (PCIS)

PERSONEL MINTENA l 126.

LA SALLE 1(2) 50-373 GE 84417 840308/1700 RADIATION HVAC (CR)

EQUIPPENT OPERATIO '

127.

LA SALLE 1 50-373 GE-04-020 840327/0244 RADIATION ISOLATION (PCIS)

MAMJAL MAINTENA HYE (580T)

EQUIPPENT 128.

LA SALLE 1 50-373 GE 84422 840411/1905 LEVEL ISCLATION(PCIS)

PERS01@iEL TESTING 129.

LA SALLE 1 50-373 GE 84-023 840415/1754 R0W ISCLATION (RWCU)

EQUIPMENT OFEATIO 130.

LA SALLE 1 50-373 GE 84-028 84513/1640 TEWERATtBE ISOLATION (PCIS)

SPURIOUS OPERATIO 131.

LA SALLE 1 50-373 GE 84-043 840627/0510 FLOW ~

ISCLATICH (RWCU)

LN(N0WN OFERATIO 132.

LA SALLE 1 50-373 GE (50.72) 840516/0609 TEWERATURE ISOLATION (PCIS)

SPtRI0l*3 0FERATIO 133.

LA SALLE 2(1) 50-S74 GE 84-004 840212/0707 LOSS OF P0 lier ISCLATION (M)

EQUIPhEXT OFERATIO '

HVAC (S8GT) 134.

LA SALLE 2 50-374 GE 84-008 840229/1740 CONDENSER ISCLATION (PCIS)

PERS0MEL TESTDG VACUUn -

135.

LA SALLE 2 50-374 GE 84-009 840300/1750 TENfPATWE ISOLATION (PCIS)

PERSONPEL MINTENA.,

136.

LA SALLE 2 50-374 GE 84413 84403/1615 R0W ISOLATION (RWCU)

EQUIFtENT CFERATM 137.

LA SALLE 2 50-374 GE 84-016 840423/0810 TENERritTE ISOLATION (RWCU)

LNOGM OPERATIC '

138.

LA SALLE 2 50-374 GE 84-023 840529/0051 TENERATURE ISOLATION (RWCU)

(DikNOWN TESTING 139.

LA SALLE 2 50-374 GE 84-023 840529/1045 R0W ISOLATION (RWCU)

EQUIPPENT OPERATIC 140.

LA SALLE 2 50-374 CE 84-023 840529/ M TEWERAT'Ji ISCLATION (RWCU)

(MkNOWN TESTING 141.

LA SALLE 2 50-374 GE 84-023 8#529/ M TEWEFAIGE ISOLATION (RWCU)

LEN0lM TESTING 142.

LA SALLE 2 50-374 GE 84-026 840M9/1028 TEWERATWE ISOLATION (RWCU)

(N(N0lm MAINTENA 143.

LA SALLE 2 50-374 GE 81-028 84617/1202 TEMPERATGE ISOLATION (RWCU)

(N(NOWN OPERATIC 144.

LA SALLE 2 50-374 GE 84-031 840622/1350 TEWCATlRE ISOLATION (RWCU)

(ENOWN TESTING 145.

LA SALLE 2 50-374 GE 84-032 840626/0843 TEMPERATURE ISOLATION (RWCU)

LN(N0lm TESTING 146.

MADE YAWEE 50-309 E

84-005 8#529/1755 PTESSURE MULTIPLE (ND)

L81KNOWN TESTING LE1"il EQUIPPENT 147.

NAIE YAREE 50-309 E

84-006 844C5/1540 ' PhESSIRE MLLTIPLE (ND)

FROCEDURE TESTING 148.

MAINE YAM (EE 50-309 CE_

84-007 640413/0905 LOSS OF P0lfR RUID (ND)

PERS0f4EL MAINTENA ISOLATION (CI) 149.'

MAIE YAREE 50-309 CE 84-007 84413/140 LOSS OF POWER FLUID (ND)

IN(N0lm MAINTENA j ISOLATION (CI) 49 i

O

TABLE A.6 (CONTINUED)

FALSE ESF ACTUATIONS DOCKET NSSS REPmi EVEhT MEASURED BASIC LNIT(S)

NUMBER VENDM NUMBER DATE / TIME PARAETER FUNCTION

• CAUSE ACTIVITY 150.

MIE YAEEE 50-309 E

84-007 840413/1450 LOSS OF PCER FLUID (ND)

LN00WN MINTENMCI ISOLATION (CD 151.

MIE YAM (EE 50-309 E

(50.72) 8#530/1200 PRESSORE FLUID (ND)

FE9$0MiEL MINTEENCI ISOLATION (CI) 152.

MCOUIRE 1 50-369 WEST 84-005 840302/1115 LOSS OF POWER POWER (DG)

FESOM4EL MAINTEENC 153.

MCOUIRE 1 50-369 EST 84-011 840329/0401 LOSS OF POWER POER (DG)

EQUIPMENT TESilNG 154.

MCGUIRE 1 50-369 EST 84-012 840330/1934 LOSS & POWER PWER (DG)

PER$0fEL TESTING 155.

MCOUIRE 1 50-369 EST 84-014 840420/1406 LOSS OF POER POWER (DG)

PERSONNEL TESTING PROCEDWE 156.

MCOUIRE 1 50-369 EST 84-017 840523/1655 LOSS OF POER POWER (DG)

ENVIRONMENT OPERATION 157.

MILLSTOE 2 50-336 E

84-001 840106/2324 (NOT DEFIED)

FLUID (M)

UNKNOWN TESTING POER (DG) 158.

MILLSTOE 2 50-336 CE 84-001 840109/0900 (NOT DEFIED)

MISCELLANEOUS UNKN0ldt TESTING 159.

MONTICELLO 50-263 GE 84-001 840101/1333 LOSS OF POWER POWER (DG)

PROCEDLRE TESTING WAC (M) 160.

MONTICELLO 50-263 GE 84-002 8M107/0830 T0XIC GAS HVAC (CR)

SFtRIOUS OPERATION 161.

'10NTICELLO 50-263 GE 84404 840110/0050 T0XIC GAS HVAC (CR)

EQUIPENT OPERATION 162.

MONTICELLO 50-263 GE 84-005 840112/1630 T0XIC CAS HVAC (CR)

PERSONEL TESTING 163.

MONTICELLO 50-263 E

84-006 840119/1003 RADIATION ISOLATION (PCIS)

PERSCNNEL TESTING HVAC (SEGT)

IESIGN 164.

MONTICELLO 50-263 GE 84-009 840207/1033 T0XIC GAS HOC (CR)

PERSONNEL WERATION EQUIFtENT 165.

MONTICELLO 50-263 GE 84-009 840215/2330 T0XIC CAS HVAC (CR)

EQUIFENT (NOT DEFINE 166.

MONTICELLO 50-263 CE 84-009 840217/OS30 T0XIC GAS WAC (CR)

EQUIPMENT (NOT CEFINE 167.

MONTICELLO 50-263 GE 84-009 840220/0600 T0XIC GAS HVAC (CR)

EQUIFt1ENT (NOT DEFINE 168.

MCNTICELLO 50-263 GE 84-009 BM307/2345 T0XIC GAS HVAC (CR)

EQUIPMENT (NOT DEFINE 169.

MONTICELLO 50-263 GE 84-012 840313/1230 T0XIC CAS HVAC (CR)

EQUIPMENT GERATION 170.

M0EICELLO 50-263 GE 84-013 840318/0620 LOSS OF POER POWER (DG)

EQUIPMENT OPERATION 171.

MONTICELLO 50-263 GE 84-013 840318/2314 LOSS OF POWER P WER (DG)

EQUIPMENT OFEATION 172.

MONTICELLO 50-263 GE 84414 840322/1325 LOSS OF PCHER ISOLATION (PCIS)

EQUIFt1ENT OPERATION WAC (M) 173.

MONTICELLO 50-263 CE 84-015 8M325/1130 LOSS OF POER ISOLATION (PCIS)

SPURICUS OPERATICN HVAC (SBGT) 174.

MONTICELLO 50-263 GE 84-016 84408/1007 RADIATION HVAC (M)

SPLRIOUS CFERATION 175.

MONTICELLO 50-263 GE 84-017 840425/0430 T0XIC OAS HVAC (CR)

FGSCNNEL OPERATICH PROCEDURE 176.

MONTICELLO 50-263 GE 84-018 840425/1000 RADIATION ISOLATION (RBV)

SFtRIOUS MAINTENANC HVAC (SBGT) 177.

MONTICELLO 50-263 GE 84-019 840427/1355 T0XIC GAS HVAC (CR)

EQUIFNENT OFERATION 178.

MCNTICELLO 50-263 GE 84-020 840530/1625 RADIATION ISOLATION (RB)

EQUIFMENT MAINTENMC HVAC (SBGT) 179.

MONTICELLO 50-263 GE 84-021 840604/1319 LOSS OF POWER POWER (DG)

FERSONNEL TESTING HVAC (SBGT)

PROCEDURE 180.

MONTICELLO 50-263 CE 84-022 840605/2252 RADIATION ISG.ATICN (RBV)

EQUIPMENT CFERATION l HVAC (SBGT) 181.

MONTICELLO 50-263 GE 84-023 840621/0140 LOSS OF POWER POWER (DG)

PROCEDURE MAINTENANC 182.

MONTICELLO 50-263 GE 84-024 840627/1350 LOSS OF POWER ISOLATION (RBV)

FGS0mEL MAlkTENANC HVAC (SBGT) 183.

NINE MILE POINT 50-220 GE 84-006 840413/1450 RADIATION HVAC (RBV)

MANUAL MAINTENANC EQUIPMENT 184.

NORTH AM4A 1 50-338 EST 84-002 840!!8/0900 FEESSURE POWER (DG)

PERSONNEL NAINTENANt FROCEIORE 50

TABLE A.6 (CONTIMED)

FALSE ESF ACTUATIONS DOCKET NSSS REPORT EVENT EASURED BASIC UNIT (S) letBER VENDOR NLPtBER DATE / TIE PARAETER FLNCTIONe CAUSE ACTIVITY 185.

0YSTER CREEX 50-219 CE 84417 840627/1400 LOSS OF POER ISOLATION (PCIS) PROCEDURE MAINTENANCE 186.

PALISADES 50-255 E

84-002 84401/1246 RADIATION ISOLATICN (CIl~

FGSCNEL OPERATICN 187.

PALISADES 50-255 CE 84-004 840408/1702 PRESSURE E TIPLE (ND)

EQUIPENT TESTING 188.

PALISADES 50-255 E

84-004 840408/1714 PRESSURE MLLTIPLE (ND)

EQUIFMENT TESTING 189.

PALISADES 50-255 E

84-005 8%512/1735 PRESSURE FLUID (M)

PROCEDURE MAINTENANCE ISOLATIM (CI) 190.

PALISADES 50-255 E

84-007 840622/0727 PRESSWE MISCELLANEOUS PERSCNEL MINTENANC 191.

PALISADES 50-255 E

84-007 840623/1434 PRESSLRE MISCELLANEOUS SPURIOUS MAINTENANCE 192.

PEA 01 BOTTOM 2 50-277 GE 84-002 840321/0130 (NOT DEFIED)

ISOLATION (PCIS) EQUIPMENT OPERAT!W WAC (SBOT) 193.

PEACH BOTTOM 2 50-277 GE 84-005 840323/1547 LOSS OF POWER ISOLATION (PCIS) EQUIPMENT TERATION 194.

PEACH BOTTOM 2 50-277 GE 84-007 840403/0915 LOSS OF POER ISOLATION (RWCU) PERSONEL MAINTEMNCE 195.

PEA 0i BnTTOM 2 50-277 GE 84409 840516/1312 LOSS OF POER RUID OFCI)

PROCEDURE MAINTENANCE 196.

POINT BEACH 2 50-301 EST 84-003 840519/0341 PRESSLRE MULTIPLE (ND)

PERSONEL OPERATION 197.

PRAIRIE ISLAND 2 50-306 WEST 84-001 840618/0740 LEVEL MISCELLANEOUS PROCEDLRE MAINTENANCE 198.

QUAD CITIES 2 50-265 GE 84403 840211/0718 LOSS OF POWER HVAC (SBOT)

PERSONNEL MAINTENANCE 199.

RANCHO SECO 50-312 BW 84-015 840319/2251 LOSS OF POER FLUID OFI)

FGSONEL OPERATION l

200.

ROBINSON 2 50-261 WEST 84-006 840621/1024 PRESSlRE MLLTIPLE (ND)

PERSCNEL MAINTENANC 201.

SALEM 1(2) 50-272 EST 84-013 840602/0354 LOSS OF PCWER POWER (DG)

PERS0 teel MAINTENANCE 202.

SALEM 1 50-272 WEST 84-014 840605/0551 LOSS OF POWER POWER (DG)

PROCEDURE MAINTENANCE 203.

SAN CN0FRE 1 50-206 EST 84402 840309/1003 LOSS OF POWER POWER (DG)

UNKNCNN TESTING 204.

SAN ONOFRE 2 50-361 CE.84402 8#130/0650 RADIATION ISOLATION (CP)

SPURIOUS MAINTEMNCI I 205.

SAN ONOFRE 2 50-361 E '84-002 840131/0655 RADIATION ISCLATION (CP)

SFWIOUS MAINTENANCI 206.

SAN ONCFRE 2 50-361 CE 84402 840201/0755 RALIATION ISOLATION (CP)

SPLRIOUS MAINTEENCI 207.

SAN ONOFRE 2 50-361 CE 84-002 840202/0730 RADIATION ISOLATION (CP)

SFWIOUS MAINTENANCI 208.

SAN CN0FRE 2 50-361 E

84-002 840203/1605 RADIATION ISOLATION (CP)

SPURIOUS MAINTENANC 209.

SAN ONOFRE 2 50-361 CE 84-004 840116/1050 RADIATION ISOLATICN (CP)

SPURIOUS TESTING i

210.

SAN ONT RE 2 50-361 E

84-004 840116/1445 RADIATION ISOLATION (CP)

SPLRIOUS TESTING 211.

SAN ONCFRE 2 50-361 E

84-007 840203/0150 PRESSURE ISOLATION (MS)

SPURIOUS MAINTENANC!

212.

SAN ON0FRE 2 50-361 E

84-007 840204/0910 PRESSURE ISOLATION (MS)

SPURIOUS MAINTENAiC 213.

SAN ONOFRE 2 50-361 E

84-011 840225/2250 RADIATION ISOLATION (CP)

EQUIPENT OFGATION 214.

SAN ONCFRE 2 50-361 84-016 840309/1933 (NOT DEFIED)

RUID (M)

PERSOPNEL TESTING MISCELLAE0VS 215.

SAN ON TRE 2(3) 50-341 CE 84-018 840324/1850 MANUAL HVAC (CR)

EQUIPMENT MAINTENANC 216.

SAN ONOFRE 2 50-361 E

84-019 840324/1934 LEVEL RUID (EFW)

EQUIPENT WGATION I

217.

SAN ONOFRE 2(3) 50-361 CE 84-022 840330/0226 RADIATICN HVAC (CR)

SFWIOUS MAINTENANC

[

218.

SAN ON0FRE 2(3) 50-361' E

84-022 840410/1906 RADIATION HVAC (CR)

SPURIOUS OPERATION 219.

SAN CN0FRE 2(3) 50-361 CE 84-022 840410/2020 RADIATICN HVAC (CR)

SPLRIOUS OPERATION 220.

SAN ONOFRE 2(3) 50-361 E

84-023 640524/0952 RADIATION HVAC (CR)

SPURIOUS OPERATION 321.

SAN CN0FRE 2(3) 50-361 CE 84-023 840527/0102 RADIATICN HVAC (CR)

SPtRIOUS OFERATION 222.

SAN CNOFRE 2(3) 50-361 CE 84-023 840527/0159 RADIATION HVAC (CR)

SPURIOUS OFERATION 223.

SAN ON0FRE 2(3) 50-361 E

84-023 840620/1606 RADIATION HVAC (CR)

SPURIOUS OFSATION 224.

SAN ON TRE 2(3) 50-361 E

84-023 840621/1130 RADIATION HVAC (CR)

SFURIOUS OPERATION 225.

SAN ONOFRE 2(3) 50-361 CE 84-029 840614/0344 T0XIC GAS ISOLATION (M)

PERSONNEL TESTING 226.

SAN ON0FRE 2(3) 50-361 CE 84-032 840530/1123 T0XIC GAS HVAC (CR)

EQUIPMENT OPERATION 227.

SAN ONOFRE 2(3) 50-361 E

84-032 840530/1425 T0XIC CAS HVAC (CR)

EQUIPMENT OFSATICH 228.

SAN ONOFRE 2 50-361 CE (50.72) 840530/0410 LOSS OF POWER RUID (ND)

UNDGM (NOT IEFINE ISOLATION (CI) 229.

SAN ONOFRE 2 50-361 CE (50.72) 840509/1553 RADIATION ISOLATION (FB)

FSSONNEL TESTING 230.

SAN ONOFRE 3 50-362 CE 84-004 840222/1940 MANUAL FLUID (M)

EQUIPENT TESTING ISOLATION (M)

MISCELLANEOUS 51

~' ~

_ _. i _ a _. Z

~

ZZ - ;

- ~ ~ - - '

o O

TABLE A.6 (CONTI E D)

FALSE ESF ACTUATIONS DOCKET N%S REPORT EVENT EASWED BASIC WIT (S)

M BER VENDOR M BER DATE / TIE PARAETER FWCTION*

CAUSE ACTIVITY 231.

SAN ONOFRE 3 50-362 E

84408 840310/le LEVEL FLUID (EFW)

EQUIPENT OPERATIM 232.

SAN ONOFRE 3 50-362 E

84-010 840424/1035 RADIATION ISOLATION (CF)

SPWIOUS CFERATION 233.

SM ONOFRE 3 50-362 E

84-010 8#502/2100 RADIATION ISOLATION (CP)

SFWIOUS OPERATION 234.

SAN ONOFRE 3 50-362 E

84-010 840509/1746 RADIATION ISOLATION (CP)

SPURIOUS (NOT DEFIE) 235.

SAN ONOFRE 3 50-362 E

84-010 840509/1746 RADIATI(W ISOLATION (CP)

SPURIOUS OPERATION 236.

SAN ON0FRE 3 50-362 E

84-010 840509/1955 RADIATION ISOLATION (CP)

SPWIOUS OPERATION 237.

SAN ONOFRE 3 50-362 E

84-010 840510/1830 RADIATIM ISOLATION (CP)

SPWIOUS<

MINTENANCI 238.

SAN ONOFRE 3 50-362 E

84410 840510/2036 RADIATION ISOLATION (CP)

SPtRIOUS MINTENANCI 239.

SM (M0FRE 3 50-362 E

84-010 8#512/0244 RADIATION ISOLATION (CP)

SPURIWS MINTENANCI 240.

SAN ONOFE 3 50-362 E

84-010 840512/0820 RADIATION ISOLATION (CP)

SPlRIOUS MINTENANCl 241.

SAN ONOFRE 3 50-362 E

84424 8%611/1817 LEVEL FLUID (EFW)

EQUIPENT OPERATION 242.

SAN ONOFRE 3 50-362 E

84426 840612/0836 RADIATION ISOLATION (CP)

EQUIPMENT MINTENANCI 243.

SAN ONOFRE 3 50-362 E

(50.72) 840526/0816 RADIATION ISOLATION (FB)

SPURIOUS (NOT DEFINE 244.

SEQUOYAH 1 50-327 EST 84-001 840102/1450 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 245.

SEQUOYM 1 50-327 EST 84-001 840105/0830 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 246.

SEQUDYAH 1 50-327 EST 84-001 8#108/1025 RADIATION ISOLATIM (CV)

SPLRIOUS OPERATION 247.

SEQUOYAH 1 50-327 EST 84-001 84112/1546 RADIATION ISOLATION (CV)

SPURIOUS OPERATICN 248.

SEQUDYAH 1 50-327 EST 84-001 840117/1744 RADIATION ISOLATION (CV)

SPtRIOUS OPERATION 249.

SEQUDYAH 1 50-327 EST 84-002 84112/0700 RADIATION ISOLATION (AB)

SPURIOUS '

0FERATION 250.

SEQUOYAH 1 50-327 EST 84-002 840112/1020 RADIATION ISOLATION (AB)

SPURIOUS OPERATION 251.

SEQUOYAH 1 50-327 EST 84-002 840118/1451 RADIATION ISOLATION (AB)

SPURIOUS OFERATION 252.

SEQUOYAH 1 50-327 EST 84-003 840120/1939 RADIATION ISOLATION (CV)

SPLRIOUS OPERATION 253.

SEQUOYAH 1 50-327 EST 003 8M129/1015 RADIATION ISOLATION (CV)

SPLRIOUS OPERATION 254.

SEQUDYAH 1(2) 50-327 EST 84-004 84114/0055 RADIATION ISOLATION (CR)

SPtRIOUS OPERATION 255.

SEQUDYAH 1(2) 50-327 EST 84-004 840114/0120 RADIATION ISOLATION (CR)

SPlRIOUS OPERATION 256.

SEQUOYAH 1 50-327 EST 84-010 840128/2130 RADIATION ISOLATION (AB)

SPLEIOUS MINTENANC I

257.

SEQUOYAH 1 50-327 EST 84-012 840201/0900 RADIATION ISOLATION (CV)

PERSONNEL MINTENANC I

258.

SEQUOYAH 1 50-327 WEST 84-012 8M206/0100 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 259.

SEQUOYAH 1 50-327 EST 84-014 840214/0749 LOSS OF POWER ISOLATION (CV)

EQUIPENT WERATION 260.

SEQUOYAH 1 50-327 EST 84-014 840220/1500 MDIATION ISOLATION (CV)

SPURIOUS OFERATIW 261.

SEQUDYAH 1 50-327 EST 84-014 8#301/0850 RADIATION ISOLATION (CV)

EQUIPMENT OPERATION 262.

SEQUDYAH 1 50-327 WEST 84415 8#220/0052 RADIAlION ISOLATION (AB)

SPURIOUS OPERATION 263.

SEQUOYAH 1 50-327 EST 84415 840221/1829 LOSS OF POWER ISOLATION (AB)

SPLRIOUS PERATION 264.

SEWOYAH 1 50-327 EST 84-020 840309/0339 RADIATION ISOLATION (CV)

SPURIOUS TESTING i

265.

SEQUOYAH 1 50-327 EST 84-020 840326/0854 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 266.

SEQUOYAH 1 50-327 EST 84-022 840330/0730 RADIATION ISOLATION (CV)

SFWIOUS OPERATION 267.

SEQUDYAH 1 50-327 EST 84-022 8@409/07% RADIATION ISOLATION (CV)

PERS01@EL MINTENANC 268.

SEQUOYAH 1 50-327 EST 84-027 840420/1642 RADIATION ISOLATION (CV)'

SPURIOUS OPERATION 269.

SEQUDYAH 1 50-327 EST 84-027 840425/1055 RADIATION ISOLATION (CV)

SFWIOUS OPERATION 270.

SEQUDYAH 1 50-327 EST: 84-027 840425/1116 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 271.

SEQUOYAH 1 50-327 EST 84-028 840417/2358 RADIATION ISOLATION (AB)

PERS01@EL OPERATION 272.

SEQUDYAH 1(2) 50-327 WEST 84429 840507/1205 RADIATION ISOLATION (AB)

PROCEDURE MAINTENANC 273.

SEQUDYAH 1(2) 50-327 EST 84-035 840521/2234 LOSS OF POER FLUID (EFW)

EQUIPMENT OPERATION ISOLATION (M) 4 274.

SEQUOYAH 1(2) 50-327 EST 84-039 840527/1950 RADIATION ISOLATION (CR)

EQUIPMENT OPERATION 275.

SEQUOYAH 1(2) 50-327 EST 84-039 840611/0543 RADIATION ISOLATION (CR)

SPURIOUS OPERATION 276.

SEQUOYAH 2 50-328 EST 84-001 840110/1535 RADIATION ISCLATION (CV)

SPURIOUS OPERATIM 277.

SEQUOYAH 2 50-328 EST 84-001 840115/0241 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 278.

SEQUOYAH 2 50-328 EST 84-001 840116/0829 RADIATION ISOLATION (CV)

SPLRIOUS OPERATION 279.

SEQUOYAH 2 50-328 EST 84-001 8#117/2335 RADIATION ISOLATION (CV)

PROEINE TERATION 280.

SEQUOYAH 2 50-328 WEST 84-001 840121/1950 RADIATION ISOLATION (CV)

SPURIOUS WERATION 281.

SEQUOYAH 2 50-328 EST 84402 840127/0123 RADIATION ISOLATION (CV)

SPURIOUS MAINTENANC 52

TABLE A.6 (CONTIMJED)

FALSE ESF ACTUATIONS DOCKET NSSS REPORT EVENT MEASWED BASIC LOGT(S)

Nlt1BER VENDOR NUMBER DATE / TIME PARAMETER FUNCTICNe CAUSE ACTIVITY 282.

SEQUOYAH 2 50-328 EST 84-002 840127/1538 RADIATICN ISOLATION (CV)

SPURIOUS MINTE?WG 283.

SEQUOYAH 2 50-328 EST 84-002 840127/2025 RADIATION ISOLATION (CW SFWIOUS OPERATION 284.

SE9UDYAH 2 50-328 EST 84-002 840129/0117 RADIATION ISOLATION (CV)

SPURIOUS CFERATIM 285.

SEQUOYAH 2 50-328 WEST 84-002 840201/1714 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 286.

SEQUOYAH 2 50-328 EST 84-002 840208/2048 RADIATION ISOLATION (CV)

SPURIOUS OPERATION 287.

SEQUDYAH 2 50-328 EST 84-003 840227/2028 LOSS OF FT)WER ISOLATION (M)

PERSONNEL MINTENMCl 288.

SEQUOYAH 2 50-328 WEST 84-003 840301/1915 RADIATION ISOLATION (CV)

SPLRIOUS MINTENANCE 289.

SEQUOYAH 2 50-328 EST 84-004 840326/0054 LOSS OF POER POWER (DG)

EQUIPMENT MINTENANC1 290.

SEQUOYAH 2 50-328 EST 84-004 840402/1026 LOSS CF POER P0 6 (DO)

PERSONNEL MINTENANCI 291.

SEQUOYAH 2 50-328 WEST 84-004 840403/0836 LOSS OF POWER POER (DO)

PERSONNEL MAINTENANC1 292.

SEQUOYAH 2 50-328 WEST 84-006 840406/0110 RADIATION ISOLATION (CV)

SPURIOUS MINTENANC1 293.

SEQUOYAH 2 50-328 EST 84-006 840408/0439 LOSS OF PCER ISCLATION (CV)

PERSONNEL MINTENANCI 294.

SEQUOYAH 2 50-328 EST 84-009 840630/1543 (NOT IEFINED)

FLUID (EFW)

PERSONEL MINTENMCI 295.

SEQUOYAH 2 50-328 EST 84-009 840630/1820 (NOT DEFIED)

FLUID (EFW)

EQUIPMENT FIAINTENANCI 296.

SlMER 1 50-395 EST 84-016 840301/1935 LOSS OF POWER FLUID (M)

EQUIPMENT TESTING POWER (DG) 297.

SUPIER 1 50-395 EST 84-017 840329/1750 LOSS OF POER POWER (DG)

PERSOPNEL TESTING 298.

Surfer 1 50-395 WEST 84-023 840417/1025 LOSS OF POER POWER (D0)

PERSONNEL MINTENANCI 299.

SLMER 1 50-395 EST 84-026 840505/1929 FLOW ISOLATICN (MS)

SPURIOUS MINTEMNCI TEtFERATWE 300.

Slt9ER 1 50-395 EST 84428 840629/1720 N0E FLUID (EFW)

EQUIPriENT OPERATION I 301.

SWRY 1 50-280 EST 84-005 840301/2135 FLOW MLLTIPLE (ND)

FERSONNEL MINTENANCI PRESSURE 302.

SUSQUEH M A 1 50-387 GE 84407 840202/0530 (NOT DEFIED)

ISOLATION (CRD)

SFWIOUS TESTING 303.

SUSQUEH M A 1(2) 50-387 GE 84-011 840301/ PR LOSS OF POER ISOLATION (SC)

DESIGN OFERATION HVAC (M) 304.

SUSQUEHMNA 1(2) 50-387 OE 84-011 840308/1000 LOSS OF POWER ISOLATION (SC)

PERSONNEL TESTING HVAC (M) 305.

SUSQUEH M A 1(2) 50-387 GE 84-014 840305/1315 LOSS OF POWER ISOLATION (SC)

PERSONNEL CFERATION i

HVAC (M) i 306.

SUSQlEMNNA 1 50-387 GE 84-019 840415/1348 PRESSWE HVAC (M)

PERSO E L MAINTENANC M7.

SUSQUEHANNA 1(2) 50-387 OE (50.72) 840125/0156 LEVEL HVAC (CR)

PERSONNEL MINTENAta 308.

SUSQUEH M A 1(2) 50-387 OE (50.72) 840128/0920 LOSS OF POWER ISOLATION (RB)

PERSONNEL TESTING HVAC (CR) 309.

SUSQlEHEA 1(2) 50-387 GE (50.72) 840131/1100 t1ANUAL ISOLATION (RB)

PERSO E L TESTING HVAC (CR) 310.

SUSQUEH N A 2 50-388 OE 84404 840501/0755 LOSS OF POER ISOLATION (RB)

PERSONNEL TESTING HVAC (CR) 311.

SUSQUEHANNA 2 50-388 OE 84-005 840515/1450 TEMPERATURE ISOLATION (RWCU)

PERSONEL TESTING 312.

TMI 1 50-289 BW 84402 840603/1155 (NOT DEFIED)

ISOLATION (ND)

MANUAL MINTENMC:

POWER (DG)

EQUIPENT 313.

TMI 1 50-289 BW 84-002 840630/0524 (NOT DEFIED)

FLUID (MI)

MANUAL MINTENAN EQUIPMENT 314.

TROJAN 50-344 EST 84-003 840218/0445 LOSS OF FCER MULTIPLE (ND)

FER$0NNEL TESTING 315.

TROJAN 50-344 WEST 84-007 840428/1624 LOSS OF POWER MULTIPLE (ND)

FERSONNEL TESTING N

316.

TROJAN 50-344 WEST 84-011 840508/1632 LOSS OF POWER MULTIPLE (ND)

PERS0?#EL MINTENANC, l 317.

TURKEY POINT 3 50-250 EST 84-002 840108/0735 FLOW ftJLTIPLE (ND)

EQUIPENT CFERATION i TEMPERATURE PROCEDJRE 318.

TURKEY POINT 3 50-250 WEST 84-006 840212/0638 LOSS OF POWER POWER (DG)

SPURIOUS CFEFATICN 319.

TWKEY POINT 3(4) 50-250 WEST 84-007 840216/0925 LOSS CF POWER POWER (DG)

EQUIPENT OPERATION 320.

TURKEY POINT 4 50-251 EST 84-004 840307/0238 RADIATION ISOLATION (M)

SPlRICUS OPERATION 53

TABLE A.6 (C0hTINUED)

FALSE ESF ACTUATIONS

~

DOCKET NSSS REPCRT EVENT EASLRED BASIC UNIT (S)

NUM5ER VENDOR NUMBER DATE / TIE PARAPETER FUNCTION

• CAUSE ACTIVITY 321.

TURKEY POINT 4 50-251 EST 84406 840505/0318 LOSS CF POER POER (DG)

PERSONEL MINTENANCE 322.

VERMONT YAl#IE 50-271 GE 84-001 840105/1252 LEVEL ISOLATION (PC[S) LNKNOWN ONRATION PRESSURE 323.

VERMONT YAWEE 50-271 GE 84-004 840417/0742 FLOW ISOLATION (PCIS) EQUIPMENT TESTING 324.

WPPSS 2 50-397 CE 84-002 840111/0840 RADIATION HVAC (CR)

SPURIOUS OFERATION 325.

WPSS 2 50-397 GE 84-002 840114/0605 RADIATION HVAC (CR)

SPLRIOUS WEPATION 326.

WPSS 2 50-397 GE 84-002 840206/1811 RADIATION HVAC (CR)

SFURIOUS CFERATION 327.

WPSS 2 50-397 CE 84-005 840123/1025 LOSS OF POER POWER (DG)

PROCEDLRE MAINTENANCE 328.

WPSS 2 50-397 GE 84-005 840208/1600 LOSS OF FCER POER (DG)

PROCEDURE MAINTENANCE 329.

WPSS 2 50-397 GE 84-014 840219/0500 LOSS OF F0WER ISOLATICN (RWCU) PROCEDLRE TESTING 330.

WPPSS 2 50-397 GE 84-015 840307/1410 LOSS OF POWER ISOLATION (SC)

PERSONNEL MAINTENANCE 331.

WPPSS 2 50-397 GE 84416 840317/0600 LOSS CF POWER ISOLATION (MI)

PERSONEL TESTING 332.

W PSS 2 50-397 E

84-017 840318/1045 RADIATION HVAC (CR)

PERSONEL TESTING 333.

WPSS 2 50-397 GE 84-018 840306/1358 RADIATION WAC (CR)

PROCEDURE TESTING 334.

WPSS 2 50-397 GE 84-019 840308/0112 T0XIC GAS HVAC (CR)

EQUIPMENT MINTENANCE 335.

WPSS 2 50-397 GE 84-022 840319/1415 LOSS OF POER POER (DG)

FERSONNEL MINTENMCE

- 336.

WPPSS 2 50-397 GE 84424 840317/0950 RADIATION HVAC (CR)

FERSONNEL TESTIl0 337.

WPPSS 2 50-397 OE 84425 840319/0610 RADIATION WAC (CR)

SPURIOUS OPERATION 338.

WPSS 2 50-397 GE 84-030 840412/0524 RADIATION HVAC (CR)

SPtRIOUS ~ TESTING 339.

WPPSS 2 50-397 GE 84-039 840426/1955 RADIATION HVAC (CR)

SPURIOUS CPERATION 340.

WPPSS 2 50-397 GE 84-046 840520/1141 RADIATION HVAC (CR)

SFURIOUS OPERATION 341.

WPPSS 2 50-397 GE 84-049 840522/2105 RADIATION WAC (CR)

SFtRIOUS OPERATION 342.

WPSS 2 50-397 GE '84-050 840526/1845 RADIATION HVAC (CR)

SPLRIOUS OPERATICN

'343.

WPSS 2 50-397 GE 84-052 840528/1612 RADIATION HVAC (CR)

SPtRIOUS OPERATION 344.

WPPSS 2 50-397 GE 84-053 840528/1057 RADIATION WAC (CR)

SPtRIOUS OPERATICH 345.

WPSS 2 50-397 OE 84-054 840529/1231 RADIATION HVAC (CR)

SPLRIOUS TESTING 346.

WPPSS 2 50-397 OE 84-055 840528/1057 FLOW ISOLATION (RWCU) (ENOWN TESTING 347.

WPPSS 2 50-397 GE 84-057 840605/0034 T0XIC GAS HVAC (CR)

EQUIPMENT OFERATION 348.

WPPSS 2 50-397 GE 84-057 840612/1705 T0XIC GAS HVAC (CR)

EQUIPMENT OPERATION 349.

W PSS 2 50-397 OE 84-058 840607/1548 RADIATICN HVAC (CR)

PERSONNEL MINTENANCE 350.

WPPSS 2 50-397 GE 84-063 840617/0430 RADIATION HVAC (CR)

SPURIOUS OPERATION 351.

WPPSS 2 50-397 OE 84-064 840623/1932 LOSS OF POWER ISOLATION (M)

EQUIPMENT TESTING HVAC (M) 352.

WPPSS 2 50-397 GE 84-064 840623/2132 LOSS OF FCER ISOLATION (M)

EQUIPNENT OPERATION HVAC (M) 353.

WPSS 2 50-397 GE 84-066 840620/1332 RADIATION HVAC (CR)

PERS0hhEL MINTENANCE 354.

WFSS 2 50-397 GE 84-067 840620/1810 RADIATION HVAC (CR)

SPLRIOUS CPERATION 355.

WPPSS 2 50-397 GE 84-068 840628/1029 RADIATICN HVAC (CR)

SPLRIOUS MAINTENMCE 356.

WPPSS 2 50-397 CE 84-069 840628/2124 RADIATION HVAC (CR)

PERSONNEL TESTING 357.

YAWEE ROE 50- 29 WEST.84-003 840403/1056 FRESSURE ISOLATION (CV)

DESIGN OFERATION 358.

YANKEE R0WE 50- 29 EST 84-009 840510/1010 LOSS OF POER POWER (DG)

PERSONNEL MDRENATEE

• AB = AUXILIARY BUILDING EFW = EMERCENCY OR AUXILIARY FEEDWATER PC = PRIMARY CONTAINMENT CB = CONTRCL BUILDING FB = FUEL BUILDING PCIS= PRIMARY CONTAINMENT ISOLATION SYSTEM CH = CHARGING HPCI= HIGH PRESSURE COOLANT INJECTION RB = REACTCR BUILDING CI = CONTAINMENT ISOLATION WI = HIGH PRESSURE I!LECTION RBV = REACTOR BUILDING VENTILATION CN = CONTAIMENT LPCI= LOW PRE 55tRE C0CLANT IPLECTION RCIC= REACTOR CORE ISOLATION COOLING CP = CONTAINMENT PURGE N = MULTIPLE R$ = RESIDUAL OR DECAY EAT REMOVAL CR = CONTROL ROOM MI = MISCELLANEOUS SB = SHIELD BUILDING CRD= CONTROL ROD DRIVE MS = MAIN STEAM SBOT= STANDBY CAS TREATENT CV = CONTAINMENT VENTILATICN ND = NOT DEFDED SFU = STANDBY FILTRATION LNITS DG = DIESEL OD4ERATOR 54

u_

.e TABLE A.7 ESF ETUATIONS - SAFETY INICTION EVENTS

• ECCS EACTOR NSSS EPORT EVENT INICTION P0 6 ACTUATION LMIT VE20R M BER DATE / TIE EQUIPfENT LEVEL TYPE DESmfPTIONOFEVENT

1. BEAVER VALLEY EST 84-002 840125/0305 NOT DEFIED 1001 FALSE PERSO N L ERROR DLRING RPS LOGIC TESTING WILE AT FlLL POWER. WRONG PUSEUTTON ACTUATED.

2.

IROWS FERRY 2 GE 84-002 840121/0556 HIGH PESSLSE 0%

RID l.0W REACTOR MTER LEVEL FOLLOWING REACTOR C00UWT (28)

SG AM FROM 641 POWER. SCRAM CAUSED BY

' INICTION PERS0f0EL EMOR DURING PCIS LOGIC TESTING.

Ilffl0PER ESET.

3. BRlMSWICK 1 GE 84406 840331/2300 !!!GH PRESSWE 01 VALID LOW EACTOR MTER LEVEL FOLLOWING REACTOR COOLANT (20).

SCRAM FROM 95% POWER. SCRAM CAUSED BY INICTION PERSONL ERROR DLRING MINTENANCE OF INSTRlfENT MR S(PPLY TO COEENSATE SYSTEM.

4. BRlNSWICK 2 GE 84-004 840222/0150 HIGH PFESSWE 01 VALID LOW EACTOR WATER LEVEL F0l10 WING EACTCR COOLANT (EB)

SCRAM FROM 971 P0 6. SCRAM CAUSED BY IKICTION LMDETECTED PE-EXISTING EQUIPfENT FAILlRE (RELAY) DLRING PCIS LOGIC TESTING. POST-MINTENANCE TESTING PROCEDURE CONTRIBUTINC FACTOR SINCE INADEQUATE TO DETECT FAILURE.

5. D. C. COOK 1 WEST 84-006 840617/2034 NOT DEFIED 681 FALSE ERROEOUS LOW STEAPLIE PRESSURE SIGNAL CONCUMENT WITH HIGH STEAM FLOW SICilAL GEERATED DLRING POER OPEMTION DlE TO EQUIPfENT FAILlRE (CAPACITOR) IN INSTRl#ENT ;

PO E SlFPLY INVERTER. EACTOR SCRAM OCCURRED SIMlLTAE00 SLY.

6. CRYSTAL RIVER 3 BW 84405 840312/1120 HIGH PRESSLRE 981 FALSE SPURIOUS HIGH PRESSlRE RELAY ACTUATION IN OE INJECTION CHAML WILE OTER CHAf0EL WAS MANUALLY TRIPPED DLRING ESF TEST. [ NIT IN POER OPEMTION.

7. CRYSTAL RIVER 3 BW 84-000 840424/1040 HIGH PESSLRE 971 FALSE EQUIPfENT FAILURE (BISTABLE) IN OE CHAML INKCTION OF LOW PESSURE INSTRllENTATION WILE OTER CHAML WAS NAMJALLY TRIPPED DURING

' ESF TEST. UNIT IN POER OPEMTION.

8. FITZPATRICK GE 84-009 840322/0744 HIGH PRESSLRE 01 VALID LOW EACTOR WATER LEVEL FOLLOWING REACTOR COOLANT (NDB)

SCMM FROM 671 POWER. SCRAM CAUSED BY INJECTION EQUIPfENT FAILURE (BEARING) DUE TO LlRE OIL FAILURE (C0lFLING) IN MAIN FEED PUPP.

9. FITZPATRICK GE 84-010 840325/0423 HIGH PRESSLEE 01 VALID MANUAL INITIATION FOLLOWING REACTOR SCRAM C00UWT (28)

FROM 25% P06 DlE TO LOW EACTOR WATER INICTION LEVEL. SCRAM CAUSED BY EQUIPfENT FAILURE (C0f0ECTOR) IN MAIN FEED PUFF CONTROL OIL SYSTEM. C0f0ECTOR IffH0FIRLY INSTALLED DlRING PRIOR MAINTENANCE.

55

e.

e TABLE A.7 (CONTIMED)

ESF ACTUATIONS - SAFETY INJECTION EVENTS ECCS EACTOR NSSS REPORT EVENT IlOECTION POER ACTUATION UNIT VD00R Mf9ER DATE / TIE EQUIPfENT LEVEL TYPE DESCRIPTION OF EVENT

10. grape OLA.F 1 GE 84401 840103/0920 LOW PRESSLRE 01 FALSE ERR 0NEOUS LOW EACTOR WATER LEVEL SIONAL C00UWT GDEMTED MING LOSS OF POER EVENT WILE INJECTION IN COLD SHJTDOW. LOSS OF POWER CONDITION CAUSED BY C0!91 NATION OF BATTERY CHARGER HIGH VOLTAGE TRIP DESIGN APE PROCEDlRE FOR

, PLACING C M RGERS ON EQUALIZATION.

11. LACROSSE AC 84-003 840220/0631 HIGH PRESSlRE 981 FALSE ERROEOUS HIGH CONTAll#ENT BUILDING CORE SPRAY PRESSlRE SIGNAL GOERATED DlE TO EQUIPPENT FAILURE (FUSE) IN NORMLLY ENERGIZED RELAY CIRCUIT.

12. MIE YAft:EE E

84406 840405/1540 LOW PRESSLRE 01 FALSE ERROE0VS LOW EACTOR PRESSLEE SIGNAL SAFETY GEERATED DlRING SIAS LOGIC TESTING INICTION WILE IN REFUELING SRITDOW. SIGNAL GDERATED DLE TO INADEQUATE TEST EQUIPPENT ClHECT10k ?TCEDlRE.

13. PALISADES E

84405 840512/1735 HIGH PESSLRE 01 FALSE ERROEDUS CONTAIMENT HIGH PESSlRE SIGNAL SAFETY GDEMTED WILE SRITDOW. SIGNAL IlOECTION GENERATED DURING ELECTRICAL MINTENANCE WORK DlE TO INADEQUATE FUSE REPLACDENT PROCEDlRE.

14. RANCHO SECO BW 84-015 840319/2251 HIGH PRESSURE 01 FALSE ERROEOUS MAMJAL START OF If! PER PROCEDlRE INJECTION FOR TOTAL LOSS OF INSTRUPENTATION POWER TO leil SYSTEM. ON.Y OE CHANEL OF POER LOST DLRING ECOVERY FROM MIN 00ERATOR HYDROGEN EXPLOSION EVENT WILE AT 92%

POER. POER LOST DlE TO OVERVOLTACE TRIP SETPOINT DRIFT.

15. SAN ONOFRE 2 E

84-016 840309/1933 CHARGING 1001 FALSE PERSOPHEL ERROR DLRING ESF LOGIC TESTING WILE AT RI.L POER. PROCEDlRAL STEPS OMITTED DURING CHAMEL TRIP LOGIC RESET ANDTEST.

16. SAN ON0FE 3 E

84-004 840222/1940 CHARGING 01 FALEE EQUIPPENT FAlllIE (PUSISUTTON CONTACTS DIRTY) DlRING PLANT PROTECTION SYSTEM TEST WILE SRITDOW WITH STEAM BUBBLE IN PRESSLRIZER. FAILURE RESlLTED IN ERROE0VS DEBERGIZATION OF TRIP LOGIC 1

MTRIX.

17. SEQUOYAH 1 EST 84-035 840521/2234 NOT DEFIED 01 FALSE EQUIPtENT FAltlRE (FUSE) IN VITAL INVERTER DURING REACTOR SCRAM FROM 1001 POER.

, SCRAM ASSOCIATED WITH TlRBIE/ GENERATOR

. BEARING FAILlRE.

1 56-me y

i, e...

TAB E A.7 (CONTI M D)

ESF ACTUATIONS - SAFETY IILECTION EBTS ECCS EACTOR NSSS lEPORT EVENT I M CTION P0 6 ACTUATION tmIT VE)OOR NLfGER DATE / TIE EQUIPlGT EVEL TYPE DESCRIPTION OF EVENT

18. SlffER EST 84-011 840210/0537 NOT DEFIED 01 VALID HIGH STEAM.IE DIFFERENTIAL PESSURE (NOB)

DLRING EC0VERY FROM REACTOR SCRAM FROM 18% POE. HIGH STEAM.IE DIFFERENTIAL PRESSWE SIGNAL GOEPATED DlE TO PERS01@ del.

j EMOR ASSOCIATED WITH STEAN VALVE EALIGl#ENT. SGAN CAUSED BY PERS0l#El.

ERROR ASSOCIATED WITH TlRBIE LLEE OIL.

19. SLERY 1 EST ~ 84-005 840301/2135 NOT DEFIED 01 FALSE ERROEOUS HIG! CONTA!!fENT PRESSLRE SIGNAL CONCLRRENT WITH HIGH STEAM FLOW SIGNAL GEMRATED WILE LMIT AT COLD SWTDOW.

' SIGNALS GOERATED DlE TO PERS010EL ERROR DLRING VITAL BUS TRANSFEk PROCE M E.

20. TROJAN IEST 84-003 840218/0445 NOT DEFIED 1001 FALSE PERS010EL ERROR DLRING VALVE TESTING GOERATED SIltLATAIEOUS EACTOR SCRAM Ale ECCS ACTUATIONS WILE OPERATING AT FlLL P06. ERROR OCClRRED IN IIPROPER FUSE REMOVAL /REPLACDENT IN PREFERRED INSTRifENT BUS ESlLTING IN DEBERGIZATION ;

OF PROTECTION SYSTEM BISTABLES.

21. TROJAN EST 84-007 840428/1624 NOT DEFIED 01 FALSE ERROEOUS HIGH CONTAlltENT PRESSLRE GOERATED A3 A ESLLT OF INCORRECT BISTABLE P06 SLPPLY LEAD REMOVAL DURING ECCS TESTING WIE LMIT WAS IN HOT SWTDOW. PROCEDLRE DID NOT SPECIFICALLY ADDRESS lelICH LEADS B E TO BE LIFTED.

22. ZION 1 EST 84-002 840102/1539 NOT DEFINED 0%

VALID i.0WPRESSLRIZERPRESSURESIGNALLDSLOCKED (ISB)

DlRING TESTING leilLE LMIT IN COLD SWTDOWN.

PERS0WEL ESET IRONG RELAY leilLE

' ETERNING SAFEGUARDS PNEL TO NORMAL.

23. ZION 1 IEST 84-004 840120/0912 NOT DEFILED 0%

VALID LOW PRESSLRIZER PRESSURE SIGNAL GENERATED (leB)

DLRING HOT SWTD06M DEPE5SlRIZATION FOR MAINTENANCE. PERS010EL DID NOT BLOCK SIGNAL leEN PERhlSSIVE LIGHT ACTIVATED.

ABBREVIATIONS ECCS = DERGENCY CORE COOLING SYSTEM Pfl! = N0lHiUCLEAR INSTRl#ENTATION ESF = ENGDEERED SAFETY FEATIRE PCIS = PRI!NY CONTAllfENT ISOLATION SYSTEM W I = HIGH PRESSURE INICTION RPS = REACTOR PROTECTION SYSTEM leB = NON-DESIGN BASIS SIAS = SAFETY INECTION ACTUATION SYSTEM 57

r...

TABLE A.8 4

ESF ACTUATIONS - ASSOCIATED FAILlRES DOCKET NSSS REPORT EVENT LMIT(S)

' N.MBER VENDOR NUMBER DATE / TIE FAILlRES REASON 1.

BEAVER VALLEY 50-334 EST 84-004 840524/0239 DIESEL GEERATOR START CONSERVATIVE RELAY SETTINGS COOLING TOER PW START CONSERVATIVE RELAY SETTINGS STEAM D W VALVE FAILWE TO SWITCH CONTACTS DIRTY OPEN IN T(AVE) MODE 2.

BROWS FERRY 1 50-259 GE 84-011 840209/0928 SOLEN 0ID VALVE FAILS.

RM0M COIL BWN OUT 3.

BROWS FERRY 3 50-296 GE 84-002 840125/2205 DIVISION II SECO W ARY RMOM RELAY FAILWE CONTA!!#ENT ISOLATION LOGIC INITIATION NOT COPPLETED 4.

BRlNSWICK 1 50-325 GE 84-005 840501/0109 TRAIN B CONTROL ROOM EERGENCY TERMAL OVERLOAD'DUE TO LN(N064 AIR FILTRATION FAN TRIP CAUSE 5.

CRYSTAL RIVER 3 50-302 BW 84-003 840228/1039 DIESEL GEERATOR TRIP FIELD OVERCURRENT WILE SYNORONIZED TO GRID 6.

DAVIS BESSE 1 50-346 BW 84-003 840302/1221 MAIN STEAM SAFETY YALVE COTTER PIN FAILlRE j

FAILlRE TO CLOSE AUXILIARY FEEDWATER VALVE IPPROPER TORGE SWITCH SETTING FAILlRE TO OPEN l

MAIN STEAM SAFETY VALVE l#$NOW FAILlRE TO OPEN 7.

DIABLO CANYON 1 50-275 WEST 84-001 840106/1415 TRAIN A SOLID STATE PROTECTION BLOW FUSE DUE TO GROUND SYSTEM FAILlRE TO ACTUATE CAUSED BY PERSO E L ERROR 8.

DUAE ARNOLD 50-331 GE 84-001 840107/0009 SAFETY RELIEF YALVE OPENS PERS0l#EL ERROR DURING TESTING <

9.

DUAE ARNOLD 50-331 E

84-008 840123/2247 OE TRAIN OF LOOP SELECTION BLOIM FUSE DlE TO FALLTY LOGIC FAILlRE TO OPERATE LIGHT BlLB SOCKET 10.

FITZPATRICX 50-333 E

84-009 840322/0744 GLM SEAL CONDENSER GASKET EXTRUDED GASKET LEAK IN HIGH PRESSLEE

, COOLANT INICTION SYSTEM f

11.

FITZPATRICK 50-333 GE 84-010 840325/0423 GLAND SEAL COEENSER GASKET LN(NOW GASKET FAILlRE LEAK IN HIGH PRESSLRE COOLANT INICTION SYSTEM 12.

FORT CAU40lM 50-285 CE 84-003 840314/1411 COMP 0ENT COOLING WATER PW EXCESS FLOW DUE TO EAD LOSS LOST DE TO CAVITATION TW OUGH RAW WATER SYSTEM 13.

GRAND GlLF 1 50-416 GE 84-016 840324/0135 DIESEL GEERATOR START FAILlRE l#RNOW 14.

GRAND GlLF 1 50-416 GE 84-028 840507/2045 "B" RECIRClLATION PUPP FAILlRE HYDRALLIC POWER UNIT FLOW TO ESTART CONTROL VALVE FAlLlRE A2 PRESSURE GUAGE SETPOINT DRIF DIESEL GElERATOR TRIP REVERSE POER IE TO PERS010El ERROR 14EN PARALLELED TO GRI DIESEL GEERATOR TRIP CONSERVATIVE REVERSE POER RELAY SETTING 15.

E. I. HATCH 2 50-366 GE 84-003 840115/le REACTOR WATER CLEAMP ISOLATION UrtNOW VALVE FAILURE TO CLOSE 16.

PEACH BOTTOM.2 50-277 GE 84-002 840321/0130 CONTAI! MENT ATHOSPERIC RELAY REPLACEMENT WIRING DILUTION LOGIC FAILURE ERROR 17.

PRAIRIE ISLAND 2 50-306 EST 84-001 840618/0740 BORIC ACID STORAGE TAft: VALVES VALVE POSITION LIGHTS FAILlRE TO CLOSE IGNORED BY PERSCl#EL 18.

SAN ON0FRE 2 50-361 CE 84-002 840130/0650 CONTAllfENT PURGE VALVE SEARED MOTOR PINION GE FAILlRE TO CLOSE i

19.

SEQUOYAH 1 50-327 EST 84-002 840118/1451 RADIATION MONITOR VACUUM Pt#P EQUIPENT FAILURE

~58

7... $

TAILE A.8 (CONTIMED)

ESF ACTUATIONS - ASSOCIATED FAILLES DOCET NSSS REPORT EVENT UNIT (S)

NUMBER VE)00R NUMBER DATE / TIE FAILWES REASON 20.

SWRY 1 50-200 EST 84-005 840301/2135 C(NTADfENT PWGE EXHAUST FAN LOW DIFFERENTIAL PRESSLEE DUE

)

FAILURE TO START TO DArPER IRIS MANUALLY CONTROLLED 21.

SUSQUEHAPNA 1(2) 50-387 OE 84-014 840305/1315 MOTOR OPERATED AIR BREAKER LOOSE SET SCREWS ON FAILlRE TO OPEN HIGH SPEED GROLMD SWITCH CONTROL ROOM HIGH SPEED GROLMD LOOSE SET SCREWS ON SWIT01 POSITION IM)ICATION HIGH SPEED GR0lMD SWITCH LOST NORMAL TELEPHOE SYSTEM LOST LN00M 22.

TIEKEY POINT 3(4) 50-250 EST 84-007 840216/0925 AUXILIARY BEAKER FAILLRE LOOSE 80l'.TS ON BREAKER TO AUTOMATICALLY TRIP ECHANISM 23 VERMONT YA>0(EE 50-271 GE 84-001 840105/1252 REACTOR FEED PUPP TRIP LIVE 1. INSTRLDENTATION SETPOINT GUT OF CALIBRATION 24.

ZION 1 50-295 EST 84-004 840120/0912 CONTAIENT FAN START FAILLEE LNDEFIED IN EVENT REPORT e

e B

59 9

f.

s Trends and Patterns Report of Unplanned Reactor Trips at U.S. Light Water Reactors

)

in

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1984 l

August 1985 l

Program Technology Branch Office for Analysis and Evaluation of Operational Data i

e Prepared By:

Lawrence Bell Patrick O'Reilly Marcel Harper

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NOTE:

This report documents the results of a study by the Office for Analysis and Evaluation of Operational Data. The findings and recomendations do not necessarily represent the position or requirements of the responsible program office or the Nuclear Regulatory Comission.

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Trends and Patterns Report Unplanned Reactor Trip at U.S. Light Water Reactors in 1984 Page Number EXECUTIVE

SUMMARY

1

1.0 INTRODUCTION

.......................................... 5 2.0 OVERVIEW OF 1984 UNPLANNED REACTOR TRIP STATISTICS.... 8 2.1 Reactor Tri ps Above 15% Power....................

11 2.1.1 Initiating Systems.........................

11 2.1.2 Causes....................................

17 2.1.3 Contribution From Maintenance, Testing and. 23 Calibration 2.1.4 Pl ant Tri p Pates.......................... 28 2.2 Reactor Trips At or Below 15% Power.............. 32 2.2.1 In i ti a ti ng Sys tems........................ 34 2.2.2 Causes.................................... 34 2.2.3 Contribution From Maintenance Testing and. 38 Calibration t

2.3 Summary of Findings and Conclusions Based on 1984'. 39 i

Reactor Trip Statistics 3.0 REACTOR TRIPS WITH ASSOCIATED FAILURES................

42 r' '

4.0 COMPARISION OF U.S. AND FOREIGN REACTOR TRIP RATES.... 44 i

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l I

11 i

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a, 1

r Page Number APPENDICES.................................................. 48 l

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Appendix A - Unplanned RPS Actuations at U.S. LWRs.... 49 in 1984 Appendix B - Sumary of 1984 Unplanned Reactor Trip... 62 Statistics by Plant Appendix C - Human Error Induced Reactor Trips........ 65 Above 15% Power Appendix D - Component and Piece-Part Failures........ 75 Above 15% Power Appendix E - Quality of LER Reactor Trip Information.. 76 Appendix F - Reactor Trips With Associated Failures... 78 Appendix G - Trips at Foreign Reactors................ 89 e

e iii

List of Figures Page Number Power Di stribution For Reactor Trips..................

12 2.1-1 i

Above 15% Power 2.1-la Trip Frequency vs. Number of Plants...................

13 2.1-2 Valve Failures, Reactor Trips Above 15% Power......... 21

)

Human Errors, Type of Personnel....................... 22 l

2.1-3 Reactor Trips Above 15% Power 2.1'-4 Causes - BOP Reactor Trips............................ 24 Power Greater Than 15%

2.1-5 Causes - Electrical System Reactor Trips.............. 25 f

i Power Greater Than 15%

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2.1-6 Causes - RPS Reactor Trips............................ 26 Power Greater Than 15%

2.1-7 Activity Underway at Time of Trip..................... 27 Power Greater Than 15%

2.1-8 Major Systems Affected By Maintenance................. 29 and Testing, Power Greater Than 15%

2.1-9 Plant Reactor Trip Rates vs. Critical Hours........... 30 Power Greater Than 15%

2.2-1 Reactor Trips At or Below 15% Power,.................. 33 Power Distribution 2.2-2 Systems Initiating Reactor Trips.......... !.......... 35

)

At Power >0% and 5 2%

l 2.2-3 Systems Initiating Reactor Trips...................... 36 At Power > 2% and s 15%

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List of Tables Page Number 2.0-1 1984 U.S. LWR Unpl anned Tri ps......................... 9 2.0-2 Average Annual LWR Trip Rates, 1983 vs. 1984..........

10 Per Reactor Per Year 2.1-1 Initiating Systems Summary, Power Greater Than 15%....

14 2.1-2 Initiating System Classes by NSSS Vendor..............

15 2.1-3 Electrical Systems Summary, Power Above 15%........... 16 2.1-4 Cause Summa ry, Power Greater Than 15%................. 18 2.1-5 Summary of Component Failures Causing Reactor Trips... 20 Power Greater Than 15%

2.1-6 Plants With Relatively Poor Trip Experience in 1984... 31 37 2.2-1 Cause Summary, Power Below 15%.

4.0-1 LWR Reactor Trip: Rates By Country - PWR................

44 4.0-2 LWR Reactor Trip Rates By Country - BWR............... 45 i

O r

.=

ie EXECUTIVE SUPMARY This report analyzes unplanned trips (i.e., scrams) that occurred at U.S.

power reactors in 1984. This study is one of a series of periodic AE00 l

trends and patterns analysis reports which will draw upon the more complete and detailed operational experience infomation required as of January 1,1984 i

by the Licensee Event Report (LER) rule (10 CFR 50.73).

In this report we define a reactor trip (i.e., scram) as any actuation of the Rea'ctor Protection System (RPS) which results in control rod motion. The progression of events leading to reactor trips and the post-trip response of the plant and personnel have obvious safety significance. Further, the Comission has concluded that a reduction in the frequency of challences to plant safety systems should be a prime goal of each licensee.

i Findings and Conclusions Based on the analysis of the reactor protection system actuations that occurred i

in 1984, the following conclusions can be made:

1.

Out of 622 unplanned RPS actuations reported in 1984, we identified a

~

total of 494 reactor trips. Two of these trips occurred at Byron, which held only a 5% power license for the portion of 1984 in which the scrams occurred.

The remaining actuations occurred while the plant was already shut down and, i

thus, did not result in rod motion.

2.

In August 1984, NRR published an analysis of 1983 scram statistics extracted from the NRC Operations Center data base.

In that study NRR identified a total of 496 trips. NRR then calculated an average trip rate of 6.5 trips per reactor per year by dividing 496 by 76 (i.e., the total number of LWRs holding or receiving a full power license during 1983). Perfoming the comparable calculation for 1984, we identified 492 trips at 83 reactors with full power licenses, for an average rate of 5.9 trips per reactor per year.

Thus, in tems of the overall perfomance of the industry we observed a slight decline (9%) in the rate of automatic and manual reactor trips from 1983 to 1984.

i 1

u.

1.

As part of the AEOD analysis of reactor trip experience, trip rates for plants in other countries were collected and analyzed. Only rough l

comparisons are possible at this time due to the age and relative lack of documentation of foreign data. However, it appears that the average reactor trip rates for the countries examined (France, Japan. West Gemany, Sweden) were below those for the U.S. reactor population of both BWRs an'd PWRs.

J 4.

While there is a tendency to focus on average behavior, neither the U.S. PWRs nor BWRs are homogeneous groups. There was significant variation in l

trip rates within the Westinghouse subclasses and the GE class. In fact

• certain U.S. reactor classes (e.g., Westinghouse 2-Loop reactors and 88W l

reactors) had scram rates that are comparable to the better foreign experience.

5.

Seventy-seven reactor trips had the post trip recovery complicated by equip-ment failures or personnel errors unrelated to the cause of the reactor trip.

About 20% of all trips above 15% power had one or more associated failure or We believe that more detailed reporting would reveal an even higher error.

percentage. We are concerned about both the overall number of such situations, and about the number of instances in which post-trip fa'ilures went uncorrected as demonstrated by their repetition following subsequent trips. Plants which demonstrated repetitive associated failures include Oconee 1 Surry 1, Surry 2, Fitzpatrick, Arkansas 2, Sumer, and Grand Gulf.

l 6.

We found that 68% of all reactor trips in 1984 occurred while the plant was at a power level above 15%. Further, 31% occurred from above 95% power.

Thus, it appears that a significant fraction, approximately one-third, of all reactor trips occurred from high power with attendant high levels of decay heat. This is contrary to the frequently stated hypothesis that most reactor trips are due to problems during start up.

7.

Above 15% power, 59% of the disturbances resulting in reactor trips originated in the following Balance-of-Plant (80P) systems: Feedwater - 27%,

Turbine - 15%, Condensate -6%, Main Generator - 6%, Main Steam - 5%. Below i

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2% power, faults in the Reactor Protection System itself were the dor.inant

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Between 2% and 15% power, again the Feedwater - 40% Turbine - 18%,

source.

and Main Steam - 13% combined for 71% of all trips that occurred between 2%

and 15% power.

8.

Hardware failure was the' dominant cause of unplanned reactor trips above 15% power. Cataloging the individual pieces of hardware, however, reveals a vast array of components and piece parts responsible for trips. This diversity suggests that it will not be possible to achieve significant

' reductions in reactor trips by focusing on a few " problem components" on an industry-wide basis. Rather, the solution seems to lie in addressing problems with the components which dominate at a particular plant, as well I

as greater attention to improved hardware condition at each plant.

4 9.

We note that the largest single class of events leading to reactor trip j

(i.e., hardware failure in major BOP systems) is historically and currently outside regulatory purview. The needed improvement in B0P material condition is the responsibility of individual licensees and industry groups. The reduction of this source of unplanned reactor trips over time will be a key 2

indication of industry efforts at self-improvement.

I r'

10. Personnel-related problems (i.e., human error, manual steam generator level control problems, and procedure deficiencies) were a substantial but secondary cause of reactor trips above 15% power, accountine for 28%. Focusing on the trips caused directly by human error (75 trips) we found that nearly half (34 trips) could be traced to unlicensed personnel. Thus, errors by unlicensed personnel account for at least 10% of all reactor trips above 15%

.1 Therefore, continued efforts to improve the performance of unlicensed l

power.

personnel appear warranted.

11. Below 15% power hardware failures also predominate, but the contribution from personnel problems (at 46%) is higher than that above 155 power. This i

3

1 1

i increased contribution tioes not result solely from manual steam generator level control problems, or from increased maintenance and testing at lower The latter conclusion is based on our finding that the percentage power.

of trips due to planned maintenance and testing is nearly equal above and below 155 power, 29% and 24% respectively, 28% overall). This leads us.to j

the conclusion that problems in executing the basic procedures necessary to start up the facility are responsible for the difference.

12. The proportion of reactor trips associated with planned maintenance, calibra.

tion, and testing activities was about 305. However, one should not equate

, problems arising while performing maintenance, calibration, and testing with errors by personnel performing these activities.

In particular when we reviewed the relevant trips above 15% power we found that the root cause of the trip

~

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in 37% of the cases was a hardware failure.

13. It appears that the trip experience for a number of plants (WPPSS 2 Callaway, Grand Gulf, Susquehanna 2, Salem 1, Salem 2, McGuire 2. Hatch 7, l'

Diablo Canyon, and LaSalle 2) was relatively poor, considering the amocnt l

of time (i.e., critical hours) that the plant were in operation during 1984 The trip experience of these plants was reviewed in detail to determine if i

any unique factors were responsible for the relatively high trip rates. Iti general these plants fit the profile of BOP hardware failure as the-dominant cause of reactor trips, with a variety of root causes at each plant. WFPSS 2 and McGuire 2 were exceptions. Both shewed a significantly higher peretntage of trips due to personnel error during testirg and maintenance than the rest f

of the population.

14. We found that manual steam generato.- level control problems at low power are a relatively minor contributor to unplanned reactor trips. We attributed only 23 of 329 total PWR trips to such problems, amounting to only 7%.

4 1

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e 1,.0 INTRODUCTION This report inalyzes unplanned tr!ps (i.e., scrams) which occurred at U.S. power reacters in 1984, This study is one 6f a series of periodic AE00 trends and patterns analysis reports which will dr.aw u'pon the more coniplete and detafled operational experience information required as of January 1,1984 by the Licensee Event Report (LER) 'cule (10 CFR 50,73). This report is an expansion of the AE00 pilot study (P406),

• Trends and Patterns Analysis of Unplannet! Reacttr Scrams at U.S.1,ight Water Reactors". Subsequent reports on this subfect w!11 be q

prepared annually.

Safety Significance of _ Reactor Trips The,re are ger.erally three phases to a schnerio or sequence of events involvir,g a 'reacter trip. First, there is the generation of some off-normal plant state which results in ope' ration of the Reactor Protecticn System (RPS) and portions of the Control Rod Drive System (CRDS). Second, there is the operation of the RPS and CROS themselves. Third, there is i

the plant and operator respcase to the trip. Each phase has safety I

significancet The RPS is designed to sense movement of the plant toward a state wherein fuel integrity or reactor coolant system integrity is potentially threatened.

~

l l

r While margins to damage are routinely incorporated in the design of the RPS, the cause and progression of such incidents have obvious safety significance.

rurther, the Commission has concluded that a reduction in the frequency of q

challenges to plant safety systems should be a prime goal of each licensee, g

!E and the Consnission believes that large Anticipated Transient Without Scram (ATWS)riskreductionscanbeachievedbyreducingthefrequencyoftransients which call for the RPS to operate.

In this regard, the Copenission is, interested both in events where the RPS was needed to mitigate the consequences of a l

transient, and events where an RPS operated unnecessarily.

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Proper operation of the RPS/CRD$ in response to a valid demand is obviously, a' major safety concern.

F?nally, becayse of the n pid change in the plant state, each t~ rip represents a potentially stressful situation during which additional equipment operation and cperator cctions are generally need64 in order to bring the plar.t to a s'afe and controlled condition. Thus we have a safety interest in kno6#ing the pro-pcFtion of unplanned reactor tefps where recovery was ceinplicated by additicnal equipment failures or operator errors, and the nature, ext 6nt pd ca9ses of tt;ose coqolications.

4

~

fources of Dats Lic6:nsee Event Reports which reported zn unplanned RF5 actuation were

~

selected for detaileo review and subsequent sorting by.1 number of categories (e.g., pewtr 16 vel prior to the actuation, inf tf ating system).

Paragraph 50.73(a)(S)(iv) cf the LER fule requires reporting of:

"Any event or conditten th6t resulted in nanual or autonatic attuation of any Engineered Safety Featcre (EST), including the Peactor ?rotection System (RPS). ftwever, actuation of an ESF., including the RPS, that resulted from and wa's part of the preclanned sequence during -test.ing or testing or reactor operation need not to be reported."

Thus, actuations that ne6d not be r$ ported and ttere' fore are outside the e

scope of this report are those initiated at the discretion of the licensee I

as part of a planned procedure or evolution.

1 Licensee Event Reports were the sole source of technical details about reactor trips. Licensees were not contacted for additional infonnation or clarification, However in order to ensure that we had a templete set

• of reports of unplanned reactor trips, we also reviewed the data on reactor trips availab1'e from the NRC Operations Center computer file. A complete listing of the RPS actuations identified for 1984 is provided in Appendix A, l

6

e Analysis Methodology In this report, we attempt to analyze the reactor trip experience from numerous perspectives in order to gain as much insight as possible from this operational experience data.

Initially, the data is viewed in aggregate, in order to determine the trend in trip experience. Then the data is " cut" based on a number of variables (e.g., plant, NSSS vendor, cause, system in which the transient initiated, power level) in order to identify any patterns or outiiers that may De worthy of further study. Finally, the date for U.S.

rehclors It compared to the experience in several foreign countries in order In each to pr6yide some perspective en the trip experience in this country.

sectich, the most dominant, significant, and/or interesting trends or patterns are dateribed in scme detail.

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l 2.0 OVERVIEW OF 1984 UNPLANNED REACTOR TRIP STATISTICS

~

We identified a total of 622 unplanned RPS actuations at U.S. Light Water Reactors (LWRs)in1984. These RPS actuations occurred over the whole range of plant status, from shutdown and de-fueled to operation at 100%

In this report we define a " reactor trip", or equivalently " reactor '

power.

l scram", as an RPS actuation which resulted in control rod motion, regardless of whether the reactor had achieved criticality prior to the rod motion. Using this definition we. identified 494 reactor trips (i.e., reactor scrams) in 1984.

Tab.le 2.0-1 provides an overview of the 1984 unplanned reactor trip statistics. Division by power level is driven by the distinctly different operating regimes during startup (defined for this report as equal to or less than 15% thermal power), and power operation which we defined as any power

~

level above 15%.

Analysis of the data (in Table 2.0-1) by NSSS vendor, and by vendor tubgroups is provided because this is such a widely used basis for classifying reactors.

~

However, the reader is cautioned not to infer a strong causal link between NSSS vendor and the occurrence of reactor trips. The range of trip rates show wide variation among individual plants belonging to the same NSSS vendor class. Appendix B provides reactor trip statistics by plant.

?-

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Table 2.0-1 1984 U.S. LWR Unplanned Trips Total No.

Number of Trip Rate Per No. of of Startup Startup TPips 1000 Critical Hours NSSS Group Units Trips (Power 5 151)

(Power > 15%)

Avg No.# Range Avg Rate Range Westinghouse:

2-loop 6

7 1.2 0-3 0.1 0-0.4 Early 4-loop 2

2 1.0 0-2 0.5 0.3-0.8 3' loop 12 29 2.4 0-6 0.9 0-1.6 4-loop 15 45 3.0 0-8 1.2 0.3-5.3 General Electric 29 46 1.6 0-7 0.8 0-5.7 Combustion Engineering 11 23 2.1 0-9 0.6 0.2-1.2 Babcock &

Wilcox 7

1 0.1 0-1 0.4 0-0.8 l

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Comparison of 1983 and 1984 Trip Expcrience i

In August 1984, NRR published an analysis of 1983 scram statistics extracted from the NRC Operations Center data base (reactor trips were not routinely reported in LERs until 1984). In that study NRR identified a total of 496 trips. NRR then calculated an average trip rate of 6.5 trips per reactor per year bly dividing 496 by 76 (i.e., the total number of LWRs holding or receiving a full power license during 1983). Performing the comparable calculation for 1984, we identified 492 trips at 83 reactors with full power licenses, for an average rate of 5.9 trips per reactor per year. Table 2.0-2 shows these 1983 and 1984 rates further broken down into manual and automatic trip rates.

Table 2.0-2 Average Annual LWR Trip Nates, 1983 vs 1984 (Per Reactor Per Year)

Average Rate Percentage Trip Type 1983 1984 Change Manual 0.9 0.7

-22%

Automatic 5.6 5.2

- 7%

Total 6.5 5.9

- 9%

In terms of the overall performance of the industry we observe a slight decline (9%) in the rate of reactor trips from 1983 to 1984.

4 10

2.1 Reactor Trips Above 15% Power Figure 2.1-1 displays trip counts as a function of power level. Three hundred thirty-seven or 68% of all reactor trips in 1984 occurred at power levels above 15%. More significantly 152 (31%) of all 1984 reactor trips occurred above 95% power. Thus, it appears well established that a significant fraction, approximately one-third, of all trips occur from high power with attendant high levels of decay heat. This is contrary to the frequently stated hypothesis that most reactor trips are due to problems during startup.

The' distribution of trip frequency vs. number of plants for 1984 is shown in Figure 2.1-la.

2.1.1 Initiating Systems We examined each reactor trip to determine the system containing the root cause of the reactor trip. That system was designated as the " initiating system" if hardware belonging to that system failed; or if operation, maintenance, or testing of that system lead to the reactor trip.

In

j naming systems and making assignments of faults to the systems, we used nomenclature and boundaries developed for the Nuclear Plant Reliability Data System (NPRDS) whenever possible. The results of this categorization are shown in Table 2.1-1.

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REACTOR TRIPS AB0VE 15% POWER '

POWER DISTRIBUTION ICDPOINT POWER FREQ CUM.

PERCENT CUM.

FREQ PE,RCENT

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28 M,

48 46 13.S5 13.85 38 M

28 74 8.31' 21.98 h

9 83 2.87 24.83 48 ES 17 ISO 5.84 29.67 88 15 115 4.45 34.12 78 18 133 5.34 38.47 e8 g.3 18 ist 5.34 44.si 88 M

34 185 18.88 54.98 188 152 337 45.18 188.e8 8

28 48 88 88 188 128 148 188 l

FREQUENCY NOTE POWER: 28 NEANS 18X THROUGH 24X,188 MEANS SEX THRUSH 198X FISURE 2.1-1 4.

12 i

._~~,l..

l

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i l

.984 "3PS AB0VE 15% POWER TRIP FREQUENCY VS. NUMBER OF PLANTS NUMBER OF PLATUS I5 -

7,

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1 2

3 4

5 6

7 8

9 12 16 17 FIGURE 2.1-1A 3-

'f TRIP FREQdE'NCY

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13

Table 2.1-1 Initiating Systems Sunnary Power Greater Than 15%

Number of Percent Systems Trips of Total

• Feedwater 91 27

• Turbine 49 15 Electrical Distribution 46 14 Reactor Protection 32 9

• Condensate 21 6

• Main Generator 21 6

• Main Steam 18 5

Control Rod Drive 10 3

Other (23 systems) 49 15 Total 337 100

? -

Balance of Plant System 14 4

l

.,-,,....-.-..,7,._

m.. _ _

We found that roughly 59% of the faults resulting in reactor trips initiated in the major balance-of-plant (BOP) systems, where the dominant contributor proved to be the feedwater system. While balance-of-plant systems are designed by a large number of architect engineers with a wide diversity in design features, 1

the BOP dominance is essentially preserved when reactor trips are further cale-gorized by NSSS vendor as shown in Table 2.1-2 for major NSSS vendors.

Table 2.1-2 Initiating System Classes by NSSS Vendor Westinghouse CE B&W GE Number Percent Number Percent Number Percent Number Percent BOP Systems:

Feedwater 61 39 8

19 4

20 17.

15 Other BOP 35 22 13 31 5

25 56 51 Total - BOP 96 61.

21 50 9

45 73 66 Non-BOP 62 39 21 50 11 55 87 34 Total 158 100 42 100 20 100 110 100

? -

The Electrical Distribution System and Reactor Protection System are the only non-BOP initiating systems with more than 10 reactor trips each. The Electrical Distribution System is actually an amalgamation of various safety and non-safety l

subsystems. Table 2.1-3 gives additional detail. The buses primarily affected are the vital AC buses and the 4.16KV (non-vital) buses. Losses or ups'ets on the vital AC buses usually cause actuation of one or more RPS channels and subsequent reactor trip.. Interruptions or failures on the 4.16KV bus cause the loss of large electric motors, which subsequently result in reactor trip.

15

)

1 a

.-,.n.,

-,n.

,,,,,n,.-,,.,,~....-_,..,.,.,,_.mn..._

,,..-,n,,-,,,-.,,.-,a..~

n.,

n-..

...... ~..... -.

Table 2.1-3 Electrical Distribution System Sumary (Power Above 15%)

Number of Trips Percent ~

Subsystem Vital AC Buses 120 VAC 15 33 4.16KV Buses 13 28 Offsite Power Feeds (115KV,230KV,345KV,500KV) 6 13 Power Supply to Reactor Coolant 4

9 Pumps 480V Buses 3

7 Unidentified Electrical Problems 3

7 Power Supply To Control Rods 2

4 Totals 46 100 o

l i

16 4

2.1.2 Causes The LER description of each reactor trip was reviewed to determine the general classification of the root cause or causes as shown in Table 2.1-4. While most of these categories are self-evident, the Manual Steam Generator Level Control

~

category requires some further explanation. This category was es'tablished for i

situations in which the licensee attributed the trip to general difficulty in f

controlling steam generator, while not specifically citing operator error in controlling water level. The latter cases were categorized as Human Error.

l i

i m.

W 9

e i

,e*

I e

e 17

._e__m.m_._.__________

l..

Table 2.1-4 Cause Summary (Power Greater Than 15%)

N yber Percent Cause Reactc Trips of Total Hardware Failure 204 60 Human Error 75 22 Procedure Deficiencies 12 4

4 Hardware Failure & Human Error 11 3

Eny'ironmental 10 3

Unknown 10 3

Manual Steam Generator Level Control 8

2 Cause Not Provided 5

1

System Design

2 q

Total 337 99*

3

• Does not add to 100% due to rounding.

?

18 4

l

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

l-.

Above 15% power hardware failures dominated. Table 2.1-5 provides a sumary of the components involved in these failures by generic classes. Appendix D contains a complete list of components or piece-parts as reported by the licensee, and demonstrates the wide range of hardware types whose failure resulted in a reactor trip. This diversity suggests that it will not be possible to achieve significant reductions in reactor trips by focusing on a f

few " problem components" on an industry-wide basis. Rather, the solution seems to lie in the addressing problems with the components which dominate at l

a particular plant, as well as greater attention to improved hardware condition at each plant.

At this time, valve failures represent the only large class of component failure.

Figure 2.1-2 displays all valve failures by valve name. Note that the Feedwater Regulating Valve, Main Steam Isolation Valve (MSIV) Turbine Stop Valve, and

~

Moisture Seperator Reheater (MSR) Drain Valves were the major contributors. The system most affected by valve failures was the Main Steam System where 39% of all reactor trips attributed to this system were the direct result of unanticipated closure of one or more MSIVs. All other valve failures represent approximately 10% or less of the associated system initiated trips.

Personnel related problems (i.e., Human Error, Manual Steam Generator Level Control problems, Procedure Deficiencies) accounted for 28% of all reactor trips above 15% power, making them a substantial, but secondary cause.

Appendix C provides further detail on the 75 trips categorized as Human Error in Table 2.1-4.

The type of personnel responsible for these trips is displayed in Figure 2.1-3.

The categories in the figure reflect the level of detail provided in the LERs (i.e., we were not able to detemine the license status for22ofthe75 cases). However, the fact remains that at least 34 of 75 (45%) trips were attributed to unlicensed personnel (e.g., technicians, vendor staffs, contractors) with unlicensed technicians by far the largest contributor.

Thus, errors by unlicensed personnel accounted for at least 10% of all reactor trips from above 15% power. Therefore, continued efforts to improve the per-fomance of unlicensed personnel appear warranted.

i

<19

---

_m.____-.----.-_-

i Table 2.1-5 Susanary of Component Failures Causing Reactor Trips Power >15%

Electrical /

Mechanical Electronic Components Components No. of No. of Component Trips Component Trips Valves 35 IC Circuits 16

)

Pumps 13 Relays 10 Heater Tubes 5

Breakers 10 Control Switches 9

Air Lines 4

Fuses 7

Controllers 7

Transmitters 6

~

Others 26*

Power Supplies 5

Total 53 Instr. Channels 5

Transformers 4

Others 27*

Total 106 This class combines a large nusber of categories (26 for mechanical components; 27 for electrical / electronic components) of component failures each of which contains three counts or less.

In addition, in 15 cases the component that failed was not specifically identified.

f 4.

20

l l

~

i i

VALVE FAILURES REACTOR TRIPS ABOVE 15X POWER s

VALVE FREQ CUM.

PERCENT CUM.

FREQ PERCENT FV REGULATION xxxxxxxxxxxxxxxxxxi 18 18 28.87 28.57 MSIV wwwvwwvi 7

17 20.00 48.57 TUR5INE STOP xxxxxxx1 4

21 11.43 60.00

~

YYxxx1 3

24 8.57 68.57 MSR DRAIN STEAM DUMP 2

1 25 2.86 71.43 SG FW ISOL 2

1 26 2.86 74.29 CONDENSATE CLEAN 2

1 27 2.86 77.14 FVP CONDENSER S

1 28 2.86 80.00 SAFETY RELIEF l2 1

29 2.86 82.86 SG INLET CHECK

'E 1

38 2.86 85.71 FV BYPASS 2

1 31 2.86 88.57 PRESURIZER SPRAY Z

l 32 2.86 91.43 CIRC FLOW 2

1 33 2.86 94.29 MS BYPASS 2

1 34 2.86 97.14 y.

INTERMEDIATE VAL 7

1 35 2.86 188.00 0

2 4

6 8

18 FREQUENCY FIGURE 2.1-2 21 9

.. _.. ~, -.

..-.,m,

,..,_,,.,.-...,_,_,..,_,,_.__,.-,r...,.

.,w,.

_.._..,w,

,-m.,.

.-,.,-__,,,--n,.,_..,,._em.,,,__

= - - -.

1 d

i EUnX ERRORS - TYPE OF ?E3SOE3L' REACTOR TRIPS ABOVE 15X POWER PERSON FREQ PERCENT TECHNICIAN 26 26 34.67 34.67 LIC OPERATOR M

19 45 25.33 60.00 i

LICENSEE STAFF M

10 55 13.33 73.33 NOT DETERMINED M

9 64 12.00 85.33 h

4 68 5.33 90.67 UNLIC OPERATOR f

2 70 2.67 93.33 UNLIC WORKER f

2 72 2.67 96.00 LIC MANAGEMENT CONTRACTOR 1

73 1.33 97.33 VENDOR STAFF 1

74 1.33 98.67 1

75 1.33 100.00.

STAFF OPS l

5 5 5 W 5 W W W g g 5 5 g W g W W

5 5 5 5 5 5 5 5 W g5 gW 0

'10 20 30 FREQUENCY

~

FIGURE 2.1-3 22 I

Section 2.1.1 identified B0P systems, the Electrical Distribution Systems, and the Reactor Protection System as the systems in which reactor trips are most frequently initiated. Figures 2.1-4, 2.1-5 and 2.1-6 show the breakdown of causes within each of these system classifications. There is_a gradual progression in the ratio of hardware-to-personnel causes moving through

~

the figures.

In the BOP systems, hardware failures predominate, accounting for 135 of 200 or 68% of all' B0P initiated trips. Thus, hardware failures in BOP systems account for 40% of all reactor trips above 15% power.

In the Electrical Distribution System, hardware failures are also the largest contributor, although less than in the BOP case.

It is interesting to note that 6 of 10 cases classified as Environmental were associated with the Electrical Distribution Systems; these events include such things as lightning strikes and high winds.

i Finally, in the case of the Reactor Protection System human error predominated.-

However, errors associated with the Reactor Protection System accounts for only I

5% of all reactor trips above 15% power.

2.1.3 Contribution from Maintenance. Testing, and Calibration

}

The concern is frequently raised that maintenance, testing, and calibration at power pose significant risks. Figure 2.1-7 places that risk in perspective.

The activities of testing, calibration, and maintenance were found to be causal factors in 99 (29%) of the reactor trips above 15% power. Thus, these activities i

I constitute.a substantial contribution to the overall reactor trip frequency.'

To gauge whether this is purely a personnel-related problem we examined the causal breakdown within the testing, calibration and maintenance activities. We found that only 50 or (51%) of the 99 trips resulted from human error or procedure deficiences during the testing, calibration,*and j

maintenance. Hardware failures accounted for 37% of these trips. Thus, equipment failures that occurred during testing, calibration, and maintenance j

account for almost as many trips as personnel-related problems.

l

, 23 i

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.--_,,.-_.._.__-.__m_-__,

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

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l 1

CAUSES - B0P REACTOR TRIPS POWER GREATER THAN 15X i

CAUSE FRE0 CLM. PERCENT =

CUM.

FREQ PERCENT HARDVARE M

135 135 87.58 67.58 HUMAN ERROR flflfj'd 38 171 18.00 85.50 h

8 179 4.88 89.50 SG LEVEL h

8 187 4.88 93.58 FROCEDURES j

8 193 3.98 98.50 BOTH NOT PROVIDED 4

197

'2.90 98.50 UNKNOWN 2

199 1.08 99.58 SYSTEM DESIGN I

200 9.58 100.00.

9 58 180 158 FREQUENCY

~~

l BOP SYSTEMS INCLUDE TURBINE CONDENSATE FEEDWATER MAIN GENERATOR MAIN STEAM BOTH HEANS THAT HARDWARE AND HUMAN ERRORS WERE INVOLVED.

FIGURE 2.1-4

\\

24

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

s 3I2CTICAL SYSTEM REACTOR " RIPS l

POWER GREATER THAN 15X CAUSE FREQ CUM. PERCENT '

CUM. -

FREQ PERCENT HARDWARE 23 23 58.99, 58.08 i

^

K. NAN ERROR 10 33 21.74 71.74 h

8 39 13.84 84.78 ENVIRONMENTAL

. NTH 3

42 8.52 91.38 PROCEDURES 2

44 4.35 95.85 NOT PROVIDED 1

45 2.17 97.83 SYSTEM DESIGN t

46 2.17 188.88 0

5 18 15 20 25 FREQUENCY BOTH MEANS THAT HARDWARE AND HUMAN ERRORS WERE INVOLVED.

FIGURE 2.1-5 i

25 t

i

,_m-.... _ _ _,, -

,y.,_,,,_,__...m.-.

.,-,.._-...,..-_.-,,.,y.,.-4

EAC"O R 210"EC"::0X SYSTSY :EAC"0R "R3S POWER GREATER THAN 15%

CAUSE FREQ CLN.

PERCENT CUM.

FREQ PERCENT HUP.AN ERROR 17 17 53.13 53.13 HARDWARE 9

26 28,13 81.25 UNKNOVN 5

31 15.63 96.88 ENVIRONMENTAL 1

32 3.13 100.00 i

i t O

5 10 15 20 FREQUENCY FIGURE 2.1-6 26 i

i

l s

t ACTIV"Y UDERWAY AT TIME OF TRIP POWER GREATER THAN 15X ACTIVITY FREO CUM.

PERCENT CUM.

1

~

FREQ PERCENT STEADY STATE M

125 125 37.09 37.09 TESTING M

75 200 22.26 59.35 UNDEFINED M

40 240 11.87 71'.22 h

33 273 9.79 81.01 STARTUP h'

18 291 5.34 86.35 MAINTENANCE h

18 309 5.34 91.89 TRCUBLESH00 TING f

i1 320 3.26 94.96 SHUTTINCNN f

7 327 2.08 97.03 i

PC'n'ER REDUCTION h

CALIBRATION 6

333 1.78 98.81 f

4 337 1.19 100.00 SPECIAL TEST 0

50 100 150 FREQUENCY FIGURE 2.1-7 i

4.

27 f

.__ _.-. m

.,____,__-_._..___..,.___,_..-_____,._____,_.._.__.,.,.,.._,m.

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

F,igure 2.1-8 displays 24 of the trips which occurred during maintenance, testing or calibration as a function of initiating systems.

Fifteen other trips were related to one system each. Hardware failures are most often involved in the case of the turbine system. Human error dominate RPS testing.

e 2.1.4 Plant Trip Rates Figure 2.1-9 provides a visual display of each plant's reactor trip rate for trips from above 15% power. The axes are trips per 1000 critical hours and the number of critical hours for the plant in 1984. While the wide range of performance in terms of both trip rate and critical hours is evident, the majority of plants cluster in the region bounded by 4800 and 8500 critical hours, with a trip rate less than 1.6 trips per 1000 critical hours (the observed value for Surry2).

S f

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28 1

4

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.-____...-._m.,---.__

. _ _ _.. _. _. _ _ _.. = _ _ _... _.. _. _.

i i

MAJOR SYSTEMS AFFECTED BY MAINTENANCE CALIBRATION & TESTING POWER GREATER THAN 15X FRE0 CUM.

PERCENT CUM.

SYSTEM FREQ PERCENT I

RPS d

20 20 23.81 23.81 TURBINE MMMd 19 39 22.62 46.43-

~

FW M) 15 54 17.86 64.29 MAIN STEAM M

10 64 11.90 76.t9 ELECTRIC!.L kW 8

72 9.52 85.71 CONDENSATE M

6 78 7.14 92.86 i

RCS

$<'j 3

81 3.57 96.43 h

3 84 3.57 100.00 CONTAINMENT

~

0 5

10 15 20 FREQUENCY LEGEND: CAUSE

• • • • < SYSTEM DESIGN EEEEEEE HARDWARE

• * *

• NJMAN ERROR EXZ2 BOTH E X ] PROCEDURES C0000 UNKNOWN ELE 52 NOT PROVIDED I

FIGURE 2.1-8 o

29 e

_______._.______.-....,__-,,_-_-_,_,_._,,.,..__y...~r..___.....____,.-,_._..,_._,.mm-.m_

I 33AC"03 "I:? 3f3S VS CI":CL EJ3S BY :?R POL'ER GREATER THAN 15%

I i

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.:f q.

P 4&

+

L 80302 4+

I 5

A

&++

+4+

+i N

.gg4 ++,

2.+ ' i + % ++ 4

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+xecuire.2 (16)

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+t +

C 6033' 1

1 R

+ 4

++

+

I

.i.

i

++

++

i T

7

+LaSalle 2 (9) l 3/10/84 C 4023-

+

i I

I

+ Salem 2 (8)

L Hatch

• f (7) +

+1PPSS 2 (

h

+

+ Salem 1 (7) 1/19/84 I

H

+Susquehanna 2 (7) 0 2030 ;

I 5/8/84 U

+

1 f Callaway 1 (f R

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+Diablo Canyon 1(2)+ Grand Gulf (4) 10/1/84 3

S

+1 4/29/84 4

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I 6''''I*****'&''''I****I**I'''

0 11 2

3 4

5 6

PLANT TRIP RATE PER 1000.0 CRITICAL HRS FIGURE 2.1-9 1

i i

e NUMBER IN PARE;' THESES IS NUMBER OF TRIPS.

DATE OF INITIAL f40TE:

)

CRITICALITY SHO'.!!! FOR HIGH RATE PLANTS IF OCCURRED IN 1 30

^

J

.: = --

Thus, it appears that the trip experience for the plants listed in Table 2.1-6 j

(i.e.,plantstotherightofthedashedlineonFigure2.1-9)wasrelatively poor, considering the amount of time (i.e., critical hours) that the plant was i

in operation during 1984. The experience of these p ants is sunnarized in Table 2.1-6.

Table 2.1-6 Plants With Relatively Poor Trip Experience in 1984 l

Name Trips Above Critical Trip Rate Per Mean Critical Hours 15% Power Hours 1000 Critical Hours Between Trips (Power > 155)

(Power >.15%)

WPPSS 2 17 2983.0 5.70 175.5 l.

Ca11'away 1 6

1131.5 5.30 188.6 Grand Gulf 1 4

1010.0 3.96 252.5 Susquehanna 2 7

2145.9 3.26 306.6

[

Salec 1 7

2672.3 2.62 381.8 j

McGuire 2 16 6138.3 2.61 383.6 Salem 2 8

3386.0 2.36 423.3 Hatch 2 7

3108.7 2.25 444.1 l

Diablo Canyon 1 2

967.1 2.07 483.6

?

LaSalle 2 9

4469.8 2.01 496.6 i

i i

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31 i

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_. _... ~.,

.,__.._,,.._,_,m_...._,-.,.

2..;

_:. 2.

--_m--

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

7 4-(

The trip experience of the plants listed in Table 2.1-6 was reviewed in detail to detemine if any unique factors were responsible for the relatively high l

trip rates. In general, these plants fit the profile of 80P hardware failures as the dominant cause of reactor trips, with a variety of root causes at each plant. WPPSS 2 and McGuire 2 (with 17 and 16 trips respectively) were exceptions.

)

Both showed a significantly higher percentage of trips due to personnel error during testing and maintenance than the rest of the population.

l 2.2 Reactor Trips at Power Levels Below 15%

Rea,ctor trips from power levels below 15% are considerably less significant than trips frcm higher power levels because they generally occur during start up when the residual decay heat is at a minimum. Consequently, discussion of these l

trips is abbreviated in comparison to the discussion of reactor trips from

~

l above 15% power. Also, as noted previously, plants spend very little time

~

l in this power regime, thus we have not calculated trip rates per reactor critical hour below 15% power.

4 l

There were 157 reactor trip ~s in 1984 at power levels less than or equal to l

l 15% power. Figure 2.2.-1 shows the distribution of these trips by power

)

level.

i

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1 e

.f l

1 s

I 22

/

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

c_..

=-._ _ _

4 l

2 S

5 4.

i 33AC"03 TI?S A" OR BK;0W 15% :?0TER i

POWER DISTICBUTIGi KEDPOINT PCWER FREO CUM. PEltCENT

, 11M,

~

~ ~

FREQ PERCENT -

N s4 s4 34.se 34.se l

s 2

Msj8g@Vg@

as-as 22.as s7.s2 4

'M 13 183 8.28 86.61

~

8 til 5.18 78.75 h

l 5

h le 121 8.37 77.87 8

la iM

~

17 138 19.83 87.98 h

8 144 3.82 91.72 12 l

14 iQ 13 157 8.28 100.88

.. s..

..v.

9 19 28 30 46 58 Se FREQUENCY NOTE: POWER 8 MEANS 8 TitROUGH IX.

FIGURE 2.2-!

i t

33

,e

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

~__y-,,,_,--,_.-,--y.---.,,,,_,,-~

y- - -

.,v.---,_

a

=

2.

u. _..

__..-__..m

-~.

~.-

s 2.2.1 Initiating Systems The Reactor Protection System (RPS) was the primary initiator of reactor trips from low power. Sixty-seven percent of these can be traced to failures in source range and intemediate range nuclear monitors.

However, mest of these trips occur below 2% power as shown by Figures 2.2-2 and 2.2-3.

The Feedwater, Main Steam, Turbine, Control Rod Drive, Electrical and Condensate systems also contributed significantly to low power trips. At power levels between 2% and 15% the Feedwater System is the primary contributor. We found a total of 22 reactor trips resulting from PWR manual feedwater control problem -

12 below 15% power and 11 above 15% power (8 classified as Manual Steam Generator Level Control problems and 3 classified as Human Error). This amounts to 12 of the 109 PWR trips below 15% power (11%), or 7% of all 329 PWR trips (regardless of power level). Thus, it appears that from an industry perspective manual level control is not a major contributor to unplanned reactor trips.

2.2.2 Causes Table 2.2-1 provides the summary of causes for reactor trips from below 15% power.

In contrast with higher power levels, personnel related problems (i.e., Human Error, Manual Steam Generator Level Control problems Procedure Deficiencies) accounted for a greater share of reactor trips, 46% vs 28%.

If i

manual steam generator level control problems are removed from the calculations, the resulting percentages are 41% and 27% respectively, demonstrating that this category does not account for the difference. As discussed in the next section, the relatively large personnel contribution does not result from increased main-tenance, testing and calibration activity during low power operations. This leads us to the conclusion that problems in executing the basis procedures

~

necessary to start up the facility are responsible for the difference.

34 i

i

a i

SYSTEM IIITIATIIG REACTOR TRIPS AT POWER GREATER THAN 8X AND LESS THAN OR EQUAL 2%

j SYSTEM FREQ CUM.

PERCENT CUM.

FREQ PERCENT RPS xxxxxxxx)ooooooooa 38 38 42.22 42.22 i

MAIN STEAM

!*?*?*?e 10 48 11.I1 53.33 CRDS M

9 57 10.00 83.33 FW 8

65 8.89 72.22 ELECTRICAL 7

72 7.78 80.00

~

J 1

TURBINE 4

76 4.44 84.44 AFW 2

78 2.22 86.87 CONDENSATE 2

88 2.22 88.89 RCS 5~

2 82 2.22 91.11 UNKNOWN 2

84 2.22 93.33 l

SBGTS 1

85 1.11 94.44 SFRCS 1

88 1.I1 95.56 SG LEVEL CONTROL 1

87 1.I1 96.67 i

STEAM DUMP

)

1 88 1.11 97.78 SI 1

89 1.I1 98.89 PCS 1

90 t.I1 180.00 i

0 10 20 30.

40 FREQUENCY i

I FIG 1JRE 2.2-2 4

i 35 l

SYS:3Y ITIXG :EAC"0R TlPS AT POWER GREATER THAN 2%

AND LESS THAN OR EQUAL 15%

SYSTEM FREQ CUM.

PERCENT CUM.

FREQ PERCENT FW 27 27 40.30 40.30 TURBINE M

12 39 17.91 58.21 MAIN STEAM M

9 48-13.43 71.64 I- -

RPS 8

56 11.94 83.58 h

3 59 4.48 88.06 CRDS h,

3 62 4.48 92.54 CONDENSATE f

2 64 2.99 95.52 RCS I

R l

REACTOR RECIRC 1

65 1.49 97.01 i

i i

.- MAIN GENERATOR 1

66 1.49 98.51

).

CVCS

)

1 67 1.49 100.00

)

a j

1

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O 10 20 30 FRE0VENCY 1

l FIGURE 2.2-3 i

i 36

d, P

Table 2.2-1 Cause Sumary, Power Below 15%

i Number of Percent of l

Cause Reactor Trips Total r'

Hardware Failure 70 46 Human Error 47 30 l

Procedure Deficiences 13 8

I Main Steam Generator Level 12 8

C'ontrol i

Unknown 8

5 Hardware & Human Error 4

3 Not Provided 3

2 Total 157 99*

7 1

i

• Does not add to 100% due to rounding.

i l

1 4

)

I 4

l 37 l

I

2-o, 2,.2.3 Contribution from Maintenance Testing, and Calibration Maintenance, Testing,andCalibrationcontributed38of157(24%)reactortrips in this power range. This compares with 99 of 337 (29%) of trips from power levels above 15%. Thus, the contribution to trips from planned testing, mai -

D tenance, and calibration is nearly identical above and below 15% power, 29%

and 24% respectively, 28% overall.

i d

i I

38 1

1 l

. ~ - _ _ _

lt E

/

I I

2,3 Sumary Findings and Conclusions Based on 1984 Reactor Trip Statistics l

Based on the analysis of the reactor protection system actuations that occurred in 1984, the following conclusions can be made.

1.

Out of 622 unplanned RPS actuations reported in 1984, we identified a j

total of 494 reactor trips. Two of these trips occurred at Byron, which held only a 5% power license for the portion of 1984 in which the scrams occurred.

The remaining actuations occurred while the plant was already shut down and, I

thus, did not result in rod motion.

i 1

l 2.

In August 1984 NRR published an analysis of 1983 scram statistics extracted from the NRC Operations Center data base.

In that study NRR identified a total of 496 trips. NRR then calculated an average trip rate of 6.5 trips -

i per reactor per year by dividing 496 by 76 (i.e., the total number of LWRs holding or receiving a full power license during 1983). Performing the l

comparable calculation for 1984, we identified 492 trips at 83 reactors with I

full power licenses, for an average rate of 5.9 trips per reactor per year.

l Thus, in tenns of the overall performance of the industry we observed a slight

{

decline (9%) in the rate of automatic and manual reactor trips from 1983 to l

1984.

4 r

3.

We found that 68% of all reactor trips in 1984 occurred while the plant l

was at a power level above 15%. Further, 31% occurred from above 95% power.

l Thus, it appears that a significant fraction, approximately one-third, of I

all reactor trips occurred from high power with attendant high levels of decay I

heat. This is contrary to the frequently stated hypothesis that most reactor trips are due to problems during start up.

i 4.

Above 15% power, 59% of the disturbances resulting in reactor trips

)

originatedinthefollowingBalance-of-Plant (BOP) systems:

Feedwater - 27%,

l Turbine - 15%, Condensate -6%, Main Generator - 6%, Main Steam - 5%. Below i

39 i

i

}

\\

1

.=::-.. '

=.-

i 25 power, faults in the Reactor Protection System itself were the dominant source. Between 2% and 15% power, again the Feedwater - 40%, Turbine - 18%,

and Main Steam - 13% combined for 71% of all trips that occurred between 2%

and 15% power.

3 5.

Hardware failure was the dominant cause of unplanned reactor trips above'

~

15% power. Cataloging the individual pieces of hardware, however, reveals a vast array of components and piece parts responsible for trips. This d

i diversity suggests that it will not be possible to achieve significant I

reductinns in reactor trips by focusing on a few " problem components" on l

.an industry-wide basis. Rather, the solution seems to lie in addressing problems with the components which dominate at a particular plant, as well as greater attention to improved material condition at each plant.

6.

We note that the largist single class of events leading to reactor trip I

(i.e., hardware failure in major BOP systems) is historically and currently outside regulatory purview. The needed improvement in 80P material condition is the responsibility of individual licensees and industry groups. The j

re<>uction of this source of unplanned reactor trips over time will be a key i

indication of industry efforts at self-improvement.

l I

i 7.

Personnel-related problems (i.e., human error, manual steam generator level control problems, and procedure deficiencies) were a substantial but secondary cause of reactor trips above 15% power, accounting for 28%. Focusing on the

}

trips caused directly by human error (75 trips) we found that nearly half (34 trips)couldbetracedtounlicensedpersonnel. Thus, errors by unli-censed personnel account for 10% of all reactor trips above 15% power. There-fore, continued efforts to improve the performance of unlicensed personnel i

appear warranted.

I,

~

40 i

i

i n _ _.__._ 2 _

,. x _ __.

x 7

t af I

~

8.

Below 15% power, hardware failures also predominate, but the contribution from personnel problems (at 46%) is higher than that above 15% power. This j

i increased contribution does not result solely'from manual steam generator l

1evel control problems, or from increaad maintenance and testing at lower power. The latter conclusion is based on our finding that the percentage, of trips due to planned maintenance and testing is nearly equal above and below 155 power, 295 and 245 respectively, 28% overall. This leads us to the conclusion that problems in executing the basic-procedures necessary i

i to start up the facility are responsible for the difference.

l

?

9.

• The proportion of reactor trips associated with planned maintenance, calibra- +

tion, and testing activities was about 30%. However, or,e should not equate j

problems' arising while' performing maintenance, calibratidnr and testi$ with

. I errors by personnel performing these activities.

In part,icular when we reviewe'd u the relevant trips above 15% power we found that the root'cause of the trip

)

in 37 cases was a hardware failure.

i i

10. It appears that the trip experience for a number of plants (WPPSS 2 Callaway, %

Grand Gulf Susquehanna' 2, Salem 1 Salem 2. McGuire 2 katch'2, Diablo' Canyon,

~

and 1.aSalle 2),was relativeIy poor, considering the amount of time (i.e.,'

criticalhours)thattheplantwereinoperationduring1984. The trip, experience of these plants was reviewed in detail to deterWoe if any, unique factors were responsible for the relatively high trip rates.

In general, these plants fit the profile of BOP hardware failure as the dominant cause l

of reactor trips, with a variety of root causes at each plapt. WPPSS 2 and

~ '

i McGuire 2 were exceptions. Both showed a significantly higher percentsge of

(

trips due to personnel error during testing and maintenance than the rest of j

the population.

"r' g

11. We found that manual steam generator level control problems at low power

~ r are a relativel, minor contributor to unplanned reactor trips. We at't's ibuted only 23 of 329 total PWR trips to such problems, amounting to only 7%.

s l

41 j

~

o..

s

__,____,._,___,..,.,_,_,__,c.-,

1..

^

~

~

~

^

t.

3.0 REACTOR TRIPS WITH ASSOCIATED FAILURES As previously noted unplanned reactor trips where the recovery was complicated by additional equipment failures or personnel errors can be of concern because of the higher level of stress and demands placed upon the operating personnel.

i

~

This section addresses this issue.

" Associated failures" are defined in this report as component failures or personnel errors that did not contribute directly to the cause of a reactor trip, i

but are associated with post-trip (e.g., normally the failure was discovered or I

occurred when the component was actuated to mitigate the consequences of the trip).

Examples of associated hardware failures included failure of AFW pumps and valves, failure of main feedwater regulating valves, failure of electrical systems, failure of steam relief and safety valves, and failure of instrumentation.

About 20% of all trips above 15% power included one or more associated failures, and over 25% of all reactor trips at power levels of 95% or higher included at least one associated failure.

In total, 77 reported trips indicated associated failures. The LERs that included associated failures reported a total of 123 separate failures. Of the 77 trips that involved associated failures, over one-third (27) included multiple associated failures. These failures are of concern because they complicate the recovery from the trip, and increase the probability that the recovery from the trip will not proceed satisfactorily.

~

r The 77 reactor trips and their associated failures are tabulated in Appendix F.

Associated failures are not usually the focus of LERs, therefore their reporting is somewhat sporadic and incomplete. Appendix E discusses this reporting deficiency further.

S 42

~ _

____._,.___.__..__--_.-____..,____,._.__m_,._._._.,_

Given our concerns about the completeness of the narrative discussion of associated failures found in the 1984 LERs, we considered 77 trips t'o be a lower bound on the number of trips with post-trip complications. However, even this number is noteworthy.

In addition, we are also concerned about the number of instances in which post-trip failures go uncorrected, as demonstrated by their

~

repetition following subsequent trips. Plants which demonstrated repetitive associated failures include Oconee 1. Surry 1. Surry 2. Fitzpatrick, Arkansas 2, Sumer, and Grand Gulf.

e em 9

43 e

• ew-~~-,.-,,v.

,,4

O e

4.0 COMPARISON OF U.S. AND FOREIGN REACTOR TRIP RATES As part of the AEOD analysis of reactor trip experience, trip rates for plants in other countries were collected and analyzed. Tables 4.0-1 and 4.0-2 shows PWR and BWR reactor trip rates by country and by U.S. NSSS vendor.

Table 4.0-1 Reactor Trip Rates By Country Pressurized Water Reactors Average Trip Pate Per Country /NSSS Period 1000 Critical Hours U.S.IM4-loop) 1984 1.8 France 1982 1.6 U.S.ig3-loop) 1984 1.3 U.S. (CE) 1984 1.0 U.S. (All PWRs) 1984 1.0 Sweden 1984(Jan-June) 0.7 U.S. ig early 4-loop) 1984 0.7 U.S.(B&W) 1984 0.4 U.S.IE2-loop) 1984 0.3 r- '

West Germany 1983 0.2 Japan 1984(Jan-Sept) 0.05 44

'~

-g-

--w.--,

Table 4.0-2 Reactor Trip Rates By Country Boiling Water Ractors Average Scram Rate /

Country Period 1000 Critical Hours U.S. (GE) 1984 1.1 Wes"t Germany 1983 0.4 Sweden 1984(Jan-June) 0.3 Japan 1984(Jan-Sept) 0.01 9

G a

l S

45 l

. ~ - - -

D,ata from foreign reactors present several problems because our information is not as current, not as complete, and may lose some further accuracy in j

translation, when compared to information on U.S. reactors. Appendix G contains j

the data and details of the calculations of trip rates for foreign LWRs. The information for foreign reactors in Tables 4.0-1 and 4.0-2 may therefore not, be as fim as information on U.S. reactors.

On the average the PWR trip rates in France are higher than in the U.S. However, it should be noted that the French data is for 1982 and subsequent scram reduction programs may have reduced French scram rates.

Trip rates for Swedish reactors are lower than the average trip rate for the U.S.

For PWRs, the Swedish scram rate is about 30% lower, and for BWRs it is about 70%

lower.

West Geman trip rates are lower than U.S. average trip rates by a factor of about 3 for BWRs and 5 for PWRs. The BWR rates come closer if we adjust for the fact that not all West German BWR turbine trips result in a reactor trip, and that all operating West Geman BWRs are less than 900 MWe [the largest U.S.

BWRs (over 1000 MWe) have the highest trip rates]. If we add the turbine trips without reactor trip back in the West German rates and drop U.S. BWRs over 1000 MWe from the U.S. rates we get figures for West Geman BWRs of 0.5 trips per r ~

thousand critical hours and for U.S. BWRs of 0.9 per thousand critical hour respectively (i.e., still a difference of about a factor of two).

The gap between the average West German PWR and U.S. PWR is wider. The difference'is lessened, but not eliminated by noting that the majority of U.S. PWR trips originate in the Balance of Plant (BOP) systems (i.e.,

feedwater turbine, main generator, condensate) and that West Geman PWRs appear to have features which avoid most trips from these sources.

46 1

Japanese reactor trip rates are more than an order of magnitude lower than the U.S. average rates. This difference has been recognized for some time, and resulted in a detailed investigation of the factors involved.

In their June 1984 report, researchers from the Battelle Human Affairs Research Centers stated that the difference could not be attributed to RPS set point differences or reporting practices. Since the gap is so wide, this in essence means that the causal factors present in the U.S. experience are nearly absent from the Japanese experience.

Only rough comparisons are possible at this time due to the age and relative lack of documentation of foreign data. However, it appears that the average reactor trip rates for the countries examined (France, Japan, West Germany, Sweden) are below those for the U.S. reactor population of both BWRs and PWRs.

~

We want to emphasize, however, that while there is a tendency to focus on '

average behavior, neither the U.S. PWRs nor BWRs are homogeneous groups.

In fact, there is significant variation in trip rates within the Westinghouse subclasses and the GE class. Certain U.S. reactor classes (e.g., Westinghouse 2-toop reactors, B&W reactors) have trip rates that are comparable to the better foreign experience.

47 s

f

4 8

6 e

f i

)

e d

e APPENDICES 9

9 48 4

Appendix A

'AULE A.1 PAGE 1 19C; e,CAC10R TRIPS NAME' DOCKET LER NONTH T:AY TIME

• /EUDDR TF:IF ; rMET,

~

1 YANKEE ROWE 27 010 11 16 045 NFST

^ ", r, ge 2

YANKEE ROWE 29 017 11 12 2010 WECT MANUAL 21 3

YANKEE ROWE 29 012 7

12 005 NEST At'TO 10' 4

YANKEE ROWE 29 015 9

5 556 WEST MANOAL

!?O 3

YANKEE RDWE

29. 316 9

15 29 UECT AUTO 100 6

BIG ROCK POINT 155 004 5

30 2002 GE AUTO i

7 BIG ROCK POINT 155 012 8

3 D34 SE AUTO 5

C BIG ROCK POINT 105 009 7

26 2234 GE AUTO 12 9

HADDAM NECK 213 021 11 3 1019 WEST AUTO 10 HADDAM NECK 213 009 G

1 10G1 WEST AUTO t

11 HADDAM NECK 213 026 11 15 1955 WEST MANUAL E '>

12 tmDD4'M NECK 213 025 11 20 935 WEST AUTO 99 13 OYSTER CREER 219 030 10 31 344 GE AUTO 1

14 OYSTER CREEK 219 033 12 3 1206 GE AUTO 5

15 NINE MILE POINT t 220 018 11 13 525 GE AUTO 4

16 DRESDEN 2 237 013 7

22 1738 GE-AUTO 93 17 DRESDEN 2 277 012 7

9 958 GE AUTO 95 18 DRESDEN 2 237 009 6

21 1 5 2'-

GE AUTO 99 19 R.E.GINNA 244 007 5

30 2220 WEST AUTO S'

20 INDIAN POINT 2 247 016 10 l'a 2 1 2 6 WEGT AUTO O

21 INDIAN POINT 2 747 025 12 28 1034 WEST NANUAL e

22 INDIAN FO!NT 2 247 018 10 20 340 WEST AU'O C

23 INDIAN FOINT 2 247 018 10 20 1707 WEST AUTO M

20 INDI AiJ FOINT 2 247 019 10 22 37 WCST AUTO SO' 25 INLIAN FOINT 2 I47 02G 1.^

17 1002 WEST AUTO 100 26 URE5 DEN 3 259 016 10 14' 13,~

CE AUTO O

27 DRESDEN 7 249 015 9

23 52t GE AUT2 3

2S DEECOEN 3

i. a7 012 2

23 104/:

GE AUTO 4

2?

DNESDEN 3 219 007 7

22 60D CE AUTO 12

?9*"LRESDEN ~

24? 001 3

23 1300 GE AUTO 15 31 DREUDEN 3 249 020 10 26 90S GE A':TC 3c 32 GRESDEN !

219 015 10 14 129 GE CJTO 90 l

33 DRECDEN 3 2 7 013 10 20 1526 CE AUTO 92 34 OPEEDEN '

249 010 3

21 2211 GE

$UTC-9' 35 TUiiK v P: INT 3 2FO O21 7

14 1114 UEGT AUTO O

36 TUFFEY POINT 3 250 002 1

8 735 WEST AUTO 1

~7 TURK 77 FOINT 3 250 001 1

0 205 WEST AUTO 30 30 TURVEY FOINT 3 256 003 1

9 1416 WEST PANUAl.

63 39'.TURKFY :OINT 3 250 003 1

25 1255 NEGT 4UTO 200 40 URKEY POINT 3 250 006 2

12 638 WEST AUTO 100 41 TURKEY POINT 3 250 007 2

16 925 UEST AUTO 100 42 TURKCY POINT 3 250 014 4

24 1646 WEST AUTO 100 43 TURVEY PO!NT 3 250 033 12 13 19 UEGT AUTO 100 R

44 TURKEY POINT 4 251 C22 10 9

226 WEST AUTO O

4D TURKEY r'UINT 4 251 023 10 16 S45 WEST AUTO O

4a TURKEY POINT 4 251 014 6

26 1123 WEST AUTO i

17 TURKEY FOINT 4 251 000 6

1 1112 WEST AUTO 1^

4G TURKEY POINT 4 251 002 2

12 1818 WEST AUTO 15 49 TURKEY POINT 4 2D1 021 9

20 1745 WEST AUTO 70 t

50 TURKEY POINT 4 251 001 2

12 945 WEST A'JTO 100 49

TADLE A.1 PAGE 2 1784 T,EACTCR TRIP 3' NAME' DOChE.T LER MONTH DAY TIME

• >ENEOR TRIP FO iET D1 TURKEY POINT 4 251 007 2

16 925 W23T AUTC lao 52 TURKEY POINT 4 251 010 6

4 121 53 TURKEY FOINT 4 251 017 0

7 1012

. WEST AUTC 1<: 0 WCST '

GUTO l '. O 54 TURKEY FOINT 4 251 025 11 24 302 WEST AUTO 10:

55' OUAD CITIES 1 254 010 5

30 918 GE AUTO 0

56 OUAD CITIES 1 254 016 8

29 1352 G2 f,UTO 6e 57 CUAD CITIES 1 254 015 0

23 726 GE AUTO 75 SG QUAD CITIE3 1 254 001 3

5 206 GE MAN'lAL 50 59 PALISADES 235 015 8

4 1355 CE AUTO 42 60 BROWN 3 FERRY 1 259 027 6

27 608 GE MANUAL 1

61 BROWNS FERRY 1 259 014 2

22 1010 GE AUTO 62 DROWUS FERRY 1 259 004 1

6 2342 GE MANUAL 12 63 BROWN 3 FERRY 1 25T I/E 8

21 1440 GE mat!UAL I '.*

4 i

64 BROWNS FERRY 1 15? 026 6

20 54 GE MADAL 65 EROWND cERRY 1 259 016 2

.29 2311 GE AUTC 93 66 BROWNS FERRY 1 259 O!!

2 9

928 GE AUTO Pi I

67 EROWNS FERRY 1 259 024 6

2 1739 GE.

AUTO 100 68 BROWNS FERRY 2 260 004 2

22 100 GE AUTO O

69 BROWNS PERRY 2 760 006 6

16 127 GE AUTO A 1.

70 DROWNR FERRY 2 260 002 1

21 556 GE AUTO 9a 71 H.B.RGEINSCM 2 241 001 1

26 1639 WEST AUTO r-12 OUAL CITIES 2 263 004 2

15 52 GE AUTC' G

73 CUAD CITIES 2 26D I/E 2

17 957 GE MANUAL 1

74 QUAD CITIES 2 265 010 10 2G 641 GE AUTO O

75 OUAD CITIES 2 245 009 9

5 1044 GE AUTO 50 76 QUAD CIT!ES 2 265 007 6

10 15' GE AUTO 06 j

77 POINT EEACH 1 214 002 7

21 417 UEST AUTC 78 POINT DEACH 1 266 004 7

21 1130 UEST MANUAL 79 OCONEE 1 267 006 12 2

417 DW AUTC JZ 005 GOONCE 1 269 007 12 3 0206 DW AUTO 07 81' OCDMEE 1 269 002 5

12 203 LW.

AUTO 10^

82 VERMONT YANKEE 271 004 4

16 742 CE-AUTC 27 G3 VERMONT YANi/2E 271 001 1

0 1252 CE SUTO 10e 84 SALEM i 272 023 to 22 1544 WEST AUTO EU CALEM i 272 001 1

1 317 WEST AUTO 20 86 SALEM i 272 003 1

10 136' WEST.

AUTO 10 07 SALEM 1 272 004 1

21 2240 WEST AUTO 60 G3 SALEM 1 272 023 12 23 2158 WEST-AUTO 77 09-SALEr1 1-272 025 11 6

645 WEST AUTO 71 90 SALEM i 272 025 11 11 109 WEST AUTO 93 91 SALEM i 272 029 12 31 2130-WEST AUTO.

93 92 SALEM i 272 002 1

7 2330 WEST.

-AUTO 10':

93 SALEM i 272 OOD 2

24 1726 WEST AUTO 109 94 DIABLO CANYOM i 275 022 7

28 709 WEST AUTO O

95 DIA9LO CANYON 1 27G 033 12 6

656 WEST AUTO O

96 DIADLO CANYON 1 275 _014 5

6 2140 WEST AUTO 2

i 97-DIAPLO CANYON 1

?75 015 3

8 1304 WEST AUTO 2

93 DIADLO CA'D 2N 1 275 032 12 5 1635 WEST AUTO 7

9?

DIABLO CAN.JN 1 27C 031 11' 28 2209 WEST.

AUTO.

1D 100.DIAELO CANYON 1 275.030 11 24 1612 WEST AUTO 21 50 l

TABLE A.1 PAGE 3 1?E4 REACTOR TRIPS NAME DOCKET LER MONTH DAY TIME VENnCR TRIC L ~ "E '

t s

101 PEACH BOTTOM 3 273 000 7

11 1920 GE tuiO

' r-102 PEACH BOTTOM 3 273 014 11 14 1705 G2 AUTO 33 103 PEACH EDTTON 3 279 I/E 1

14 1815 GE MANUAL SC 104 FEACH BOTTOM 3 278 003 2

9 1GO7 GE duTO 72 105 PEACH BOTTOM 3 278 011 8

21 1401 SE AU1D 100 106 SURRY 1 200 008 4

7 142 WEST AUTO 1

107 SURRY 1 230 016 6

19 414 WEST AUT2 10 103 SURRY 1 230 026 12 31 1524 WEST AUTO 47 109 SURRY 1 200 020 9

26 2227 WEST AUTO 8^

i 110 SURRY 1 280 001 1

6 1324 WEST AUTO 100 111 SURRY 1 280 002 1

18 934 WEST MANUAL 100 112 SURR7 1 280 003 2

6 1847 WEST AUTG "QO 113 SURRY 1 280 013 6

13 1530 WEST AUTO 100 114 SURRY 2 2S1 012 4

20 216 WE3T AUTO O

115 SURRY 2 281 002 1

14 630 WEST MANUAL 2

116 SURRY 2 231 009 1

15 1607 WEET AUTO 2

117 SURRY 2 2S! 021 12 16 1520 WECT AUTO 20

. 1_18 SURRY 2 201 016 11 20 419 WEST AUTO 21 119 SURRY 2 791 019 12 11 2324 WEST AUTO 22 120 SURRY 2 201 O20 12 31 140 UEST

' AUTO 22

.121 SURRY 2 201 000 1

14 1315-UEST AUTO 23 122 3URRY 2 2G1 010 4

19 1540 WEST AUTO OC-

{

123 SURDY 2 281 010 4

13 6(.

WEST AUTO e.:.

124 EURRY 2 301 001 1

13 123f.

WEST MANUAL 100 123 0".'RRY 2 201 000 3

16 93~

WEST AUTO 100 126 GURRY 2 2SI 013 0

7 1A22 WEST AUTO 100 177 SUDnY 2 291 015 10 29 155' WEST AUTO 100 122 SURRY 2 251 01C 12 11 1100 UEST AUTO 100 129 PPlatFIE ISL/N.E 1

^32 001 1

3 1747 WEST AUTO 10 13f[ PRA!DTE ISLAND '

282 005 3

31 2

WEST AUTO 20 131 FRn!FIE :SLAND 1 232 011 11 7 2026 WEST AUTO 24 132 PRAIR:E I3LANO 1 202 003 0

30 1439 WEET AUTC 1X 133 FDF;' CALHOUN 1 203 013 7

22 2130 CE (UTC U3 134 INLIGN PCINT 2 206 002

.1 28 11D WEST AUTO O

135 INDI AN PDI'4T 3 206 014 10 13 136 WEET AUTO O

136 INDIAN POINT 3 286 004 2

9 1112 WEST AUTO 90 177 INDIAN 7 DINT 3 296 005 2

20 1940 WEST AUTO 70 130 INDIAN POINT 3 2?6 006 3

9 G32 WEST AUTO 9?,

139 INDIAN DOINT 3 206 008 5

29 1984 WEST AUTO 100 100 IMD!AN POINT 3 206 009 6

16 221 WEST AUTO 100 141 INDIAN POINT 3 296 011 7

12 1517 NEST AUTC 10' -

142 INDIAN FOINT 3 236 013 G

22 2122 WEST AUTO 100 143 OCONCE 3 287 004 6

7 2233 BW AUTO 19 144 OCONEE !

237 003 6

7.1321 SW AUTO 20 145 OCDNEE 3 287 002 2

16 315 SW AUTC 100 146 OCONEE 3 207 005 8

la 1126 BW AUTO 100 147 2:ON 1 295 011 4

5 1646 WEST AUTO 1

143 ZION 1 295 008 2

23 2143 WEST AUTO 15-149 ZION 1 295 010 2

24 602 UEST AUTD 34 4

150 ZIO:i 1 295 009 2

22 1741 WEST AUTC CO 7

51

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

-w

' 'ADLE A.1.PAGE 4 1954 REACTOR TRIPS NAME DOCNET LER MONTH DAY TIME VENDOR TRIP PCNCR

+

151 ZION 1 295 012 4

2 2005 MEST AUTC 100 152 ZION 1 295 033 12 6

45 WEST CUTO 1 0

153 EROWNS FERRY 3 296 012 11 20 1152 GE MANUAL C

154 EROWNS FERRY 3 296 015 12 9 1204 GE MANUAL CL 155 COOPER 290 003 1

30 2333 GE AUTO

'5 156 COOPER 298 002 1

29 1948 GE AUTC

~o 157 COOPER 258 010 8

8 1638 GE AUTO

?O 153 POINT DEACH 2 301 004 9

28 1137 WEST AUTG O

159 CRYSTAL RIVER 3 302 003 2

20 1039 BW AUTO 70 160 CRYSTAL RIVER 3 302 010 4

26 1039 LW AUTO 97 til ZION.2 304 017 7

4 1120 WEST AUTO O

162 ZION 2 304 I/E 7

5 1530 WEST MAMUAL i

163 ZION 2 304 016 7

9 2335 WEST AUTC 1

164 ZION 2 304 01G 7

8 230 WEST AUTO 2

165 ZION 2 304 007 3

27 250 WEST AUTO 6

166 ZION 2 304 002 1

7 630 WEST AUTO 10 4

, 167 ZION 2 304 001 1

6 1600 WEST MANUAL 100 16G ZION 2 304 CO3 1

16 1612 WEST AUTO 100 169 KEWAUNEE 305 008 5

5 1804 WEST AUTO-0 1.70 KEWAUNEE 305 002 3

16 2345 WEST AUTO 2

171 MEWAUNEE 2'G 010 5

7 2300 WEST AUTO 1."*

172 KEWAUNEE 3C5 007 5

7 1917 WEST AUTO 25 173 MEWAUNEC 305 314 7

3 103r WEST AUTO 100 174-MAINE YANUEE 309 009 6

22 1G00 CE AUTO O

175 MAIt'E YANKEE 709 009 6

22 1752 CC AUTO 2

176 MAINE YANKEE 309 017 11 4 1347 CE AUTO 3

177 MAINE YANKEE 30 000 6

22 1333 CE AUTO 9

173, MAINE YANV.EE 309 001 1

12 821 CE MANUAL 77 17T MAINE YANKEE 309 015 11 3 2224 CE AUTO DO 130 MAINE YANKEE 309 016 11 10 750 CE AUTO 90 1E1 MAINE YAMMCE 309 016 11 11 2256 CE AUTO 100 182 SALEM 2 211 012 4

24 927 WEST AUTO 2

183 SALEM 2 311 015 5

30 1526 WEST AUTO 10 1G4 GALEM 2 311 010 4

23 1600 WEST AUTO 22 105 SALEM 2 311 010 4

27 1923 WEST AUTO 30 186 SALEM 2 311 022 9

5 312 WEST

' AUTO 54 187 SALEM 2 311 018 7

25 1320 WEST AUTO i d.

ISS SALEM 2 311 000 4

6 917 WEST AUTO 99 109 SALEM 2 311 013 5

11 1006 WEST AUTO 107' I?O SALEM 2 311 021 8

26 1711 WEST AUTO 100 191 SALEM 2 311 024 10 4

915 WEST AUTO ICO 172 RANCHO SECO 1 312 025 il 18 300 BW AUTO 16 193 RANCHO SECO 1 312 007 2

29 1743 BU AUTO AD-194 RANCHO SECO 1 312 010 6

1 917 195 PANCHO SECO 1 312 015 3

19 2151 BW AUTO 68 BW AUTO 05 196 ARKANSA3 1 313 002 3

16 2243 SW AUTO 17 197 ARKANSAS 1 313 004 4

21 1612 EW AUTO

'S 198 ARKANSAS 1 313 005 '

10 5

924 EW AUTO C5 199 D.C. COOK 1 315 008 6

17 2034 WEST-AUTO LO 200 D.C. COOK 1 315 001 1

23 1351 WEST AUTO 97 52 a-- - _ - - _ - _ - - - -. _ - - _ - - - - - - _ -,, - -

y v-

'ASLE A.1 FAGE D 1904 RCACTOR TRIPC NAME DOCKET LCR MONTH DAY TIME VENDOR

'rIn "C;tte:

201 D.C.CDOK 1 315 018 D

14 1529 WEST A0TO

'00 202 D.C. COOK 2 316,031 11 20 1620 WEST AUTC O

203 D.C. COOK 2 316 032 11 20 2032 WEGT MANUAL ta 204 D.C.CCOM 2 316 025 9

12 733 WEST AUTC 27 205 D.C.CCOK 2 316 029 11 11 736 WEST MANUAL 73 206 D.C. COOK 2 316 O!O 11 19 356 WEST AUTO 96 207 D.C. COCK 2 316 002 2

18 245 WEST AUTO 109 203 D.C. COOK 2 316 020 8

5 1414 W.EST AUTO 100 209 D.C.CDOM 2 316 024 9-11 1517 WEST AUTO 100 210 CALVERT CLIFF 3 1 317 004 2

28 2027 CE MANUAL GD 211 CALVERT CLIFFS 1 317 002 1

27 1347 CE AUTO 107.

212 CALVERT CLIFCS 1 317 009 8

28 2156 CC MANUAL 100 213 CALVERT CLIFFS 1 317 013 10 2 1608 CE MANUAL 100 214 CALVERT CLIFF 2 1 317 013 11 20 1716-CE MANUAL 1CO 215 CALVERT CLIFFS 2 31D 008 10 3 1948 CE AUTO 92 216 CALVERT CLIFFS 2 318 003 4

15 1020 CE AUTO 100 217 HATCH 1 321 023 11 6 1535 GE AUTO-0 213 HATCH 1 321 012 12 6 1730 GE AUTO-C 219 HATCH 1 321 016 9

29 936 GE AUTO 1

220 HATCH 1 321 016

?

30 200 GE AUTO 1

221 HATCH I T21. 006 3

11 857 CE MANUAL

-3 222 HAT 2H 1 32i I/E 8

31 415 GE MANUAL 40 223 HATCH 1 321 I/E C

2S 2047 GE MANUAL 45 224 MATCM 1 321 001 2

11 G52 GE AUTO 60 225 HATCH 1 321 007 6

4 121 GE AUTO 95 226 HATCH i N21 015 8

3 2146 GE AUTO 95

'27 324 012 10 24 1140 CE AUTC 7

228, IRUNSWICiJ 2

.BFUNSWICK 2 324 004 2

22 15G GE AUTO 57 229 DRlWCWICR 2 324 013 11 27 123 -

CE AUTO 9F 230 CRUN94ICK 1 325 034 12 7 1913 GE AUTO' 1

231 EDi*USWICK 1 325 034

-12 8

409 CE AUTO t.

232 BRU3 WICK 1 325 002 2

3 44 GE AUTO 25 233 DRUNSWICK 1 325 026 9

18 1039 GE AUTO SC 234 BRUNSWICK 1 325 006 3

31 2300 GE AUTO 95 235 ERUNSWICK 1 325 014 8

1 1417 CE AUTO 95 236 BRUN? WICK 1 325 023 9

10 909 CE AUTO 99 23 7 SEQUOYAH 1 327 031 D

6 217 WEST-AUTO 0

223' GEQUOYAH i 327 064 9

25 2143 WEST AUTO O

13 9 SEGUOYAH 1

'O7. 007 1

10 1610 WEST AUTC 4

240 SECUO'/AH 1 327 013 1

30 1930 WEST AUTO 4

241 SEDt:0 YAM 1 327 030 4

19 2133 WEST AUTO 12-24 2 GEOUDYAH 1 327 006 1

10 204-WEST AUTO 13 24 3 SEQUOYAH 1 327 026 4

17 2148 WEST AUTO

'iB 244 GEOUCYAH 1; 327 033 5

11 1400 WEST AUTC 2!

!45 SEQUOYAH 1 327 032 5

10 2322 WEST AUTO 36

!46 SEQUOYAH 1 327 033 5

_ 21 2234 WEST AUTO 100 6

2 2050 WEST MANUAL 73

?47 SEOUDYAH 1 327 033 NK3 SEQUOYAH 1 327 036 6

18 2115 WEST AUTO 100

!49 SEOUOYAH 1 327 054 8

27 2033 WEST AUTO 100

!50 SEQUOYAH 2 328 020 12 16 026 WEST AUTO-0-

53 j

e "4

TABLE A.1 PAG 2 6 1904 REACTOR TRIPS NAME DOCKET LER MONTH DAY TIME VENDOR TRIP PCNER

-~----

251. SEQUDYAH 2 320 021 12 29 1532 WEST AbTO 16.

'252 SEQUOYAH 2 328 017 9

6 1000 WEST AUTO 1G 253 SEQUOYAH 2 328 018 9

10 412 WEST AUTO 19 254 SEDUOYAH 2-328 014 8

30 844 WEST AUTO 25 255 SEQUOYAH 2 328 018 9

10 1255 WEST AUTO 20 256 SEQUOYAH 2 323 003 5

19 1157.

WEST AUTO 30 257 SEQUOYAH 2 328 018 9

.10 901 WEST AUTO 30 250 SEQUOYAH 2 32S 016 9

9 803 WEST AUTO 97 259 SEQUdVAH 2 328 015 9

5 523 WEST AUTO 100 260 DUANE ARNOLD 331 037 9

29 1431 GE AUTO 1

261 DUANE ARNOLD 331 040 11 4

134 GE AUTO 56 262 DUANE ARNOLD 331 042 11 23 640 GE AUTO 81 263 DUANE ARNOLD 331 027 7

13 902 GE AUTD 99 264 DUANE ARNOLD 331 001 1

7 808 GE AUTO 100 265 DUANE ARNOLD 331 008 1

23 2247 GE AUTO 100 266 FITZPATRICK 333 013 6

25 2222 GE AUTQ 20 267 FITZFATRICK 333 010 3

25 423 GE.

AUTO 23 263 FITZPATRICK 33,3 023 11 4 1746 OE AUTO 30 269

TT2 PATRICK 333'009 3

22 744 GE AUTO 67 270 BEAVER VALLEY 1 334 003 3

12 2100 WEST AUTO O

271 BEAVER VALLEY 1 334 000 7

6 2140 NEST AUTO O

272 LEAVER VALLEY 1 334 017 12 23 1415 WEST AUTO O

273 DEAVER VALLEY 1 334 012 10 11 1453 WEST AUTO 94 274 DEAVER VALLEY 1 334 001 1

14 1957 WEST' AUTO 100 275 EEAUER VALLEY 1

.334 002 1

25 305 WEST MANUAL 100 276, BEAVER VALLEY 1 334 004 5

24 239 WEST AUTO 100-277* ET.LUCIE 1 335 003 5

14 531 CE MANUAL 1

278 ST.LUCIE 1 335 009 9

14 -944 CE MANUAL 32

)

279 ST l.UCIE 1 335 006 7

26 313 CE AUTO 99 280 ST.LUCIE 1 335 007 3

23 816 CE AUTO.

59 1

281 ST.UICIE 1 335 005 6

26 1002 CE AUTO 100 202 ST.LUCIE 1 335 I/E 12 19 1024 CE AUTO 100 j

283 ' MILLSTONE 2 336 002 1

11 1345 CE AUTO 15

{

234 MILLSTONE 2 336 012 11 28 1950

~CE MANUAL ~

62 285 MILLSTONE 2 336 011 11 15 926 CE.

AUTO 100 i

236 NORTH ANNA 1 338 026 12 31 1426 WEST MANUAL 0

287 NORTH ANNA 1 330 020 11 18 1422 WEST AUTO 3

288 NORTH ANNA 1 33e 014 9

28.2027 WEST MANUAL 11 209 NORTH ANNA 1 33'O 014 9

30 1616 WEST AUTO 20 290 NORTH ANNA 1 338 003 2

8 957 WEST

' AUTO 21 j

'291 NORTH ANNA 1 330 018 10 12 1546-WEST AUTO 100 292 NORTH ANNA 1 338 019 11 14 640

-WEST

. AUTO 100 293 NORTH ANNA 1 33S O21 11 25 546 WEST.

AUTO 100 294 NORTH ANNA 1 338 C26 12 31 704 WEST AUTO' 100 295-NORTH ANNA 2 339 001 3

13 1702 WEST AUTO O

296 NORTH ANNA 2 339 001 3

13 2006:

WEST AUTO 1

297 NORTH ANNA 2 339 002 5

5 125.

WEST MANUAL 2

298 NORTH ANNA 2 339 001 3

13 1530 WEST AUTO 100 299 NORTH ANNA 2 339 005 6

25 1328 WEST AUTO 100 300 TROJAN 344 017 9

26 2326 WEST AUTO.

1 54

u v

TABLE A.1 PAGE 7 1984 REACTCR TRIPS NAME DOCKET LER MONTH DAY TIME VENDOR TPTP FOMER

+

301 TROJAN 344 016 9

20 818 WEST AUTO 10

.302 TROJAN 344 020 10 15 2232 WEST AUTO 22 303 TROJAN 344 018 10 18 1423 WCST AUTO 2c.

304 TROJAN 324 006 4

27 1827 WEST AUTO 70 305 TROJAN 344 004 3

1 1045 WEST AUTO

?G 306 TROJAN 344 003 2

18 745 WEST AUTO 100 307 DAVIS-BESSE 1 346 I/E 9

12 109 BW AUTO O

308 DAVIS-BESSE 1 346 001 1

8 2318 DW AUTO

• e 309 DAVIE-EESSE 1 346 013 9

11 1235 BW AUTO 70 310 DAVIS-BESSE 1 346 010 6

24 1354 BW MANUAL 94 311 DAVIS-BESSE 1 346 003 3

2 1220 BW AUTO 79 312 FARLEY 1 348 002 2

10 2358 WCST AUTO 10 313 FARLEY 1 348 001 1

9 2328 WEST AUTO 100 314 SAN ONOFRE 2 361 020 3

26 633 CE AUTO 2

315 SAN ONOFRE 2 361 050 8

26 1816 CE AUTO 10

- 346 SAN ONOFRE 2 361 016 3

9 1949 CE MANUAL 27 317 SAN ONOFRE~2 361 019 3

24 1934 CE AUTO 100 318 SAN CNOFRE 2 361 043 8

8 1710 CE AUTO 100 319 SAN ONOFRE 3 362 OC3 1

7 30 CE AUTO O

320 SAN ONOFRE 3 352 007 3

5 ISOC CE AUTO O

321 SAN ONOFRE 3 362 017 5

5 402 CE AUTO 1

322 SAN ONOFRE 3 352 017 5

8 210P CE AUTO O

323 SAN ON cRE 3 362 032 8

0 1540 CE AUTO 35 324 SAN ONOFRE 3 362 000 3

10 214C CE AUTO 26 325 SAN ONCFRE 3 362 022 6

1 417 CE AUTO 72 326 SAN ONOFRE 3 262 024 6

11 1817 CE AUTO 100 327. SAN DNOFRE 3 362 040 12 6 1947 CE AUTO 100 326 FARLEY 2 364 001 1

18 403 WEST AUTO 19 1 329 FARLEY 2 364 016 12 20 1732 WEST B1cNUAL 00 1 330 FARLEY 2 364 00.3 1

30 1627 WES.

suTO 100 331 FARLEY 2 364 004 3

27 1247 WEST AUTO 100 332 FARLEY 2 364 003 4

9 1207 WEST AUTO 100 333 FARLEY 2 364 012 10 26 930 WEST AUTO

.100 334 HATCH 2 366 033 11 17 13 GE AUTO 59 335 HATCH 2 366 033 9

30 1245 GE AUTO c9 l 336 HATCM 2 366 I/E 10 4 2003 GE AUTO C9 i 337 HATCH 2 366 021 9

21 1801 GE AUTO 100 333 HATCH 2 366 036 11 29 717 GE AUTO 100 339 HATCH 2 36.6 I/E 12 30 1725 GE AUTO 100 l 340 HATCH 2 366 033 12 30 1624 GE AUTO 1CO 341 ARKANSAS 2 368 001 1

28 031 CE AUTO O

342 ARKANSAS 2 368 007 3

10 551 CE AUTO O

343 ARKANSAS 2 36S O2O 7

26 1139 CE AUTO O

344 ARKANSAS 2 368 003 1

30 928 CE AUTO 4

345 ARMANSAS'2 360 008 3

12 1321 CE AUTO 4

346 ARKANSAS 2-368 021 7

28 13 CE AUTO 3

347 ARKANSAS 2 368 027 s 10 31 507 CE AUTO 7

348 ARKANSAS 2 36S 014 6

10 1334 CE AUTO 8

349 ARKANSAS 2 368 004 1

31 2047 CE AUTO in 350 ARKANSAS 2' 368 011 5

7 126 CE AUTO 65 55

1 4

1 TABLE A.1 FASE B 1984 REACTOR TRIPS NAME DOCKET LER MONTH DAY TIME VENDOR.

T R I r* ^ ~.9 7 0 t

351. ARKANSAS 2 360 028 11 3 1104 CE MJTO ce f

'352 ARKANSAS 2 368 013 6

17 1249 CE AUTO 100 i

353 ARKANSAS 2 368 019 7

20 118 CE AUTO 100.

354 ARKANCAS 2 368 024 O

23 842 CE AUTO 10G 355 ARKANCAS 2 360 026 10-26 1157 CE AUTO

- 10G 356 MCGUIFE 1 369 000 6

6 1756 WEST AUTO 90 F 357 MCGUIRE 1 369 002 1

30 1603 WEST

. AUTO-94 l 353-' MCGUIRE.1

^

369 023 7

23 600 WEST AUTO' 9.00 359 NCGUIRE 1 369 024 8

21 2148 WEST-AUTO 10 :-

360 MCGUIRE 1 369 024 8

21 2148 WEST AUTO-100 361 MCGUIRE 2 370 006 2

3 134 WEST-MANUAL 3

362 MCGUIRE 2 370 000 e

21 2225 WEST AUTO O

363 MCGUIRE 2 370 029 11 15 1904 WEST MANUAL 20 364 MCGHIRE 2 370 613 5

11 51 WEST AUTO 23 j 365 MCGUIRE 2 370 027 10 25 1423 WEST MANUAL 27

-36%

MCGUIRE 2 370 016 7

19 1840 WEST MANUAL 73 4 367 MCGUIRE 2 370 033 12 17-520' WEST-AUTO 77 I 368 MCGUIRE 2 370 005 2

2 1111 WEST MANUAL G7 i 369 MCCUIRE 2 370 009 3

19 1501 NEST AUTO 100

' 370 MCGUIRE 2 370 010 4

19 1040 WEST AUTO 100

' 371 MCGUIRE 2 370 011 4

23 100 WEST.

AUTO 109

-372 MCGUIRE 2 37'O 012 3

10 1252 WEST AUTC 100 i-373 MCGUIFE 2 370 1/E G

25.140C WEST AUTO 100 374 MCGUIRE 2 370 015 7

3 160" WEST AUTG

'100 375 MCGUIRE 2 370 021

' 376' MCGUIRE 2 370 026

. B 31 914-UEST AUTO 100 10 23 446 WEST AUTO 100

' 377,.MCGUIRE 2 370 031 11 24 1555' WEST AUTD-100

' 370 MCGUIRE 2 370 034 12 21 629-

' WEST AUTG' 100 379 LASALLE 1 273 056 9

21 1426 FE AUTD

'23

! 380 LASALLE 1 373 002

.1 6 2005 GE AUTC 10 i 381 LASAi.LE 1 373 022 4

14 1905 GE

' AUTC 32-

! 082.LASALLE 1 373 029 5

31 1615 GE AUTO-SC s

>.383 LASALLE 1 373 003 1

13 2114-GE-

. AUTO 00 3G4 LASALLE 1-373 005 1

16 1522 GE AUTO G0

' 385 LASALLE 1 373 011 2

13 44 GE-AUTC 05 386 'LAGALLE 1 37 039 6

24 800 GE AUTO C3 j ;387, 'LASALLE 1 373 007 2

3 1346 GE' AUTO-G9

-389 LASALLEL2 374 012 4

26 510 GE MANUAL ~

1

' 309 -LASALLE 2 374 017 5

3 2340 GE MANUAL

.10

. 390 LASALLE 2 374 042 7

28 2131 GE MANUAL.

16

, 391 LAEALLE 2 374 025 6

6 530 GE:

AUTO 24, 392 LASALLE 2

-374 020 5

21 1824 GE AUTO 4"-

i

,393 LASALLE 2.

374 002 S

17 845 GE AUTO 22.

i 394 LASALLE 2 374 033 7

9 1907 GE.

' AUTC:

65-

-395 LASALLE 2-374'047 8

5-1900 GE AUTO SD '

396 LASALLE 2 374 050 8

10 753 GE AUTO 93 397 LASALLE 2 374 085 12 14 1333 GE AUTO 9T 393 -LASALLE 2 374 071-10 27-450 GE-AUTC 9n 399' SUSOUEHANNA 1 307 035 7

18 514-

'GE

' AUTO

'20-400 SUSCUEHANNA 1 387 033 7.

16 1806 GE AUTO'

-27 2

as.

56 9 + -.I, y y

y

.c - wwwpem+

T

,-.r.

., + -,

, +, - -

.---+v 3--

TADLE A.1 PACE 9 1984 REACTOR TRIPS NAME DCCKET LER MONTH DAY TIME t'ENDOR TRIF FOUE?

v

.-~----

401 SUSOUEHANNA 1 387 010 2

25 1848 EE MANUAL "A

400 SUSOUEHANNA 1 307 010 3

3 103 CE AUTO Ti 403 SUSOUEHANNA 1 387 028 6

13 1720 GE AUTG IN 404 SUSOUEHANNA 1 387.027 7

3 1412 GE AUTO 10' 403 SUSOUEHANNA 1 387 034 7

10 915 GE AUTO 100 406 SUSOUEHANNA 2 388 001 4

5 1449 GE AUTO O

407 SUSQUEHANNA 2 3C8 006 5

27 1346 GE MANUAL 0

403 SUSQUEHANNA 2 3C8 006 5

28 1545 GE MANUAL.

2 409 SUSQUEFANNA 2 38C 034 7

15 1007 GE AUTO 25 410 SUSOUEHANNA 2 388 013 7

26 137.

GE AUTO 20 411 SUSQUEHANNA 2 388 017 8

26 23 GE AUTD 4

412 SUSOUEHANNA 2 3G8 017 8

26 2003

-GE AUTO 45 413 CUSCUEHANNA 2 3CG Ole 9

3 332 GE nuxD 26 414 SUSQUEHANNA 2 33G O21 9

3 GE AUTO 100 l

415 SUSOUEHANNA 2 308 021 9

30 120 GE AUTO 100 4f6 ST.LUCIE 2 389 013 11 19 1537 CE AUTO o

417 ST.LUCIE 2 7.C ? 012 11 19 1242 CE MANUAL 20 I

418 GT.LUCIE 2 339 003 1

29 1713 CE AUTO

-22 419 ST.LUCIE 2 309 016 12 19 1134 CE AUTO 23 420 ST.LUCIE 2 359 015 12 IG 235'.

CE SUTO 20 421 ST.LUCIE 2 3G9 011 il 21 977 CE AUTO 65 422 GT.LUCIE 2 OS? 014 11 29 4GL CE AUTO 63 423 ST.LUCIE 2 339 001 1

19 132c CE ouTO ter 424 ST.LU2IE 2 330 004 2

? 102:

CE AUTO 100 425 ST.LUCIE 2 709 003 8

30 1356 CE AUTO 1^O 425 SUMMEF 37G 031 12 17 1736 WEST AUTO O

42?

SUMMER 3?5 010 2

7 1234 WEST AUTO 3

423 SUMMER 370 bi i O 2227 WEST AUTO 429 SUMMEE 3:0 041 9

2E 2153 WEST AU~O 10 430 GUMMEP 3"3 024 4

22 703 WEST AUTC 11 431 Sur ii40' 373 024 4

29 EOD WEST AUTO 12 432 SUM?iEP 3?5 011 2

10 510 WEST AUTO 1E 433 CUMMER 3?D 032 7

29 457 WEST AUTO 60 404 SUMMER 395 049 12 27 1035 WEST AUTO 73 435 SUMMER 373 005 1

17 C42 WEST AUTO 100 436 SUMMEP 375 008 2

7 1341 WEST AUTO 10f 437 SUMMER

!95 02C 4

25 247 WEST AUTO 100 430 WPPS2 2 377 033 8

12 437 GE MANUAL 1

439 WPPUS 2 297 115 10 23 2240 GE Auru 440 WP'GO 2 397 104 10 4 2101 GE AUTG 3

441 WPPSS 2 377 076 4

23 1328 GE AUTO G

442 WPPSS 2 377 105 10 6

824 GE AUTO 9.

443 WPPUS 2 397 000 8

1 1803 GE AUTO' 15 444 WPPEG 2 37T 079 S

9 425 GE AUTD 15 44D WPPSS 2 397 042 U

17 1016 GE MANUAL l'

446 WPPSG 2 3?7 043.

5 1? 1910 GE AUTO 17 447 WPPGS 2 "77 044 G

13 1110 GE AUTO 10 448 WPPSS 2 377 060 6

13 2333 GE AUTC 12 4

449 WPPSS 2 397 OG1 5

28 1055 GE AUTO 10 450 WPPSG 2 377 045 5

18 1642 GE~

AUTO 20 9

57

9

' TABLE A.1 PAGE 10 1984-REACTOR TRIPS WAt1E DOCKET LER MONTH DAY TIME VENDCR TRIT' T GWER

+

451 WPPS3 2 397 054 5

29 1230 GE

[UTO 2C

'4 5 2 WPPSS 2 397 056 6

1 347 GE AUTO 20 453 WPPSS 2 397 124 12 3

858 GE AUTO

?f 454 WPPSS 2 397 109 10 13 602 GE MANUAL 40 453 WPPSS 2 397 112 10 20 2225 GE AUTO 4A 456 WPPSS 2 397 125 11 27 156 GE AUTO 45 457 WPPSS 2 397 089 8

16 1255 GE AUTO 60 458 WPFGS 2 397 095 9

10 2130 GE AUTO

$6 459 WPPSS 2 397 114 10 28 340 GE AUTO 92 460 WPPSS 2 397 123 12 2

530 GE MANUAL 96 461 WPPSS 2 397 129 12 28 1059 GE AUTO 100

~ 462 LA CROSSE 409 016 9

8 1447 ALLIS CHALMERS AUTO O

4 463 LA CROSSE 409 019 11 9

107 ALLIS CHALMERS AUT.O O

464 LA CROSSE 409 001 1

7 1842 ALLIS CHALMERS AUTO 30 j465 LA CROSSE 409 000 1

17 5 ALLIS CHALMERS MANUAL 75 466 LA CRDESE 409 018 11 13 823 ALLIS CHALMERS AUTO 95 467 LA CPCEGE 409 021 11 24 1340 ALLIS CHALMERS-AUTO 95 468 LA CROSSE 409 007 5

29 701 ALLIS CHALMERS AUTO 96 469 LA CT:CEEE 409 018 11 8 1015 ALLIS CHALMERS

-AUTO 99 470 LA CROS2E 409 066 4

19 1725 ALLIS CHALMERS AUTO 90 471 GRAND GULF 1 416 040 9

5 1430 GE AUTO O

472 - GRAND GULF 1 416 05G 12 24 1232 GE AUTO 2

473 GRAND GULF 1 416 030 5

2D 91S GE AUTO 4

474 GRAND GULF 1 416 I/E 9

9 63C GE MANUAL 4

475 GRAND 5:JLF 1 116 0D2 11 24 805 GE AUTO 13 476 GPAND GULF 1 416 037 12 21 448 GE AUTO 13 477" ' GRAND GULF 1 416 045 10 14 1700 GE AUTC 19 478 GRAND CULF 1 416 033 11 29 53 GE MANUAL 53 479 BYRON 1 4 01 !/E 12 8 1429

'4EST ITNUAL 0

430 BYRON 1 434 I/E 12 25 213 WEST MAMUAL 481 C A L L.".W A'l 1 463 047 10 6 1437 WEST AUTO 0

402 CALLAWAY I 433 047 10 6 2120 WEST AUTO O

493 CALLAWAY 1 483 046 1,0 5 1720 WEST AUT3 1

404 CALLAWAY 1 483 040 10 10 1424 WEST AUTO i

485 CALLAWAY 1 403 052 10 16 1310 WEST MANUAL T

486' CALLAWAY 1 433 056 10 22 521 WCST AUTO 4

4 8 7-CALLAWAY 1 4C3 065 12 18 36 WE5T AUTO 12 488 CALLAV.'AY 1 403 056 10 23 1531 WEST AUTO 15 4G9 CALLAWAY 1 403 059 11 6

454 WEST.

AUTO 16 490 CALLAMAY 1 483 057 10 27 350 WEST AUTO 19 491 CALLAWAY I 433 039 11 5 1156 WEST AUTO 45 492 CALLAWAY 1 433 060 11 14 1451 WEST AUTO Si 493 CALLAWAY 1 403 061 11 29 305 WEST AUTO UO 494 CALLAWAY 1 423 064 12 17 139 WEST AUTC 10A 1

58 m

. ~ - -

'AOLE A.2 FAGE 1 1984 RPS ACTUATION 3 MITHOUT ROD MOTION NAME DOCMET LER MONTH DAY TINC VENDOR TR!P P3UEa i

1 OIG ROCK POINT 135 005 5

31 125 GE MANUAL 0

2 DIG FGCK FOINT 155 006 6

1 250 GE AUTC 0

3 DIO ECCK."OINT 155 007 6

11 1229 GE AUTO O

4 DIG. ROCK FOINT ISD 000 6

27 1056 CE AUTO 3

5 LJG ROCM FOINT 155 c10 7

27 1023 GE AUTO O

6 OYSTEF CREEK 219 000 9

10 GE AUTO O

l.

7 NINE MILE POINT 1 220 006 4

13 1450 GE AUTO O

O NINC MILE PO HT 1 220 005 5

9 S43 GE AUTO O

9 NINE. MILE FOINT 1 220 007 5

21 611 GE AUTO O

10 NINC 11ILE PO!M1 1 220 007 0

21 620 GE AUTC O

11 NINE MILE FOINT 1 220 000 3

24 1937 GE AUTO O

12 NINE 11!LE PD NT 1 220 031 6

3 2130 GE Mt.NUAL O

10 NIDE MILE PO!NT.1 220 010 6

8 1644 GE Au rO O

14 NINE MILE FOINT 1 220 017 11 12 1129 GE AUTO 0

15 MILLGTCNE 1 045 006 4

13 1255 GE AUTO O

16 DRESEEN 3 24? I/E 3

7 1010 GE AUTO O

17 DREODEN O 247 I/E 3

7 DE AUTQ O

18 DRESDEN 3 249 I/E 3

17 106 EE MANUAL O

19 DnESDEN 3 249 002 3

26 1509 GE AUTO O

20 DRESLEli 3 249 004 4

05 1050 GE AUTO 6

21 DPESDCrt 3 249 011 0

22 411 GE ACTO O

22 DREEDEM 3 249 O'7 10 14 1011 GE AUTO Q

1 1

23 OUAD CITIII !

254 003 3

6 65; GE AUTC C

1 24 OU6D CITIEC 1 254 003 3

6 707 GC AUTO O

25 OUAL Cf7IE5 1 234 003 3

6 722 GE AUYO O

26 OUAO CIT!E5 1 254 007 5

19 Coo CE AUTC O

27,0UAD CIT?t3 1 234 010 C

30 917 GE AUT2 0

22" OUAD CITIES 1 254 011 6

15 1200 EE AUTO 4

29 'QUf:D CITIZE 1 234 013 D

B 2006 SE AU~O O

30 CUAD CITIEC i 2L4 !/E G

25 13G7 -

CE AUTO

^

O!

QUAD CITIE5 1 254 I/E O

25 1407 OE AUTO O

32 PAL 12ADCZ 255 1/E O

10 147.G CE MA*P.'A' 23' tiONTICELLO CSO 002 11 27 1420 CE AUTO O

24 MONTICELLO 263 I/E 12 29 916 GE AUTO O

33 OUAD CITIES 2 260 001 1

3 1107 GE AUTO O

36 OUAD CITIES 2 265 001 1

5 755 GE AUTO' C

37 GUAD CITIES 2 263 002 1

6 1310 GE AUTO O

3 33 VERMCNT YANKEE 271 009 6

17 756 GE AUTO O

l 39 VERI 10NT YANREE 271 015 7

24 1254 GE AUTG-G 40 VER.'iGNT YANKEE 271 016 7

28 1300 GE AUTO O

41 VEFMONT YANEEE 271 018 8

1 731 GE AUTC 0

42 DIADLO CANYON 1 275 021 7

20 205D WEST AUTO O

43 SURRY 1 250 023 12 3

05?

-WEST-AUTO O

44 PILGRIM 293 001 3

16 25 GE AUTO O

~

43 PILGRIM 293 001 3

27 GE' AUTO O

46 PILGRIM 293 008 U

21 1205 GE AUTO O

47 FILCRIM 293 014 i 9

28 1415 GE

. AUTO O

49 ZION 1-295 001 1

5 705-WEST

~Al i'O O

49 ZION 1 295 007 2

23 1712 WEST MANUM, O

50 ZION 2 304 010 3

30 735 WEST AUTO O

1 59

-n'm.

' ~,

~ ~

---,v-.

-r

TABLE A.2 FACE 2 1904 RPS ACTUATIONS WITHOUT ROD F1GTION NAME DOCKET LER MONTH DAY TIME VEN"OR TRIP PC',C.^

+

__~____

Si RANCHO SCCO 1 312 000 7

3 1616 DW

$JTO O

52 MATCH i 321 016 9

30 910 GE AUTO

^

53 HATCH 1 321 I/E 10 12 1400 GE.

AUTO O

C4 HATCH 1 321 021 10 19 1630 GE AUTO

?

53 HATCH 1 321 023 11 6 1345 GE AUTO 56 HATCH 1 321 022 11 12 1450 GE MANUAL o

57 HATCH 1 321 012 11 14 715 GE AUTO O

58 HATCH 1 321 012 11 20 S47 GE MANUAL 3

59 HATCR 1 321 026 12 10.2010 GE AUTO O

i 60 SHOREHAM 2 322 001 12 23 531 GE AUTO O

61 BRUNSWICK 2 32a 000 7

27 1046 GE-AUTO O

62 DRUNSWICK 2 324 009 8

10 1459 GE f.UTO O

63 BRUNSWICK 2 324 009 0

10 149 GE AUT,0 0

64 ERUNOWICK 2 324 010 0

27 1032 GE AUTO O

65 ERUNSWICK 2 324 025 9

10 915 GE AUTO O

66 ERUNCWICK 2 324 011 9

24 2134 GE AUTO O

67 BRUNSWICV 2 324 018 11 23 1026 GE AUTO O

68 DUANE ARNOLD 331 01D 4

30 337 GE AUTO O

69 DUANC ARNOLD 3d1 I,'E 7

14 152a GE AUTO O

'O FIT 2PATRich' 333 01S 9

18 1315 GE AUTO O

71 FITZFATFICK 33'3 018 9

18 GE AUTO O

72 FIT 2 PATRICK 333 02C 9

28 1617 GE AUTO O

1 73 FITZPATFICK 333 020 9

28 2302 GE AUTO O

74 FITZFATRICK 333 I/E 10 6 1650 GE AUTO C-i 75 FITZPATRICK 333 022 10 28 1840 GE AUTO O

76.FARLEY 1 348 012 4

21 1133 HEST MANUAL e

77 LIHEMICK 1 352 002 10 31 1359 GE AUTO O

78 L1!1ERICK 1 352 005 11 9

208 GE AUTO O

79 L!t1ERICM i 352 023 11 29 1913 GE PUTO O

CO LIMERICK 1 252 039 12 21 252 GE Aula O

81 HATCH 2 366 I/E 7

31 500 CE AUTO O

02 HATCH 2 366 I/E 9

14 1700 GE AUTO

?_i 83 HATCH 2 366 I/E 8

21 1305 CE AUTO O

04 MATCH 2 366 :/E 10 7 1D30 GE AUTO O

85.

HATCH 2 366'I/E 10 20 1413 GE AUTO-O 1

C6 MCGUIRE 1 369 015 4

26 030 WEST MANUAL O

67 MCGUIRE 2 370 003 1

22 2024 WEST AUTO O

88 LAGALLE 1 373 008 2

18 2045 GE

. AUTO O

89 LASALLE 1 373 00?

2 19 1010 GE AUTO O

90- LASALLE 1 373 010 2

19 2110.

GE-AUTO O-91 LASALLE 2 374 001 1

5.1418 GE AUTO O

H92 LA?;ALLE 2 374 002 1

13 540 GE AUTO O

.93 LASALLE 2 374 011 2

13 100 GE AUTO O

94 LAGAL E 2.

374 I/E 6

16 159 GE MANUA!.

O J

93 LASALLE 2 374 049 7

31 1811 GE AUTO O

96 LASALLE 2 374 045 7

31 944 GE AUTO 97 SUSQUEHANNA 2 388 003 4

9 GE AUTO O

98 SUSOUEHANNA 2 3DO 003 4

9 GE AUTO O

99 SUSDUEHANNA 2 238 003 4

9 GE AUTO O

100 SUGOUEHANNA 2

.388 003 4

9 GE AUTO O

3 60

1 TAELE A.2 PAGE 3 1984 RPS ACTUATIONS WITHouT ROD MOTION NAME DOCKET LER MONTH DAY TIME VENDOR TRIS POWr.:

1 F

I

=

101 SUSOUEHANNA 2 3S0 003 4

9 GE

[UTO 302 SUSQUEHANNA 2 388 003 4

9 GE P.U TO O

103 SUMMER 395 050 12 18 1333 NEST AUTO 104 WPPSS 2 397 003 1

20 20 CE MANUAL

^

105 WPPSS 2 397 007 1

27 1448 GE AUTO

?

106 WFPSS 2 397 007 1

31 1252 CE AUTO O

107 WPPSS 2 397 014 2

19 500 GE AUTO O

103 WPPSS 2 397 011 3

2 1408 GE AUTO O

109 WPPS$ 2 397 011 3

9 151S GE AUTO o

110 WPPSS 2 377 02S 3

20 1630 GE AUTO O

111 WPFSS 2 3?7 090 0

7 2239 GE AUTC-0 112 WPPSS 2 397 091 8

23 421 GE AUTO O

113 WPPSS 2 397 113 10 21 136 GE AUT,0 0

114 WPPSE 2 397 131 12 29 304 GE AUTO O

,115 LA CROSSE 409 014 8

22 103; ALLIS CHALMERS AUTO O

116 GRAND GULF-1 416 002 1

14 1010 CE

' AUTO O

117 GRAND GULF 1 416 002 1

14 1030 CE AUTO O

110 GRAND GULF 1 416 000 1

14 1035 CE AUTO O

119 CRAND CULF 1 416 011 3

9 1329 GE AI.'TC O

120 GRAND GULF 1 416 033 7

2 1125 GE AUTO O

121 GRAND GULF 1 416 04C 9

5 1615 GE A'_' T D 0

122 BYRGli 1 t-94 025 12 13 1441 WEST AUTO' O

123 CALLAWAY 1 403 014 7

14 257 WEET MANUAL 0

124 CALLAWAY I 483 015 7

16 150 WECT MANUAL 0

125 CALLA %4Y 1 400 042 9

23 805 WEST AUTO 0

125 CALLAWAY 1 483 045 9

30 1029 WEST AUTO 12I"'CALLAWAY 1 493 040 10 10 1826 (CEST AUTO O

123 CAL _AWAY 1 433 040 10 10 IS!D NCOT AUTC O

O e

4 61

l APPENDIX 8 1984 REACTOR TRIP RATES NAME MANUAL AUTO LESS THAN GREATER CRITICAL TRIP RATE PER MEAN TIME MATIC OR EQUAL THAN HOURS 1000 HOURS BETWEEN TRIPS 15% POWER 15% POWER POWER GT 15 POWER GT 15%

WPPSS 2 4

20 7

17 2983.0 5.70 175.5 CALLAWAY 1 1

13 6

6 1131.5 5.30 188.6 GRAND GULF 1 8 2 6

3 4

1010.0 3.96 252.5 SUSQUEHANNA 2 2

8 1

7 2145.9 3.26 306.6 SALEM 1 0-10 3

7 2672.3 2.62 381.8 i

MCGUIRE 2 5

13 0

16 6138.3 2.61 383.6 SALEM 2 0

40 2

8 3386.0 2.36 423.3 HATCH 2 0

7 0

7 3108.7 2.25 444.1 DIABLO CANYON 1 0

7 3

2 967.1 2.07 483.6 LASALLE 2 3

8 2

9 4469.8 2.01 496.6 SURRY 2 2

13 2

12 7435.3 1,61 619.6 BROWNS FERRY 3 2

0 1

1 700.7 1.43 703,7 LASALLE 1 0

9 0

9 6280.0 1.43 697.8 SEQUOYAH 2 0

10 0

9 6334.0 1.42 703.8 NORTH ANNA 1 2

7 2

6 4759.9 1.26 793.3 ST.LUCIE 2 1

9 0

9 7379.2 1.22 819.9 TURKEY POINT 4 0

11 3

6 5079.8 1.18 846.6 SURRY 1 1

7 2

6 5293.7 1.13 882.3 i

D.C. COOK 2 2

6 1

6 5294.8 1.13 882.5 em SEQUOYAH 1 1

12 4

7 6206.1 1.13 886.6 SUMMER 0

12 5

6 5553.4 1.08 925.6 SUSQUEHANNA 1 1

6 0

7 6549.3 1.07 935.6 DRESDEN 3 0

9 4

4 3889.0 1.03 972.3 TROJAN O

7 2

5 4895.4 1.02 979.1 INDIAN POINT 3 0

9 0

7 6941.6 1.01 991.7 TURKEY POINT 3 1

8 1

7 7366.6 0.95 1052.4 LA CROSSE 1

3 0

7 7437.0 0.94 1062.4 ST.LUCIE 1 2

4 1

5 5555.2 0.90 1111.0 HATCH 1 3

7 3

5 5638.7 0.89 1127.7 MCGUIRE 1 0

5 0

5 6090.8 0.82 1218.2 2

SA% ONOFRE 3 0

9 3

4 5070.7 0.79 1267.7 J

ARKANSAS 2 0

15 6

6 7631.9 0.79 1272.0 YANKEE ROWE 2

3 0

5 6398.6 0.75 1279.7 RANCHO SECO 1 0

4 0

4 5338.8 0.75 1334.7 BRUNSWICK 2 0

3 1

2 2650.1 0.75 1325.1 DUANE ARNOLD 0

6 1

5 6627.1 0.75 1325.4 1

DAVIS-BESSE 1 1

4 0

4 5529.0 0.72 1382.3 FARLEY 2 1

5 0

6 8375.7 0.72 1396.0 t

4 a

9 G

e A

l

i l

l APPENDIX B 1984. REACTOR TRIP RATES NAME MANUAL AUTO LESS THAN GREATER CRITICAL TRIP RATE PER MEAN TIME MATIC OR EQUAL THAN HOURS 1000 HOURS BETWEEN TRIPS 15% POWER 15% POWER POWER GT 15 POWER GT 15%

BRUNSWICK 1 0

7 2

5 7023,8 0.71 1404.8 CALVERT CLIFFS 1 4

1 0

5 7531.0 0.66 1506.2 PALISADES 6

0 1

0 1

1550.5 0.64 1550.5 PEACH BOTTON 3 1

4

-0 5

7757.7 0.64 1551.5 OUAD CITIES 1 1

3 0

3 4766.9 0.63 1589.0 ZION 1 0

6 2

4 6319.8 0.63 1579.9 BROWNS FERRY 1 4

4 3

5 8067.4 0.62 1813.5 BEAVER VALLEY 1 1

6 0

4 6476.3 0.62 1819.1 OCONEE 3 0

4 0

4 6520.7 0.61 1830.2 MAINE YANKEE 1

7 3

4 6688.8 0.60 1872.2 SAN ONOFRE 2 1

4 2

3 5272.4 0.57 1757.5 FITZPATRICK 0

4 0

4 7087.2 0.56 1771.8 ARKANSAS 1 0

3 0

3 6222.4 0.48 2074.1 DRESDEN 2 0

3 0

3 6511.4 0.46 2170.5 i

INDIAN POINT 2 1

5 2

2 4718.4 0.42 2359.2 OCONEE 1 0

3 0

3 7452.4 0.40 2484.1 D.C. COOK 1 0

3 0

3 8085.9 0.37 2695.3 PRAIRIE ISLAND 1 0

4 1

3 8321.3 0.36 2773.8 BROWNS FERRY 2 0

3 0

2 5895.7 0.34 2947.9 COOPER 0

3 1

2 5952.6 0.34 2976.3 mm NORTH ANNA 2 1

4 2

2 6136.0 0.33 3068.0 ZION 2 2

6 5

2 6285.2 0.32 3142.6 1

HADDAM NECK 1

3 1

2 6515.6 0.31 3257.8 i

CALVERT CLIFFS 2 0

2 0

2 6630.2 0.30 3315.1 QUAD CITIES 2 1

4 0

2 6988.6 0.29 3494.3 VERMONT YANKEE O

2 0

2 7115.2 0.28 3557.6 j

KEWAUNEE O

5 2

2 7570.5 0.26 3785.3 CRYSTAL RIVER 3 0

2 0

2 8346.5 0.24 4173.3 MILLSTONE 2 1

2 1

2 8596.8 0.23 4298.4 FORT CALHOUN 1 0

1 0

1 5336.3 0.19 5386.3 i

R.E.GINNA 0

1 0

1 6848.7 0.15 6848.7 FARLEY 1 0

2 1

1 7005.8 0.14 7005.8 1

BIG ROCK POINT O

3 3

0 6981.9 0.00 1

SAN ONOFRE 1 0

0 0

0 888.6 0.00

@YSTER CREEK 0

2 2

0 1700.0 0.00 NINE MILE POINT 1 0

1 1

0 6414.0 0.00 MILLSTONE 1 0

0 0

0 6990.2 0.00 H.B. ROBINSON O

1 0

0 616.1 0.00 1

e 4

e i

l 4

i i

APPENDIX 8 1984. REACTOR' TRIP RATES NAME MANUAL AUTO LESS THAN GREATER CRITICAL TRIP RATE PER MEAN TIME MATIC OR EQUAL THAN HOURS 1000 HOURS BETWEEN TRIPS 15% POWER 15% POWER POWER GT 15 POWER GT 15%

MONTICELLO O

O O

O 310.6 0

POINT BEACH 1 1

1 0

0 6420.1 0

OCONEE 2 0

0 0

0 8784.0 0

PEACH 80TTOM 2 0

0 0

0 2583.9 0

PILGRIM 0

0 0

0 170.3 0

POINT 8EACH 2 0

1 0

0 7544.2 0

PRAIRIE ISLAND 2 0

0 0

0 7844.0 0

8YRON 1 2

0 0

0 0.0 E

e e

b O

e E

e>

a L

Appendix C Table C.1 Personnel Error-Induced Reactor Trips at Power >155 at BWRs Personnel No.

System Power (1)

Involved Cause

?

r 1.

Reactor Protection 66 Licensee Staff The improper connection l

2 of a te'st switch to the RPS logic by a test engineer i

led to a reactor trip.

2.

Reactor Protection 95 Technician A technician vented the variable side of the I

reactor water level instrument which then sent a pressure surge and i

caused that instrupent to actuate.

3.

Reactor Protection 24 Technician Grinding induced vibration 4

while installing a ground connector by electrician on a RPS panel cause a reactor trip.

l 4.

Reactor Protection 99 Technician An instrument rack was jarried in the reactor building and this caused a spurious signal to the RPS and a reactor trip.

S.

Reactor Protection 60 Technician Technicians were conduct-ing surveillance tests in two RPS channels at the same time.

6.

Reactor Protection 100 Unlicensed A worker proceeded to work Worker on equipment without acquiring 1

the proper clearances. By their opening and closing i

equalyzing and isolation valves, a water level instrument caused a reactor trip.

7.

Tarbine 68 Technician While troubleshooting the EHCS, the technicians' actions caused loss of the EHCS power supply.

i d

I t

65 4

--ge-,-----_--,

--,.,-c-

,7-m

,,,.,,.,.-y.,,

____,,-,-..n_,,-___,-,--...,,-,,-,,-cm,-,,--,w,,--m-,.

-,,,,,,--,--~_..,-,_m.

Pers nn21 g.

System Power (%)

Involved Cause 8.

Turbine 93 Operator An operator opened the wrong flow bypass valve for the EHCS of the wrtng unit.

9.

Turbine 95 Licensee Staff The operating staff did not ve~rify that,the Maximum combined Flow limit was at its maximum and prior to the start of control valve surveillance.

10.

Turbine 61 Unlicensed During testing, personnel i

Operator inadvertently actuated the main turbine oil tank level switch.

t 11.

Turbine 25 Staff An improper valve lineup caused fast closure of the turbine control valve.due to low condenser pressure.

12.

Containment 94 Operator The operator did not follow written procedures.

13.

Containment 97 Technician Inadequate replacement procedures.

14.

Condensate 4'O Operator Valve left in the wrong position.

15.

Condensate 19 Operator The operator set the main condensate filter diminera-i lizer set point controller to low.

16.

Condensate 18 Licensee staff The staff failed to imple-ment in a timely fashion the operating instruction for the condensate system.

17.

Condensate 92 Operator An operator mistakenly closed the wrong valve.

18.

Electrical 30 Technician A technician failed to check (480 V. Bus) the voltage on an under-i voltage relay.

1 e

66 i

l -

l Psrs:nnel g.

System Power (%)

Involved Cause 19.

Electrical 95 Operator An undervoltage developed (480 v. Bus) on the essential bus due to shift supervisors incorrect response.

20.

Electrical 45 Not-determined The main power trans.former i

differential overcurrent relay was wired incorrectly.

21.

Main Generator 80 Technician Inadvertent removal of the main generator potential transformer fuse.

22.

Turbine 40 Operator The operator did not verify inputs to the EHCS system.

23.

Main Steam 60 Technician Technician created a spurious low pressure signal in main steam logic while testing.

24.

Main Steam 85 Vendor staff An incorrect terminal connection was made to the turbine control valve.

25.

RCIC 89 Technician Inproper placement of chameter leads during a test.

26.

Feedwater 52 Operator The operator miscalculated the reactor vessel level and erroneously placed the feedwater pump in auto.

27.

Feedwater 89 Technician A signal mismatch was created during calibration of the feedwater flow.

28.

Feedwater 53 Technician Mishandling of the ground leads by technician resulted in grounding of the input to the feedwater pump controller.

l 29.

Feedwater 25 Operator The operator failed to follow plant procedures during transfer from feedwater startup control.

1 i

/

l 1

67 i

____._._____-.._,___,______.,__,.-,........_,._-_-__m..

_.-,.._._.___,_.,-..,____._r,

1 Personnel

'No System Power (1)

Involved Cause 30.

Instrument 95 Operator Operator closed the Air instrument air supply valve which resulted in a condensate filter demineralizer outlet valve closing.

31.

Main Steam Line 98 Technician The technicians failed Monitoring Sys.

to follow approved plant procedures.

e e

e w

f l

68

- -, _. - _ ~ -

~

~

~'

e e

1 Table C.2

,f Personnel Error-Indecad Reactor Trips at Power >155 at PWR:

i Personnel

^

g.

System Power (1)

Involved 1.

Reactor Protection 100 Technician High Flui' Rate Signal i

generated 5y technician while testing Nucledr Instrumentation System.

2.

Reactor Protection 100._

Technician The improper use of test leads which had an exposed connector duririg testing of Nuclear Instrumentatf on System.

/

3.

Reactor Protection 100 Techn'cian While testing, a technici.tre i

used an ungrounded lead with a digital voltmeter T '

which caused a fuse to blev

~

1 r

in the Nuclear @strumentat'.On g

/

System.

4.

Reactor Protection 63 I

Operator The operator opened the wrong reactor trip bretitr during j-a maintenance operation.

5.

Reactor Protection 89 Technician During testing, the technician opened the wrong compartraent and pushed the reactor trip pushbuttop.[

6.

Reactor Frotection 94 Technician While testing, a technician opened the wrong control rod drive breaker.

7.

Reactor Protection 73 Operator During testing, the operator h,

opened the wrong reactor trip breaker.

8.

Reactor Protection 100 Operator During testing, the operator failyl to follow procedures.

9.

Reactor Protection 75 Tirchnician During testing, an -

improper test signal

~

/

was used which caused the feedwater valve to close and a subsequent reactor trip.

69 r

f f

'>a

l Parsonnel g.

System Power (1)

Involv;d Cause 10.

Reactor Protection 77 Technician During instrument cali-bration, the technician error while reducing the Power Range setpoints.

11.

Reactor Protection 99 Technician Reactor coolant flow transmitter 4qualizing valve leak-through due to improper closure method at system operating pressure.

12.

Turbine 100 Technician During troubleshooting, a technician used and under-ground test instrument.

This caused the EHC to fail safe and the turbine to trip.

This led to a reactor trip.

13.

Turbine 21 Operating An improperly wired controls Staff caused the condenser dump valve to fail.

14.

Turbine 48 Technician During unit operation, a-reactor trip occurred because of the failure to reinstall a support bracket on the EHC discharge line.

This led to loss of fluid thru a discharge valve on the line which opened due to excessive vibration.

1 J5.

Turbine 100 Technician During a maintenance operation, the technician did not adequately review the system status prior to the start of work on the Turbine Bearing Wear Detector.

16.

Turbine 25 Technician An incorrectly wired pressure switch caused a turbine trip and a reactor trip.

17.

Turbine 100 Operator The operator did not follow procedures while trying to reestablish auto level control in the moisture separator drain tank.

70 I

Personnel No.

System Power (1)

Involved Cause 18.

Turbine 70 Technician Timber used for dunnage l

bumped the MSR cabinet actuating the high level switch, causing a turbine trip and a reactor-trip.

19.

Containment 100 Operator Operator's judgement in deciding to pull atmosphere sampling valve fuse without proper technical review.

20.

Reactor Coolant 99 Operator While testing was in progress, System an operator inadvertently tripped a reactor coolant Pump.

21.

Reactor Coolant 100 Operator While testing, the PORY bicek System valve was not verified open by plant procedures.

j Procedures were changed to reflect proper valve lineup for test.

- 22.

Condensate 50 Operator During unit operation, poor condensate pump suction strainer venting technique led to loss of a feed pump and reactor trip.

23.

Condensate 100 Technician During maintenance, an air-line supplying powdex outlet valve was sheared while an attempt was being made to straighten it.

i 24.

Electrical 100

' Operator An operator and an independent verifier failed to identify proper equipment to be removed from service.

25.

Electrical 100 Unlicensed The operator erroneously Operator opened the output breakers to the inverter supplying ROVAC vital buses. ~

71 1

l

,__._,___._..,__,,,,._r,_-_.-.........,__...,,,_...,w_,

,c,

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

Personnel pic[.

System Power (1)

Involved Cause 26.

Electrical 100 Unlicensed A construction electrician Operator accidently tripped the 4.16k bus.

l 27.

Electrical 100 Operations Inadequate analysis of Staff the load shed task.

28.

Electrical 100 Unlicensed An error in the switching Personnel order requested and executed by non-nuclear personnel.

29.

Electrical 85 Unlicensed A janitor acci-Contractor dentally bumped the hand switch on feeder power supply to the RCP (the breaker from the auxiliary transfonser to the 6.9KY bus.)

30.

Electrical 26 Operator An operator during the process of shutting-down, unintentionally deenergized the power to the Reactor Plant Coolant Pump while transferring loads.

31.

Electrical 100 Operator An unanticipated system interaction took place during the removal of obsolete cables during plant modifications.

32.

Control Rod Drive 100 Operator /

The operator inadver-Equipment tenly racked out and opened the reactor trip breaker instead of an alternate trip bypass.

33.

Control Rod Drive 73 Operator The operator reduced turbine load more quickly than reactor power.

4 t

72 i

. r.-

J. - n- '. : L

o Personnel No.

System Power (%)

Involved Cause 34.

ESFAS 27 Technician A technician actuated i

the ESFAS during a surveillance on the unit's protection system.

35.

Feedwater 78 Technician While troubleshooting the circuitry of the feedwater pump thrust bearing wear detector, a lead came in contact with an adjacent terminal, c:ampleting a circuit and causing a turbine runback and subsequent reactor trip.

36.

Feedwater 39 Operator Manual steam generator level control problem encountered by operator.

1 37.

Feedwater 100 Operator The operator failed to select the proper steam generator control channel during testing.

38.

Feedwater 22 Operator The operator fed the steam generator more than required while manually controlling

~,-

level.

39.

Feedwater 16 Operator '

During a load reduction, the operator closed the i

main regulator valve too fast and the automatic bypass valve could not respond in time to supply flow to the steam generator.

40.

Feedwater 18 Operator The operator failed to maintain steam generator water level.

l 41.

Feedwater 21 Operating Failure by the staff to Staff check proper valve If neup prior to unit startup.

t 73

Personnel pict.

System Power (%)

Involved Cause 42.

Feedwater 30 Operator An operator inadver-tinely stopped the feedwater lube oil pump which then tripped the operating feedwater pump and led to a reactor trip.

43.

Steam Generator 100 Technician The technician failed Level Control to remove the field System leads from the signal isolator inputs for the steam generator narrow range level recorder.

44.

Main Steam 100 Technician A technician erroneously interrupted current flow to the solenoid valve which control the MSIV.

74

Appendix D Component Failures Power >15%

Mechanical Electrical / Electronic Components Components No. of No. of Component Counts Component Counts Pump Bearing 5

Relays 10 Heater Tubes 5

Breakers 10 Control Valves 6

IC & Circuits 16 Valves 23 Fuses 7

Atr Lines 4

Control Switches 9

Pumps 8

Power Supplies 5

Filters 2

Instru. Channel 5

Intake Screen 1

Transmitters 6

Hose 1

Transformers 4

Indicator 1

Capacitors 2

Moisture Trap 1

Electric Coils 3

Nozzle 1

Inverters 3

0-Ring 1

Solenoids l'

Strainer 1

Ring Brushes 1

Seal 3

Elec. Connectors 3

Valve Actuator 4

Trans. Lines 2

Valve Linkage

-1 Alternators 1

Pinfon Gear 1

Bus Bars 1

Unloader i

Volt Compar.

1 Relief Yalve 1

Insulators 2

Expansion Joint 1

Instru. Conn.

1 Gasket 3

Lightning Accestors 1

r ~

Pipe Weld 1

Instrument Line 3

Fan 1

Thermocouples 2

Control Linkage 2

Controller 7

M.S. Reheater 1

Exciter Bearing 2

Turbine Blade 1

1 75

I s

APPENDIX E Quality of LER Reactor Trip Information

~

The LER rule, 10 CFR 50.73, was formulated to provide detailed information,on subjects felt to be most important to understanding the lessons provided by operating experience.

The' number of subjects was limited in order to keep the quantity of report at a reasonable level and thus allow improvements in quality without increasing the total reporting burden. Another objective of the rule was to collect complete information, (i.e., all occurrences) for the reportable events. Our close examination of the LERs reporting reactor trips lead us to conclude that licensees are doing well on completeness, but have not achieved the level of detail required by the rule.

10 CFR 50.73(b) describes in detail the requirements for the current of an LER.

It requires that licensees provide:

"A clear, specific narrative description of what occurred so that knowledgeable readers conversant with the design of commercial nuclear power plants', but not familiar with the details of a particular plant, can understand the complete event." [50.73(b)(2)(i)]

In some cases, the overall intent of this requirement is not being met because the licensees are providing only a brief abstract of an event.

This practice r~

represents little improvement over the LERs required prior to issuance of 10 CFR 50.73.

The most egregious examples have been brought to the attention of regional personnel for corrective action.

10 CFR 50.73(b)(2)(ii)(j) also states, in part, that:

"(2) For each personnel error, the licensee shall discuss...

livl The type of personnel involved (i.e., contractor personnel, utility licensed operator, utility nonlicensed operator, other utility personnel)."

t 76

l

+

In a few instances, licensees are using language which is vagua when discussing personnel error, hinting that personnel are involved and avoiding clear state-ments of findings.

In a large number of instances, the license status of each individual is not provided.

10 CFR 50.73(b)(2)(fi)(k) further requires discussion of:

~

" Automatically and manually initiated safety system responses" In most of the cases examined, detailed discussion of the plant response after the reactor trip is missing. Many reports contain words such as "the plant responded normally" or "all ESFs responded as designed." This does not meet the requirement of the rule to discuss these responses in sufficient detail that " readers conversant with the design of commercial nuclear power plants, but not familiar with the details of a particular plant can understand the complete event" (emphasis added).

In order to assess the challenge to safety systems posed by reactor trips it is necessary to have complete information.

Lastly, 10 CFR 50.73(b)(2)(ii)(c) requires " Dates and approximate times of occurrences." In many cases examined, the time of the reactor trip was not provided in the LER and had to be extracted from the Incident Response Center file.

e 4

77

e j

l T

~~

APPENDIX F Associated Failures i

Unit LER Power Failures Reason 1

i

1) Yankee Rowe 17 61 Boiler feed pumps failed Sensing line deterioration j

50-029 to automatically trip and pressure switch failure i

i

2) Indian Point 2 25 100 Malfunction of safety Solidified boric acid and 4

f 50-247 injection pumps gas binding of the pumps

3) Turkey Point 3 14 100 Loss of AFW control and Failed instrument power 50-250 indication and condensate supply l

storage tank level indication l

4) Turkey Point 4 22 0

Closure of letdown line Blown fuse caused loss 50-251 pressure control valve and of power to vital panel RCS pressue drop caused by l

l opened PORY M ) Palisades

]

5 15 48 Safeguards bus did not Blown fuse in bus supply l

j 50-255 fast transfer to start-up breaker l

power i

6) Browns Ferry 2 2

94 "A" recirculation pump Sensing switches on low end 50-260 did not trip.

of accuracy band l

l i

7) Quad Cities 2 10 0-One control rod was not Scram discharge riser j

50-265 inserted valve was mispositioned f

1 i

8) Ococee 1 2

100

1) two main steam relief Not stated j

50-269 valves did not reseat properly j

2) Control rod drive Power supply faulty i

relative position l

indication was off 4

l i

e Unit LER Powe'r Failuros RIason

9) Oconee 1 6

43 Main steam relief valves Not fully known; did not reseat properly setpoint adjusbaent'

10) Oconee 1 7

57

1) Emergency feedwater Unknown level control did not operate properly

2) Main steam relief valves Not fully known; did not reseat properly setpoint adjustment

11) Vermont Yankee 1

100 Reactor feed pump trip Level transmitter out of 50-271 calibration

12) Salem 1 2

100 Minor seat leakage in main Unknown i

50-272 steam isolation valve steam assist valves

13) Salem 1 25 91 Condensate pumps were Operator error inadvertently removed a

service

}

14) Diablo Canyon 1 30 21 Inadvertent safety injection; Personnel error and i

50-275 caused ECCS; contents of boron incomplete procedures i

injection tank were injected j

into RCS

15) Surry 1 1

100

1) "A" feed regulation valve Nut (unknown origin) 50-280 would not fully close in valve internals i

2) Failure of automatic Undercompensation of l

l reinstatement of source intermediate range range channels channel i

i

16) Surry 1 2

100

1) "A" main feed regulating Not determined j

valve did not fully close 1

1

2) Source range detector failed Compensation problems to automatically reinstate with intermediate channel

3) Source range detector did Not determined l

Not reinstate manually i

o i

.g Unit LER Power Failures Reason

~

17) Surry 1 3

100

1) "A" feed regulation valve Not detemined would not fully close

2) Source range did not Undercompensation of automatically reinstate intemediate range

3) Manual reset circuit for Capacitor problems source range malfunctioned

18) Surry 1 8

1

1) Source range failed high; Pre-amp failure

2) Other source range inoperable Source range detector due to noise failure

19) Surry 1 15 100

1) Failure of mechanical seal Bearing housing on "A" sain feed pump-wet detached; vibration pump loosened screws m

l

2) "A" sain feed regulation Cut motor lead block valve failed due to l

a grounded motor lead i

3) Failure of automatic Slight-under reinstatement of source compensation of j

range channels intemediate range channel t

i

20) Surry 2 1

100

1) Auxiliary feed valve Automatic control

)

50-281 would not remain closed relay malfunction J

l

2) Vessel leakoff Leaking reactor vessel j

temperature increased head inner sedl J

1

3) Source range would not Undercompensation of j

automatically reinstate intemediate range l

channel a

1

\\

}

Unit LER Power Failures Reason l

l-

21) Surry 2 3

23 Source range monitor did not Failure of capacitor in j

automatically reinstate crowbar circuit due to age

22) Surry 2 5

100

1) "B" main feed reg. valve Not stated t

failed to completely close

2) Rod position indicator Not stated gave incorrect indication i

jl

23) Surry 2 10 86 Main turbine No. 1 stop valve Not determined did not close

24) Surry 2 10 85 Source range instruments Compensation problem failed to automatically with intermediate range reinstate channels

)

25) Surry 2 15 100

1) Control rod appeared to No specific problem j

momentarily stick found; position indication suspected

2) Nuclear instrumentation Problem suspected to be i

channel failed to in crowbar circuit in automatically reinstate; power supply

3) Respo.nse after reinstatement Detector failure l

was abnormal l

4) Auxiliary feed pump relay One of the coil leads j

failed causing valve faults opened l

5) "A" reactor coolant pump "D" transfer bus was lost power deenergized for testing k

l l

i

.i

J Unit LER Power Failur:s R ason

26) Cooper 10 90 Breaksrs did not automatically Unknown 50-298 operate to transfer power to

.I startup transformer

27) Crystal River 3 3

74

1) "B" emergency diesel generator Field overcurrent due to 50-302 output breaker tripped electrical fault

2) Reactor coolant flow dropped Reactor coolant pumps momentarily did not have power for 5 seconds

28) Crystal River 3 10 97

1) Atomspheric dump valve Not stated (ADV) failed to reseat a

2) Several main steam safety Improper setpoint j

valves (MSSV) failed to reseat

3) Erroneous indication on Loss of non-nuclear instrumentation; instrumentation (NNI) condensate system plant failed capaciter computer, and annunciators (wrong rating) m lost i

N

29) Salen 2 10 30 Steam generator process control Malfunctioning feedwater 50-311 control system valve demand water flow channels j

controller failed i

30) Rancho Seco 1 15 85

1) Partial loss of non-nuclear Overvoltage trip setpoint 50-312 instrumentation (NNI) setpoint drift

2) Pressurizer code safety Septpoint not correct valve lifted early

3) Turbine bypass valve stuck Not identified l

stuck open i

31) Rancho Seco 1 25 16

1) Difficulty starting up Not stated auxiliary boiler

)

l

2) Some difficult with "B" Auto start pressure switch auxiliary feedwater pump failed to reset; valve steam admission valve needed cleaning and lubrication

i

.g Unit LER Power Failures Reason

32) D.C. Cook 2 20 100 Flow control valves in Limit switches improperly 50-316 auxiliary feedwater system set did not operate properly

33) Calvert Cliffs 1 2

100 Main feedwater pump tripped Not stated 50-317

34) Calvert Cliffs 1 15 100 Feedwater heater extraction Not stated steam line ruptured; man in (main turbine trip) vicinty received 2nd degree burns 1

35) Calvert Cliffs 2 3

100

1) One of four turbine bypass Current to pneumatic signal 50-318 valves remained partially converter out of adjustment open

2) Low level in steam Operator inexperinence generator i

36) Hatch 1 7

95 Reactor high pressure scram Faulty test equipment; i

50-321 instrumentation did not instruments out of actuate properly calibration l

37) Hatch 1 15 95 "A" safety relief valve did Setpoint drift l

open; declared inoperable 1

i

38) Brunswick 2 12 7-

1) Safety / relief valve tail Slippage of recorder i

50-324 pipe temperature recorder drive chain gave erroneous indication 1

J

2) Safety / relief valve sonic IC chip connection position indication did not required cleaning i

function i

l i

J l

1 j

i i

~~

Unit LER Power Failurbs i

R:ason l

39) Brunsuick 2 18 98

1) Reactor recir. pump *B" did Bad reset potentiometer

~*-

automatically run back in pump controller j

2) Low pressure coolant Excessive seat leakage injection loop B was past isolation valve inoperable

3) Reactor core isolation Failure of in service i

cooling system was test equipment inoperable

4) Residual heat removal Water hammer in steam 1

loop "A" inoperable steam condensing piping

40) Brunswick 1 6

95 High pressure coolant Not stated

}

50-325 injection system j

automatically isolated i

j

41) Brunswick 1 14 95 Main steam isolation valve Solenoid pilot valve did not automatically close failed m 42) Sequoyah 1 13 4

1) "A" main feed pump turbine Not determined j

50-327 failed to trip

2) Turbine driven auxiliary Dirty contacts or poor feedwater pump failed to connection of cable start 1

l

43) Sequoyah 1 35 100 Loss of 120 VAC vital inverter; Blown fuse as a result, several systems i

malfunctioned i

3

44) Sequoyah 1 54 100 Reactor coolant system pressure Instrument relay rack l

channel failed low breaker tripped - blown fuse J

45) Sequoyah 2 14 25

1) Main feedwater isolation Stuck contact A sticky j

50-328 valve failed to close lubricant

)

2) "B" main feedwater pump Incorrect solenoid valve reset itself 1

J I

~

Unit LER Power Failures Reason 4

46) Sequoyah 2 15 100

1) Containment isolation valve Limit switch improperly adjusted not indicate closed

2) Invalid pipe break signal Incorrectly wired pressure j

switch

47) Sequoyah 2 16 97 Turbine driven auxiliary Loose limit switch actuation i

feed pump level control valve am j

indication not correct i

48) Duane Arnold 8

100 LPCI loop select logic Blown fuse - faulty light l

50-331 channel inoperable bulb socket j

49) Duane Arnold 40 7

All nonessential loads lost; Startup transformer tripped j

NRC hotilne lost; normal ground fault radiation air sampling 4

capability lost; normal s

conductivity monitoring lost.

I cn 50) Duane Arnold 42 81 NRC telephone system unavail-Loss of nonvital power; spurious able; normal conductivity fire protection deluge system monttoring lost actuation

51) Fitzpatrick 9

67 High pressure coolant injection Gasket failure 50-333 system (HPCI) gland seal condensor flange leak i:

52) Fitzpatrick 10 25 High pressure coolant injection Gasket failure System (HPCI) gland seal condenser developed a large leak l

4

53) Beaver Valley 1 4

100

1) Undervoltage auto start of Pertiaps conservative relay 50-334 "I diesel generator settings j

l

2) Cooling tower pumps tripped Conservative relay settings?

E

3) Condenser steam dump valves Switch contacts dirty

]

failed to open in T AVG mode

}

1 j

k

q Unit LER Power Fallures Reason

54) Beaver Valley 1 12 94 Busses 1A and 18 temporarily Not stated lost offsite power

55) St. Lucie 1 6

99 Steam bypass and control Failed pressure transmitter 50-335 system did not fully actuate; as a result, 5 S/G safety l

relief valves lifted momentarily

56) Millstone 2 12 62 Main feedwater check valve Valve stem bound up; i

j 50-336 failed to seat required adjustment

57) North Anna 1 19 100

1) "B" main feed valve and "B" Vital bus inverter failure i

50-338 feed bypass valve failed caused by damaged SCR's and a 1

i closed blown fuse

2) "B" wide range steam 4

generator level indication l

failed low j

3) Auxiliary feedwater pump

.a failed to auto start i

4) Other equipment lost power i

58) North Anna 2 2

2 Apparent stuck control rod IRPI for control rod out of i

50-339 callbartion

~

l

59) Trojan 6

78 Main steam nonreturn check Valve shaft packing friction 50-344 valves failed to close forces too high l

60) Trojan 16 15

1) Emergency diesel generator High crankcase pressure;

]

tripped reason unknown 1

2) Steam driven auxiliary Failed pressure transmitter 4

i feedwater pump tripped

]

3) Diesel driven auxiliary Several time delay relays j

feedwater pump failed to not set correctly l

automatically start

4) Safety injection signal Probable spuvious high steam flow j

l f

l i

i i

i

.g Unit LER Power Failures Reason

61) Davis-Besse 1 3

99

1) On main steam safety Failed cotter pin 50-346 (MSSV) did not fully close

2) Auxiliary feedwater valve Torque switch setting failed to open

3) One main steam safety valve Unknown failed to lift

62) Farley 1 1

100 Source range monitors Failure of both source 50-348 failed to indicate any range detector

{

counts

63) Hatch 2 21 100 RCIC tripped three times No known reason

54) Arkansas 2 13 100 Two reactor coolant pumps Fast transfer to 6900 50-368 and a circulating water volt bus was unsuccessful pump tripped m 65) Arkansas 2 24 100 Two reactor coolant pumps Lockout relay tripped 50-368 tripped during automatic transfer of auxiliary loads i

66) McGuire 2 10 100 Defective signal conditioning Diode shorting 50-370 circuit card in digital electro-hydraulic turbine control

67) LaSalle 1 5

80 Loss of circulating water Timing in field exciter 50-373 to condenser - pumps tripped circuit not set properly l

1 s

t I

Unit LER Power Failures R:astn

68) Susquehanna 1 28 100 Slow transfer of 4 KV bus Not stated 50-387 caused diesel generator start

69) St. Lucie 2 4

100

1) Auxiliary feedwater pump Transients on power supply 50-389 tripped on overspeed cause not stated

2) Main steam safety valve Cotter pin was missing from (MSSV) on steam generator spindle nut stuck partially open

70) St. Lucie 2 16 25 Loss of "B" side electrical Transformer feeder breaker system; resulted in damage did not open to RCP seals

71) Summer 24 11

1) Steam generator "B" feed-Defective air motor on 50-395 water isolation valve failed Iqydraulic pump to auto close

2) Urgent failure alars on rod' Blown fuse control

3) Source range detector Defective detector developed excess spiking and failed low 3

72) Summer 25 100 Feedwater regulating valves did Air bleedoff valves improperly not automatically close adjusted

73) Lacrosse 18 98 Forced circulation pumps Not stated; operated after 50-409 discharge val.ve did not fully lubrication.

close;

74) Grced Gulf 1 45 19 M tiple equipment trips; air Adverse weather caused voltage 50-416 supply was lost transients

75) Grand Gulf 1 53 53

1) Malfunction of emergency Not stated 50-416 notification system

2) RCIC turbine tripped Not determined

76) Grand Gulf 57 18 RCIC isolated High steam flow signal in RCIC steam supply

77) Cc11away,1 46

'l Main feedwater isolation valve ltydraulic fluid leakage; 50-483 failed to close o-ring failure

Appendix G Trips at Foreign Reactors G.1 REACTOR TRIPS IN JAPAN IN 1984

~

Sources of Data Sources of data for capacity and electricity generation are " Nucleonic's Week" and " Nuclear News". Sources of data on reactor trips or scrams and availability are the reports "The Second Meeting on Nuclear Regulatory Matters Between U.S. and Japan", October 31, 1984, and " Nuclear Power Development in Japan". Tokyo Electric Power Co., Sept.1983. Data in Japanese reports is usually, but not always, given in terms of fiscal year.

Their fiscal year begins on April 1st of the calendar year, so that comparison to other data is not straightforward.

Japanese Nuclear Power Plant Population At the end of December,1984, there were 28 operating nuclear power plants in Japan, including 14 BWRs,12 PWRs, one GCR, and one HWLWR (heavy-water-moderated, boiling light-water-cooled reactor).

Information on' Japanese reactors is presented in the table below.

I t

89

o Table G.1-1 Operating Japanese Nuclear Power Plants,1984

)

Gross; Net Reactor Reactor Commercial Unit Capacity, MWe Type Supplier Operation Tsuruga 1 357;340 BWR/2 E

3/70 Fukushima 1-1 460;439

" /3 GE 3/71 1-2 784;760

"/4 E

7/74 I-3 784;760 Toshiba 3/76 I-4 784;760 Hitachi 10/78 I-5 784;760 Toshiba 4/78 I-6 1100;1067 E

10/79 Fukushima 11-1 1100;1067 Toshiba 4/82 i

II-2 1100;1067 Hitachi 2/84 Shimane 1 460;439 Hitachi 3/74 Hamaoka 1 540;516 Toshiba 3/76 Hamaoka 2 840;814 Toshiba 11/78 Tokai 2 1100;1056 E

11/78 Onagawa 524;500 Toshiba 6/84 Mihama 1 340;320 PWR W; 2 Loop 11/70 Mihama 2 500;470 MI; 2 Loop 7/72 Takahama 1 826;780 W; 3 Loop 11/74 Takahama 2 826;780 M I; 3 Loop 11/75 Mihama 3 826;780 M I; 3 Loop 12/76 Genkai 1 559;529 MHI; 2 Loop 10/75 Genkai 2 559;529 MI; 2 Loop 3/81 Ikata 1 566;538 MHI; 2 Loop 9/77 Ikata 2 566;538 M I; 2 Loop 3/82 Ohi 1 1175;1120 W; 4 Loop 3/79 Ohi 2 1175;1120 W; 4 Loop 12/79

.i i

Sendat 1 890;846 MI; 3 Loop 7/84 Tokai 1 166;159 GCR GEC 7/66 Fugen 165;148 HWLWR Hitachi/MI 3/79 i

i 1

i 1,/ MHI-Mitsubishi 90 4

4

-.._.~,.--_,m

--_.--,-.e,,-,_,+m,..+

-w,-,,~,.-.__,_r

.y..

,_,,__w,m,-q-,--,,w_w,--,_-v_,,.

Summarizing the above table:

Number of Reactor Gross Units Type Capacity, MWe 14 BWR 10,717 12 PWR 8,808

\\

2 Other 331 28 Total 19,856 From the reactor supplier, it can be seen that Japan first imported each type of reactor, and then built their own after that. The first 2-Loop unit, the first 3-Loop unit, and the first 4-Loop plant (2 units) of PWRs were supplied by Westinghouse, and subsequent units were supplied by Japanese vendors. Similarly for BWRs, the first BWR/2, BWR/3, BWR/4, and of the first 1100 MWe BWRs were supplied by General Electric, with subsequent units supplied by Japanese vendors.

M 91

i Trips for 9 months of calendar year 19M (last quarter of FY83 and first half of FYM) for LWRs are listed below.

Date of Name of Outline of Occurrence Power Station Incidents and Failures Jan.17,19M Kansai Electric During rated power operations, the Power Co., Ltd.

warning lamp indicating " low flow Mihama Power rate of back-water of the primary Station. Unit cooling pump" was lit. Thus, the No. 1 (PWR) reactor was shut down manually for repairs.

Jan. 17, 19M Kansai Electric Sealing water return flow was larger Power Co., Ltd.

than normal level, thus the operation M1hama Power of the reactor was stopped again for i

Station, Unit reinspection. (Manual) l No.1 (PWR)

May 5,19M Tokyo Electric During rated power operations, the 1

power Co., Ltd.

main generator tripped due to the i

Fukushima Daint (II) loss of main generator magnetic N.P.S., Unit No.1 field, causing the reactor to shut 4

(BWR) down automatically.

Aug. 24,19M Kansai Electric During rated power operations, the i

Co., Ltd.

surface of the floor under the C-l Oh! Power Station, loop crossover tube covered with Unit No. 2 water was discovered by the TV 1

(PWR) camera. As a result, the nuclear i

reactor was manually shut down for investigation and repair.

I i

I 1

l i

4 92 i

.o

Only one of these shutdowns was automatic (May 5). The total for the first months of 1984 for light water reactor was therefore one automatic and three manual trips.

Reactor trips per reactor calendar year were calculated by multiplying

~

rreactor trips count for 9 months by 4/3 and dividing by the number of LWR reactors in operation. Table G.1-2 provides the results.

Table G.1-2 Reactor Trips per Reactor Year In Japan Total LWRs BWR PWR Number of Units 26 14 12 Manual Trips (9 months) 3 0

3 Automatic Trips (9 months) 1 1

0 Manual Trips (12 months - extrapolated) 4 0

4 Automatic Trips (12 months - extrapolated)

.1. 3 1.3 0

~

Manual Trips per Reactor Year

'O.15 0.0 0.33 Automatic Trips per Reactor Year 0.05 0.10 0.0 Total Trips per Reactor Year 0.20 0.10 0.33 l

93

v Critical hours are not available for Japanese plants for the 9 months j

for which we have trip counts. However, the ratio of generating hours to calendar hours is available for April-September,1984. For BWRs this ratio was 0.78, and for PWRs 0.72.

If we use generating hours as an approximation for critical hours, and assume that the ratio measured over 6 months is representive of the entire 9 month period for which we have trip data, then we can estimate the trip rate per critical hour by dividing 8760 hours0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br /> times the proper ratio into the rates in Table G.1-2.

The' figures are given in Table G.1-3.

Table G.1-3 i

Reactor Trip Rates per Reactor Critical Hour (Estimated) 1 All i

LWRs BWR PWR

~

i Manual 0.02E-3 0.0 0.05E-3 Automatic 0.01E-3 0.01E-3 0.0 Total 0.03E-3 0.01E-3 0.05E-3

.~

l i

94 1

i G.2 REACTOR TRIPS IN SWEDEN IN 1984 i

e Sources of Data The primary sources of data for Swedish reactor trips are the six month reports, " Report on Safety Related Occurrences and Reactor Trips", by the Swedish Nuclear Power Inspectorate, and the quarterly reports, " Quarterly Report, SKI, State Nuclear Power Inspectorate." Additional information was obtained from the report " Experience in Plant Transients - The Swedish s

s.

RKS Program", RKS-83-11, September 26, 1983, " Nucleonics Week", and the U.S. NRC Foreign Events File.

Swedish Nuclear Power Plant Population

]

Sweden has 10 operating nuclear power plants--seven Swedish-designed BWRs

)

and three Westinghouse-designed PWRs. An additional two large (1100 W e) j BWRs were completed last year, but are not yet in commercial operation.

Characteristics of the 10 operating Swedish nuclear power plants are listed below.

1 Table G.2-1 Operating Swedish Nuclear Power Plants,1984 l

Electrical i.

j Reactor Thermal

Power, Date of Reactor

Supplier, Power, Gross / Net Commerical Unit Type NSSS

.MWth We Operation i

)

Barseback 1 BWR Asea-Aton 1700 530/570 1975 Barseback 2 BWR Asea-Aton' 1700 590/570 1977 l

95 i

I

Forsmark 1 BWR Asea-Aton 2700 940/900 1981 Forsmark 2 BWR Asea-Atom 2700 940/900 1981 i

Oskarshamn 1 BWR Asea-Atom 1375 460/440 1972 Oskarshamn 2 BWR Asea-Atom 1800 615/595

- 1975 Ringhals 1 BWR Asea-Atom 2270 780/750 1976 Ringhals 2 PWR Westinghouse 2440 840/800 1975 Ringhals 3 PWR Westinghouse 2783 960/915 1981 Ringhals 4 PWR' Westinghouse 2783 960/915 1984 1

Reactor Trips in the First Half of 1984 in Sweden There were 15 reactor trips in the first half of 1984 in Sweden. Thirteen of the 15 were at power greater than zero. The number of reactor trips at each unit is listed below.

i y

• l l

5 t

96 4

4

---

w-

,-,-,,-,,w,-,,,-%---.--,,----,,,,y,p.,,y

.,,,y_,..,w-

.,,.-__,_,_y,-w.y.

_.._m.-

_----~.,,-,,,,,.7.--e,-m,vyr_-.

3..._

a Unit

. Reactor Trips Barseback 1 0

Barseback 2 0

Forsmark 1 1

Forsmark 2 0

Oskarshamn 1 4

Oskarshamn 2 2

Ringhals 1 1

s-Ringhals 2 4

Ringhals 3 1

Ringhals-4 2

15 If these numbers are extrapolated to one year by doubling the six months numbers, and are divided by the number of reactors, the results are reactor trips per reactor calendar year. The rates are as follows:

Type of Reactor Reactor Trips / Reactor Calendar Year (istimated)

BWR 2.3 s

PWR 4.7 BWR and PWR 3.0 i

97

\\

Critical hours were not available for Swedish reactors. However, the percent of total time in operation (generator tied into the power grid) is available for each quarter. An estimate can be made of critical _ hours by assuming that critical hours are not much greater than time tied into the grid. Multiplying percent of time in operation by hours in the period therefore results in an estimate of critical hours. Approximate critical hours and reactor trip rates are given in Table G.2-2.

eum a

e m

e 98

Table G.2-2 Reactor Trip Rates Per Critical Hour (Estimated)

Percent of Time Generator on Line Approx.

Reactor Trips Trips per Unit 1st Quarter 2nd Quarter Crit. Hrs. at Power Critical Hour Barseback 1 100 97 4310 0

Barseback 2 100 98 4340 0

Forsmark 1 100 100 4380 1

Forsmark 2 100 59 3480 0

Oskarshamn 1 98 99 4310 4

Oskarshamn 2 100 76 3850 2

Ringhals 1 100 95 4270 1

Ringhals 2 87 14 2210 4

Ringhals 3 99 44 3130 1

.Ringhals 4 97 99 4240 2

Total 38,590 15 0.4E-3 BWR 28,950 8

0.3E-3 PWR 9,640 7

0.7E-3 1

O 9

99

G.3 REACTOR TRIPS IN WEST GERMANY Sources of Data

~

Sources of data for capacity and electricity generation are " Nucleonics Week" and " Nuclear News". Data on 1983 reactor trips were provided to AE0D by GRS.

Figures for 1984 were not yet available at the time of this writing.

West German Nuclear Power Plant Population At the end of 1983, ther were 11 operating commercial nuclear power plants in West Germany, including seven PWRs and four BWRs. Two inore BWRs were added-in 1984. Information on Gerlman reactors is presented in Table G.3-1.

~

Reactor Trips in West Germany Reactor trips per calendar year for 1983 are given in Table G.3-2.

e 100

o Table G.3-1 West German Operating Reactors (1984)

Capacity Reactor No. of Date of Unit Gross, Net MWe Supplier Loops Comm. Oper.

PWR Obrigheim 345, 328 Siemens 2L 3/69 Stade 662, 630 Siemens 4L 5/72 Biblis A 1204.1146 Siemens 4L 3/75 Biblis 8 1300,1240 Siemens 4L 1/77 Neckar 855, 795 KWU 3L 12/76 Unterweser 1300,1230 KWU 4L 10/79 Grafenrheinfeld 1290,1235 KWU 4L 6/82 Total PWR 6956,6604

~

BWR Wuergassen 670, 640 AEG 3/72 Brunsbuettel 806, 771 AEG 2/77 Isar 1 907, 870 KWU 3/79 Philippsburg 1 900,' B64 KWU 2/80 Kruesnel 1316.1260 AEG 3/84 Grundremmingen 1310,1244 KWU 7/84 Total BWR 5909,5649 Total, PWR+BWR 12865,12253 i

I 101

.... ~ -

Table G.3-2 Reactor Trips in West Germany No. of Reactor Reactor Trips per Turbine Trips (No 5 actor Trips)

Units Type Reactor Calendar Year Per Reactor Calendar Year

~

Manual Auto Total 4

BWR 0.25 2.00 2.25 0.50 7

PWR 0

1.43 1.43 0.86 11 Total 0.09 1.64 1.73 0.73 Availability of West German plants average about 715*. Using this number, the above trip rates can be converted to average rate per critical hour. The re-l.

suits are shown in Table G.3-3.

Table G.3-3 Reactor Trip Rate per Reactor Critical Hour (Estimated)

Reactor Trips per Reactor Type Reactor Critical Hour Manual Automatic Total BWR 0.04E-3 0.32E-3 0.36E-3 PWR 0

0.23E-3 0.23E-3 Total 0.01E-3 0.26E-3 0.28E-3 l

• Presentation by Dr. H. Weidlich, W. Germany, to NRC on 4/27/84.

4 102

--,rv---m,.,

-wv.w-y-,.y

,,,y-ww,w-we-wmw------,vy-----w-

--v,

-%.--m-.,-w

,--rw---,--------v we--r

,-,-w-e%--+a-

=

3

.e

-w

--v.

--pv--

G.4 Reactor Trips in France Sources of Data Sources of data for capacity and electricity generation are " Nucleonics Weeks" and " Nuclear News". Sources of data on reactor trips include "A Review of Operating Experience, Study of the Scrans which Occurred in the PWR 900 Generating Units from 1979 to 1982", by Electricite de France (EdF)., 20 May 1983. Data on French scrass after 1982 was not available at the time of this writing.

French Nuclear Power Plant Population The EDF report cited contained data on 21 PWRs. Ten 900 MW PWRs have been added since then, so that there were 31 at the end of 1984. Data on power and date of commercial operation is given for 900 MW PWRs operating at the end of 1984 in Table G.4-1.

The 21 reactors covered in the EDF report are indicated with an asterisk in the table.

8.

103

. ~. -

e Table G.4-1 France - 3 Loop, 900 W PWRs Date of Gross Net Cosen. Oper Unit Power,We Power, Mwe 12/77

• Fessenheim 1 930 880 3/78

• Fessenheim 2 930 880 2/79

• 8ugeye 2 957 920 2/79

• Bugeye 3 957 920 6/79

• Bugeye 4 937 900 1/80

• Bugeye 5 937 900 9/80

• Dampierre 1 942 890 2/81

• Dampierre 2 942 890 5/81

• Dampierre 3 942 890 11/81

• Dampierre 4 942 910 11/80

• Gravelines 81 957 910 12/80

• Gravelines B2 957 910 6/81

• Gravelines B3 957 910 10/81,

• Gravelines B4 957 910 12/84 Gravelines C5 957 915 12/80

• Tricastin 1 957 915 12/80

• Tricastin 2 957 915 5/81

• Tricastin 3 957 915 11/81

• Tricastin 4 957 910 12/81

• Bigyais 1 957 910 2/83

• Blayais 2 957 910 11/83 Blayais 3 957 910 9/83 Blayais 4 957 870 10/83 Chinon B1 924 870 1984 Chinon B2 924 880 10/83 St. Laurent B1 928 880 6/83

• St. Laurent B2 928 880 8/83 Cruas 1 928 880 10/84 Cruas 2 S28 880 4/84 Cruas 3 928 880 11/84 Cruas 4 928 880 Total 29,273 27,830 I

104

- -... ~.....

?

6' Reactor Trips in France in 1982 The French report stated that for 1982, there were 9.30 scrams per reactor calendar year, if all of the reactors, including those in initial start-up were included. Although it was not stated explicitly, this repo~rt used a

~

capacity factor of 0.65. This rate translates to 1.63 E-3 scrams per reactor critical hour. There was no data to show the breakdown between manual and automatic scrams. Comparison with U. S. experience are subject to some qual-ification, since the French data is for 1982, and subsequent scram reduction programs mentioned in the EDF report may have reduced French scram rates.

i 1

p. -

105

__.