ML043630017

United States Nuclear Regulatory Commission

Accident Sequence Precursor Program

Results, Trends, and Insights (SECY-04-0210)

November 8, 2004

Christopher Hunter 

(1-301-415-4127, csh3@nrc.gov)

Don Marksberry 

(1-301-415-6378, dgm2@nrc.gov)

Operating Experience Risk Assessment Branch

Division of Risk Analysis and Applications

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001
Note: The results presented in this paper were reported in the annual Commission Paper,

SECY-04-0210, “Status of the Accident Sequence Precursor (ASP) Program and the

Development of Standardized Plant Analysis Risk (SPAR) Models,” November 8, 2004. (See

ADAMS Accession No. ML0425803665.)
1

Results, Trends, and Insights from the 

Accident Sequence Precursor (ASP) Program

This attachment discusses the results of accident

sequence precursor (ASP) analyses conducted by

the U.S. Nuclear Regulatory Commission (NRC),

as they relate to events that occurred during Fiscal

Years (FYs) 2001–2004. These results were

presented in SECY-04-0210 (Ref. 1). Based on

those results, this document also discusses the

NRC’s analysis of historical ASP trends, and the

evaluation of the related insights. The 11 tables

and 14 figures that augment this discussion

appear at the end of this attachment.

1.0 ASP Event Analyses

Table 1 summarizes the status of the NRC’s ASP

analyses, as of September 15, 2004. Specifically,

the table identifies the number of preliminary and

final analyses that the NRC staff has completed

for events that occurred during each fiscal year

(2001–2004), as well as the number of preliminary

analyses that are still underway, which include

events that will be rejected as precursors. (Note

that, as of August 31, 2004, the staff had not yet

screened all of the FY 2004 events and

unavailabilities.) The following subsections

summarize the results of these analyses, which

are further detailed in the associated Tables 2–9.

FY 2001 analyses. The ASP analyses for

FY 2001 identified 23 precursors. Of those 23

precursors, 18 were identified on the basis of final

analyses, and 5 are expected to be precursors

because they relate to events that involved

cracking of the control rod drive mechanism

(CRDM).1

 All 23 of these precursors occurred at

power. 

Table 2 presents the results of the staff’s ASP

analyses for FY 2001 precursors that involved

initiating events, while Table 3 presents the

analysis results for precursors that involved

precipitating conditions. In addition, Table 4 lists

the CRDM cracking events that occurred during

FYs 2001–2003.

FY 2002 analyses. The ASP analyses for

FY 2002 identified 14 precursors. Of those

14 precursors, 8 were identified on the basis of

final analyses, 1 is a potential precursor based on

preliminary analysis, and 5 are potential

precursors (expected to be precursors) because

they relate to CRDM cracking events. All 14 of

these precursors occurred at power.

The staff has completed its preliminary analysis of

the multiple conditions that occurred at the

Davis-Besse Nuclear Power Station coincident

with degradation of the reactor pressure vessel

(RPV) head; the document has been issued for

peer review. This event is a potential significant

precursor.2

Table 5 presents the results of the staff’s ASP

analyses for FY 2002 precursors that involved

initiating events, while Table 6 presents the

analysis results for precursors that involved

precipitating conditions. In addition, as previously

noted, Table 4 includes CRDM cracking events

that occurred during FY 2002.

FY 2003 analyses. In February 2004, the NRC

staff completed its screening and

review of licensee event reports (LERs)

concerning events that occurred during FY 2003. 

On the basis of that review, the ASP analyses

have (thus far) identified 10 precursors, including

2 based on final analyses and 8 based on

preliminary analyses. All 10 of these precursors

occurred at power. An additional 22 analyses are

ongoing, but the results of some of these

analyses will not exceed the precursor threshold.

Table 7 presents the results of the staff’s ASP

analyses for FY 2003 precursors that involved

initiating events, while Table 8 presents the

analysis results for precursors that involved

precipitating conditions. The staff may identify

additional precursors after completing the

1 ongoing analyses of FY 2003 events. As of September 15, 2004, the staff has not

completed its preliminary ASP analyses of

CRDM cracking events that occurred during

FYs 2001–2003. However, based on

sensitivity analyses completed to date, the

staff anticipates that these events will yield an

increase in core damage probability (ΔCDP)

that is greater than or equal to 1x10-6.

2 A significant precursor has a conditional core

damage probability (CCDP) or change in core

damage probability (ΔCDP) that is greater

than or equal to 1x10-3.
2

FY 2004 analyses. The staff has completed all

screening and reviews for potential significant

precursors through September 15, 2004. In

particular, the staff had reviewed a combination of

LERs and daily event notification reports (as

required by Title 10, Section 50.72, of the Code of

Federal Regulations, 10 CFR 50.72) to identify

potential significant precursors. The staff is still

screening and reviewing LERs concerning other

potential precursor events that occurred during FY

2004. 

The staff has also completed three preliminary

analyses for losses of offsite power (LOOPs) that

occurred during FY 2004 at Palo Verde Nuclear

Generating Station, Units 1, 2, and 3. Table 9

addresses the Unit 2 event within the context of

important precursors for FYs 2001–2004.

2.0 Industry Trends

This section discusses the results of trending

analyses for all precursors and for precursors

grouped by the order of magnitude of their CCDPs

or ΔCDPs (called CCDP bins).

Statistically significant trend. The trending

method used in this analysis is consistent with

those methods used in the staff’s risk studies (See

Appendix E of Reference 5.) The trending method

uses p-value for determining the probability of

observing a trend as a result of chance alone. A

trend is considered statistically significant if the pvalue is smaller than 0.05. The p-value is shown

for each trend in the figure provided at the end of

this attachment. 

Data coverage. Most of the data used in the

trending analyses span the period from FY 1993

through FY 2002. In addition, the trends include

the results of both final and preliminary analyses

of potential precursors. However, the following

exceptions apply to the data coverage of the

trending analyses:

• Significant precursors (10-3 bin). The trend of

significant precursors (i.e., CCDP and ΔCDP >

1x10-3) includes events that occurred during FYs

2003 and 2004. The results for FY 2004 are

based on the staff’s screening and review of a

combination of LERs and daily event notification

reports (10 CFR 50.72).3

 The staff analyzes all

potential significant precursors immediately. 

• CRDM cracking events. The staff is still

conducting its preliminary analyses of cracking

that occurred in CRDM housings during FYs

2001 and 2002. Sensitivity analyses conducted

to date show that these cracking events are

most likely potential precursors but not

significant presursors. Therefore, the staff has

included these events in the total count and

trending of all precursors (i.e., CCDP and

ΔCDP > 1x10-6). However, the staff has not

included these events in the CCDP bin trends

because their exact ΔCDP values are not yet

known.

2.1 Occurrence Rate of All Precursors

The NRC’s Industry Trends Program (ITP)

provides the basis for addressing the agency’s

performance goal measure of “no statistically

significant adverse industry trends in safety

performance” (one measure associated with the

Safety goal established in the NRC’s Strategic

Plan). Although the principle measures come

from the Reactor Oversight Program, NRC’s

Office of Nuclear Reactor Regulation (NRR) also

uses precursors identified by the ASP Program to

assess industry performance. Thus, the method

used to trend precursors is consistent with the

analysis used to trend the other indicators in the

ITP.

Results. No statistically significant trend has

been observed in the occurrence rate for all

precursors that occurred during the period from

1993 through 2002. Figure 1 depicts the

occurrence rate per reactor-year for all precursors

by fiscal year.

Figure 1 also shows the ASP results for events

that occurred before FY 1993, which were derived

using a less-rigorous methodology but are shown

to provide historical perspective.

Data coverage. The trend of all precursors

includes the ongoing analyses of events that

involved cracking in CRDM housings. 

2.2 Occurrence Rate of Precursors by CCDP

Bin

In addition to the rate of occurrence of all

precursors, the staff analyzed the data to

determine whether trends exist in the rate of

occurrence of precursors with CCDPs of different

orders of magnitude. The method used in this

analysis is based on a staff technical paper

presented at the International Topical Meeting on 3 The staff has completed all screening and

reviews through September 15, 2004.
3

Probabilistic Safety Assessment (See Reference

2.)

Figure 2a is a histogram displaying the number of

precursors per fiscal year for the CCDP $10-3 bin. 

(Note that Figure 2a shows the number of

precursors instead of the occurrence rate.) This

figure does not show a trend line because the staff

did not detect a statistically significant trend.

By contrast, Figures 2b–d are histograms of the

occurrence rate as a function of fiscal year for the

other three CCDP bins (10-4, 10-5, and 10-6). 

Because these figures represent statistically

significant trends, each figure shows the trend line

of the mean occurrence rate, with the 90-percent

confidence band indicated by error bars.

Results. The trending analysis of the four CCDP

bins (>10-3, 10-4, 10-5, and 10-6) yielded the

following results for the period from FY 1993

through FY 2002:

CCDP

Bin Trend

>10-3 No statistically significant trend

10-4 Decreasing trend -

almost statistically significant

10-5 Decreasing trend - statistically

significant

10-6 Increasing trend - statistically

significant

While no trend was detected in the highest CCDP

bin (>10-3) and trends in bins 10-4 and 10-5 are

decreasing, an increasing trend was detected in

the lowest CCDP bin (10-6). The cause of this

increasing trend will be investigated in an

upcoming study. In FY 2005, the staff will initiate

a detailed evaluation of the ASP data to

investigate the nature of trends and identify

insights that can be applied in the NRC’s

regulatory programs. 

Data coverage. The trends of precursor bins do

not include the ongoing analyses of events that

involved cracking in CRDM housings. The trend

of the CCDP $10-3 bin includes events for FYs

2003 and 2004. All other bins cover the period

from FY 1993 through FY 2002.

3.0 Insights and Other Trends

The discussion of significant precursors in

Section 3.1 covers the period from FY 1993

through FY 2004, although the FY 2004 results

are based on the staff’s screening and review of a

combination of LERs and daily event notification

reports (10 CFR 50.72).4

 Section 3.4, which

addresses the LOOP initiating events, also covers

the period from FY 1993 through FY 2004.5

 The

insights presented in the remaining sections

cover the period from FY 1993 through FY 2002. 

3.1 Significant Precursors

The ASP Program provides the basis for the FY

2004 performance goal measure of “no more than

one event per year identified as a significant

precursor of a nuclear accident” (one measure

associated with the Safety Goal established in the

NRC’s Strategic Plan). Specifically, the Strategic

Plan defines a significant precursor as an event

that has a probability of at least 1 in 1000 (10-3) of

leading to a reactor accident. (See Reference 3.) 

It should be noted that this performance goal was

changed to zero events per year beginning in FY

2005. 

Table 11 summarizes the top 20 significant

precursors that occurred during the period from

FY 1974 through FY 2004.

Results. Figure 2a depicts the number of

significant precursors that occurred during FY 

1993–2004. A review of the data for that period

reveals the following insights:

• The staff did not identify any significant

precursors during FYs 2001, 2003, and 2004.

• The multiple conditions coincident with

degradation of the RPV head at Davis-Besse

represent a potential significant precursor for

FY 2002. The specific conditions included

cracking of CRDM nozzles, degradation of the

RPV head, potential clogging of the emergency

sump, and potential degradation of the

high-pressure injection (HPI) pumps.

• The performance goal measure of “no more

4 The staff has completed all screening and

reviews through September 15, 2004.

5 FY 2004 includes LOOP events counted

through September 15, 2004. 
4

than one event per year identified as a significant

precursor of a nuclear accident” has not been

exceeded during the period from FY 1993 through

FY 2004.

• The staff did not observe any statistically

significant trend in the occurrence of significant

precursors during FYs 1993–2004.

• Significant precursors have occurred, on

average, about once every 4 years. The events

in this group involve differing failure modes,

causes, and systems.

• Two additional precursors with a CCDP $1x10-3

have occurred in the past 12 years. Specifically,

the event at Wolf Creek Generating Station

(1994) involved a reactor coolant system (RCS)

draindown to the refueling water storage tank

during hot shutdown, while the event at Unit 2 of

the Catawba Nuclear Station (1996) involved an

extended, plant-centered LOOP with an

emergency diesel generator (EDG) out of

service for maintenance. 

3.2 Important Precursors

Precursors with a CCDP or ΔCDP $1x10-4 are

considered important in the ASP Program. An

important precursor generally has a CCDP higher

than the core damage probability (CDP) estimated

by most plant-specific probabilistic risk

assessments (PRAs).

The staff identified three important precursors that

occurred during FYs 2001 and 2002. By contrast,

the staff’s preliminary analyses of plants affected

by the power blackout in the Northeast United

States in August 2003 identified five potential

important precursors. In addition, the staff has

preliminarily identified one potential important

precursor for FY 2004.

The staff is continuing to analyze events that

occurred during FYs 2003 and 2004, and these

ongoing analyses may identify additional important

precursors. Table 9 summarizes the important

precursors identified so far. 

Data coverage. Results summarized below do

not include events that occurred during FYs 2003

and 2004.

Results. A review of the data for FYs 1993–2002

reveals the following insights:

• The mean occurrence rate of important

precursors exhibited a decreasing trend that is

almost statistically significant during the period

from FY 1993 through FY 2002, as shown in

Figure 3.

• Important precursors occur infrequently (about

two per year on average). 

• Twenty-one important precursors occurred

during the period from FY 1993 through

FY 2002 period. Of these, 33 percent involved

a LOOP initiating event.

3.3 Initiating Events vs. Conditions

A precursor can be the result of either (1) an

operational event involving an actual initiating

event such as a LOOP, or (2) a condition found

during a test, inspection, or engineering

evaluation. A condition involves a reduction in

safety system reliability or function for a specific

duration (although no reactor trip initiator actually

occurred during this time).

Results. A review of the data for FYs 1993–2002

reveals the following insights:

• Over the past 10 years, conditions

outnumbered initiating events (73 percent

compared to 27 percent, respectively). This

predominance was most notable in FYs 2001

and 2002, when conditions contributed to

91 percent and 100 percent of the identified

precursors, respectively.

• The mean occurrence rate of precursors

involving initiating events has exhibited a

decreasing trend that is statistically significant

for the period from FY 1993 through FY 2002,

as shown in Figure 4. Specifically, the

occurrence rate of such precursors decreased

over this period by a factor of seven.

• The mean occurrence rate of precursors

involving conditions has exhibited an increasing

trend that is statistically significant for the period

from FY 1993 through FY 2002, as shown in

Figure 5. Specifically, the occurrence rate of

such precursors increased over this period by a

factor of two. As discussed in Section 2.2,

above, the nature of increasing trends will be

investigated in an up coming study.
5

3.4 Precursors Involving Loss of Offsite

Power Initiating Events

The LOOP event at Quad-Cities Station Unit 2,

which was attributable to a failure of 

the main power transformer, was the only

precursor involving an initiating event during FY

2001. No LOOP events occurred during FY 2002.

In FY 2003, the power blackout in the Northeast

United States in August 2003 caused nine plants

to lose offsite power, and the staff’s preliminary

analyses identified eight of those events as

potential precursors.6

 Three additional LOOP

events occurred during FY 2003. The staff is

continuing its preliminary analyses of those

events, which occurred at Palisades Nuclear

Power Plant and Units 2 and 3 of the Peach

Bottom Atomic Power Station.

As of September 15, 2004, six LOOP events have

occurred during FY 2004. The staff has

completed its preliminary analyses of the LOOP

events at Palo Verde Units 1, 2, and 3, but is still

conducting the remaining analyses of the events

at Vermont Yankee Generating Station, Unit 2 of

the Brunswick Steam Electric Plant, and Unit 3 of

the Dresden Nuclear Power Station. 

Data coverage. Results summarized below

include LOOP events for FYs 2003 and 2004.

Although the staff is still analyzing six LOOP

events that occurred during FY 2003 and 2004,

experience has shown that these LOOP events

are most likely precursors.

Results. A review of the data for FYs 1993–2004

reveals the following insights:

• The mean occurrence rate of precursors

resulting from a LOOP has exhibited an

increasing trend that is statistically significant for

the period from FY 1993 through FY 2004, as

shown in Figure 6. Specifically, the occurrence

rate of such precursors increased over this

period by a factor of three.

• Without the LOOP events that occurred as a

result of the blackout in the Northeast United

States on August 14, 2003, the identified

precursors did not exhibit any statistically

significant trend (either increasing or

decreasing) for the period from FY 1993

through FY 2004. The review of the LOOP

events associated with the Northeast blackout

is the focus of the staff’s action plan for

resolving U.S. nuclear power plant issues

relating to the electric power grid concerns. 

• Approximately one-half (48 percent) of the

LOOP precursor events that occurred during

FYs 1993–2004 were evaluated to be important

precursors (CCDP$1.0x10-4).

• A simultaneous unavailability of an emergency

power system train was involved in 4 of the 34

LOOP precursor events during FYs 1993–2004. 

Specifically, those four events involved a safety

bus at Palo Verde Unit 2, which failed to

sequence loads (2004); an EDG at Peach

Bottom Unit 3, which tripped about 2.5 hours

into the LOOP event as a result of low jacket

coolant pressure (2003); an output breaker to

an EDG at Indian Point Station Unit 2, which

tripped open after closing (1999); and an EDG

that was out of service for maintenance at

Catawba Unit 2 (1996). Three of these four

precursors had a CCDP >1x10-4. 

3.5 Precursors at Boiling- vs. PressurizedWater Reactors

Five precursors in FY 2001 and one in FY 2002

occurred at a boiling-water reactor (BWR). The

precursor counts for pressurized-water reactors

(PWRs) include the ongoing analyses of events

involving cracking in CRDM housings.

A review of the data for FYs 1993–2002 reveals

the following results for BWRs and PWRs:

BWRs

• The mean occurrence rate of precursors at

BWRs does not exhibit a trend that is

statistically significant for the period from FY

1993 through FY 2002, as shown in Figure 7.

• No precursors occurred at BWRs during the

4-year period from FY 1997 through FY 2000.

PWRs 

• The mean occurrence rate of precursors at

PWRs does not exhibit a trend that is

6 The ASP analysis of the LOOP event at DavisBesse on August 14, 2003, showed that this

event did not meet the threshold of a

precursor in the ASP Program. (The CCDP

was less than 1 x 10-6.) The plant had been

shut down for more than two years before this

event occurred. 
6

statistically significant for the period from FY 1993

through FY 2002, as shown in 

Figure 8. 

• Historically, an average of 11 precursors per

year occurred at PWRs during FYs 1993–2002.

3.6 Precursors Caused by Unavailability of

Safety-Related Equipment7

Most precursors involve the unavailability of

safety-related equipment. Such events typically

occur during periods of extended unavailability of

equipment without a reactor trip, or in combination

with a reactor trip in which a risk-important

component is unable to perform its safety function

as a result of an unavailability condition.

A review of the data for FYs 1993–2002 reveals

the following insights concerning the unavailability

of safety-related equipment:

Equipment unavailabilities at BWRs

• Nine precursors involving the unavailability of

safety-related equipment occurred at BWRs

during FYs 1993–2002. The events in this

group involved various failure modes, causes,

and systems.

Emergency core cooling systems

• An unavailability of safety-related high- and/or

low-pressure injection trains contributed to

58 percent of all identified precursors that

occurred at PWRs during FYs 1993–2002. 

Most of these unavailabilities were caused by

failures in either the emergency core cooling

system (ECCS) (29 percent) or emergency

power sources (24 percent), or resulted from

design-basis issues involving other structures or

systems that impact either the ECCS or one of

its support systems (29 percent). 

• The 19 precursors that involved a failure in an

ECCS train yield the following insights:

S Eighteen precursors involved a conditional

unavailability that was identified during

testing, inspection, or engineering reviews. 

S Fourteen precursors involved a condition that

affected sump recirculation during

postulated loss-of-coolant accidents of

varying break sizes.

Auxiliary/emergency feedwater systems

• The unavailability of one or more trains of the

auxiliary and emergency feedwater (AFW/EFW)

systems contributed to 44 percent of all

precursors that occurred at PWRs. Most of

these unavailabilities were caused by failures in

the AFW/EFW systems (24 percent) or

emergency power sources (44 percent), or

resulted from design-basis issues involving

other structures or systems that impact either

the AFW/EFW systems or one of their support

systems (32 percent).

• The 12 precursors that involved a failure in an

AFW/EFW train yield the following insights:

S Five of the train failures occurred following a

reactor trip.

S Ten of the precursors involved the

unavailability of the turbine-driven

AFW/EFW pump train.

Emergency power sources in PWRs

• The unavailability of emergency power

sources,8

 such as EDGs and hydroelectric

generators (at Oconee), contributed to

26 percent of all precursors that occurred at

PWRs. Most of these unavailabilities were

caused by random hardware failures in the

emergency power system (57 percent). The

other unavailabilities were attributable to

design-basis issues (23 percent) and losses of

service water (23 percent).

• All LOOP events at PWRs had operable

turbine-driven AFW pumps.

Section 3.4 (above), discusses insights related to

precursors that involved a LOOP with a

simultaneous EDG unavailability.

7 The sum of percentages presented in this

section does not always equal 100-percent

because some precursors involve multiple

equipment unavailabilities.

8 Not all EDG unavailabilities are precursors. 

An EDG unavailability for a period of less

than one surveillance test cycle (1 month) is

screened out in the ASP Program (assuming

no other complications). In addition, the risk

contributions of EDG unavailabilities vary

plant-to-plant and may result in a ΔCDP less

than the threshold of a precursor (1 x 10-6). 

Reference 4 provides a detailed engineering

analysis of EDG unavailabilities.
7

3.7 Causes of Precursors Involving

Conditions 

Precursors involving conditional unavailability of

safety-related systems and components 

are attributable to numerous causes. For the

purposes of this review, the staff classified ASP

data into five causal categories, including (1)

design-basis issues, (2) hardware/material

failures, (3) procedure errors, (4) maintenance

deficiencies, and (5) other personnel/human

errors that were not related to categories 1–4. 

Design-basis issues arise when the design of

plant structures, systems, and/or components

deviates from the regulatory requirements and

assumptions used in safety analyses.

Results. Figure 9a depicts the distribution of

precursor causes within the five categories, while

Figure 9b plots precursors related to design-basis

issues. A review of the data for FYs 1993–2002

reveals the following insights:

• More than half (55 percent) of all identified

precursors related to design-basis issues, and

almost half of those had a ΔCDP > 1x10-5.

• Human-related deficiencies (i.e., procedures,

maintenance, and other human errors)

accounted for 30 percent of the identified

condition-related precursors. Random hardware

failures account for the remaining 70 percent of

condition-related precursors.

3.8 Annual ASP Index

The staff derives the annual ASP index for orderof-magnitude comparisons with industry-average

core damage frequency (CDF) estimates derived

from PRAs and individual plant examinations

(IPEs). The index for a given fiscal year is the

sum of the CCDPs divided by the number of

reactor-years (RYs). 

Results. Figure 10 depicts the annual ASP

indices for FYs 1993–2002, with indices prior to

FY 1993 provided for historical context. A review

of the ASP indices reveals the following insights:

• Based on order of magnitude, the average ASP

index for the period from FY 1993 through

FY 2002 is consistent with the CDF estimates

from the IPEs.9

• The increase in the ASP index for FY 2002 is

attributable to the multiple conditions coincident

with degradation of the RPV head

at Davis-Besse. Both the preliminary ASP

analysis results and the associated index are

subject to change based on peer review

comments.10

Limitations. Using CCDPs from ASP results to

estimate CDF is difficult because (1) the

mathematical relationship requires a significant

level of detail, (2) statistics for frequency of

occurrence of specific precursor events are

sparse, and (3) the assessment must also

account for events and conditions that did not

meet the ASP precursor criteria.

The ASP models and process do not explicitly

address all CDF scenarios, such as fires,

flooding, and external events. Thus, they are

incomplete for use in estimating total CDF. In

addition, using CCDP can overestimate the CDF

because of double counting. 

Because of these and other limitations, the staff

has primarily used the CCDPs as a relative

trending indication. Nonetheless, ASP results can

be linked to CDF by using an annual ASP index. 

The IPEs also give incomplete estimates of total

CDF, although the IPEs are reasonably similar in

scope to the current ASP Program.

3.9 Consistency with PRAs and IPEs

A secondary objective of the ASP Program is to

provide a partial validation of the dominant core

damage scenarios predicted by PRAs and IPEs. 

Most of the identified precursor events are

consistent with failure combinations identified in

PRAs and IPEs. However, a review of the

precursor events for FYs 1994–2002 reveals that

approximately 20 percent of the identified

precursors involved event initiators or failure

modes that were not explicitly modeled in the

PRA or IPE concerning the specific plant at which

the precursor event occurred. Table 10 lists

9 The CDF estimates in the IPEs range from 1

x10-6/RY to 3 x10-4/RY, with an average value

of 6 x10-5/RY. 

10 All preliminary results and subsequent indices

are subject to change. The indices for

FYs 2001 and 2002 also include the CRDM

cracking events, for which the staff used a

ΔCDP value of 5 x10-5 for each event. 
8

these precursors. The occurrence of these

precursors do not imply that explicit modeling is

needed; however, there could be insights that

could be fed-back to future revisions of the PRA.

4.0 References

1. U.S. Nuclear Regulatory Commission. “Status

of the Accident Sequence Precursor (ASP)

Program and the Development of Standardized

Plant Analysis Risk (SPAR) Models,”

Commission paper SECY-04-0210, November

8, 2004. (ADAMS Accession No.

ML0425803665.)

2. Rasmuson, D.M., and P.D. O’Reilly. “Analysis

of Annual Accident Sequence Precursor

Occurrence Rates for 1984–94,” in Proceeding

of the International Topical Meeting on

Probabilistic Safety Assessment. American

Nuclear Society (ANS), Park City, Utah. 29

September – 3 October, 1996. Vol. III, pp.

1645–1652. ANS: LaGrange Park, Illinois. 

1994.

3. U.S. Nuclear Regulatory Commission. 

NUREG-1100, Vol. 20, “Performance Budget,

Fiscal Year 2005.” NRC: Washington, DC. 

February 2004.

4. U.S. Nuclear Regulatory Commission. 

NUREG/CR-5500, Vol. 5, “Reliability Study: 

Emergency Diesel Generator Power System,

1987–1993.” NRC: Washington, DC. 

September 1999.

5. U.S. Nuclear Regulatory Commission. 

NUREG/CR-5750, “Rates of Initiating Events at

U.S. Nuclear Power Plants: 1987–1995.” NRC:

Washington, DC. February 1999.
9

Table 1. Status of ASP analyses as of September 15, 2004.

Status FY 2001 FY 2002 FY 2003 FY

2004a

Final analysis completed 18 8 2 0

Preliminary analysis completed 0 1 8 3

Preliminary analysis underway (includes events

that may be precursors) 5 5 22 7a

a. As of September 15, 2004, the staff has not yet screened all of the FY 2004 events and unavailabilities.

Table 2. FY 2001 at-power precursors involving initiating events (as of September 15, 2004). 

Plant Description/Event Identifier Plant

Type

Event

Date CCDP

Quad-Cities 2 Reactor scram attributable to failure of main power

transformer. LER # 265/01-001 BWR 8/2/01 5x10-6

LaSalle 2

Reactor scram attributable to actuation of the

under-voltage protective circuit on the Division 1

Engineered Safety Feature (ESF) Bus.

LER # 374/01-003

BWR 9/3/01 1x10-5
10

Table 3. FY 2001 at-power precursors involving conditional unavailabilities (as of September 15, 2004).

Plant Description/Event Identifier Plant

Type

Event

Date

Importance

(CCDP-CDP)

Oconee 1, 2, & 3

Non-seismic 16-inch fire system piping header transited

through the auxiliary building and posed a potential

flooding problem if the piping ruptured during a seismic

event. IR # 269/01-08

PWR 11/1/00

5x10-6

(Unit 1)

4x10-6

(Units 2 & 3)

Prairie Island 

1 & 2

Bearing lubrication for the cooling water pumps

degraded following a LOOP. LER # 282/00-004 PWR 11/1/00 1x10-6

Limerick 2

A manual scram occurred because a main steam relief

valve (MSRV) failed open as a result of erosion and

oxidation of the first stage pilot valve disk seating area.

LER # 353/01-001

BWR 2/23/01 3x10-6

Fermi 2

EDG 14 was inoperable for more than the time allowed

by the Technical Specifications(7 days).

LER # 341/01-001

BWR 3/28/01 3x10-6

Kewaunee

The licensee failed to provide a fixed fire suppression

system for Fire Area TU-95B, and this could result in a

postulated lube oil fire involving the AFW pump.

IR # 305/02-06

PWR 3/28/01 1x10-5

Surry 1 and 2 EDG failed as a result of insufficient lubrication.

LER # 280/01-001 PWR 4/15/01

3x10-6

(Unit 1)

6x10-6

(Unit 2)

Calvert Cliffs 1 AFW pump turbine bearing failed as a result of steam

intrusion. LER # 317/01-001 PWR 5/16/01 1x10-5

Dresden 3

The high-pressure coolant injection (HPCI) system was

inoperable following a water hammer event.

LER # 249/02-005

BWR 7/5/01 3x10-6

Palisades Smoke detectors in the cable room were not installed in

accordance with code. LER # 255/01-008 PWR 7/27/01 1x10-6

ANO 1

Fire protection and procedures were inadequate for the

north switchgear room, Fire Zone 99-M.

IR # 313/01-06

PWR 8/3/01 4x10-6

Cook 1 & 2 Degraded ESW flow rendered both Unit 2 EDGs

inoperable. LER # 316/01-003 PWR 8/29/01

1x10-5

(Unit 1)

7x10-6

(Unit 2)
11

Table 4. FYs 2001–2003 CRDM cracking events.a

Plant Event

Date Description/Event Identifier

Oconee 1 12/4/00 RPV head leakage resulted from primary water stress corrosion cracking

(PWSCC) of one CRDM nozzle. LER # 269/00-006

Oconee 3 2/18/01 RPV head leakage resulted from PWSCC of nine CRDM nozzles. 

LER # 287/01-001

ANO 1 3/24/01 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 313/01-002

Oconee 2 4/28/01 RPV head leakage resulted from PWSCC of four CRDM nozzles.

LER # 270/01-002

Palisades 6/21/01 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 255/01-004

Crystal River 10/1/01 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 302/01-004

TMI 1 10/12/01 RPV head leakage resulted from PWSCC of five CRDM nozzles. 

LER # 289/01-002

Surry 1 10/28/01 RPV head leakage resulted from PWSCC of two CRDM nozzles.

LER # 280/01-003

North Anna 2 11/13/01 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 339/01-003

Davis-Besse 2/27/02

Cracking of CRDM nozzles, RPV head degradation, potential clogging of the

emergency sump, and potential degradation of the HPI pumps. 

LER # 346/02-002

St. Lucie 2 4/3/02 RPV head leakage resulted from PWSCC of one CRDM nozzle.

LER # 389/03-002

a. The staff issued the preliminary analysis of Davis-Besse for peer review in September 2004. The analyses of cracking events at

the remaining plants are ongoing. The risk associated with multiple cracks at a given plant will be considered collectively in one

analysis for each plant (i.e., only one precursor for each plant) 

Table 5. FY 2002 at-power precursors involving initiating events (as of September 15, 2004). 

Plant Description/Event Identifier Plant

Type

Event

Date CCDP

None
12

Table 6. FY 2002 at-power precursors involving conditional unavailabilities (as of September 15, 2004).

Plant Description/Event Identifier Plant

Type

Event

Date

Importance

(CCDPCDP)

Harris

Debris accumulated in suction lines to the “A” residual

heat removal (RHR) pump and “A” containment spray

pump. LER # 400/01-003

PWR 10/8/01 6x10-6

Point Beach 

1 & 2

Potential common-mode failure of all AFW pumps.

LER # 266/01-005 PWR 11/29/01 7x10-4

(Units 1 & 2)

Callaway

Foreign object rendered the “B” emergency service

water (ESW) pump inoperable, and foreign material in

the condensate storage tank (CST) caused a failure of

the “A” AFW pumps. LER # 483/01-002

PWR 12/3/01 2x10-5

Davis-Bessea

Cracking of CRDM nozzles, RPV head degradation,

potential clogging of the emergency sump, and potential

degradation of the HPI pumps. LER # 346/02-002

PWR 2/27/02 6x10-3

Braidwood 1

The bleed path for the power-operated relief valve

(PORV) was inoperable because of leaking accumulator

check valves. LER # 456/02-002

PWR 4/16/02 4x10-6

Columbia 2 Four safety-related systems had unreliable breakers. 

IR # 397/02-05 BWR 4/25/02 6x10-6

Oconee 3

The emergency power supply cable from the auxiliary

service water switchgear to the HPI pump was

inadequately installed. IR # 247/02-15

PWR 5/30/02 9x10-6

Indian Point 2

Moderate degradation of the control room west wall

could allow smoke and gases to penetrate the control

room in the event of a turbine building fire.

IR # 247/02-10

PWR 7/19/02 7x10-6

a. Preliminary analysis results are subject to change.
13

Table 7. FY 2003 at-power precursors involving initiating events (as of September 15, 2004).a

Plant Description/Event Identifier Plant

Type

Event

Date CCDP

Fermi 2b

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 314/03-002

BWR 8/14/03 2x10-4

Fitzpatrickb

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 333/03-001

BWR 8/14/03 9x10-5

Ginnab

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 244/03-002

PWR 8/14/03 2x10-4

Indian Point 

2 & 3b

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 247/03-005

PWR 8/14/03

1x10-4

(Unit 2)

7x10-5

(Unit 3)

Nine Mile Point 

1 & 2b

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 220/03-002

BWR 8/14/03

3x10-5

(Unit 1)

5x10-4

(Unit 2)

Perryb

Reactor trip and loss of offsite power occurred as a

result of the power blackout in the Northeast United

States on August 14, 2003. LER # 440/03-002

BWR 8/14/03 5x10-4

a. Other analyses are ongoing.

b. Preliminary analysis results are subject to change.

Table 8. FY 2003 at-power precursors involving conditional unavailabilities (as of September 15, 2004).a

Plant Description/Event Identifier Plant

Type

Event

Date

Importance

(CCDPCDP)

Point Beach 

1 & 2

A design deficiency in the AFW orifices could cause

debris plugging of the pumps’ recirculation line, and

subsequent common-cause failure of all AFW pumps. 

LER # 266/02-003

PWR 10/29/02

6x10-5

(Unit 1)

4x10-4

(Unit 2)

a. Other analyses are ongoing.
14

Table 9. FYs 2001–2004 important precursors (as of September 15, 2004).

Plant Description/Event Identifier Event

Date CCDP

Point Beach 1 & 2

This condition involved a design deficiency in the air-operated

minimum-flow recirculation valves of the AFW pumps. The valves

fail closed on loss of instrument air, and this could potentially lead to

pump deadhead conditions and a common-mode, non-recoverable

failure of the AFW pumps. Because the pressurizer PORVs also

depend on instrument air, an event involving a loss of instrument air

may also result in the loss of feed-and-bleed cooling capability.

LER # 266/01-005

11/29/01

7x10-4

(Both

Units)

Davis-Bessea

Cracking of CRDM nozzles, RPV head degradation, potential

clogging of the emergency sump, and potential degradation of the

HPI pumps. LER # 346/02-002

2/27/02 6x10-3

Point Beach 2

This condition involved a design deficiency in the flow-restricting

orifices in the recirculation lines of the AFW pumps. Because of this

design deficiency, the orifices are vulnerable to debris plugging

when the suction supply for the AFW pumps is switched to its

safety-related water supply (the service water system). Blocked flow

in the recirculation lines of the AFW pumps, combined with

inadequacies in plant emergency operating procedures, could

potentially lead to pump deadhead conditions and a common-mode,

non-recoverable failure of the pumps. The mean ΔCDP was 6x10-5

for Unit 1. LER # 266/02-003

10/29/02 4x10-4

Northeast

Blackout

Fermi 2a

Ginnaa

Indian Point 2a

Nine Mile Point 2a

Perrya

Reactor trip and loss of offsite power resulted from the power

blackout in the Northeast United States on August 14, 2003. The

plant-to-plant variations in CCDP are primarily attributable to the

varying durations of the LOOP at each site, minor problems with

mitigating systems in several plants, and design differences among

the plants. The offsite power recovery times used in the ASP

analyses are based on the times at which the grid control centers

gave permission to use the power, as reported in the LERs and

information compiled by the NRC’s regional offices. The related

ASP analyses also considered any additional time to get power from

the switchyard to a safety bus, and the probability of failing to

successfully restore the power. An important plant design feature

with respect to the risk of station blackout is the time to battery

depletion. Other important design features include the configuration

of EDGs and alternative power sources, and the availability of

turbine-powered mitigating systems. 

See Table 7 for LER numbers.

8/14/03

2x10-4

2x10-4

1x10-4

5x10-4

5x10-4

Palo Verde 2a

A ground fault in the electrical grid resulted in losses of offsite power

to all three units at Palo Verde. With the exception of one EDG in

Unit 2, all EDGs started and loaded onto engineered safeguard

buses. (The Unit 2 Train “A” buses had been de-energized as a

result of the loss of the EDG.) The CCDPs for Units 1 and 3 are

4x10-5. IR # 528/04-12

6/14/04 7x10-4

a. Preliminary analysis results are subject to change.
15

Table 10. Precursors involving failure modes and event initiators that were not explicitly modeled in the PRA

or IPE concerning the specific plant at which the precursor event occurred.

Plant Year Event Description

Columbia 2 2002 Common-cause failure (CCF) of breakers used in four safety-related systems.

IR # 397/02-05

Davis-Besse 2002

Cracking of control rod drive mechanism nozzles and reactor pressure vessel head

degradation, potential clogging of the emergency sump, and potential degradation of the

high-pressure injection pumps. LER # 346/02-002 

Callaway 2002

Potential common mode failure of all auxiliary feedwater pumps due to foreign material in

the condensate storage tank caused by degradation of the floating bladder. 

LER # 483/01-002

Point Beach 

1 & 2 2002

Potential common mode failure of all auxiliary feedwater (AFW) pumps due to a design

deficiency in the AFW pumps’ air-operated minimum flow recirculation valves. The valves

fail closed on loss of instrument air and this could potentially lead to pump deadhead

conditions and a common mode, non-recoverable failure of the AFW pumps. 

LER # 266/01-005

Harris 2002 Potential failure of residual heat removal pump ‘A’ and containment spray pump “A” due to

debris in the pumps’ suction lines. LER # 400/01-003

Kewaunee 2001

Failure to provide a fixed fire suppression system could result in a postulated fire that

propagates and causes the loss of control cables in both safe shutdown trains. 

IR # 305/02-06

Prairie Island 

1 & 2 2000

A 1988 change in the backwash system for the cooling water pump drive shaft bearing

lubrication water supply system could result in loss of plant cooling water during postulated

loss-of-offsite-power conditions. LER # 282/00-004

Oconee 

1, 2, & 3 2000

Non-seismic 16-inch fire system piping header transited through the auxiliary building and

posed a potential flooding problem should the piping rupture during a seismic event. 

IR # 269/00-08

Cook 1 & 2 1999 Postulated high-energy line leaks or breaks in turbine building leading to failure of multiple

safety-related equipment. LER # 315/99-026

Oconee 

1, 2, & 3 1999 Postulated high-energy line leaks or breaks in turbine building leading to failure of

safety-related 4 kV switchgear. LER # 269/99-001

Cook 2 1998 Postulated high-energy line break in turbine building leading to failure of all component

cooling water pumps. LER # 316/98-005

Oconee 

1, 2, & 3 1998

Incorrect calibration of the borated water storage tank (BWST) level instruments resulted

in a situation where the emergency operating procedure (EOP) requirements for

BWST-to-reactor building emergency sump transfer would never have been met; operators

would be working outside the EOP. LER # 269/98-004

Haddam Neck 1996 Potentially inadequate residual heat removal pump net positive suction head following a

large- or medium-break loss-of-coolant accident due to design errors. LER # 213/96-016

LaSalle 

1 & 2 1996 Fouling of the cooling water systems due to concrete sealant injected into the service

water tunnel. LER # 373/96-007

Wolf Creek 1996

Reactor trip with the loss of one train of emergency service water due to the formation of

frazil ice on the circulating water traveling screens with concurrent unavailability of the

turbine-driven auxiliary feedwater pump. LER # 482/96-001 

Wolf Creek 1994 Blowdown of the reactor coolant system to the refueling water storage tank during hot

shutdown. LER # 482/94-013
16

Table 11. Significant (CCDP $ 10-3) accident sequence precursors during the 1969–2004 period—ordered by

event date. (See note.)

Plant CCDP Date Description

Davis-Besse 6x10-3

Preliminary 2/27/02

Multiple conditions coincident with reactor pressure vessel (RPV)

head degradation

The analysis included multiple degraded conditions discovered on various

dates. These conditions included cracking of control rod drive

mechanisms (CRDM) nozzles and reactor pressure vessel (RPV) head

degradation on February 27, 2002; potential clogging of the emergency

sump on September 4, 2002; and potential degradation of the highpressure injection (HPI) pumps on October 22, 2002. LER # 346/02-002

Catawba 2 2x10-3 2/6/96

Loss of offsite power (LOOP) with an emergency diesel generator

(EDG) B unavailable

When the reactor was at hot shutdown, a transformer in the switchyard

shorted out during a storm, causing breakers to open and resulting in a

LOOP event. Although both EDGs started, the output breaker of EDG

“1B” to essential bus “1B” failed to close on demand, leaving bus “1B”

without AC power. After 2 hours and 25 minutes, operators successfully

closed the EDG “1B” output breaker. LER # 414/96-001 

Wolf Creek 1 3x10-3 9/17/94

Reactor coolant system (RCS) blowdown to refueling water storage

tank (RWST)

When the plant was in cold shutdown, operators implemented two

unpermitted simultaneous evolutions, which resulted in the transfer of

9,200 gallons (34,825 liters) of RCS inventory to the RWST. Operators

immediately diagnosed the problem and terminated the event by closing

the residual heat removal (RHR) cross-connect motor-operated valve

(MOV). The temperature of the RCS increased by 7 EF (4 EC) as a result

of this event. LER # 482/94-013

Harris 1 6x10-3 4/3/91

HPI unavailability for one refueling cycle

A degraded condition resulted from relief valve and drain line failures in

the alternative minimum flow systems for the charging/safety injection

pumps, which would have diverted a significant amount of safety injection

flow away from the reactor coolant system. The root cause of the

degradation is believed to have been water hammer, as a result in air left

in the alternative minimum flow system following system maintenance and

test activities. LER # 400/91-008

Turkey Point 3 1x10-3 12/27/86

Turbine load loss with trip; control rod drive (CRD) auto insert fails;

manual reactor trip; power operated relief valve (PORV) sticks open

The reactor was tripped manually following a loss of turbine governor oil

system pressure and the subsequent rapid electrical load decrease. 

Control rods failed to insert automatically because of two cold solder joints

in the power mismatch circuit. During the transient, a PORV opened but

failed to close (the block valve had to be closed). The loss of governor oil

pressure was due to a cleared orifice blockage and the auxiliary governor

dumping control oil. LER # 250/86-039
Plant CCDP Date Description

17

Catawba 1 3x10-3 6/13/86

Chemical and volume control system (CVCS) leak (130 gpm) from the

component cooling water (CCW)/CVCS heat exchanger joint (i.e.,

small-break loss-of-coolant accident (LOCA))

A weld break on the letdown piping, near the CCW/CVCS heat exchanger

caused excessive RCS leakage. A loss of motor control center (MCC)

power caused the variable letdown orifice to fail open. The weld on the

1-inch (2.54-cm) outlet flange on the variable letdown orifice failed as a

result of excessive cavitation-induced vibration. This event was a smallbreak LOCA. LER # 413/86-031

Davis-Besse 1 1x10-2 6/9/85

Loss of feedwater; scram; operator error fails auxiliary feedwater

(AFW); PORV fails open

While at 90-percent power, the reactor tripped with main feedwater (MFW)

pump “1” tripped and MFW pump “2” unavailable. Operators made an

error in initiating the steam and feedwater rupture control system and

isolated AFW to both steam generators (SGs). The PORV actuated three

times and did not reseat at the proper RCS pressure. Operators closed

the PORV block valves, recovered AFW locally, and used HPI pump “1” to

reduce RCS pressure. LER # 346/85-013

Hatch 1 2x10-3 5/15/85

Heating, ventilation, and air conditioning (HVAC) water shorts panel;

safety relief valve (SRV) fails open; high-pressure coolant injection

(HPCI) fails; reactor core isolation cooling (RCIC) unavailable

Water from an HVAC vent fell onto an analog transmitter trip system panel

in the control room (the water was from the control room HVAC filter

deluge system which had been inadvertently activated as a result of

unrelated maintenance activities). This resulted in the lifting of the SRV

four times. The SRV stuck open on the fourth cycle initiating a transient. 

Moisture also energized the HPCI trip solenoid making HPCI inoperable. 

RCIC was unavailable due to maintenance. LER # 321/85-018

Lasalle 1 2x10-3 9/21/84

Operator error causes scram; RCIC unavailable; RHR unavailable

While at 23-percent power, an operator error caused a reactor scram and

MSIV closure. RCIC was found to be unavailable during testing (one

RCIC pump was isolated and the other pump tripped during the test). 

RHR was found to be unavailable during testing due to an inboard suction

isolation valve failing to open on demand. Both RHR and RCIC may have

been unavailable after the reactor scram. LER # 373/84-054

Salem 1 5x10-3 2/25/83

Trip with automatic reactor trip capability failed

When the reactor was at 25-percent power, both reactor trip breakers

failed to open on demand of a low-low SG level trip signal. A manual trip

was initiated approximately 3 seconds after the automatic trip breaker

failed to open, and was successful. The same event occurred 3 days

later, at 12-percent power. Mechanical binding of the latch mechanism in

the breaker under-voltage trip attachment failed both breakers in both

events. LER # 272/83-011
Plant CCDP Date Description

18

Davis Besse 1 2x10-3 6/24/81

Loss of vital bus; failure of an AFW pump; main steam safety valve

lifted and failed to reseat

With the plant at 74-percent power, the loss of bus “E2" occurred due to a

maintenance error during CRDM breaker logic testing. A reactor trip

occurred, due to loss of CRDM power (bus “E2"), and instrumentation

power was also lost (bus “E2" and a defective logic card on the alternate

source). During the recovery, AFW pump “2" failed to start due to a

maladjusted governor slip clutch and bent low speed stop pin. A main

steam safety valve lifted, and failed to reseat (valve was then gagged). 

LER # 346/81-037 

Brunswick 1 7x10-3 4/19/81

RHR heat exchanger damaged

While the reactor was in cold shutdown during a maintenance outage, the

normal decay heat removal system was lost because of a failure of the

single RHR heat exchanger that was currently in service. The failure

occurred when the starting of a second RHR service water pump caused

the failure of a baffle in the waterbox of the RHR heat exchanger, thereby

allowing cooling water to bypass the tube bundle. The redundant heat

exchanger was inoperable because maintenance was in progress. 

LER # 325/81-032 

Millstone 2 5x10-3 1/2/81

Loss of DC power and one EDG as a result of operator error; partial

LOOP

When the reactor was at full power, the 125v DC emergency bus was lost

as a result of operator error. The loss of the bus caused the reactor to

trip, but the turbine failed to trip because of the unavailability of DC bus

“A.” Loads were not switched to the reserve transformer (following the

manual turbine trip) because of the loss of DC bus “A.” Two breakers (on

the “B” 6.9kV and 4.16kV buses) remained open, thereby causing a

LOOP. EDG “B” tripped as a result of leakage of the service water (SW)

flange, which also caused the “B” 4.16 kV bus to be de-energized. An

operator recognition error caused the PORV to be opened at 2380 psia. 

LER # 336/81-005

St. Lucie 1 1x10-3 6/11/80

Reactor coolant pump seal LOCA due to loss of component cooling

water (CCW); top vessel head bubble 

At 100-percent power, a moisture-induced short circuit in a solenoid valve

caused a CCW containment isolation valve to shut causing loss of CCW

to all reactor coolant pumps (RCPs). While reducing pressure to initiate

the shutdown cooling system (SCS), the top head water flashed to steam,

thus forming a bubble (initially undetected by the operators). During the

cooldown, the SCS relief valves lifted and low-pressure safety injection

(LPSI) initiated (i.e., the other LPSI pump started charging, while the other

was used for cooldown). LER # 335/80-029

Davis Besse 1 1x10-3 4/19/80

Loss of 2 essential busses

When the reactor was in cold shutdown, two essential busses were lost

due to breaker ground fault relay actuation during an electrical lineup. 

Decay heat drop line valve was shut, and air was drawn into the suction of

the decay heat removal pumps, resulting in loss of a decay heat removal

path. LER # 346/80-029
Plant CCDP Date Description

19

Crystal River 3 5x10-3 2/26/80

Loss of 24-volt DC power to non-nuclear instrumentation (NNI)

The 24-volt power supply to the NNI was lost as a result of a short to

ground. This initiated a sequence of events in which the PORV opened

(and stayed open) as a direct result of the loss of the NNI power supply. 

HPI initiated as a result of depressurization through the open PORV, and

with approximately 70 percent of NNI inoperable or inaccurate, the

operator correctly decided that there was insufficient information available

to justify terminating HPI. Therefore, the pressurizer was pumped solid,

one safety valve lifted, and flow through the safety valve was sufficient to

rupture the reactor coolant drain tank rupture disk, thereby spilling

approximately 43,000 gallons (162,800 liters) of primary water into the

containment. LER # 302/80-010

Hatch 2 1x10-3 6/3/79

Loss of feedwater; HPCI fails to start; RCIC is unavailable

During a power increase, the reactor tripped due to a condensate system

trip. HPCI failed to initiate on low-low level due to a failed turbine stop

valve. In addition, water from leaking mechanical seal lines and an

unknown valve caused water to back up and contaminate the pump oil. 

RCIC was out of service for unspecified reasons. LER # 366/79-045

Oyster Creek 2x10-3 5/2/79

Loss of feedwater flow

While testing the isolation condenser, a reactor scram occurred. The

feedwater pump tripped and failed to restart. The recirculation pump inlet

valves were closed. The isolation condenser was used during cooldown.

LER # 219/79-014

Three Mile Island 2 1 3/28/79

Loss of feedwater; PORV failed open; operator errors led to core

damage

Operators misinterpreted plant conditions, including the RCS inventory,

during a transient that was triggered by a loss of feedwater and a stuckopen PORV. As a result, the operators prematurely shut off the highpressure safety injection system, turned off the reactor coolant pumps,

and failed to diagnose and isolate a stuck-open pressurizer relief valve. 

With the no RCS inventory makeup, the core became uncovered and fuel

damage occurred. In addition, contaminated water was spilled into the

containment and auxiliary buildings. LER # 320/79-012

Salem 1 1x10-2 11/27/78

Loss of vital bus and scram; multiple components lost

While the reactor was at 100-percent power, vital instrument bus “1B” was

lost as a result of the failure of an output transformer and two regulating

resistors. Loss of the vital bus caused a false low RCS loop flow signal,

thereby causing a reactor trip. Two AFW pumps failed to start (one

because of the loss of vital bus “1B”, and the other because of a

maladjustment of the over-speed trip mechanism). Inadvertent safety

injection occurred as a result of decreasing average coolant temperature

and safety injection signals. LER # 272/78-073

Calvert Cliffs 1 3x10-3 4/13/78

LOOP; one EDG failed to start

With the plant shutdown, a protective relay automatically opened the

switchyard breakers, resulting in a LOOP. EDG “11" failed to start. EDG

“22" started and supplied the safety busses. LER # 317/78-020
Plant CCDP Date Description

20

Farley 1 5x10-3 3/25/78

Low-Low water level in one SG trip/scram; turbine-driven AFW pump

fails 

A low level condition in a single SG resulted in a reactor trip. The turbinedriven AFW pump failed to start. Both motor-driven AFW pumps started,

but were deemed ineffective because all recirculation bypass valves were

open (thereby diverting flow). A recirculation valve was manually closed.

LER # 348/78-021

Rancho Seco 1x10-1 3/20/78

Failure of NNI and steam generator dryout

When the reactor was at power, a failure of the NNI power supply resulted

in a loss of main feedwater, which caused a reactor trip. Because

instrumentation drift falsely indicated that the steam generator contained

enough water, control room operators did not take prompt action to open

the AFW flow control valves to establish secondary heat removal. This

resulted in steam generator dryout. LER # 312/78-001

Davis-Besse 1 5x10-3 12/11/77

AFW pumps inoperable during test

During AFW pump testing, operators found that control over both pumps

was lost because of mechanical binding in the governor of one pump and

blown control power supply fuses for the speed changer motor on the

other pump. LER # 346/77-110

Davis-Besse 1 7x10-2 9/24/77

Stuck-open pressurizer PORV

A spurious half-trip of the steam and feedwater rupture control system

initiated closure of the startup feedwater valve. This resulted in reduced

water level in SG “2.” The pressurizer PORV lifted nine times and then

stuck open because of rapid cycling. LER # 346/77-016

Cooper 1x10-3 8/31/77

Partial loss of feedwater; reactor scram; RCIC and HPCI degraded

A blown fuse caused the normal power supply to the feedwater and RCIC

controllers to fail. The alternate power supply was unavailable due to an

unrelated fault. A partial loss of feedwater occurred, and the reactor

tripped on low water level. RCIC and HPCI operated, however, both

pumps did not accelerate to full speed (RCIC due to the failed power

supply and HPCI due a failed governor actuator). LER # 298/77-040

Zion 2 2x10-3 7/12/77

Testing causes instrumentation errors

With the reactor in hot shutdown, testing caused operators to lose

indications of reactor and secondary system parameters. In addition,

inaccurate inputs were provided to control and protection systems. 

LER # 304/77-044

Millstone 2 1x10-2 7/20/76

Loop from grid disturbance; errors in EDG loading fail the emergency

core cooling systems (ECCS)

With the reactor at power, a main circulating water pump was started, and

this resulted in an in-plant voltage reduction to below the revised trip set

point. This isolated the safety-related buses and started the EDGs. Each

time a major load was tied onto the diesel, the revised under-voltage trip

set points tripped the load. As a result, at the end of the EDG loading

sequence, all major loads were isolated even though the EDGs were tied

to the safety-related buses. LER # 336/76-042
Plant CCDP Date Description

21

Kewaunee 5x10-3 11/5/75

Inoperable AFW pumps during startup as a result of leaks from the

demineralizer into the condensate storage tank (CST)

Mixed bed resin beads were leaking from the demineralizer in the makeup

water system and migrated to the CST. As a result, during startup, both

motor-driven AFW pump suction strainers became clogged, thereby

resulting in low pump flow. The same condition occurred for the turbinedriven AFW pump suction strainer. LER # 305/75-020

Brunswick 2 9x10-3 4/29/75

Multiple valve failures; RCIC inoperable as a result of stuck-open

down/safety valve

At 10-percent power, the RCIC system was determined to be inoperable,

and SRV “B” was stuck open. The operator failed to scram the reactor

according to the EOPs. HPCI system failed to run and was manually shut

down as a result of high torus level. Loop “B” of RHR failed as a result of

a failed service water supply valve to the heat exchanger. The reactor

experienced an automatic scram on manual closure of the main steam

isolation valve (MSIV). LER # 324/75-013

Browns Ferry 1 2x10-1 3/22/75

Cable tray fire

The fire was started by an engineer, who was using a candle to check for

air leaks through a firewall penetration seal to the reactor building. The

fire resulted in significant damage to cables related to the control of Units

1 and 2. All Unit 1 emergency core cooling systems were lost, as was the

capability to monitor core power. Unit 1 was manually shut down and

cooled using remote manual relief valve operation, the condensate

booster pump, and control rod drive system pumps. Unit 2 was shut down

and cooled for the first hour by the RCIC system. After depressurization,

Unit 2 was placed in the RHR shutdown cooling mode with makeup water

available from the condensate booster pump and control rod drive system

pump. LER # 259/75-006

Turkey Point 3 2x10-2 5/8/74

Failure of three AFW pumps to start during test

Operators attempted to start all three AFW pumps while the reactor was at

power for testing. Two of the pumps failed to start as a result of

over-tightened packing. The third pump failed to start because of a

malfunction in the turbine regulating valve pneumatic controller. 

LER # 250/74-LTR

Point Beach 1 5x10-3 4/7/74

Inoperable AFW pumps during shutdown 

While the reactor was in cooldown mode, motor-driven AFW pump “A” did

not provide adequate flow. The operators were unaware that the in-line

suction strainers were 95 percent plugged (both motor-driven pumps “A”

and “B”). A partially plugged strainer was found in each of the suction

lines for both turbine-driven AFW pumps. LER # 266/74-LTR

Point Beach 1 1x10-3 1/12/71

Failure of containment sump valves

During a routine check of the containment tendon access gallery, air was

observed leaking from the packing of one sump isolation valve. Operators

attempted to open the valve, but the valve failed to open due to a shorted

solenoid in the hydraulic positioner. The redundant sump isolation valve

was also found inoperable due to a stuck solenoid in the hydraulic

positioner. LER # 266/71-LTR
22

*NOTE (to Table 10):

• Events are selected on the basis of CCDPs, as estimated by the ASP Program.

• Because of model and data uncertainties, it is difficult to differentiate between events with CCDPs that are within a

factor of about 3. 

• ASP analyses have been performed since 1969, and the associated methodologies and PRA models have evolved

over the past 30 years. Consequently, the results obtained in the earlier years may be conservative when compared to

those obtained using the current methodology and PRA models.
23

0 

0.1 

0.2 

0.3 

0.4 

0.5 

Precursors/Reactor Year

84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02

Fiscal Year

CRDM Cracking Events

Final Data

Historical

Figure 2: Total precursors–occurrence rate, by fiscal year. No trend line is shown because no trend was

detected that was statistically significant (p-value= 0.34). The results prior to FY 1993 are shown to provide

perspective. The ongoing analyses of events involving cracks in the CRDM housings are included FY 2001

and 2002 data.
24

0.00

0.02

0.04

0.06

0.08

0.10

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 2b: Precursors in CCDP bin 10-4-occurrence

rate, by fiscal year. The decreasing trend is almost

statistically significant (p-value = 0.11).

0

1

2

3

4

5

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Number of Precursors

Figure 2a: Precursors in CCDP bin 10-3-number of

precursors, by fiscal year. No trend line is shown

because no trend was detected that is statistically

significant.

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 2c: Precursors in CCDP bin 10-5-occurrence

rate, by fiscal year. The decreasing trend is

statistically significant (p-value = 0.002). 

0.00

0.04

0.08

0.12

0.16

0.20

0.24

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 2d: Precursors in CCDP bin 10-6-occurrence

rate, by fiscal year. The increasing trend is statistically

significant (p-value = 0.0001).

0.00

0.02

0.04

0.06

0.08

0.10

0.12

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 3: Important precursors (CCDP =

10-4)-occurrence rate, by fiscal year. The decreasing

trend is almost statistically significant (p-value = 0.14).
25

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 4: Precursors involving initiating

events-occurrence rate, by fiscal year. The

decreasing trend is statistically significant (p-value =

0.0001). 

0.00

0.04

0.08

0.12

0.16

0.20

0.24

0.28

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

CRDM cracking events

arithmetic average

mean (per reactor calendar year)

Figure 5: Precursors involving conditional

unavailability of equipment-occurrence rate, by fiscal

year. The increasing trend is statistically significant

(p-value = 0.005). 

0.00

0.04

0.08

0.12

0.16

0.20

0.24

0.28

0.32

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

CRDM cracking events

arithmetic average

Figure 8: Precursors involving PWRs-occurrence

rate, by fiscal year. No trend line is shown because

no trend is detected that is statistically significant

(p-value = 0.37). 

0.00

0.02

0.04

0.06

0.08

0.10

0.12

0.14

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Fiscal Year

Occurrence Rate

arithmetic average

mean (per reactor calendar year)

Figure 6: Precursors involving loss of offsite power

initiating events-occurrence rate, by fiscal year. The

increasing trend is statistically significant (p-value =

0.02).

0.00

0.04

0.08

0.12

0.16

0.20

0.24

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year

Occurrence Rate

arithmetic average

Figure 7: Precursors involving BWRs-occurrence

rate, by fiscal year. No trend line is shown because no

trend was detected that is statistically significant

(p-value = 0.36). 
26

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

60%

65%

Design Hardware Procedure Personnel Maintenance

Precursor Cause

Percent (%)

Delta-CDP Bin: > 1E-4

Delta-CDP Bin: 1E-5 to 1.0E-4

Delta-CDP Bin: 1E-6 to 1E-5

Precursors from other causes

Figure 9a: Causes of precursors- percentage, by

cause type.

0

4

8

12

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002

Fiscal Year 

Number of Precursors Caused by Design Error

Figure 9b: Precursors caused by design-basis

issues- number of precursors, by fiscal year. 
27

1.0E-06 

1.0E-05 

1.0E-04 

1.0E-03 

ASP Index (per reactor year)

82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02w/o

Calendar Year

Annual ASP Index

Average CDF from IPEs

10-year ASP Index

Figure 10: Annual ASP Index - ASP Index for a year is the total CCDP of all precursors divided by the

total number of reactor years in a given year. Years with significant precursors (i.e., CCDP > 1E-3): 1983

(2), 1984 (2), 1985 (3), 1986 (2), 1990 (1), 1991 (1), 1994 (1), 1996 (1), and 2002 (1). The ongoing

analyses of events involving cracks in the CRDM housings are included FY 2001 and 2002 data. The

CCDPs of these events are assumed to be 5 x 10-5. The bar labeled “w/o” is FY 2002 index without the

potential precursor at Davis-Besse.