ML031220453
| ML031220453 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 05/02/2003 |
| From: | Howell A NRC/RGN-IV/DRP |
| To: | Hinnenkamp P Entergy Operations |
| References | |
| EA-03-077, IR-02-007 | |
| Download: ML031220453 (19) | |
See also: IR 05000458/2002007
Text
May 2, 2003
Paul D. Hinnenkamp
Vice President - Operations
River Bend Station
Entergy Operations, Inc.
P.O. Box 220
St. Francisville, Louisiana 70775
SUBJECT:
RIVER BEND STATION - NRC SPECIAL INSPECTION REPORT 50-458/02-07
Dear Mr. Hinnenkamp:
On February 7, 2003, the NRC issued the subject special inspection report, which discussed a
finding concerning the failure to properly lock open Condensate Prefilter Vessel Bypass Flow
Control Valve CNM-FCV200. This apparent violation resulted in a loss of feedwater flow to the
reactor pressure vessel following a reactor scram on September 18, 2002.
This finding was assessed based on the best available information, including influential
assumptions, using the Significance Determination Process described in NRC Inspection
Manual Chapter 0609 and was preliminarily determined to be a finding with some increased
importance to safety (White), which may require additional NRC inspection. The finding has a
preliminary assessment of low to moderate safety significance because the combination of risk
associated with a loss of feedwater and from external events, such as a fire in conjunction with
a loss of the feedwater system, over a period of approximately 126 days. This caused the
probability of core damage to increase by approximately 1.6 X 10-6/yr. The most significant
transient sequences contributing to the increase in risk were those involving the failure of the
main feedwater system following a reactor trip combined with the random failures of the high
pressure core spray, the reactor core isolation cooling, and the automatic depressurization
systems. The NRC Significance Determination Process Phase 3 risk evaluation is enclosed.
Our preliminary determination was discussed with members of your staff during a telephone call
on April 11, 2003.
This finding was also an apparent violation of Technical Specification 5.4.1 in that
Valve CNM-FCV200 was not properly locked open in accordance with required procedures and
is being considered for escalated enforcement action in accordance with the "General
Statement of Policy and Procedure for NRC Enforcement Actions" (Enforcement Policy),
NUREG-1600. The current Enforcement Policy is included on the NRCs Web site at
http://www.nrc.gov/what-we-do/regulatory/enforcement.html.
Entergy Operations, Inc.
-2-
Since the NRC has not made a final determination in this matter, no Notice of Violation is being
issued for this inspection finding at this time. In addition, please be advised that the number
and characterization of apparent violations described in the subject inspection report may
change as a result of further NRC review.
Before we make a final decision on this matter, we are providing you an opportunity to:
(1) present your perspectives on the facts and assumptions used by the NRC to arrive at the
proposed finding and its preliminary significance at a Regulatory Conference, or (2) submit your
position on the proposed finding and preliminary significance to the NRC in writing. If you
request a Regulatory Conference, it should be held within 30 days of the receipt of this letter
and we encourage you to submit supporting documentation at least one week prior to the
conference in an effort to make the conference more efficient and effective. If a Regulatory
Conference is held, it will be open for public observation. If you decide to submit only a written
response, such submittal should be sent to the NRC within 30 days of the receipt of this letter.
Please contact David Graves at 817/860-8141 within 10 business days of the date of receipt of
this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we
will continue with our significance determination and enforcement decision and you will be
advised by separate correspondence of the results of our deliberations on this matter.
In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter and its
enclosures will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records (PARS) component of NRCs document
system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-
rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Arthur T. Howell III, Director
Division of Reactor Projects
Docket: 50-458
License: NPF-47
Enclosure:
SDP Phase 3 Evaluation
cc w/enclosure:
Executive Vice President and
Chief Operating Officer
Entergy Operations, Inc.
P.O. Box 31995
Jackson, Mississippi 39286-1995
Entergy Operations, Inc.
-3-
Vice President
Operations Support
Entergy Operations, Inc.
P.O. Box 31995
Jackson, Mississippi 39286-1995
General Manager
Plant Operations
River Bend Station
Entergy Operations, Inc.
P.O. Box 220
St. Francisville, Louisiana 70775
Director - Nuclear Safety
River Bend Station
Entergy Operations, Inc.
P.O. Box 220
St. Francisville, Louisiana 70775
Wise, Carter, Child & Caraway
P.O. Box 651
Jackson, Mississippi 39205
Mark J. Wetterhahn, Esq.
Winston & Strawn
1401 L Street, N.W.
Washington, DC 20005-3502
Manager - Licensing
River Bend Station
Entergy Operations, Inc.
P.O. Box 220
St. Francisville, Louisiana 70775
The Honorable Richard P. Ieyoub
Attorney General
Department of Justice
State of Louisiana
P.O. Box 94005
Baton Rouge, Louisiana 70804-9005
H. Anne Plettinger
3456 Villa Rose Drive
Baton Rouge, Louisiana 70806
Entergy Operations, Inc.
-4-
President
West Feliciana Parish Police Jury
P.O. Box 1921
St. Francisville, Louisiana 70775
Michael E. Henry, State Liaison Officer
Department of Environmental Quality
P.O. Box 82135
Baton Rouge, Louisiana 70884-2135
Brian Almon
Public Utility Commission
William B. Travis Building
P.O. Box 13326
1701 North Congress Avenue
Entergy Operations, Inc.
-5-
Electronic distribution by RIV:
Regional Administrator (EWM)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (PJA)
Branch Chief, DRP/B (DNG)
Senior Project Engineer, DRP/B (RAK1)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (NBH)
D. P. Loveless (DPL)
G. F. Sanborn, D:ACES (GFS)
K. D. Smith, RC (KDS1)
F. J. Congel, OE (FJC)
OE:EA File (RidsOeMailCenter)
ADAMS: Yes
No Initials: __dng____
Publicly Available
Non-Publicly Available
Sensitive
Non-Sensitive
R:\\_RB\\2003\\RBS Choice Letter.wpd
RIV:C:DRP/B
SRA/DRS
D:ACES
NRR/DIPM
D:DRP
DNGraves
DPLoveless
GFSanborn
LADudes
ATHowell III
/RA/
/RA/
GMVasquez for E - DNGraves
/RA/
5/1/03
5/1/03
5/1/03
4/28 /03
5/2/03
OFFICIAL RECORD COPY
T=Telephone E=E-mail F=Fax
ENCLOSURE
Preliminary Significance Determination
A.
Brief Description of Issue
In May 2002, a full-flow condensate filter bypass valve was improperly manipulated such
that, if a large feedwater transient occurred, such as one that would occur following a
reactor scram, the valve could fail closed, and the feedwater and condensate systems
would be lost as a source of makeup water to the reactor vessel.
On September 18, 2002, following a reactor scram, the valve failed closed, resulting in
the loss of feedwater and condensate systems. Additionally, the reactor water cleanup
system, which returns water to the reactor via the feedwater system, continued to inject
hot water into the feedwater system and backwards into the condensate system through
open recirculation valves. The control rod drive hydraulic pumps, which take suction
from the condensate system, began cavitating (which lasted for approximately
70 minutes) as a result of the hot reactor water being introduced into the pump suction.
The cavitation of the operating pump was not detected by the control room operators.
Main feedwater is the normal source of water supply to the reactor, and CRD hydraulics
provides an additional source of makeup that is utilized when necessary. Both systems
have risk significance.
The event is described in significant detail in NRC Inspection Report 50-458/2002-07.
B.
Statement of the Performance Deficiency
Performance Deficiency: The licensee installed a plant modification, in a temporary
condition, without providing sufficiently detailed operating procedures and/or operator
training.
Supporting Information: On May 15, 2002, operators failed to properly lock Condensate
Prefilter Vessel Bypass Flow Control Valve CNM-FCV200 in the open position as
required by SOP-0007, Revision 21, Condensate System. As a result, following a
reactor scram, normal system flow oscillations caused the valve to close. The closure of
Valve CNM-FCV200 resulted in a loss of all power conversion system flow.
Bypass Valve CNM-FCV200 was installed during the licensees Spring maintenance
outage as part of a modification to provide full-flow condensate filtration. The segment
of line in which the valve was installed carries 100 percent of the condensate flow
without redundancy. The modification was left in an incomplete condition. Normal
operations of the system were permitted, provided the bypass valve was locked in the
open position, and the bifurcating lines to the filters were isolated. This configuration
should have left the system operating as if in a premodified condition. The configuration
of the valve was not reassessed until after the September 18 reactor scram.
-2-
The air operator for Valve CNM-FCV200 was not connected to a controller, nor to an air
source. Therefore, the valve had to be mechanically restrained in the open position.
Craftsmen left the valve in the open position with the handwheel disengaged; plant
procedures had been revised to require that the valve be locked in the open position.
However, this valve operator type was new to River Bend, and plant operators were not
familiar with the operation of the valve. Operators, therefore, locked the handwheel, but
did not engage the manual operator.
In summary, the following actions resulted in condensate and feedwater being
unavailable to respond following an accident:
Valve CNM-FCV200 was installed in a section of condensate pipe that handled
full system flow without redundancy.
The full-flow filtration system installation was not completed prior to normal plant
operation.
The motive force (instrument air) and controller for Valve CNM-FCV200 were not
installed.
The design of Valve CNM-FCV200 was new to plant operators and they had not
received training on the operation of the valve.
Craftsmen left Valve CNM-FCV200 in the open position with the manual
mechanism not engaged. Operators later locked the handwheel in the open
position but did not engage the manual mechanism. This left the valve in a
condition that packing and actuator piston friction were the only things keeping
the valve open.
Normal feedwater flow oscillations, following a reactor trip, resulted in the valve
closing and being held closed with system differential pressure. This resulted in
a loss of all condensate flow.
Upon loss of all condensate flow, the feedwater pumps tripped on loss of suction.
C.
Significance Determination Basis
Reactor Inspection for IE, MS, B cornerstones
1.
Phase 1 screening logic, results, and assumptions
In accordance with Inspection Manual Chapter 0612, Appendix B, Issue
Disposition Screening, the inspectors determined that the finding was more than
minor because the issue was associated with the configuration control of
operating equipment alignment. The failure to properly lock open
Valve CNM-FCV200 resulted in the loss of condensate and feedwater flow to the
reactor vessel. Therefore, this performance deficiency affected the mitigating
-3-
systems cornerstone objective to ensure the availability, reliability, and capability
of systems that respond to initiating events to prevent undesirable
consequences.
In accordance with Inspection Manual Chapter 0609, Appendix A, Significance
Determination of Reactor Inspection Findings for At-Power Situations, the
inspectors determined that this issue affected high pressure primary injection
systems, involved mitigating systems, did not affect fire protection defense-in-
depth, and did not affect the safety of a shutdown reactor. Therefore, the
mitigating systems column was followed. The following questions were
answered:
Is the finding a design qualification deficiency confirmed not to result in loss of
function per GL 91-18? No.
Does the finding represent an actual loss of safety function of a system? Yes,
the main feedwater system.
Therefore, Phase 1 directed that a Phase 2 estimation be completed.
2.
Phase 2 Risk Estimation
In accordance with Inspection Manual Chapter 0609, Appendix A, the inspectors
conducted a Phase 2 estimation using the Risk-Informed Inspection Notebook
for River Bend Station, Unit 1, Revision 1. The dominant affected accident
sequences are provided in Table 1. The inspectors assumed that the plant
conversion system and control rod drive hydraulics were unavailable to respond
to accidents.
The Phase 2 estimation resulted in an estimated White finding. The
performance deficiency existed for significantly less than the 365 days assumed
in the notebook and licensee analysts stated that the Phase 2 worksheets were
overly conservative for analyzing a loss of control rod drive hydraulics.
Therefore, the analyst determined that the finding should be evaluated using the
Phase 3 process.
3.
Phase 3 Analysis
Internal Initiating Events:
The following techniques were used in this evaluation.
a.
The analyst quantified the internal risk using the INEEL Standardized
Plant Analysis Risk Model for River Bend Station, Revision 3i. Rather
than attempt to model the loss of short-term availability of the control rod
drive hydraulics system, the analyst quantified the model with a loss of
condensate and feedwater. The model was then quantified with the
-4-
control rod drive system also unavailable. The resulting quantification
indicated an increase over the baseline core damage frequency between
4.0 x 10-6 and 6.4 x 10-6 over a 126-day exposure.
b.
The licensee developed a model for analyzing the internal risk associated
with the performance deficiency using a modified version of their
Revision 3 PRA model. The licensee revised the model by setting the
frequency of a loss of all feedwater initiating event to the frequency of a
normal trip. Additionally, the model was changed to indicate a loss of
short-term cooling from the control rod drive system, while providing for
long-term recovery of the control rod drive system following the cavitation
event, provided that high pressure core spray (HPCS) and reactor core
isolation cooling (RCIC) had been available.
The analyst reviewed the licensees modified model in detail during a site
visit on January 9, 2003. Several errors in modeling and/or imprecise
assumptions were detected and changed during this visit. Based on this
review, the analyst concluded that the revised model was adequate for
evaluating the performance deficiency and that the assumptions used by
the licensee were reasonable. Therefore, the analyst determined that this
result was the best estimate of the internal risk associated with the failure
to ensure that Valve CNM-FCV200 remained in the open position during
power operations.
The resulting increase over the baseline core damage frequency was
7.7 x 10-7 over a 125-day period.
NOTE: The licensee used 125 days in their analysis, while the analyst
used 126 days. The actual time from entering Mode 2 following the
maintenance outage and the September 18 reactor scram was 126 days,
5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The analyst determined by hand calculation that the difference
of 1 day exposure time does not impact the results of the evaluation.
c.
The following influential assumptions were made:
Valve CNM-FCV200, if not fixed in the open position, would have
failed shut during any at-power initiating event resulting in, or that
should have resulted in, a scram.
This condition existed prior to plant restart on May 15, 2002, until
the reactor trip on September 18, 2002.
Operators were not familiar with the valve type and had not been
trained on the design of the valve. Therefore, it is assumed that
any operator could have made a similar error in locking the valve
in position.
-5-
The forces holding the valve open (the packing resistance and the
actuator friction) would not have changed appreciably in 4 months.
Therefore, the exposure time for this condition was 126 days.
Valve CNM-FCV200 failing closed results in the loss of all
condensate and feedwater flow to the reactor pressure vessel.
No recovery credit should be given for the feedwater or
condensate systems. Because the full-flow filtration system
modification was incomplete, no indication of the
Valve CNM-FCV200 position was available in the main control
room. Additionally, plant operators visually inspecting the
condensate system for indications of system abnormalities would
have observed a valve in the locked open position. It should be
noted as additional supporting evidence that the operators did not
determine the cause of system failure during their response to the
event on September 18, 2002.
The control rod drive hydraulic system would not be functional for
the first 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> of a transient because, during the event, the
pump cavitated for a significant period of time (approximately
70 minutes) while provided high temperature suction water. The
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> corresponds to the long-term cooling function of the
system, given that another system has provided cooling water to
the reactor until that time.
Reactor water cleanup flowing backwards through the feedwater
and condensate systems, combined with extraction steam heating
of the isolated systems until the turbine tripped, resulted in
excessive control rod drive suction temperatures.
Prior to the installation of Valve CNM-FCV200, a loss of
condensate to the feedwater pump suction would have resulted in
the long-cycle recirculation pathway remaining closed. However,
because Valve CNM-FCV200 went closed, this bypassed normal
system logic and the recirculation path opened when condensate
system flow was lost. Therefore, reactor water cleanup system
flow would have continued to pump forward to the reactor through
the feedwater injection lines.
There are the following two possible event progressions:
(1)
All flow, with the exception of control rod drive system flow,
is lost early in the event.
-6-
In this case, reactor vessel level would decrease rapidly
and the reactor water cleanup system would automatically
isolate on a low level signal.
In this scenario, reactor water cleanup would not cause
high temperatures in the control rod drive system suction.
However, in this case, control rod drive hydraulics would
not provide sufficient flow to the core. These sequences
are already accounted for in the licensees baseline model,
and would not affect the change in core damage
frequency.
(2)
Feedwater provides flow to the vessel for a short period of
time, as occurred on September 18, and either the HPCS
or RCIC systems are available for a short period of time.
In this case, the reactor water cleanup system would
remain in service and respond as observed on
September 18. In accordance with the emergency
operating procedures, control room operators would
maximize CRD flow. Maximizing flow requires starting a
second pump and increasing both pumps flow rates.
These sequences would result in cavitation of the pumps
and a loss of control rod drive system flow in the short term
(less than 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />). This loss of short-term control rod
drive flow results in a change from the baseline risk and
was modeled in the licensees revised PRA.
The following calculations were performed and the results of all model
runs are documented in Table 3:
The analyst used the SPAR model to quantify the internal change
in risk for a loss of feedwater; a loss of condensate and feedwater;
and a loss of condensate, feedwater, and control rod drive
hydraulics. The latter is the closest to actual circumstances, while
the other runs provide indication of the sensitivity for lesser
system failures.
The SPAR model provides a basic event designating the
probability that all the pumps in a system will fail to run within the
same mission time. This basic event represents the common
cause failure rate for the pumps. For each of the three systems,
the analyst set this common cause failure rate to 1.0 using a
logical TRUE house event. The model was then quantified.
-7-
The analyst requested that the licensee use their model of record
to analyze the internal risk associated with a loss of all main
feedwater and the control rod drive system. Designated as
Licensees R3.0" in Table 3, this result provided a validation of
the SPAR model and indicated the upper bound for internal risk as
quantified by the licensees model. Finally, this result shows the
sensitivity of the results to the modeling of long-term recovery of
the control rod drive system. The dominant accident sequences
for this analysis are provided in Table 2.
External Initiating Events:
The analyst used the following methods for determining the change in risk from
external events. The change in risk from a loss of feedwater during a fire was
determined to be between 8.2 x 10-7 and 2.1 x 10-6 for the 126-day period. The
methods used are documented below:
Fire:
a.
The analyst used the River Bend IPEEE to estimate the change in risk
resulting from external events. Although the feedwater system is not
considered a safe shutdown system in the licensees IPEEE, feedwater
was used to screen out 18 fire areas that had been previously modeled
as greater than 1 x 10-6 /yr CDF.
The licensee reanalyzed each of these fire areas by using the developed
fire scenario and quantifying their internal PRA model with fire damaged
equipment taken out of service. Without crediting feedwater, each of
these scenarios resulted in a core damage frequency of less than
1 x 10-6/yr CDF. These would have screened out in the IPEEE; however,
the numbers indicated that feedwater was important to these scenarios.
At the analysts request, the licensee requantified each of the fire
scenarios giving credit for feedwater at its nominal failure rate. The
analyst determined that this represented the baseline fire risk for the
18 areas. As documented in Table 4, the inspector subtracted this
baseline from the licensees analyzed risk without crediting feedwater.
The change in risk upon a loss of feedwater for these 18 fire areas was
calculated to be 8.16 x 10-7 for the 126-day period.
2.36 x 10
-6/yr * (126/365)yrs exposure = 8.2 x 10
-7
b.
In the second method, the analyst assumed, qualitatively, that feedwater
was as important to external events as it is to internal events. The CDF
was divided by the licensees baseline CDF to quantify the importance.
This importance was then multiplied by the licensees external events
baseline to provide a quantitative result.
-8-
1.035 x 10-5 (case) - 8.110 x 10-6 (baseline) = 2.24 x 10-6
2.24 x 10-6 ÷ 8.110 x 10-6 = 27.6%
2.25 x 10-5 /yr (external baseline) * .276 * [125/365]yrs
= 2.1 x 10-6 CDF
c.
Finally, the analyst noted that this analysis only included 18 fire areas.
Many other fire areas in the plant would normally be mitigated using the
condensate and feedwater systems. However, the licensee does not have
these areas modeled or assessed. Therefore, qualitatively, it can be
assumed that the risk calculated in paragraph a. represents the lower
bound.
Seismic, Winds, Floods, and Other External Events:
The licensee does not model these events in their PRA or IPEEE. However, the
analyst noted that River Bend Station was susceptible to these external events,
particularly high winds and flooding. Additionally, being a versatile system,
feedwater should be available to provide core cooling in all accident scenarios
except secondary line breaks and a loss of offsite power. The most probable
external event scenarios would also result in a loss of offsite power. In these
events, feedwater would not have been available regardless of the performance
deficiency. Therefore, these other external events were determined, qualitatively,
to impact the change in risk for this finding, but were not assumed to increase the
overall risk by greater than one order of magnitude.
Quantitative Bounds:
To determine the range of possible outcomes, the analyst added the highest
result from the internal review and the highest result from the external review.
The lower bound of the range was the licensees revised internal risk result,
assuming that a negligible result in external events approaches zero
quantitatively. These bounding valves are documented in Table 3.
Sensitivity of Results:
While the results of this evaluation are definitely sensitive to the first four
assumptions documented in Section C.3.c, they are based on observed physical
conditions during the September 18, 2002 event. Also, they are conservative in
that they result in the higher risk significance, and the licensee does not dispute
them. Therefore, a sensitivity analysis was not performed on these assumptions.
-9-
Case 1:
The licensees assumption that control rod drive hydraulics would be available for
long-term cooling is a best estimate assumption. However, should the operators
have maximized CRD flow in accordance with emergency operating procedures
while the suction temperature was above 300F, there would have been a high
likelihood of permanent pump damage. Therefore, the SPAR and licensees
models were quantified with control rod drive inoperable for short- and long-term
cooling. The licensees model is sensitive to this assumption in that the 1 x 10-6
threshold is crossed if CRD flow is not available.
Case 2:
Several methods were used to qualitatively assess the risk from external events
caused by the performance deficiency. The two methods used by the analyst
indicated values near that of the internal events model results. However,
assuming that the fire risk associated with a loss of feedwater is zero clearly has
an impact on the analysis. The analyst believes that the licensees approach is
invalid.
Results and Preliminary Color:
The calculated CDF analysis results, including both internal and external
assessments, fall in a range of 7.7 x 10-7 to 8.4 x 10-6. The analysts best
estimate judgment was 1.6 x 10-6. This used the licensees revised model results
combined with the qualitative estimate of the external risk using the licensees
IPEEE fire areas and an analysis quantified with the licensees internal events
PRA model. Therefore, the preliminary analysis indicates that the finding is of low
to moderate risk significance (White).
-10-
Table 1
Phase 2 Dominant Accident Sequences
Initiating Event
Sequence
Contribution
TRANS-PCS-RCIC-CHR-LICRD
9
TRANS-PCS-RCIC-HPCS-DEP
7
Loss of Reactor Plant
Component Cooling Water
TCCP-PCS-RCIC-CHR
9
TCCP-PCS-RCIC-HPCS-DEP
9
Loss of 120 Vdc Emergency
Division I
TDCI-PCS-CHR
6
TDCI-PCS-HPCS-LPI
8
TDCI-PCS-HPCS-DEP
8
Loss of 120 Vdc Emergency
Division II
TDCII-PCS-CHR-LDEP
8
TDCII-PCS-RCIC-CHR
7
-11-
Table 2
Phase 3 Dominant Accident Sequences
Model
Initiating Event
Sequence
Contribution
SPAR 3i
2.3 x 10-6
8.8 x 10-7
Loss of Vital Medium
Voltage Bus
Div II Vital DC
5.8 x 10-7
RCIC, SSW-CF, NOREC-1H
2.1 x 10-7
Licensees
Revised
(Loss of Feedwater)
3.1 x 10-7
Loss of Normal Service
Water
SSW, NORECOVERY
2.3 x 10-7
-12-
Table 3
Analysis Results
Model Used
Assumptions
Exposure
126
3.9 x 10-6
Feedwater/Condensate
126
4.0 x 10-6
Feedwater/Condensate/Contr
ol Rod Drive
126
6.4 x 10-6
Licensees R3.0
Feedwater/Control Rod Drive
125
3.9 x 10-6
Licensees Revised*
Feedwater Initiating Event
Loss of Short-Term CRD
125
7.7 x 10-7
External IPEEE*
Feedwater Importance to 18
Named Fire Areas
126
8.2 x 10-7
External Qualitative
Feedwater Importance the
same in external events as
internal
126
2.1 x 10-6
Licensees External
Feedwater not important
125
0
Total CDF
(External + Internal)
Highest
126
8.4 x 10-6
Total CDF
(External + Internal)
Lowest
125
7.7 x 10-7
Total CDF
(External + Internal)
Analysts Best Estimate
126
1.6 x 10-6
- The designated quantities were used in determining the analysts best estimate.
-13-
Table 4
External Events (Internal Fire)
Fire Area
Fire Affected Components
Case
Failed)
Baseline
at Nominal)
CDF/year
AB-2/Z-1
5.64E-08
4.64E-11
5.65E-08
C13A
A Standby, Normal Service Water
3.55E-10
1.55E-11
3.70E-10
C13B
B Standby, Normal Service Water
3.55E-10
1.55E-11
3.70E-10
C18
Div I DC, Normal Service Water
4.92E-07
3.80E-09
4.96E-07
C19
Div II DC, Normal Service Water
4.74E-07
3.56E-09
4.78E-07
C20
9.77E-09
1.34E-10
9.91E-09
C21
7.53E-09
1.12E-10
7.64E-09
C22
2.33E-08
1.38E-10
2.34E-08
C23
B Battery Charger, Inverter
1.04E-08
1.02E-09
1.14E-08
C26
A Battery Charger, Inverter
1.40E-08
1.04E-09
1.50E-08
DG1
Div II AC, D/G, 4160 Switchgear,
Normal Service Water
1.61E-07
1.61E-09
1.63E-07
DG2
Div III AC, HPCS, Normal Service
Water
2.39E-09
4.64E-11
2.44E-09
DG3
Div I AC, 4160 Switchgear, HPCS,
3.90E-07
4.51E-09
3.94E-07
DG-5/Z-1
3.51E-07
2.80E-09
3.54E-07
DG-5/Z-2
2.83E-07
2.18E-09
2.86E-07
PH-01/Z-1
A Standby Service Water
2.24E-08
2.47E-08
4.71E-08
PH-01/Z-2
A Standby Service Water
1.92E-09
6.80E-10
2.60E-09
PH-02/Z-1
B Standby Service Water
7.40E-09
4.28E-09
1.17E-08
PH-02/Z-2
B Standby Service Water
3.17E-09
1.93E-09
5.09E-09
TOTAL
2.36E-06