ML030410114
| ML030410114 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 02/07/2003 |
| From: | Graves D NRC/RGN-IV/DRP/RPB-B |
| To: | Hinnenkamp P Entergy Operations |
| References | |
| IR-02-007 | |
| Download: ML030410114 (35) | |
See also: IR 05000458/2002007
Text
February 7, 2003
Paul D. Hinnenkamp, Vice President - Operations
River Bend Station
Entergy Operations, Inc.
P.O. Box 220
St. Francisville, Louisiana 70775
SUBJECT: NRC SPECIAL INSPECTION REPORT 50-458/02-07
Dear Mr. Hinnenkamp:
On November 14, 2002, the NRC completed a Special Inspection at the River Bend Station.
The enclosed report documents the inspection findings which were discussed with you and
members of your staff on November 14, 2002.
The inspectors examined activities associated with a reactor scram and subsequent system
interactions that occurred on September 18, 2002. The inspection was conducted in
accordance with Inspection Procedure 93812, Special Inspection, and the inspection team
charter. The inspectors reviewed selected procedures, records, and evaluation activities. The
inspectors also interviewed plant personnel. As a result of this inspection, the NRC developed
a sequence of events, initiated a risk significance determination of the event, and assessed
your response to and evaluation of the event.
Based on the results of this inspection, the NRC has identified an issue that requires further
analysis to determine the significance. This issue was an apparent violation of Technical Specification 5.4.1.a, which requires the licensee to establish and implement procedures to
operate the condensate system. Condensate Prefilter Vessel Bypass Flow Control
Valve CNM-FCV200 was not locked open as required and constitutes an apparent violation of
this Technical Specification.
The final significance of this apparent violation is to be determined. The issue was initially
characterized as having a safety significance of more than minor. Further determination of
significance will be made through a Phase 3 significance determination analysis by the NRC.
In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response will be made 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).
Entergy Operations, Inc. -2-
Should you have any questions concerning this inspection, we will be pleased to discuss them
with you.
Sincerely,
/RA/
David N. Graves, Chief
Project Branch B
Division of Reactor Projects
Docket: 50-458
License: NPF-47
Enclosure:
NRC Inspection Report
50-458/02-07
cc w/enclosure:
Executive Vice President and
Chief Operating Officer
Entergy Operations, Inc.
P.O. Box 31995
Jackson, Mississippi 39286-1995
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
Entergy Operations, Inc. -3-
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
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. -4-
Technological Services
Branch Chief
FEMA Region VI
800 North Loop 288
Federal Regional Center
Denton, Texas 76201-3698
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)
Scott Morris (SAM1)
RBS Site Secretary (LGD)
W. Maier (WAM)
D. Thatcher (DFT)
R:\_RB\2002\RB2002-07RP-MOM.wpd
RIV:RI:DRP/B DRS/OB DRS/PSB C:DRP/B
MOMiller JFDrake JSDodson DNGraves
/RA/ /RA/ E - DNGraves /RA/
1/16/03 1/6/03 1/7/03 2/7/03
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
ENCLOSURE
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 50-458
License: NPF-47
Report: 50-458/02-07
Licensee: Entergy Operations, Inc.
Facility: River Bend Station
Location: 5485 U.S. Highway 61
St. Francisville, Louisiana
Dates: September 24 through November 14, 2002
Inspectors: M. O. Miller, Resident Inspector River Bend Station, Team Leader
J. S. Dodson, Project Engineer
J. F. Drake, Operations Engineer
Approved By: D. N. Graves, Chief, Project Branch B
ATTACHMENT: Special Inspection Charter
TABLE OF CONTENTS
SUMMARY OF FINDINGS
REPORT DETAILS
1 Special Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2 Event Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2.1 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2.2 Details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Reactor Power Response
Reactor Pressure Response
Reactor Water Level Response
Feedwater and Condensate Systems Response
CNM-FCV200, Condensate Pre-Filter Vessel Bypass Flow Control Valve
CRD System Response
3 Special Inspection Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
3.1 Sequence of Events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
3.2 Operator Response . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
3.3 Unmonitored Release Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
3.4 Posttrip Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
3.5 Root Cause Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
3.6 Risk Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
3.7 10 CFR 50.72 Report Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
4 Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
ATTACHMENT:
Special Inspection Charter
SUMMARY OF FINDINGS
River Bend Station
NRC Inspection Report 50-458/02-07
IR 50-458/02-07; Entergy Operations, Inc.; on 09/24/2002-11/14/2002; River Bend Station.
Special Inspection Report. Event Followup.
The report covers a special inspection conducted by Region IV inspectors concerning a reactor
scram with a loss of the condensate and feedwater systems and the condensate storage tank
discharge of steam. The significance of most findings is indicated by their color (Green, White,
Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process.
Findings for which the Significance Determination Process does not apply are indicated by the
severity level of the applicable violation. The NRCs program for overseeing the safe operation
of commercial nuclear power reactors is described at its Reactor Oversight Process website at
http://www.nrc.gov/NRR/OVERSIGHT/ASSESS/index.html.
A. Inspector Identified Findings
Cornerstone: Mitigating Systems
- (to be determined) The inspectors identified an apparent violation of Technical
Specification 5.4.1.a, which requires that written procedures be established,
implemented, and maintained covering the applicable procedures recommended in
Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33,
Revision 2, Appendix A, Item 4.n requires instructions for operation of the condensate
system.
System Operating Procedure SOP-0007, Condensate System, Revision 21, required
Condensate Prefilter Vessel Bypass Flow Control Valve CNM-FCV200 to be locked
open. On September 18, 2002, Valve CNM-FCV200 was found to be not properly
locked open. The failure to properly lock Valve CNM-FCV200 in the open position
resulted in unexpected closure of the valve and a loss of feedwater flow to the reactor
vessel following a reactor scram.
The final significance of this issue will be determined using the Significance
Determination Process (Section 3.5).
REPORT DETAILS
1 Special Inspection Activities
The NRC conducted this special inspection to better understand the circumstances
surrounding a malfunction in the turbine control system, the subsequent reactor scram,
loss of feedwater, and a discharge of steam from the Condensate Storage Tank (CST)
that occurred on September 18, 2002. The decision to conduct a special inspection was
based on these collective factors:
- The licensees risk evaluation documented a Conditional Core Damage
Probability for the scram as 9.3E-7. This was statistically equivalent to the
threshold (1E-6) established in Manual Chapter 8.3 for conducting special
inspections.
- The event included an unexpected loss of feedwater.
- Steam was unexpectedly released from the CST.
The inspectors used Inspection Procedure 93812, Special Inspection, to conduct the
inspection. The team reviewed procedures, logs, instrumentation printouts, corrective
action documents, and design and maintenance records for the equipment of concern.
The team interviewed key station personnel regarding the event and subsequent
posttrip review investigation.
2 Event Description
2.1 Summary
On September 18, 2002, at 8:24 p.m. with the plant at full power, a turbine control
system malfunction caused the turbine control and intercept valves to slowly close. The
turbine bypass valves (BPVs) opened in response to the increase in steam line
pressure. An upscale neutron flux automatic reactor scram occurred 3.5 seconds after
the onset of the transient. When reactor water level began to decrease following the
scram, feedwater flow increased. This caused Condensate Prefilter Vessel Bypass
Flow Control Valve CNM-FCV200 to close unexpectedly, isolating the condensate
system from the feedwater system. The reactor feedwater pumps (RFP) tripped on low
suction pressure shortly after Valve CNM-FCV200 closed. A reactor low water level
alarm (Level 3) was received as reactor water level continued to decrease.
The operators manually started reactor core isolation cooling (RCIC), stabilized the plant
in Mode 3, Hot Shutdown, controlled reactor water level between +10 and +51 inches on
narrow range (NR) reactor water level instruments, and maintained reactor pressure
between 500 and 1090 psig using the turbine BPVs.
Operators in the turbine building reported water coming from under the doors to each
Steam Jet Air Ejector (SJAE) room. The reactor operators shut down the condensate
pumps and nuclear equipment operators (NEO) isolated the SJAE intercondensers to
terminate the water coming from the SJAE rooms.
At approximately 10 p.m., an inspector arriving onsite observed a plume of steam
coming from the CST vent. In addition, loud banging noises were noted coming from
the CST. The inspector notified control room personnel of these observations. It was
later determined that water was flowing from the reactor water cleanup system (RWCU)
filter demineralizers to the CST via the feedwater and condensate system.
2.2 Details
At 8:24 p.m., a transient in the +22 volt supply to the turbine control system caused the
turbine control valves and intercept valves to slowly close. The BPVs opened
automatically to control reactor pressure as designed. When the BPVs reached their full
open position and the turbine control valves continued to close, reactor pressure
increased to 1087.6 psig. This pressure increase resulted in a reactor power increase
and reactor water level decrease.
Reactor Power Response
Approximately 3.5 seconds into the transient, the average power range monitor (APRM)
system generated a scram signal on upscale neutron flux from five of the eight APRMs.
The licensee analysis showed that a relatively slow transient of this type could be
expected to trip sufficient APRM channels to terminate the transient without causing all
channels to trip. The highest rated thermal power value recorded was 121.99 percent
rated thermal power on APRM E. Licensee analysis of the core thermal performance
showed that no core thermal limit was exceeded.
Reactor Pressure Response
The maximum reactor pressure of 1087.6 psig was reached approximately 4.4 seconds
into the transient. This was less than one second after the scram was initiated. The
scram terminated the pressure transient. There were no reactor safety relief valve
actuations because the maximum pressure reached was below the minimum lift setpoint
of 1133 psig.
Reactor Water Level Response
Prior to the event, reactor water level was in the normal range at 36 inches as indicated
by the NR level indicators. At the same time, the average reactor water level was
21.8 inches as indicated on the wide range (WR) reactor water level instruments. The
WR level instruments normally indicate lower than the NR instruments due to the
recirculation pump suction effect on the pressure at the WR level instrument variable leg
sensing taps. The higher the power level (therefore the higher the reactor recirculation
system flow) the lower the indicated reactor water level on the WR level instruments.
At 3.4 seconds from the start of the turbine control system malfunction (just prior to the
scram), the average WR level instruments indicated 17.73 inches. When the scram was
initiated, the reduction in reactor power caused a further reduction in reactor water level
as the steam voids in the core collapsed. At 9.42 seconds from the start of the turbine
control system malfunction, reactor water level stopped decreasing at -24 inches, as
indicated on the WR level instruments.
As a result of the decrease in reactor water level, feedwater flow increased and reactor
water level reached about +20 inches when the feedwater flow was lost (at
approximately 35 seconds into the event). This caused reactor water level to drop again
quickly to about zero inches. Over the next 9 minutes, reactor water level continued to
decrease because the turbine control valves were not yet completely shut. At 8:33 p.m.,
the turbine control valves closed when the turbine tripped. Reactor water level reached
-21 inches WR before the operators manually started RCIC and restored reactor water
level.
Feedwater and Condensate Systems Response
Following the scram, the feedwater flow control valves opened in response to lowering
reactor water level. This increased feedwater flow caused Condensate Prefilter Vessel
Bypass Flow Control Valve CNM-FCV200 to close unexpectedly (Figure 1).
The closure of Valve CNM-FCV200 isolated flow to the RFPs and they tripped on low
suction pressure. When Valve CNM-FCV200 closed, condensate system pressure
increased to greater than 800 psig for a short duration (less than one second). The
gaskets on the SJAE intercondensers failed as a result of the pressure surge. The
failed gaskets allowed the condensate pumps to transfer water from the hotwell to the
turbine building 95 foot elevation. At 8:33 p.m., the operators shut down the condensate
pumps to stop this transfer of water.
Flow in the feedwater system and much of the condensate system stopped when
Valve CNM-FCV200
closed, which, in turn,
caused the condensate
system and RFP
minimum flow valves to
open. This created a
flowpath to vacuum-drag
water from the feedwater
and condensate systems
to the hotwell, which was
still under condenser
vacuum. Interlocks
closed the minimum flow
valves when the RFPs Figure 1
tripped and the
condensate pumps were
shut down.
The resulting high hotwell level caused condenser hotwell reject level control
Valve CNS-LCV105 to the CST to open.
When CNS-LCV105 opened, it created
an abnormal and reverse flowpath from
the condensate and feedwater systems
to the CST (Figure 2).
The RWCU system, which takes suction
from the reactor recirculation system and
discharges to the feedwater lines, was in
service at the time of the event. At
8:25 p.m., immediately after the RFPs Figure 2
tripped, RWCU flow increased rapidly.
As the feedwater system depressurized
(due to RFP and condensate minimum flow
valves being open to the main condenser)
the flow path for RWCU was from the
reactor recirculation system, through
RWCU filter demineralizers, backwards
through feedwater Line B into the
feedwater and condensate systems
(Figure 3). A check valve on feedwater
Line A prevented a similar flowpath through Figure 3
feedwater Line A. The check valve on
feedwater Line A had been installed to
prevent reverse flow in the feedwater system during RCIC injection.
There were two separate flowpaths from the condensate system into the CST
discharging 200 psig fluid that was between 356 and 378EF. One flowpath was through
Valve CNS-LV105. This line terminates in the CST below the surface of the water. The
water in the CST was cooler
and quenched the flashing
steam, which accounted for
the loud noises. The second
flow path was through the
control rod drive (CRD)
pumps minimum flow line and
into the space above the water
level in the CST. That fluid
was flashing into steam and
issuing from the vent on the
roof of the CST. The
operators closed Valve CNS-
LCV105 at 11:30 p.m., which
Figure 4
isolated one of the two flowpaths of water from RWCU to the CST. At 11:36 p.m. the
operators closed the low pressure feedwater heater inlet valves to start a condensate
pump. This isolated the remaining path of water from RWCU to the CRD to the CST,
and temperatures in the condensate and feedwater system began to return to their
normal values (Figure 4).
Condensate Prefilter Vessel Bypass Flow
Control Valve CNM-FCV200
The licensee had previously developed a
plant modification to install full flow filtration
equipment (prefilters) in the condensate
system. The licensee planned to install the
modification in two phases. The first phase
of the modification was installed in May
2002. The installed portion of the Figure 5
modification included Condensate Prefilter
Vessel Bypass Flow Control Valve CNM-
FCV200 (Figure 5).
CNM-FCV200 was a triple eccentric metal seated valve,
similar to a butterfly valve. The valve actuator was air-
operated with a handwheel for manual operation.
The photos on the right were taken with the handwheel
engaged and the handwheel disengaged. When the lever
was in the engaged position (moved to the left as shown in
the top photo), the handwheel was physically connected to
the valve through gears. Chaining the handwheel would then
keep the valve from moving. When the lever was in the Handwheel engaged
disengaged position (moved to the right as shown in
the lower photo), the valve was not connected to the
handwheel.
Because the handwheel was disengaged, the only
thing holding the valve open was friction from the
packing and internal components and the weight of the
disc. When flow through the valve increased
suddenly, as occurred when the feedwater system
tried to restore reactor water level following the scram,
the force on the disc was enough to cause the valve to
go closed. Handwheel Disengaged
CRD System Response
Design
The CRD system contains two pumps, with one pump normally running. The pump
takes a suction from the condensate system and supplies high pressure water to the
control rod hydraulic control units for normal control rod movement and control rod
scram functions. A portion of the CRD pump discharge flow is diverted through the
minimum flow bypass line to the CST. This flow is controlled by an orifice and is
sufficient to prevent pump damage if the pump discharge was inadvertently closed.
Condensate water to the CRD system is processed by two sets of filters. The CRD
pump suction filters are disposable element type with a 25-micron absolute rating. A
250-micron strainer in the CRD suction filter bypass line protects the CRD pumps when
the filters are being serviced. Downstream of the CRD pumps are two parallel drive
water filters which have a filtration rating ranging from 50-micron to 15-micron absolute.
A differential pressure indicator and main control room alarm monitor the in-service
suction filter element as it collects foreign materials. A similar arrangement is provided
for the drive water filters.
CRD Pump Suction Filters and Drive Water Filter
Normally, the suction supply to the CRD pumps was from the condensate system.
When pressure in the condensate system decreased to less than that from the head of
water in the CST, the CST became the suction source. When this occurred, the suction
filter differential-pressure alarm annunciated. The operators responded to the high
differential-pressure annunciator by implementing the alarm response procedure. The
operators bypassed the suction filter and placed the standby drive water filter in service.
The CRD suction filter was found to be fouled with red iron oxide debris. The licensee
stated that this was not an unusual occurrence when the CRD pump suction shifted
from the condensate system to the CST.
Temperature Response
The normal temperature in the part of the condensate system upstream of the feedwater
heaters was approximately 180EF. During the transient on September 18, 2002,
condensate temperature increased to approximately 350EF due to RWCU flow through
the system from about 9:40 p.m. until 11:15 p.m. The inservice CRD pump was
cavitating during this time as a result of the high temperature in the CRD pump suction.
The following was a list of CRD Loads:
- Charging header
- Drive header
- Cooling header
- Reactor recirculation pump seal purge
- Reactor water level reference leg backfill
While the CRD pump was cavitating, there was no flow through the charging or drive
headers. Therefore, these headers were not subjected to the higher condensate
system temperatures. These headers acted as a thermal barrier between the CRD
pumps and control rod hydraulic control units. The scram occurred at 8:25 p.m. with
CRD suction temperature at 128EF. At 8:58 p.m., the scram was reset and CRD pump
suction temperature had increased to 143EF as a result of residual heat in the low
pressure feedwater heaters. The temperature remained about 143EF for approximately
35 minutes following the scram reset. At the time of the scram reset, the CRD flow
control valves were closed, diverting flow to the charging header. The scram
accumulators were fully charged approximately 10 minutes later, before the temperature
of the water supply to the CRD pumps began to increase from RWCU flow. When the
scram accumulators were fully charged, the CRD flow control valve began to open,
redirecting flow to the cooling water header. Therefore, the scram accumulators were
not exposed to the elevated condensate water temperatures.
CRD fluid temperature peaked at approximately 350EF at 10 p.m. As CRD fluid
temperature began to increase, flow was supplied to the cooling water header and then
to the CRD mechanisms. The CRD mechanisms were normally exposed to high
temperatures and can withstand temperatures in excess of 500EF. Therefore, based on
the observed temperatures and design capabilities of the mechanisms, no functions
associated with the CRD mechanisms were affected.
High temperature water (350EF) from the CRD system was also being injected into the
reactor recirculation pump seals at a flow rate of 2 gpm per recirculation pump. This
CRD water was cooled by the reactor plant component cooling water system before
injection into the reactor recirculation pump seal cavity area. The highest reactor
recirculation pump seal temperature was 165EF, which was within the normal range. No
seal high temperature alarms were received.
The reactor water level reference leg backfill system was designed to reduce the
probability of step changes in indicated reactor water level caused by steam bubble
formation in the reference leg. The formation of steam bubbles in the reference leg can
force water mass out of the reference leg, which would cause indicated reactor water
level to increase. The steam bubbles then either collapse or vent out of the reference
leg and the indicated reactor water level returns to normal. There were no signs of step
changes in indicated reactor water level seen by the operators or noted during a review
of reactor water level graphs. At the nominal settings of 0.004 to 0.012 gpm through
long, uninsulated, small bore lines that supply the CRD water to the reference legs,
ambient losses to atmosphere would be such that the temperature of the water arriving
at the reference legs would be well below the temperature necessary for step changes
in indicated reactor water level to occur.
3 Special Inspection Areas
3.1 Sequence of Events
a. Inspection Scope
The inspectors developed a sequence of events related to the September 18, 2002,
reactor scram and compared it to the licensees sequence of events to determine if the
event had been accurately reviewed.
b. Background
The inspectors developed a sequence of events related to the identification and
timeliness of actions taken in response to the event of September 18, 2002. The time
line was generated from the sequence of events printout, annunciator log report,
archived operator logs, and interviews with the licensees staff.
This sequence of events was then compared to the licensees sequence of events. The
only differences identified in the licensees sequence of events were minor event
omissions. These were resolved as being related to the level of detail chosen by the
licensee for their sequence of events and had no impact on the licensees ability to
assess the event.
c. Findings
No findings of significance were identified.
3.2 Operator Response
a. Inspection Scope
The inspectors evaluated the adequacy of the operator response to this transient. The
sequence of events log, the annunciator report, and the operator logs were reviewed.
The inspectors also interviewed 10 control room operators and NEOs that were on duty
at the time of the event.
b. Background
The operators implemented the following procedures in response to the reactor scram
and loss of the condensate and feedwater systems:
- AOP-002, Main Turbine and Generator Trips, Revision 15A
- AOP-003, Automatic Isolations, Revision 17B
- AOP-006, Condensate/Feedwater Failures, Revision 13
The licensed operators recognized the loss of condensate and feedwater systems and
started the RCIC system to maintain reactor water level. The operators placed residual
heat removal Loop A in service to remove the heat of RCIC from the suppression pool.
The licensee was unaware of the steam issuing from the CST vent and the loud noises
in the CST until informed by one of the inspectors. The licensee initially believed that
the source of the steam and noise was RCIC recirculation flow diverted back to the
CST, although this had not been observed in the past. The RWCU flow into the CST
was unintentionally terminated when the low pressure feedwater heater inlet valves were
closed as part of the preparations for starting a condensate pump, almost 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after
the scram. The source of the vent steam was not determined until after the event was
terminated and the plant response was evaluated by the licensee.
Two NEOs were contaminated upon entering the SJAE rooms to investigate the water
leaking from under the door. The contaminated personnel were properly
decontaminated. No internal exposures occurred.
Fire alarms sounded on the turbine building 67 foot elevation as a result of the paint
melting off the condensate system piping. Operators responded appropriately to the fire
alarms. No injuries were reported.
c. Findings
No findings of significance were identified.
3.3 Unmonitored Release Evaluation
a. Inspection Scope
The inspectors interviewed cognizant personnel and reviewed the CST venting to
atmosphere (unmonitored release) during the event. The following items were reviewed
and compared with regulatory requirements:
C Radiation Section Procedure RSP-0008, Offsite Dose Calculation Manual,
Revision 11
C Condition Reports CR-RBS-2002-01371 and -01372 and current offsite dose
calculations contained in Condition Report CR-RBS-2002-01384
C Evaluation of Potential for Unmonitored Release of Radioactive Material from
Turbine Building during Post SCRAM Period on September 18, 2002, by Davey
Wells, Superintendent Radiation Protection
C Radiological Evaluation of the CST Release, by Senior Environmental
Specialist (1136)
C Technical Requirements Manual Section 3.11, Radioactive Effluents
The inspectors performed independent calculations of the potential radiation release
using RWCU effluent sample data to determine if the licensees calculations were
accurate and no release in excess of 10 CFR Part 50, Appendix I, requirements
occurred.
b. Background
There were two flowpaths of reactor coolant from the reactor to the CST from 9:25 p.m.
until 11:30 p.m. The reactor coolant traveled from the reactor to the RWCU pumps
through two parallel filter demineralizers and into feedwater Line B. Reactor coolant
then flowed backwards through the feedwater system into the condensate system.
Once in the condensate system the reactor coolant had two flowpaths to the CST. One
flowpath was through Condenser Hotwell Reject Level Control Valve CNS-LCV105.
Valve CNS-LCV105 was opened early in the event due to high water level in the hotwell.
At 11:30 p.m., the operators closed Valve CNS-LCV105, isolating this flowpath. The
other flowpath was through the CRD pumps. The CRD pumps normally take suction on
the condensate system. The CRD pump minimum flow line discharges to the CST.
During the event, reactor coolant from the RWCU system, via the condensate system,
and CRD pumps minimum flow line, was being discharged to the CST. At 11:36 p.m.,
the operators closed the low pressure heater string inlet valves to start a condensate
pump. This stopped RWCU flow to the CST.
c. Findings
No findings of significance were identified.
3.4 Posttrip Review
a. Inspection Scope
The inspectors evaluated the adequacy of the licensees posttrip review. Included in this
review was the thoroughness of the licensees assessment of the event, whether
potential complications on the plant systems (i.e., extent of condition) were properly
considered and whether the immediate corrective actions were comprehensive and
appropriate.
b. Background
1. Scram Report and Post-Trip Review Checklist
General Operating Procedure GOP-003, Scram Recovery, Enclosure 1, Post Trip
Review Checklist, dated September 18, 2002, and Enclosure 2, Scram Report, dated
September 18, 2002, were completed and presented to the Operational Safety Review
Committee (OSRC) for review.
The OSRC meeting was held in two parts on September 19, 2002. The first session
reviewed the following items related to a plant restart:
- GOP-003, Scram Recovery, dated September 18, 2002
- Cause of the increase in temperature in the CST
The OSRC concluded that no further review of GOP-003 was required and that nuclear
plant response was satisfactory. Four issues required further review:
- Provide a troubleshooting plan for EHC and plant conditions necessary for that
troubleshooting.
discussions relative to RWCU as the source of the elevated temperatures.
- Provide the results of an assessment of components served by CRD, with regard
to the effect of the high temperature water being pumped by the CRD pumps for
the 3-hour period.
The second OSRC meeting was convened at 12 midnight on September 19, 2002, to
address the four questions remaining from the first OSRC meeting.
The OSRC approved plant restart and unrestricted operation under the following
conditions:
- The troubleshooting plan as outlined for the EHC system be pursued with
appropriate instrumentation installed for monitoring during power operation, and
- A mode restraint condition report be written to address the impact of the higher
CRD water temperatures on equipment in the CRD system and answered prior
to entering Mode 2.
The licensee made appropriate entries into their corrective action program. These
corrective actions were assigned and given a due date. The mode restraint corrective
actions were completed prior to entering Mode 2.
2. Licensee Evaluation of Piping and Component Pressure Transient
Operations personnel reported condensate piping coating damage, piping noises during
the reactor scram transient, and water flooding on the turbine building 67 foot and
95 foot elevations. Consequently the licensee conducted two separate walkdowns
(described below) of the condensate and feedwater system. Other than the SJAE
intercondenser gasket failure, no physical damage was observed.
At 1 a.m. on September 19, 2002, the licensee walked down the condensate full flow
filtration area, condensate and feedwater piping, both heater bays on the turbine
building 67 foot elevation, the SJAE rooms on the turbine building 95 foot elevation, the
condenser recycle valve room, and piping/hangers in RFP and condensate pump areas.
This walkdown focused primarily on identifying transient-induced physical damage to
these systems.
The following items were identified:
- Condensate Prefilter Vessel Bypass Flow Control Valve CNM-FCV200 indicated
80 percent closed. This valve handwheel was normally locked open. This was
immediately reported to the outage control center and the operations shift
manager.
- Pipe coupling for condensate system flow Element CNM-FE114 leaking
- Component cooling water to condensate Pump C seal leak
- Low pressure feedwater heater BPV CNM-MOV136 broken tie rod on the
actuator cover
- Damaged paint on the low pressure feedwater heater bypass line
- Extensive amounts of unidentified debris were noted around several floor drains.
The licensee entered each of these items in the corrective action program and
appropriate corrective actions were taken.
At 8 p.m. on the evening of September 19, 2002, the licensee repeated this walkdown
(with the exception of the full flow filtration) after condensate Pump CNM-P1B had been
placed in service to pressurize the system. This walkdown focused on leak detection
and capturing conditions potentially missed during the first walkdown. Seventeen leaks
were identified as well as a loose pipe clamp and a detached leak seal injector nozzle.
An evaluation of the pressure transient in the piping as a result of the closure of
Valve CNM-FCV200 was also conducted. The value of the pressure used in the
evaluations of piping and components was 925 psig. This value was derived from
failure of the gaskets in the end-bells of the SJAE intercondensers, plant process
computer recordings of the event, and mechanical engineering stress analyses.
An analytical assessment of the condensate piping indicated that static stresses were
allowable up to a maximum pressure of approximately 1850 psig. During a water
hammer event, the stress applied was short in duration and thus the pressure the piping
could withstand was much higher than the allowable static pressure of 1850 psig. The
condensate pressure values were sampled by the plant process computer at
one second intervals. The highest recorded value was approximately 800 psig. Any
pressure higher than this lasted less than one second.
3. Licensee Evaluation of Piping and Component Temperature Transient
A series of events resulted in an increased fluid temperature in the condensate and
other interconnected systems. The temperature transient was an unexpected event and
not evaluated in the design basis of the affected systems. Licensee engineers
evaluated the impact of the temperature on the affected piping, equipment nozzle, pipe
supports, and in-line plant components. It was concluded that the evaluated piping and
plant components were not adversely affected by the temperature transient and can be
relied upon to perform their design functions.
The following was a summation of evaluations for each component:
- The normal operating temperature of the affected condensate piping ranges
from 142EF to 304EF. The condensate piping and feedwater heaters were not
safety related. The affected piping was qualified to the requirements of
ANSI B31.1. Evaluations concluded that the affected piping, pipe supports, and
equipment nozzles did not exceed the design code allowable values. The effects
of the thermal transient on the instrumentation tubing were bounded by the
existing design.
- The condensate demineralizers were qualified to a maximum temperature of
175EF for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or less. The maximum temperature transient above 180EF
lasted for less than 5 minutes. The maximum temperature recorded was 238EF
for approximately one minute. Due to the relatively short duration of the thermal
transient and the inherent flexibility of the piping, the effects of the transient on
the piping, pipe supports, and equipment nozzles were considered negligible.
- The CST was qualified to a temperature of 200EF, higher than the maximum
transient temperature noted during this event (180EF). The line from Condenser
Hotwell Reject Level Control Valve CNS-LCV105 is supported by spring hangers.
Thus this pipe section was very flexible and capable to accommodate expansion
in the riser.
- The suction and discharge piping of the CRD pumps within the fuel building was
Class II piping and was qualified to an operating temperature of 120EF in pipe
stress calculations. A preliminary review of the calculated maximum stresses
shows that there was sufficient margin to accommodate the effects of the
temperature transient to 350EF, and no code allowables were exceeded.
- CRD system piping inside the containment and drywell, including recirculating
pump seal purge piping, was qualified by a licensee vendor. A sample review of
the qualifying calculations showed that there was sufficient margin in the piping
thermal stress to accommodate the effects of the temperature increase in the
system for a short duration as permitted by ASME Section III, NC-3612.3.
- No evaluation was required for the high pressure feedwater heaters since their
design temperatures were higher than the transient maximum temperature of
350EF. The feedwater and condensate heater manufacturer was contacted and
concluded that a 350EF temperature in the tube side would not cause adverse
effects on the structural integrity of the heaters.
- The licensee determined that no damage to the CRD pumps occurred as a result
of the cavitation. The pump was subsequently restarted and proper operation
was observed.
c. Findings
No findings of significance were identified.
3.5 Root Cause Evaluation
a. Inspection Scope
The inspectors reviewed the licensees root cause determinations for completeness and
accuracy. Key assumptions and facts were independently verified.
b. Background
The licensee prepared two Root Cause Analyses.
C Automatic Reactor Scram on High Neutron Flux, dated October 28, 2002
C Closure of Condensate Valve CNM-FCV200, dated November 21, 2002
Generic implications were considered. Each root cause analysis presented evaluations
of previous similar occurrences at other plants and a corrective action plan.
Automatic Reactor Scram on High Neutron Flux
The licensee conducted a Kepner-Trego problem analysis and concluded that the most
likely cause for the event was a momentary bus ground or failure of a power supply.
Short-term corrective actions were completed and included the following:
- The permanent magnet generator +22 volt and the house +22 volt power
supplies were replaced.
- Field cables, wiring, circuitry, connections, and critical card edge connectors
were inspected.
- Tests with the turbine simulated to be running at 1800 rpm to determine system
response were conducted.
- A high speed data acquisition system was installed on additional points in the
turbine control system cabinet to obtain additional data if the event should recur.
There were 18 long-term corrective actions identified. Several were completed during
this inspection. The following were representative of the actions:
- Test removed power supplies, in house and at the vendors facilities. No
malfunctions were identified.
- Evaluate alternate power supply vendors and alternate configurations.
- Develop plans and inspect 22vdc bus work.
- Determine a plan for additional inspections/testing to be performed in the next
refueling outage if cause for the trip was not determined first.
- Perform additional evaluations of minimum reactor water level reached after the
scram (approximately -24 inches). This was completed satisfactorily.
- Investigate whether any offsite power line transients occurred around the time of
the event which may have contributed to the event or the plant response after
the event.
Closure of Condensate Prefilter Vessel Bypass Flow Control Valve CNM-FCV200
The licensee employed several methods during this root cause analysis. They included:
- document reviews
- personnel interviews
- field walkdowns
- barrier analysis
- TAP root
- Event and causal factor analysis
- Entergy standard root cause investigation guide
Two root causes were identified for the closure of Valve CNM-FCV200:
C Failure to meet management expectations
C Failure to follow up on identified problems
For the root cause failure to meet management expectations, seven inappropriate
actions were identified by the licensee:
1. The Valve CNM-FCV200 request was issued with only subtle indication that the
valve was other than what was normally installed in the plant.
2. The training department failed to identify the need for operator training.
3. A component engineer failed to identify different operational aspects of the valve.
4. After providing assurance to management that the valve would not go closed
during manual operation, the responsible engineering analysis was limited to
feedback provided by the vendor, rather than a comprehensive analysis.
5. Following identification of a potential nonfamiliarity with the new valve actuator,
an operator and an engineer failed to resolve the issue.
6. Following difficulty getting the valve open, the organization failed to flag that
personnel did not know how to operate the valve.
7. An operator directed a contractor, who was not a qualified representative, to lock
the valve when he opens it. At the time the valve was locked open, it was within
a tagging boundary and under control of the contractors. No procedural violation
occurred.
For the root cause failure to follow up on identified problems, there were five
inappropriate actions identified:
1. Following identification of a potential nonfamiliarity with the new valve actuator,
an operator and an engineer failed to resolve the issue.
2. An operator identified the need to learn valve operation without capturing in the
process.
3. A procedure writer identified a need to learn valve operation without capturing it
in the process.
4. An untrained operator was assigned to verify valve locked open.
5. A valve lineup change in condensate system operating Procedure SOP-0007 did
not include handwheel engage[d].
The licensee determined that, during the plant modification to install the condensate full
flow filtration system, the construction team installed Valve CNM-FCV200 in the closed
position so that it could be inserted between two flanges. After the valve was installed,
the construction team engaged the manual handwheel and opened the valve. The
intent had been to keep the handwheel engaged with the valve and locked in position.
At some point following opening, however, the handwheel was disengaged from the
valve. The licensee wrapped the handwheel and engaging lever with a chain and put a
padlock on the chain. The licensee believed that the construction workers that opened
the valve also disengaged the handwheel to prevent inadvertent manual operation.
With the handwheel and manual operator disengaged from the valve, the only thing
holding the valve in position was the weight of the valve disc and the friction of the valve
packing on the valve stem. When the scram took place on September 18, 2002,
feedwater flow increased in response to a reactor water level decrease. This increased
feedwater flow, with the handwheel disengaged from the valve, caused Valve CNM-
FCV200 to close unexpectedly.
There was only one other valve in the plant from this particular vendor with a manual
operator, and the manual operator was significantly different and smaller than the valve
used for this application. The Engineering Request for this modification did not call out
this difference and, as a result, the operations and training staff did not recognize a
difference in the operator/valve interface. As a result, training personnel did not obtain
the documents necessary to determine that valve operation would be different. Training
personnel took credit for previous training experience and assumed the new valve was
similar to other valves already installed in the plant.
The inspectors reviewed the licensees assessment of the failure to properly lock open
Valve CNM-FCV200 and the corrective action taken. The licensee appropriately used
their processes to subsequently provide training to all of the operators, and made the
necessary revision to Condensate System Operating Procedure SOP-007.
c. Findings
An apparent violation of Technical Specification 5.4.1.a was identified when the licensee
failed to lock open Condensate Prefilter Vessel Bypass Flow Control
Valve CNM-FCV200, as required by System Operating Procedure SOP-0007,
Condensate System, Revision 21. The risk significance determination was still in
progress when this report was completed. The final risk significance determination has
yet to be determined.
On September 19, 2002, at 1 a.m. following a reactor scram and loss of feedwater on
September 18, 2002, the licensee determined that Valve CNM-FCV200 had not been
properly locked open, as required by procedure. This performance deficiency occurred
on May 15, 2002, when an individual signed a valve lineup affirming Condensate
Prefilter Vessel Bypass Flow Control Valve CNM-FCV200 was locked open. It was not
properly locked open and, as a result, the feedwater flow transient resulting from a
reactor scram on September 18, 2002, caused Valve CNM-FCV200 to close
unexpectedly and cause a complete loss of feedwater. Corrective actions taken or
planned by the licensee have been entered into the licensees corrective action program
as Condition Report CR-RBS-2002-1372.
The inspectors conducted a Phase I significance determination of the performance
deficiency in accordance with Manual Chapter 0609, which led to a Phase II significance
determination. The Phase II analysis indicated that the significance was potentially
greater than very low. The Phase II determination was validated by an NRC Senior
Reactor Analyst (SRA), and a Phase III analysis was initiated. The final risk
determination was in progress at the end of this inspection.
Technical Specification 5.4.1.a requires written procedures be established,
implemented, and maintained covering the applicable procedures recommended in
Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33,
Revision 2, Appendix A, Item 4.n, requires instructions for operation of the condensate
system. System Operating Procedure SOP-0007, Condensate System, Revision 21,
required Condensate Prefilter Vessel Bypass Flow Control Valve CNM-FCV200 to be
locked open. On September 18, 2002, Valve CNM-FCV200 was not properly locked
opened. This is an apparent violation of Technical Specification 5.4.1.a
(50-458/2002-07-01). The licensee has revised Procedure SOP-0007 and trained the
operators on the proper operation Valve CNM-FCV200.
3.6 Risk Analysis
a. Inspection Scope
The inspectors reviewed the licensees risk analysis of the event, as documented by
Entergy Inter-Office Correspondence SA-02-030, Risk Impact of Feedwater System
Out of Service, dated September 27, 2002. An independent risk analysis being
conducted by NRC was in progress at the end of this inspection.
b. Background
The licensee conducted an analysis of the risk impact of the feedwater system being out
of service. The licensee calculated the incremental change in core damage frequency
at 9.3E-7 and concluded that the calculated incremental risk value with the feedwater
out of service for 4 months was nonrisk-significant. Four months was the approximate
time that Condensate Prefilter Vessel Bypass Flow Control Valve CNM-FCV200 was not
properly locked open.
The inspectors examined the significance of this issue by completing Phases 1 and 2
Significance Determination Process (SDP) worksheets in accordance with NRC Manual
Chapter 0609. The evaluations assumed that Valve CNM-FCV200 would have failed
shut during any full power reduction event, that this condition existed for approximately
4 months, that the packing resistance did not change appreciably over that duration, and
that the valve failing closed would result in a complete loss of condensate and feedwater
flow to the reactor. The existing condition was the result of a performance deficiency
(failure to properly lock open Valve CNM-FCV200) affecting the Mitigating Systems
cornerstone and represented a loss of safety function of non-Technical Specification
equipment, specifically the condensate and feedwater systems. The dominant accident
sequences identified from the Phase 2 SDP River Bend Station site-specific
risk-informed notebooks included Table 3.1, Transients (Reactor Trip), Sequence 4;
Table 3.11, Loss of 120 VDC Emergency Division I, Sequences 1, 2, and 3; and
Table 3.12, Loss of 120 VDC Emergency Division II, Sequences 1 and 2. The issue
was mitigated by the fact that all emergency core cooling systems were available. The
Phase 2 SDP evaluation determined that the issue was potentially of greater than minor
safety significance. The Phase 2 analysis was validated by a regional Senior Reactor
Analyst, and a Phase 3 analysis was initiated. The Phase 3 analysis was in progress at
the issuance of this report. Therefore, the final significance of this issue is to be
determined.
c. Findings
No findings of significance were identified.
3.7 10 CFR 50.72 Report Evaluation
a. Inspection Scope
The inspectors reviewed the 10 CFR 50.72 report submitted by the licensee to
determine whether it satisfied the subject reporting requirements.
b. Background
The reactor scram occurred at 8:25 p.m. on September 18, 2002. The NRC Operations
Center was notified at 11:41 p.m. in accordance with 10 CFR 50.72 requirements (Event
Notification 39200).
The licensee completed NRC Form 361, Reactor Plant Event Notification Worksheet,
and transmitted a copy to the NRC Operations Center, in addition to telephone
notification. Several observations were noted by the inspectors in their review of the
completed Form 361. In the description section of the form, the licensee stated The
plant systems performed as required post scram. The cause of the scram was stated
as being still under investigation. In addition, the section of the Event Notification
Worksheet asking Anything Unusual or Not Understood was checked No. The
question Did All Systems Function As Required was checked Yes.
The licensee indicated that their interpretation of the required reporting information was
to focus on the reactor/core, emergency core cooling systems, and other safety-related
systems. The condensate and feedwater systems, the CRD system, the CST, and
RWCU were not safety-related systems, and the licensee did not believe those systems
needed to be addressed as long as the reactor was shut down safely and being
maintained in a safe and shut down condition. With this view in mind, the Event
Notification stated that plant systems performed as required post scram, that nothing
unusual or not understood occurred, and that all systems functioned as required.
The inspectors reviewed the reporting requirements identified in 10 CFR 50.72 and the
guidance provided in NUREG 1022, Event Reporting Guidelines 10 CFR 50.72 and
50.73." Although no regulatory noncompliance was identified, the report to the
Headquarters Operations Center was lacking detail and information regarding the
complexity of the event and the impact the event had on nonsafety-related, although
important, systems.
b. Findings
No findings of significance were identified.
4 Exit Meeting Summary
The inspectors presented the inspection results to Paul D. Hinnenkamp, Vice President
- Operations, and other members of licensee management during an exit meeting on
November 14, 2002. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether or not any materials discussed during the
exit should be considered proprietary. No proprietary information was identified.
ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensee
B. Biggs, Coordinator, Licensing
W. Brian, Director, Engineering
D. Burnett, Superintendent, Chemistry
T. Gates, Manager, System Engineering
W. Holland, Radiation Protection Outage Coordinator
J. Leavines, Manager, Licensing
T. Lynch, Manager, Operations
J. Malara, Manager, Design Engineering
J. McGhee, Manager, Maintenance
D. Mims, General Plant Manager
P. Page, Supervisor, Health Physics
W. Spell, Senior Environmental Specialist
T. Trepanier, Assistant General Manager
W. Trudell, Manager, Corrective Action and Assessment
D. Wells, Superintendent, Radiation Protection
Operators Interviewed
David Bowman, Turbine Building Operator
Kevin Burnett, Auxiliary Control Room Operator
Forrest Drummond, Radwaste Operator/Auxiliary Control Room Operator
Ken Jelks, Control Building Operator
Brian Kelley, Operations Shift Manager
Lemar Palmer, Outside Operator
Eric Pickrell, Reactor Building Operator
Scott Shultz, Unit Operator
Erich Weinfurter, Shift Technical Advisor
Terry Wymore, Control Room Supervisor
ITEMS OPENED AND CLOSED
Opened
50-458/2002-07-01 AV Failure to properly lock open Valve CNM-FCV200
Closed
None
LIST OF ACRONYMS AND INITIALISMS USED
APRM average power range monitor
CFR Code of Federal Regulations
CR-RBS River Bend Station Condition Report
CRD control rod drive
CST condensate storage tank
HCU hydraulic control units
NEO nuclear equipment operator
NR narrow-range
NRC U.S. Nuclear Regulatory Commission
OSRC operational safety review committee
RCIC reactor core isolation cooling system
RWCU reactor water cleanup system
SDP significance determination process
SRA senior reactor analyst
WR wide-range
ATTACHMENT TO NRC INSPECTION REPORT 50-458/02-07
September 23, 2002
MEMORANDUM TO: Michael O. Miller, Resident Inspector, River Bend Station
FROM: Ken E. Brockman, Director, Division of Reactor Projects
SUBJECT: SPECIAL INSPECTION CHARTER TO EVALUATE THE RIVER BEND
STATION REACTOR TRIP WITH COMPLICATIONS
In response to the reactor trip that occurred at the River Bend Station on September 18, 2002,
and the subsequent complications due to the isolation of the condensate system and the loss of
physical integrity of the Steam Jet Air Ejector condensers, a Special Inspection Team is being
chartered. You are hereby designated as the Special Inspection Team leader. The Special
Inspection Team will consist of yourself; Mr. James Drake, Reactor Engineer; and James Dodson,
Reactor Inspector. Additional regional resources are available for consultation as needed.
A. Basis
At approximately 8:24 p.m. on September 18, 2002, the River Bend Station scrammed
from 100 percent reactor power due to a high average power range monitor flux trip. All
control rods fully inserted in the core. The cause of the reactor trip and the details
surrounding the subsequent complications in the plant response are currently under
investigation by the licensee. Preliminary evidence indicates that a failure of a control
card within the electrohydraulic control system, resulting in rapid cycling of the turbine
generator bypass valves, may have been the cause for the high power scram.
Following the scram, both steam jet air ejector condensers experienced gasket failures
on the end bells of the condensers, and all reactor feed pumps tripped on low suction
pressure. Operators responded to the condensate system gasket failure by securing all
condensate pumps and manually isolating the steam jet air ejector condensers. With
the loss of condensate to the reactor vessel, operators manually initiated the reactor
core isolation cooling system to maintain the appropriate reactor level and remove
decay heat.
Upon securing the condensate pumps, the control rod drive pumps automatically aligned
suction to the condensate storage tank. Following this transfer, alarms in the control
room indicated high differential pressure conditions on the control rod drive pumps
suction and discharge filters. Operators bypassed the filters and were able to regain
flow. The high differential pressure condition was a result of particulate in the
condensate storage tank being collected in the control rod drive system filters. The
transient causing the steam jet air ejector condenser gasket failure and loss of feed
Michael O. Miller -2-
pump suction pressure were both apparently caused by an inadvertent closure of the
condensate full flow filter bypass valve following the scram.
B. Scope
The team is expected to perform fact-finding in order to address the following:
C Develop a complete sequence of events related to the September 18, 2002,
C Review the licensees root cause determination for completeness and accuracy.
Independently verify key assumptions and facts.
C Evaluate the adequacy of the operator response to the transient (i.e., timeliness
in initiating manual reactor trip, emergency operating procedure usage, etc.).
C Evaluate the accuracy and completeness of the licensees 10 CFR 50.72 report.
C Review the adequacy of the posttrip review. Include in this review the
thoroughness of their assessment of the event and whether potential
complications on the plant systems (i.e., extent of conditions) were properly
considered, the quality and adequacy of the operability evaluations, and the
comprehensiveness and appropriateness of the immediate and long-term
corrective actions.
C Review the licensees risk analysis of the event.
C Review the event to determine whether there are any generic impact issues
related to the condensate storage tank design of venting to the atmosphere,
controls of all operated valves, foreign material exclusion, and the
appropriateness and concerns of an unmonitored release point.
C. Guidance
Inspection Procedure 93812, "Special Inspection," provides additional guidance to be
used by the Special Inspection Team. Your duties will be as described in Inspection
Procedure 93812. During performance of the Special Inspection, designated team
members are separated from their normal duties and report directly to you. The team is
to emphasize fact-finding in its review of the circumstances surrounding the event, and it
is not the responsibility of the team to examine the regulatory process. Safety concerns
identified that are not directly related to the event should be reported to the Region IV
office for appropriate action.
The Team will report to the site, conduct an entrance, and begin inspection no later than
Tuesday, September 24, 2002. Tentatively, the inspection should be completed by the
close of business on September 27, 2002, with a report documenting the results of the
inspection issued within 30 days of the completion of the inspection. While the team is
Michael O. Miller -3-
on site, you will provide daily status briefings to Region IV management, who will
coordinate with NRR to ensure that all other parties are kept informed.
This Charter may be modified should the team develop significant new information that
warrants review. Should you have any questions concerning this Charter, contact Ken
Brockman, Director, Division of Reactor Projects at (817) 860-8248.
cc:
E. Merschoff
T. Gwynn
S. Morris
W. Ruland
A. Howell
M. Webb
A. Gody
D. Graves
P. Alter