Part 21 Report - 1995-033
ACCESSION #: 9412200148
LICENSEE EVENT REPORT (LER)
FACILITY NAME: River Bend Station PAGE: 1 OF 18
DOCKET NUMBER: 05000458
TITLE: REACTOR SCRAM DUE TO SPURIOUS SIGNALS FROM UNDAMPED
ROSEMOUNT MODEL 1153 TRANSMITTERS
EVENT DATE: 09/08/94 LER #: 94-023-01 REPORT DATE: 12/12/94
OTHER FACILITIES INVOLVED: DOCKET NO: 05000
OPERATING MODE: 1 POWER LEVEL: 97
THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR
SECTION:
50.73(a)(2)(i), 50.73(a)(2)(iv), 10CFR21 SPL.RPT:T.S.3.5.1
LICENSEE CONTACT FOR THIS LER:
NAME: T.W. Gates, Supervisor-Nuclear TELEPHONE: (504) 381-4866
Licensing
COMPONENT FAILURE DESCRIPTION:
CAUSE: X SYSTEM: JC COMPONENT: LT MANUFACTURER: R370
B BN TRB D245
REPORTABLE NPRDS: Y
Y
SUPPLEMENTAL REPORT EXPECTED: NO
ABSTRACT:
On September 8, 1994 at 8:28 PM, with the reactor at 97 percent power, an
automatic reactor scram occurred due to a false high reactor water level
condition sensed on channels C and D of the reactor water level
instrumentation. During this event, the RCIC turbine tripped due to
binding of the turbine governor valve. The conditions leading to this
failure have been determined to be reportable pursuant to 10CFR21. Since
the HPCS system was manually operated during this event, this supplement
also finalizes the Special Report required by Technical Specification
3.5.1 concerning emergency core cooling system (ECCS) injections.
The cause of this event is spurious signals from undamped Rosemount model
1153 transmitters in response to process noise. The model 1153
transmitters that were in service in the reactor water level
instrumentation application have been replaced with Rosemount model
1152s. Extensive monitoring was conducted as a conservative measure
during the startup from the forced outage and continuing into power
operation for a limited period of time.
The investigation of transmitter performance revealed that the model 1153
susceptibility to process noise would not have prevented the transmitters
from functioning properly in an actual event. Equipment and radiological
issues, including reactor vessel cooldown and the Technical Specification
surveillance time limit non-compliances for radiological and chemistry
sampling were evaluated and determined not to be safety significant.
Therefore, this event did not compromise the health and safety of the
public.
END OF ABSTRACT
TEXT PAGE 2 OF 18
1.0 REPORTED CONDITION
On September 8, 1994 at 8:28 PM, with the reactor at 97 percent
power, an automatic reactor scram occurred due to a false high
reactor water level condition sensed on channels C and D of the
narrow range reactor water level instrumentation (*JC-LT*).
During the course of the event, surveillance time limits
requiring sampling of noble gases, tritium, and reactor coolant
conductivity were not met. Therefore, this event is reported
pursuant to 10CFR50.73(a)(2)(iv), to document the reactor
scram, and 10CFR50.73(a)(2)(i)(B) to document the
non-compliances with the Technical Specifications.
2.0 INVESTIGATION
2.1 Initial Conditions
The plant was at 97 percent power with power ascension in
progress to 100 percent power at a rate of 1 percent per
hour. During the previous shift, power had been reduced
to 76 percent in response to loss of a non-safety-related
chiller. No surveillance test procedures were being
performed and no maintenance was in progress in the
containment.
2.2 Event Description
On September 8, 1994, at 8:28 PM, an automatic reactor
scram occurred due to a false high reactor water level
condition, sensed by the C and D channels of the narrow
range reactor water level instrumentation. The control
room operators had no indication of the origin of the
scram at the time it occurred. There was no control room
indication of a reactor water level increase or a
feedwater level excursion. Operators initiated recovery
procedures.
By design, the reactor scram did not result in an
automatic trip of the main turbine (*TA*) or electric
generator (*TB*) or the reactor feed pumps (*SJ-P*).
During the process of completing AOP-0002,
"Turbine/Generator Trip," the unit operator (UO)
recognized that the turbine had not tripped. Recognizing
that the normal trip for this condition would be the
generator trip on reverse power, the operator attempted to
determine if a reverse power condition actually existed.
The digital generator load indicator was alternately
indicating 5 and 6 MW. The analog generator load
indicator had decreased to 0 MW, but the generator output
breakers (*TB-BKR*) had not opened on reverse power as
expected by the operator. The UO immediately reported to
the Control Room Supervisor (CRS) that the turbine was
still on-line.
TEXT PAGE 3 OF 18
Since reactor pressure was continuing to drop, the crew
felt that some action was required to take the turbine
off-line regardless of whether or not a reverse power
condition existed. After evaluating the condition, the
CRS directed the crew to manually trip the turbine,
intending to intentionally arm the generator anti-motoring
trip function, so that the generator output breakers would
automatically open.
Following the turbine trip, the main generator failed to
trip on reverse power and was manually tripped at 8:40 PM,
approximately twelve minutes after the reactor scram. The
manual trip of the generator resulted in a slow bus
transfer of non-safety related station services, as
designed.
The slow bus transfer resulted in the de-energization of
non-safety related loads as the bus supply source was
shifted from the normal station service transformers
(*XFMR*) to the preferred station service transformers
(*XFMR*) (i.e., off-site power). The de-energization of
the non-safety related buses resulted in the loss of power
to all condensate pumps (*SD-P*), all feedwater pumps
(*SJ-P*), reactor recirculation pumps (*AD-P*), and both
Reactor Protection System (RPS) (*JC-BU*) buses. Loss of
normal power to the RPS buses caused a balance of plant
isolation and main steam isolation valve (ISV) closure.
This loss of electrical power also caused a failure of the
Safety Parameter Display System (SPDS) (*IU*) and the
Emergency Response Information System (ERIS) (*IQ*)
computers.
The Reactor Core Isolation Cooling (RCIC) (*BN*) system
was manually started to provide make-up to the reactor
pressure vessel, but tripped on a mechanical overspeed
condition. The High Pressure Core Spray (HPCS) pump
(*BG-P*) was then manually started and used to raise
Reactor Pressure Vessel (RPV) level and maintain adequate
core cooling. Main steam safety-relief valves (*SB-RV*)
were cycled by the operators, as required by procedures,
to control RPV pressure. During the event, an automatic
transfer of the HPCS suction source, from the condensate
storage tank (CST) (*TK*) to the suppression pool,
occurred on high suppression pool water level. After due
consideration, the HPCS system was manually transferred
back to the CST, as directed by EOP-0001 "RPV Control."
Emergency procedures were utilized to assure control of
RPV and containment parameters. On three occasions, SRVs
automatically actuated at the relief setpoint. At 10:09
PM, the Shift Superintendent declared a Notification Of
Unusual Event (NOUE) at his discretion to mobilize
assistance to maintain the plant in a stable condition.
There were no unmonitored radiological releases and all
effluents remained within established limits.
TEXT PAGE 4 OF 18
At 11:21 PM, reactor feedwater was restored to service.
Restoration of other plant systems was proceeding in
accordance with plaint procedures. At 12:30 AM on
September 9, all Emergency Operating Procedures were
exited and the NOUE was terminated.
2.3 SEQUENCE OF EVENTS
20:28 Automatic reactor scram (Initiating signal: RPV
Water Level 8 signals to RPS channels C and D.).
Recirculation pumps transferred to slow speed
automatically.
20:38 Manual trip of main turbine.
20:40 Manual trip of Main Generator output breakers.
Normal (13.8 kV) station service buses NPS-SWG1A
and NPS-SWG1B "slow transfer" from the normal
station service transformers to the preferred
station service transformers. Non-safety
related plant equipment was deenergized as
follows:
- Condensate and feedwater pumps (loss of normal
high pressure makeup to the reactor vessel).
- RPS A and B (results in a full MSIV and BOP
isolation). (Normal power supply to safety
related RPS busses is via non-safety related
motor generator sets. RPS fails safe on loss of
power.)
- Reactor recirculation pumps.
- Circulating water pumps A & C.
- Instrument Air Compressor B
- One Normal Service Water pump.
TEXT PAGE 5 OF 18
- Emergency Response Information System (ERIS)
computer.
- Safety Parameter Display System (SPDS) computer.
20:41 RPS A&B manually transferred to alternate
supply.
20:44 Operators attempted to provide coolant makeup
water to the reactor via the Reactor Core
Isolation Cooling (RCIC) System. The RCIC
turbine trips on overspeed and cannot be reset
from the Main Control Room.
Safety Relief Valves used to manually control
reactor pressure.
20:49 Restored Drywell Cooling.
20:57 High Pressure Core Spray (HPCS) pump started
manually to provide coolant makeup water to the
reactor. Level at 0" (wide range) and lowering
(Note: Normal operating water level is +35
inches, auto-initiation setpoint is -43 inches,
and the top of the active fuel is -162 inches).
21:18 Opened B21*MOVF019 (*SB-20*), Main Steam Drain
Outboard Isolation Valve, establishing a vent
path from the reactor vessel to the main
condenser to assist in reactor pressure control.
21:20 Restored Turbine Building Chillers (*NM-CHU*) to
service.
21:27 Started Residual Heat Removal System in
Suppression Pool Cooling Mode.
21:38 Valve 1CNS-MOV112 (*SD-20*) could not be opened
during condensate fill and venting
21:56 Reset Reactor Scram.
22:03 Re-inserted one-half scram on Division I to
comply with Technical Specification 3.3.1,
"Reactor Protection System Instrumentation.
22:09 Notification of Unusual Event declared.
TEXT PAGE 6 OF 18
22:20 Restarted Condensate Pump CNM-P1A (*SD-P*).
23:21 Started Main Feed Pump A (*SJ-P*).
23:51 Re-opened Main Steam Isolation Valves (*SB-ISV*)
after chillers reduced area temperatures below
the isolation setpoint.
00:17 Secured HPCS. Reactor water level maintained
with main feed pump.
00:30 Exited Emergency Operating Procedures and
terminated Notice of Unusual Event.
2.4 Turbine Response
As designed the reactor scram did not result in an
automatic trip of the main turbine. Instead, operators
manually tripped the turbine at 2238, ten minutes after
the scram. Operators manually tripped the generator
breakers at 2040. The manual trip of the generator
resulted in a slow bus transfer of nonsafety-related
station services, as designed.
The feedwater control system reactor vessel level
transmitters are used to sense reactor water level and
trip the main turbine and feedwater pumps on high water
level. The nuclear boiler instrumentation reactor vessel
level transmitters sense reactor water level and trip the
reactor on high water level. In this case, since two
level transmitters in the nuclear boiler instrumentation
system sensed the high reactor water level, an automatic
scram resulted. However, since only one level transmitter
in the feedwater control system sensed a high reactor
water level, the main turbine and feedwater pumps did not
automatically trip. Process computer data indicate that
the scram was caused by level 8 signals from narrow range
reactor water level instrumentation channels C and D.
ERIS data indicates that narrow range feedwater level
transmitter 4C reached the level 8 setpoint and that 4A
and 4B did not. The two-out-of-three logic required to
produce a turbine trip was not satisfied since only one of
three channels reached the level 8 setpoint. Therefore,
with regard to the reactor vessel high water level
signals, the main turbine trip logic functioned as
designed.
TEXT PAGE 7 OF 18
2.5 Generator Response
By design, the reactor scram did not result in an
automatic trip of the main turbine or generator.
Operators inserted a manual trip of the turbine
approximately 10 minutes after the reactor trip. The
manual turbine trip resulted in turbine stop valve
closure. Following the turbine trip, the main generator
did not trip on reverse power. Normally, the generator
output breakers are expected to open upon reverse power to
the generator following a reactor scram. The generator
output breakers were manually opened at 2040,
approximately twelve minutes after the reactor scram,
since the reverse power trip function had not initiated.
The manual trip of the generator resulted in a slow bus
transfer of non-safety related station services, as
designed.
The investigation revealed that the failure of the reverse
power trip to initiate as expected was due to common mode
calibration inaccuracies in the reverse power relays, 32G
and 32G1, combined with a very low power factor (i.e.,
high reactive load). The generator was operating under a
large reactive load at a very low power factor which
resulted in an extreme phase angle at the relay. The
relays were found to have been misadjusted by 2 degrees
for relay 32G1 and 4 degrees for relay 32G. This combined
with inherent relay inaccuracy, resulted in the failure of
the relays to actuate because the generator was operating
within the error band of the relay trip point. This is
the root cause of the failure of the generator output
breakers to open on reverse power.
2.6 Transfer to Offsite Power
During a main turbine trip, the main generator should trip
after reverse power occurs. Two automatic transfer
schemes ("fast" and "slow") are provided to transfer
station electrical loads from the main generator to
off-site power. In accordance with the system design, a
slow, instead of a fast, transfer occurred during this
event. A slow bus transfer provides a protective function
for station equipment and differs from a fast transfer in
that it results in the tripping of all bus loads. Manual
restoration of those loads is required following a slow
transfer.
The slow transfer of 1NPS-SWG1A and 1B was not anticipated
by Operations personnel, but the evaluation revealed that
it occurred correctly. Since the generator output
breakers were manually tripped prior to the reverse power
trip occurring, relay logic blocked the fast transfer
TEXT PAGE 8 OF 18
from occurring. Thus, the prerequisites for the fast
transfer were not met. With regard to the function of the
fast/slow transfer circuits, no corrective action is
required. However, the indications available to the
operators could be improved to allow evaluation of the
reverse power condition and support operators' decision
when to trip the generator output breakers.
2.7 RCIC Turbine Trip
On September 8, 1994, subsequent to the manual opening of
the generator output breakers after the scram, the slow
transfer to the preferred offsite power resulted in a loss
of normal feedwater.
Upon the loss of feedwater, the operators initiated
actions to manually start the RCIC turbine in anticipation
that it may be needed to help control reactor vessel
coolant level and reactor pressure. The RCIC turbine
tripped when steam was admitted to the turbine. The
operator could not reset the RCIC turbine from the control
room and the indications that he had were consistent with
a mechanical overspeed trip which by design must be reset
locally. Subsequent field investigation verified that the
mechanical overspeed trip device was actuated and had
caused the RCIC turbine to trip. The cause of the RCIC
pump turbine overspeed was found to be binding of the
turbine governor valve due to accelerated corrosion of the
valve stem. The root cause of the accelerated corrosion
is the combined effect of problems with the surface
treatment of the governor valve stem, improper washer
material in the valve gland area and characteristics of
the carbon spacers in the gland area (i.e., porosity and
the presence of sulfur). The investigation revealed that
the surface treatment of the stem was non-uniform, with
variations in thickness and defects present. The sulfur
in the carbon spacers can leach out in a moist environment
and create an electrolytic solution to support galvanic
corrosion. The improper washer material can also promote
galvanic corrosion. EOI has determined that this
condition is reportable pursuant to 10CFR21. The stem,
washers and spacers were manufactured by Terry Steam
Turbine Company. Dresser-Rand Steam Turbines is the
current vendor. The stem, spacers, and washers were new
equipment installed during refueling outage 5.
The washers supplied in 1984 were installed during
refueling outage 5. One of these washers was selected for
analysis which revealed that it was made out of 300 series
stainless steel instead of 410 stainless. Another group
of washers was supplied in 1985. Of the 21 washers in the
1985 order, 20 of them were 300 series stainless steel,
and one was 400 series stainless steel. The part number
of the washers supplied in 1984 and 1985 was the same,
P/N#54846.
TEXT PAGE 9 OF 18
2.8 MOV Issues
The post-scram investigation revealed that SWP*MOV40A
(*BS-20*) failed during midstroke due to a short in one of
its control cables. The safety function of 1SWP*MOV40A is
to open during a standby service water initiation. Valve
1SW*PMOV40A was approximately 30% open when it failed
during mid-stroke. A generic design vulnerability
applicable only to Limitorque SMB-00 actuators was
identified and measures have been implemented to prevent
recurrence.
In addition, several non-safety power operated valves
(MOVs and SOVs) also failed to respond as expected. These
valves were in balance-of-plant (BOP) systems and had no
impact on the ability to safely shut down the reactor and
maintain it in a safe shutdown condition.
The root cause for the problems associated with the
non-safety related valves is the lack of a preventive
maintenance program.
2.9 Event Response Information System and Safety Parameter
Display System
During the plant transient, the normal power supply to the
Safety Parameter Display System (SPDS), transient analysis
computers which is part of the Emergency Response
Information System (ERIS) and Digital Radiation Monitoring
System (DRMS) was lost. Upon discovering that the
computer systems were inoperable, the system engineer
attempted to archive any available data, then restarted
the computer systems and restored them to their normal
display and data collection functions. The cause of the
failure was that the power inverter (*INVT*), 1BYS-INV06,
which supplies power to these systems, was unavailable.
The inverter was in bypass for maintenance.
TEXT PAGE 10 OF 18
2.10 Reactor Vessel Stratification, Cooldown, Pressure/
Temperature Limits
The investigation included evaluation of reactor vessel
stratification, cooldown, and the effect on pressure and
temperature limits. The cooldown rate exceeded the
Technical Specification limit of 100 degrees F per hour.
The evaluations to address these issues revealed that in
each case, the thermal transient effects were bounded by
previous analyses, including the thermal transient effects
due to the cooldown rate. Usage factors for the HPCS
nozzle, piping, and recirculation system piping and
components were determined to be within the design values.
The total accumulated actuation cycles for the HPCS nozzle
was calculated to be 15. The circumstances that led to
the initiation of the HPCS system are described in Section
2.2, Event Description. This report provides the
information required for the Special Report pursuant to
T. S.3.5.1.
2.11 Noble Gas and Tritium Samples
After the reactor scram, Chemistry did not obtain samples
of main plant noble gas and tritium within one hour even
though the dose equivalent I-131 concentration exceeded
three times normal. The tritium and noble gas samples
were taken approximately one hour late.
Following the event, an investigation of the TS
requirements was conducted. This investigation found that
the TS wording changed prior to issue of the initial low
power operating license to add the one hour time limit for
sampling tritium and noble gases following thermal
transients. The change created a time requirement that is
inconsistent with the other licensing basis documents
reviewed and the TS from the other operating boiling water
reactor (BWR) 6 plants in the United States. The one hour
limit following reactor thermal transients cannot be
fulfilled following a reactor scram due to time
requirements for sampling and analysis. While the
surveillance was not performed within one hour, the
requirements of the action statement of T.S.3.11.2.1 were
not violated. The dose rate due to radioactive effluents
was always within the TS limits.
TEXT PAGE 11 OF 18
The missed sample was a recurrence of a previous event,
documented in LER 87-013 and Condition Report (CR) 87-962,
in which the same TS samples were missed following a
reactor scram. In that event, the root cause was failure
of control room personnel to notify chemistry personnel
that the plant had scrammed. The corrective actions for
that event included adjusting the volume on the plant
paging system in the chemistry lab and investigating a
possible change to the TS. The response from that
investigation stated that there was inadequate
justification to request a change. The corrective actions
for LER 87-013 were not sufficient to prevent recurrence
and are considered part of the cause of the missed
chemistry sample.
Contributing factors included absence of the sample pump
at 1RMS*RE125, and delays entering the Auxiliary Building
due to operation of the SGTS.
2.12 Conductivity Sample
Following the reactor scram, chemistry failed to obtain
the reactor coolant conductivity analysis once per every
four hours after a loss of continuous conductivity
recording. Prior to the reactor scram only the Reactor
Water Cleanup System (*CE*) (WCS) influent conductivity
monitor was operable in accordance with TS 3/4.4.4. The
recorder in the control room for the reactor recirculation
conductivity monitor had been determined to be inoperable
earlier that day by the on-shift chemistry technician.
While obtaining the dose equivalent I-131 samples at 0206
of that same night the on-shift chemistry technician
observed flow from the WCS sample line, although at a
reduced rate. Communications with control room personnel
at 0230 informed him that the WCS pumps had tripped
following the scram; however, he was unaware that
containment isolation valves for this system had closed
and that the reactor recirculation conductivity recorder
was not operable.
The root cause of the missed conductivity sample was
determined to be the lack of timely communications between
control room and chemistry personnel regarding status of
the reactor water cleanup system. Chemistry personnel
were also unaware that the reactor recirculation
conductivity recorder was inoperable.
TEXT PAGE 12 OF 18
2.13 Radiological Impact
Two radiological transients occurred subsequent to the
scram. A transient in the turbine building ventilation
system resulted in a build-up of noble gases in the
turbine building. After the ventilation system was
restored to service, noble gas levels rapidly decreased to
normal. In addition, a radiological transient in the
containment building occurred subsequent to safety relief
valve actuation which resulted in an increase in
containment building activity. An evaluation and off-site
dose calculation was performed prior to initiating a
reactor building purge. As a result, radiological
conditions in containment stabilized and returned to
normal.
The contribution of these transients to the off-site dose
was below TS and 10CFR off-site radiological limits. A
review of the events determined that the radiological
procedures utilized during the event were adequate for
transient events. The review also concluded that
communication and staffing (including augmented staffing)
were adequate to perform the required RP activities. No
corrective actions are required.
3.0 Root Cause Evaluation
All available data associated with reactor operation that
could potentially affect reactor water level
instrumentation was reviewed and all potential failure
modes were identified using event and causal factors
charts, Kepner-Tregoe (K-T) analysis, and failure mode
analysis.
Two major paths were considered in the investigation of
the level 8 signal. One of these paths considered an
actual change in reactor vessel level. The other path
considered was an indicated level transient. The analysis
of the events in the indicated level transient path led to
the conclusion that the probable cause of the event was
process noise resulting in a large amplitude trip signal
on the RPS C and D level transmitters and feedwater level
transmitter C. The investigation included
in-vessel-visual-inspections (IVVI). The information
gained from these inspections was evaluated and resulted
in ruling out many theorized causes.
The cause of this event is spurious signals from undamped
Rosemount model 1153 transmitters in response to process
noise. All three of these transmitters are Rosemount
model 1153 transmitters. Rosemount model 1152
transmitters were used for RPS channels A and B and these
channels did not initiate a level 8 signal. The
investigation revealed that all three of the model 1153
transmitters had been installed as replacements for
Rosemount model 1152s.
TEXT PAGE 13 OF 18
The three affected 1153s had minimum damping; two were set
at minimum damping and one had no damping card installed.
The investigation of the damping issue revealed that the
time response testing requirements for the transmitters
results in minimal damping.
The investigation also revealed deficiencies in the
maintenance of these transmitters. While these issues did
not contribute to the root cause, they are being
addressed. A damping card was not installed on RPS level
channel C and feedwater level transmitter C was undamped.
However, if the damping card had been installed on RPS
channel C, it would probably have been set to minimum
damping, and the scram would still have occurred. The
minimization of damping was permissible given the design
guidance available to maintenance personnel; however,
improvements in the areas of generic modification guidance
and maintenance planning win be evaluated.
Based on testing that was performed, engineering personnel
concluded that the transmitters would have functioned
properly during an actual level transient. The
investigation also revealed that no electrical or
significant hydraulic transient existed.
4.0 Corrective Action
As a result of the September 8 event, Entergy Operations
promptly formed a "Significant Event Response Team" (SERT)
to investigate the event and develop appropriate
corrective actions. The SERT team was authorized by the
plant manager and its membership included a high level of
management from multiple departments. The team's function
was to investigate root cause and provide corrective
actions for all deficiencies identified during the
September 8 event. Management oversight was provided by
members of the executive staff led by John McGaha, Vice
President-Operations.
The event response organization was supplemented by
offsite Entergy Operations personnel and nuclear industry
expertise, including General Electric and root cause
analysis experts from Failure Prevention International
(FPI). An assist team from the Institute of Nuclear Power
Operations (INPO) was also onsite to investigate the
event.
TEXT PAGE 14 OF 18
Review of selected condition reports associated with this
event was conducted by the Corrective Action Review Board
(CARB). This board is comprised of the direct reports to
the Vice President - Operations, the General Manager -
Plant Operations and his direct reports, Manager, Nuclear
Safety and Assessment, and the QA Manager. This review is
conducted to assure proper root cause determination and
development of effective corrective actions for events
determined to be significant by the criteria of River Bend
Nuclear Procedure RBNP-030, "Initiation and Processing of
Condition Reports. "
The sections below document the current status of the
primary corrective actions for the issues identified in
this event.
4.1 Rosemount Model 1153 Transmitters and Backfill System
o The Rosemount 1153 transmitters that were in service
in the reactor water level instrumentation and
feedwater level applications have been replaced with
Rosemount model 1152s which do not have the same
sensitivity to process noise.
o A verification of all aspects of the configuration of
all safety related Rosemount transmitters was
performed prior to startup. Plant walkdowns were
used to baseline the configuration and verify the
transmitters based on model number, required damping,
and mounting.
o Time response testing methodology will be reviewed
with a focus on industry practices.
o Generic modifications for changeouts of equipment and
the maintenance planning process will be evaluated.
o To address a potential vulnerability identified by
the investigation, the backfill system has been
modified to relocate the orifices downstream of the
check valves.
TEXT PAGE 15 OF 18
o EOI developed a monitoring program to track important
process parameters during the startup from the forced
outage and following this for a limited time during
power operation. The objective of this program was
to identify operational anomalies to minimize the
risk of recurrence, as a conservative measure. The
monitoring program was completed with no unusual
events or anomalies detected.
4.2 Operations
With respect to operator performance, several lines of
investigation are being pursued as a result of this event.
The goal of this investigation is to identify areas where
enhancements will result in improved operator performance.
Specific areas of interest include:
o Event Reconstruction. In the interest of obtaining a
complete, clear understanding of a significant plant
event, Operators should be debriefed as soon as
possible. Although individual debriefings were
conducted by operations management, a full crew
debriefing was not conducted in a timely manner. The
delay in conducting a full crew debriefing will be
evaluated and appropriate guidance developed
regarding the timeliness of these interviews.
o Procedures. The AOP for turbine and generator trip
contains requirements related to verification of
generator trip. This procedure, AOP-0002, has been
revised to improve the procedural guidance for
positive verification of reverse power conditions.
Procedure Enhancements identified during review
included revision of AOP-0001, "Reactor Scram," to
improve the turbine trip verification, and SOP-0080,
"Turbine Generator Operation," to provide a caution
on turbine/generator motoring.
o Training. The crew's understanding of the issue of
the fast/slow transfer of station loads was not clear
and the simulator modeling and associated training
was incorrect. Simulator modifications have been
implemented to correct deficiencies. Training has
been provided during the last licensed operator
requalification module concerning the procedure
changes to AOP -0001 and AOP-0002. In addition, a
simulator scenario has been developed which requires
operator action to manually open the generator output
breakers following failure of the generator reverse
power/anti-motoring trips.
TEXT PAGE 16 OF 18
4.3 Generator Response
Both reverse power relays were recalibrated to maintain
the phase angle of each at its setpoint with the tightest
tolerance attainable. Improvements in the applicable
maintenance procedure, MCP-1005, are being considered.
4.4 Transfer to Offsite Power
To improve the indications available to the operators for
evaluation of the reverse power condition and determining
when to trip the generator output breakers, the SPDS
system graphic display in the control room has been
upgraded to indicate negative megawatts. This display
will allow operators to monitor reverse power conditions.
4.5 RCIC Turbine Trip
The governor valve stem has been replaced with a new stem
having an aluminized coating for increased corrosion
resistance. Washers of the proper material have been
installed, and periodic monitoring of the stem resistance
is being performed, pending further evaluation of
monitoring data.
4.6 Motor Qperated Valves
Corrective actions being implemented for SWP*MOV40A are:
o The damaged wire and lug were replaced and
repositioned to avoid rubbing.
o Nine (9) additional SMB-00 actuators were identified
and have been inspected for similar lug
configurations on contacts LS-1 and LS-9. No
additional problems were identified.
o Maintenance procedures will be revised to include
guidance on proper positioning of wires landed on
contacts LS-1 and LS-9.
TEXT PAGE 17 OF 18
River Bend Station is implementing a preventive
maintenance program action plan with a focus on
reliability centered maintenance (RCM), and prioritization
by Maintenance Rule system and component importance. The
predictive and preventive maintenance tasks for non-safety
related valves will be addressed in the context of this
program.
4.7 ERIS and SPDS
The services building power inverter, 1BYS-INV06 has been
restored to service. Replacement of the ERIS system is
being evaluated. This evaluation will also address
concerns with the ease of retrieval of historical data
from past events.
4.8 Noble Gas and Tritium Sampling
To prevent recurrence, Technical Specifications
3/4.11.2.1.2, Table 4.11.2.1.2-1 will be revised to remove
the one hour sampling and analysis requirement for noble
gases, and the tritium sampling requirements. License
Amendment Request (LAR) 94-11, "Gaseous Effluents, " was
submitted to the NRC on October 4, 1994 (RBG-40919).
Other corrective actions include changes to operations
announcement practices, revision of SOP-0043 to provide
safe access to the auxiliary building when the standby gas
treatment system is in operation, and ensuring the proper
equipment is dedicated and staged for ready access near
1RMS*RE125. These actions have been implemented.
4.9 Conductivity Sample
Chemistry Procedure, CSP-0101, has been revised to
incorporate a shutdown enclosure in the procedure.
Corrective actions have also been implemented to address
timeliness of required chemistry actions and assure that
chemistry personnel coming on-shift will be cognizant of
current equipment status.
5.0 Safety Assessment
Based on testing that was performed, engineering personnel
concluded that the transmitters would have functioned
properly during an actual level transient. The
investigation also revealed that no electrical or
significant hydraulic transient existed.
TEXT PAGE 18 OF 18
The evaluation of other equipment related issues revealed
the following:
o The reactor scram did not result in an automatic trip
of the main turbine or electric generator, by design.
The "two out of three" logic required to produce an
automatic turbine trip was not satisfied since only
one of three feedwater level transmitter channels
provided a level 8 signal.
o The slow transfer was also determined to have
occurred as designed. The conditions required for a
fast transfer to occur were not satisfied.
o The HPCS system was available throughout this event
and was operated manually to provide makeup to the
reactor vessel following the trip of the RCIC
turbine.
o The reactor vessel cooldown rate has been evaluated
and the thermal transient effects were bounded by
previous analyses. Other thermal effects, such as
thermal stratification, were also shown to be bounded
by previous analyses.
o The contribution to offsite dose as a result of this
event was analyzed and determined to be below
Technical Specification limits and other regulatory
limits.
Operator actions were correctly prioritized throughout the
event. While they did encounter unexpected responses from
some plant equipment, the operators effectively utilized
the available resources to diagnose and respond to reactor
and plant system indications. They focused on reactor
safety and took actions to manually control reactor water
level and pressure. Based on the above considerations,
EOI concludes that this event did not compromise the
health and safety of the public.
Note: Energy Industry Identification System (EIIS) Codes are
identified in the text as (*XX*).
ATTACHMENT TO 9412200148 PAGE 1 OF 2
Entergy Operations, Inc.
River Bend Station
5485 U.S. Highway 61
ENTERGY P.O. Box 220
St. Francisville, LA 7075
(504) 336-6225
FAX (504) 635-5068
5485 U.S. Highway 61
JAMES J. FISICARO
Director
Nuclear Safety
December 12, 1994
U. S. Nuclear Regulatory Commission
Document Control Desk
Mail Stop P1-37
Washington, DC 20555
Subject: River Bend Station - Unit 1
Docket No. 50-458
License No. NPF-47
Licensee Event Report 50-458/94-023-01
File No.: G9.5, G9.25.1.3
RBG-41099
RBF1-94-0129
Gentlemen:
In accordance with 10CFR50.73, enclosed is the subject report.
Sincerely,
JJF/jr
enclosure
ATTACHMENT TO 9412200148 PAGE 2 OF 2
Licensee Event Report 50-458/94-023-01
December 12, 1994
RBG-41099
RBF1-94-0129
Page 2 of 2
cc: U.S. Nuclear Regulatory Commission
611 Ryan Plaza Drive, Suite 400
Arlington, TX 76011
NRC Sr. Resident Inspector
P.O. Box 1051
St. Francisville, LA 70775
INPO Records Center
700 Galleria Parkway
Atlanta, GA 30339-3064
Mr. C.R. Oberg
Public Utility Commission of Texas
7800 Shoal Creek Blvd., Suite 400 North
Austin, TX 78757
Louisiana Department of Environmental Quality
Radiation Protection Division
P.O. Box 82135
Baton Rouge, LA 70884-2135
ATTN: Administrator
*** END OF DOCUMENT ***
Page Last Reviewed/Updated Tuesday, March 09, 2021