United States Nuclear Regulatory Commission - Protecting People and the Environment

ACCESSION #:  9412200148
                       LICENSEE EVENT REPORT (LER)

FACILITY NAME: River Bend Station                         PAGE: 1 OF 18

DOCKET NUMBER:  05000458


EVENT DATE:  09/08/94   LER #:  94-023-01   REPORT DATE:  12/12/94

OTHER FACILITIES INVOLVED:                          DOCKET NO:  05000


50.73(a)(2)(i), 50.73(a)(2)(iv), 10CFR21 SPL.RPT:T.S.3.5.1

NAME: T.W. Gates, Supervisor-Nuclear        TELEPHONE:  (504) 381-4866

       B             BN               TRB                 D245



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


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          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.


2.1            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

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

               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.

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               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

               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*)

               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.

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               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

               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

               -         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

               -         Reactor recirculation pumps.

               -         Circulating water pumps A & C.

               -         Instrument Air Compressor B

               -         One Normal Service Water pump.

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               -         Emergency Response Information System (ERIS)

               -         Safety Parameter Display System (SPDS) computer.

               20:41     RPS A&B manually transferred to alternate

               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

               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.

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               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

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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

               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

               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

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               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,

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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

               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.

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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. were
               not violated.  The dose rate due to radioactive effluents
               was always within the TS limits.

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               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.

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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

               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

               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.

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               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

               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

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               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.

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               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

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/, Table 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

               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

               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
                                   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



In accordance with 10CFR50.73, enclosed is the subject report.



ATTACHMENT TO 9412200148                                    PAGE 2 OF 2

Licensee Event Report 50-458/94-023-01
December 12, 1994
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


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