United States Nuclear Regulatory Commission - Protecting People and the Environment


ACCESSION #:  9705050262

                       LICENSEE EVENT REPORT (LER)



FACILITY NAME:  Beaver Valley Power Station Unit 1        PAGE: 1 OF 8



DOCKET NUMBER:  05000334



TITLE:  Inadvertent Operation of 345 KV Bus Backup Timer Relay

        Results in Dual Unit Reactor Trips



EVENT DATE:  03/19/97   LER #:  97-005-01   REPORT DATE:  05/02/97



OTHER FACILITIES INVOLVED: Beaver Valley Power      DOCKET NO:  05000412

                           Station Unit 2



OPERATING MODE:  1   POWER LEVEL:  100%



THIS REPORT IS SUBMITTED PURSUANT TO THE REQUIREMENTS OF 10 CFR

SECTION:

50.73(a)(2)(i), 50.73(a)(2)(iv), OTHER: 10CFR Part 21



LICENSEE CONTACT FOR THIS LER:

NAME:  R.L. LeGrand, Vice President Nuclear TELEPHONE:  (412) 393-7622

       Operations and Plant Manager



COMPONENT FAILURE DESCRIPTION:

CAUSE:  B   SYSTEM:  BA   COMPONENT:  V    MANUFACTURER:  E334

REPORTABLE NPRDS:  Y



SUPPLEMENTAL REPORT EXPECTED:  NO



ABSTRACT:



On March 19, 1997, at approximately 0606 hours, while operating at 100%

nominal power, Beaver Valley Power Station (BVPS) Units 1 and 2

experienced simultaneous reactor trips due to the opening of the output

breakers for both units.  The event was initiated by an inadvertent

operation of the Bus Backup Timer relay on the #3-345 KV bus in response

to a phase to ground fault which occurred on the Ohio Edison system's

Mansfield-Hoytsdale 345 KV line.  An Emergency Notification System (ENS)

report was made pursuant to the requirements of 10CFR50.72(b)(2)(ii) at

0922 hours on March 19, 1997.  This event is also reportable pursuant to

the requirements of 10CFR50.73(a)(2)(i) and 10CFR50.73(a)(2)(iv).



Operations responded to the dual unit trip by entering the appropriate

plant Emergency Operating Procedures (EOPs).  Stabilization of Unit 1 was

completed at approximately 0608 hours on March 19, 1997, with the

mitigating equipment operating in the expected manner to control the

transient.  Unit 1 Emergency Diesel Generator (EDG) EE-EG-1 started due

to momentary undervoltage on 4 KV emergency bus AE, but was not required

to load, since bus AE did not lose power.  Unit 1 EDG EE-EG-2 did not

start and was conservatively declared inoperable as of 0606 hours on

March 19, 1997, until testing was completed which demonstrated that the

undervoltage condition on bus DF was of insufficient duration to start

EDG EE-EG-2.  Both Unit 1 EDGs functioned as designed.



Stabilization of Unit 2 was completed at approximately 0610 hours on

March 19, 1997, with the mitigating equipment operating in the expected

manner to control the transient with the exception of "B" Steam Generator

Auxiliary Feedwater (AFW) flow indicating lower than normal.  Subsequent

investigation indicated that this was due to the concurrent event failure

of a check valve in the "B" AFW injection header.  The "B" AFW injection

header was declared inoperable at 1206 hours on March 19, 1997, and,

pursuant to the requirements of Technical Specifications (TS), Unit 2

commenced a boration and cooldown towards Mode 4 at 1210 hours on March

19, 1997.  An update to the ENS notification pursuant to the requirements

of 10CFR50.72(b)(1)(i)(A) was made at 1302 hours.  Unit 2 entered Mode 4

at 1731 hours on March 19, 1997.  An evaluation of the AFW check valve

failure pursuant to the requirements of 10CFR21 was completed April 24,

1997.  ENS Notification of 10CFR21 reportability was made at 1403 hours.



The root cause of the dual unit trip event was inadequate implementation

of design specifications and design review which resulted in incorrect

wiring between the Unit 2 Static Breaker Failure Unit Relay and its

associated Static Relay Unit Bus Backup Timer.  Both units were safely

shut down in accordance with the applicable procedures.  There were no

implications to the health and safety of the public as a result of this

event.



END OF ABSTRACT



TEXT                                                          PAGE 2 OF 8



PLANT AND SYSTEM IDENTIFICATION



Westinghouse Pressurized Water Reactor (PWR)



345 KV Switchyard Static Relay Unit (SRU) Bus Backup Timer Relay 62-J143

{FK/62/A500}



345 KV Switchyard Static Breaker Failure Unit (SBFU) Relay 50-J140

{FK/50/A500}



AFW to Steam Generator Nozzle Check Valves 2FWE-99, 2FWE-100, and 2FWE-10

1, Enertech Type DRV-Z {BA/V/E334}



Unit 1 Emergency Diesel Generator (EDG) EDG EG-EE-1 {EK/GEN/E147}



Unit 1 Emergency Diesel Generator (EDG) EDG EG-EE-2 {EK/GEN/E147}



*    Energy Industry Identification System (EIIS), component function

     identifier, and manufacturer codes appear in the text as

     (SS/CCC/MMMM).



CONDITION PRIOR TO OCCURRENCE



Unit 1: Mode 1, 100% Reactor Power

Unit 2: Mode 1, 100% Reactor Power



DESCRIPTION OF EVENT



On March 19, 1997, at approximately 0606 hours, while operating at 100%

nominal power, Beaver Valley Power Station (BVPS) Units 1 and 2

experienced simultaneous reactor trips due to the opening of the output

breakers for both units.  The event was initiated by an inadvertent

operation of the Bus Backup Timer relay 62-J143 {FK/62/A500} on the

#3-345 KV bus.  A phase to ground fault occurred on the Ohio Edison

system's Mansfield-Hoytsdale 345 KV line which was detected by the BVPS

switchyard protection equipment, and began shedding various loads through

the opening of line breakers.  An Emergency Notification System (ENS)

report was made pursuant to the requirements of 10CFR50.72(b)(2)(ii) at

0922 hours on March 19, 1997.



Operations responded to the dual unit trip by entering the appropriate

plant Emergency Operating Procedures (EOPs).  Stabilization of Unit I was

completed at approximately 0608 hours on March 19, 1997, with the

mitigating equipment operating in the expected manner to control the

transient.  Unit 1 Emergency Diesel Generator (EDG) EE-EG-1 {EK/GEN/E147}

started due to momentary undervoltage on 4 KV emergency bus AE, but was

not required to load, since bus AE did not lose power.  Unit 1 EDG

EE-EG-2 {EK/GEN/E147} did not start and was conservatively declared

inoperable as of 0606 hours on March 19, 1997, until testing was

completed which demonstrated that the undervoltage condition on bus DF

was of insufficient duration to start EDG EE-EG-2.  Both Unit 1 EDGs

functioned as designed.



Stabilization of Unit 2 was completed at approximately 0610 hours on

March 19, 1997, with the mitigating equipment operating in the expected

manner to control the transient with the exception of "B" Steam Generator

Auxiliary Feedwater (AFW) flow indicating lower than normal.  Subsequent

investigation indicated that this was due to the concurrent event failure

of check valve 2FWE-100 {BA/V/E334} in the "B" AFW injection header.  A

later inspection of the check valve revealed that the seat ring had moved

out of its design position, partially blocking the flow stream.  The "B"

AFW injection header was declared inoperable pursuant to the requirements

of Technical Specification (TS) Limiting Condition for Operation (LCO)

3.7.1.2.b at 1206 hours on March 19.  1997.  The action statement for TS

LCO 3.7.1.2.b requires that the plant be in at least hot standby (Mode 3)

within 6 hours and in hot shutdown (Mode 4) within the following six

hours.  Hence Unit 2 commenced a boration and cooldown towards Mode 4 at

1210 hours on March 19, 1997.  An update to the ENS notification was made

at 1302 hours.  Unit 2 entered Mode 4 at 1731 hours on March 19, 1997.



TEXT                                                          PAGE 3 OF 8



CAUSE OF EVENT



The root cause of the dual unit trip event was inadequate implementation

of design specifications and design review which resulted in incorrect

wiring between the Unit 2 Static Breaker Failure Unit Relay and its

associated Static Relay Unit Bus Backup Timer.



Evaluation of the Unit 1 Emergency Diesel Generator (EDG) operation

during the event demonstrated that both diesel generators functioned as

designed.  Due to design differences in autostart circuitry and the

difference in duration of the undervoltage signals on their respective

emergency buses, EDG #1 autostarted and EDG #2 was not required to start.



The root cause of the reduced AFW flow in the "B" injection header was a

thermal gradient across the valve body experienced as relatively cold AFW

was injected into the system through the hot valve.  This allowed the

seat ring to lose its interference fit within the valve body bore and

move into the flow stream, partially blocking AFW flow.



ANALYSIS OF EVENT



Dual Unit Trip



On March 19, 1997, the Vice-President of Nuclear Operations assigned an

Event Review Team (ERT) for each unit.  Team members were assigned from

various departments to collect and review information and thoroughly

investigate this event in accordance with Site procedures.  The Nuclear

Engineering Department (NED), with the support of the Relay Group,

evaluated the cause of the 345 KV system disturbance and performed the

associated root cause analysis.  The following dual unit trip analysis

information was provided by the ERT Report.



Prior to the event on March 19, 1997, BVPS Units 1 and 2 were operating

at 100% nominal power supplying power to the 345 KV electrical grid.  The

outputs of 345 KV buses #3 and #4 were connected to buses #5 and #6,

respectively, which is the normal configuration.  The primary line

protection for the Mansfield Substation that includes the Mansfield-

Hoytdale 345 KV line was out of service due to a communications

difficulty.  The substation's secondary line protection was in service.



At 0606 hours, a phase to ground fault occurred on the Ohio Edison

system, Mansfield-Hoytdale 345 KV line.  The fault was detected by BVPS

switchyard protection equipment which began shedding various loads

through the opening of line breakers.  During the 13.5 cycle time that

the fault was detected, the following eight (8) BVPS switchyard 345 KV

breakers opened:



          PCB-341   PCB-331   PCB-362   PCB-333

          PCB-366   OCB-93    PCB-346   PCB-352



The opening of Unit 1 and 2 output breakers PCB-331, PCB-341, PCB-352 and

PCB-362 resulted in the concurrent unit trips.



The BVPS bus protection scheme consists of differential relays, Static

Breaker Failure Unit (SBFU) relays and Static Relay Unit (SRU) timers.

The SBFU relays and SRU timers are used as part of a backup protection

scheme and are designed to operate on the detection of a stuck (failed)

breaker.  This combination of relays and timers serves as a backup to the

various bus differential relays.  Normally, the bus differential relays

operate for a fault on the affected bus by clearing (opening) breakers

that feed the affected bus.  However, if any of the breakers fail to

trip, the breaker failure scheme with SBFU relays and SRU timers is used.



The breaker failure scheme assumes one breaker that feeds the affected

bus has failed to clear.  If so, it then trips the next breaker(s) in the

circuit in a continuing attempt to isolate the fault from the bus.  The

backup protection scheme operates with a time delay following bus

differential relay initiation.  The SRU timer is automatically reset if

the detected fault is cleared within the established time delay period.

The breaker failure scheme consists of one SBFU relay for each breaker on

the bus and one SRU Bus Backup Timer for the entire bus.  The SRU Bus

Backup Timer has two (2) inputs for each breaker on the bus as sensed

through each individual SBFU relay.  These inputs consist of a

differential relay operation and a breaker overcurrent condition.  If the

SRU timer times out and the fault has not yet been cleared by the

differential relays, then the timer will operate.



TEXT                                                          PAGE 4 OF 8



Operation of the timer will, in turn, trip the next breaker(s) in the

circuit for any of the lines on the bus that are indicating an

overcurrent condition in an attempt to isolate the fault and an apparent

stuck breaker.



Various sequence of events logs were reviewed by the ERT to determine if

unexpected conditions existed prior to, or in response to, the plant

trips at Units 1 and 2.  In addition, the Relay Group performed an

investigation which included the switchyard fault recorder and conducted

equipment tests to determine the reasons for the unanticipated switchyard

breaker and relay actuations.



The investigation identified a wiring discrepancy with the current

interlock of the #3-345 KV Bus Backup Timer.  This discrepancy involved

the incorrect wiring between the Unit 2 SBFU current interlock relay

(504140) (FK/50/A500) for PCB-352 and its associated SRU timer (624143).

Two (2) outputs of the SBFU were cross-connected.  This cross-connection

resulted in a current interlock inputting into the relay portion of the

timer.  The relay output of this SBFU relay was connected to the current

input of the SRU timer and the current output of the SBFU relay was

connected to the relay input of the SRU timer.



With the SRU timer scheme wired with these SBFU outputs reversed, two (2)

conditions were needed for the timer to operate.  First, there needed to

be a current condition greater than the setpoint of the SBFU relay

(providing a false differential input to the SRU timer).  Second, a

sufficient fault current duration was needed to operate the timer.  The

ground interlock setting of the SBFU relay was set for 400 amps.  The

measured ground current on the Mansfield-Hoytdale line at the time of the

fault was approximately 2800 amps.  The SRU timer was set for eight (8)

cycles.  With a fault duration of 13.5 cycles, both conditions were met

for the timer to operate.



The backup protection scheme for Unit 2 was wired in accordance with

wiring diagrams that were issued in 1984.  The scheme was checked

satisfactorily when testing each breaker's interlock individually, which

is the typical testing mode for both trip checking and for routine relay

calibration.  Based on the results of the reviews and investigative

efforts completed, the functions of the protection scheme operated during

the event as would be expected, based upon the identified (incorrectly)

as-installed wiring configuration.



As described above, when the fault on the Mansfield-Hoytdale line

occurred, the primary line protection for the Mansfield Substation was

out of service due to line communications difficulties.  The secondary

line protection was in service.  The 13.5 cycle fault duration was the

normal secondary line clearing time.  Even with this line protection

scheme, BVPS should not have tripped any of the eight (8) breakers.



The 345 KV bus backup protection scheme, as identified on the electrical

schematic diagram, correctly identified the SBFU relay and SRU wiring

connections.  However, this wiring was not properly reflected in the

associated electrical wiring diagram.  The as-installed wiring

configuration for the Unit 2, PCB-352 SBFU relay and SRU timer matched

the (incorrect) wiring diagram.  The design review process in effect at

the time of installation did not detect the design errors between these

two (2) diagrams.



Unit 1 Emergency Diesel Generator Operation



During the Unit 1 trip, EDG EE-EG-1 autostarted but EDG EE-EG-2 did not

autostart.  Subsequent review of the Sequence of Events Recorder (SER)

showed an undervoltage diesel generator start permissive existed for

0.200 seconds on 4 KV bus AE (EDG EE-EG-1) and 0.166 seconds on 4 KV bus

DF (EDG EE-EG-2).  EDG EE-EG-2 was declared inoperable as of 0606 hours

on March 19, 1997, because it appeared the EDG had failed to autostart.



The SER printout indicated that the undervoltage start permissive for

EE-EG-2 did actuate, but for a very short period of time.  The most

probable cause for the diesel generator not to autostart, was that the

start permissive actuated for too short a period of time, which did not

allow all of the relays in the auto start circuit to actuate.  In order

to prove this hypothesis, functional testing of EDG EE-EG-2 undervoltage

autostart circuit was performed on March 20, 1997.



The testing demonstrated that the start actuate time for EDG EE-EG-2 on

Start Circuit No. 1 was 0.198 seconds and 0.194 seconds on Start Circuit

No. 2.  The 4 KV Bus DF undervoltage diesel generator start signal which

existed during the plant trip on March 19, 1997 was 0.166 seconds.  Based

on the measured start actuate times being longer than the start which

existed during



TEXT                                                          PAGE 5 OF 8



the plant trip, EDG EE-EG-2 should not have autostarted, and responded as

designed in response to the plant conditions that existed during the

plant trip transient.



Undervoltage autostart testing was also performed on EDG EE-EG-1 on March

22, 1997.  The start actuate time for EDG EE-EG-1 on Start Circuit No. 1

was 0.170 seconds.  The 4 KV Bus AE undervoltage diesel generator start

signal which existed during the plant trip was 0.200 seconds.  The start

actuate time for EDG EE-EG-1 is faster that EDG EE-EG-2, due to one less

relay in the start circuit.  An interposing relay for Appendix R

separation is used on EDG EE-EG-2 and not used on EDG EE-EG-1.  Based on

the measured start actuate time being less than the duration of the start

signal which existed during the plant trip, EDG EE-EG-1 started, as

designed, in response to the plant conditions that existed during the

plant trip transient.



Unit 2 Auxiliary Feedwater Low Flow to "B" Steam Generator



Automatic AFW actuation occurred at Unit 2 due to the trip.  Computer

data showed that AFW flow to the "B" steam generator increased to at

least 244 GPM initially and then decreased to 150 GPM with no changes in

system controls.  This low flow ultimately led to declaring the "B" AFW

injection line inoperable and entry into Technical Specification

3.7.1.2.b at 1206 hours on March 19, 1997.  The action statement for TS

LCO 3.7.1.2.b requires that the plant be in at least hot standby (Mode 3)

within 6 hours and in hot shutdown (Mode 4) within the following six

hours.  Unit 2 commenced a boration and cooldown towards Mode 4 at 1210

hours on March 19, 1997.  One steam generator and one motor-driven AFW

pump were sufficient to meet the decay heat removal requirements for the

reactor trip event.



Low flow to "B" steam generator was indicated on two separate flow

indicators (same flow element with different taps).  The firs computer

data point for the "A" and "C" AFW lines was approximately 245 GPM, but

then increased (as expected) to 280 GPM.  All three AFW lines should

indicate similar flows when all of the throttle valves (2FWE-HCV100A-F)

are open.  All AFW throttle valves were open during at least the first

nine (9) minutes after AFW actuation.  Control Room benchboard indication

and local valve position indication verified the "B" steam generator

throttle valves (2FWE-HCV100C and D) to be fully open, while "B" steam

generator post-trip level recovery lagged behind the "A" and "C" steam

generators.  This indicated a possible flow restriction downstream of the

junction of the "A" and "B" AFW headers.



A calibration check of one of the two flow instruments for the "B" AFW

line was performed with satisfactory results, indicating that the flow

instruments were accurate in indicating reduced flow.  Reverse flow

leakage was measured on AFW check valves 2FWE-99, 100, and 101 with

satisfactory results.  Flow elements 2FWE-FE100B and 2FWE-FE101B and

adjacent piping were inspected for foreign material with a horoscope.  No

foreign material was identified, indicating that the obstruction was not

in the now elements or adjacent piping.  Test pressure gauges were

installed at key locations throughout the "B" AFW lines and the Motor

Driven AFW Pump Full Flow Test was performed to determine the location of

the restriction.  This test indicated a high differential pressure

between flow element 2FWE-FE101B and 2FWE-100 with flow of 180 GPM

through the line.  The test data pointed to 2FWE-100 as the likely cause

of the flow restriction.  Valve 2FWE-100 was removed from the system and

inspected.  The seat ring was observed to have backed out of its position

approximately 9/16".  The total travel of the disc and stem is 5/8".  The

backing out of the seat ring pushed the disc back 90% of its travel.

Approximately 1/16" of disc travel was observed when stroked by hand

indicating that the seat and disc were not bonded.



Check valves 2FWE-99 and 2FWE-101 were also removed from their respective

lines and inspected.  No significant anomalies were noted for these

valves.



All three AFW check valves were sent to the vendor (Enertech) for further

analysis and corrective modifications.  Examination by Enertech confirmed

that the seat for valve 2FWE -100 had moved out of its body position by

9/16".  A 1/16" to 1/8" band was observed around the seat ring.  This

indicated that the seat ring may have moved out 1/16"-1/8", possibly as a

result of the Unit 2 trip on January 6, 1997, which was the last time the

AFW lines experienced flow.  High magnification using microscopy (400X)

indicated damage (palling) to the seat ring, with the seating surface

found to be work hardened.  It is postulated that the disk experienced

chatter after the March 19, 1997 trip when the seat moved the additional

7/16".  The cycling of the disk work hardened the seat ring.  This would

also explain the spalling noted under high magnification.  No anomalies

were noted for 2FWE-99 and 2FWE-101.



TEXT                                                          PAGE 6 OF 8



Analysis by Enertech concluded that thermal gradient conditions created

by introducing low temperature AFW through the hot valve 2FWE-100 caused

rapid cooling of the seat ring, allowing it to displace.  The thermal

gradient is established as follows.  2FWE-100 is 20.25 inches from the

Main Feedwater (MFW) pipe in the horizontal direction, whereas 2FWE-99

and 2FWE-101 are a much greater distance from their respective MFW lines.

2FWE-100 is exposed to 430 Degrees F MFW on the downstream side which

thermally expands the body, including the seat ring.  The temperature of

AFW flowing into the valve is significantly lower.  After the trip,

indicated AFW temperature was 60 Degrees F.  The as-found body/scat ring

interference for valve 2FWE-100 was 0.006".  Calculations show a

differential temperature ("delta-T") of approximately 370 Degrees F is

necessary to free the seat ring, which corresponds to the delta-T

observed for 2FWE-100.



CORRECTIVE ACTIONS



Completed Corrective Actions:



Dual Unit Trip



1.   On March 19, 1997, the Vice-President of Nuclear Operations assigned

     an Event Review Team (ERT) for each unit.  Team members were

     assigned from various departments to collect and review information

     and thoroughly investigate this event in accordance with Site

     procedures.



2.   A modification was completed to resolve the incorrect wiring between

     the Unit 2 SBFU current interlock relay for PCB-352 and its

     associated SRU timer, including field proof testing, on March 22,

     1997.



3.   DLC Substations Department completed an investigation of operations

     of the SBFU relays versus measured fault currents and rechecked the

     calibration of the fault recorder on March 25, 1997.



4.   The Nuclear Engineering Department (NED), with the support of the

     Relay Group, evaluated the cause of the 345 KV system disturbance

     that initiated the relay protective actuation that initiated the

     event and completed the root cause analysis March 25, 1997.



5.   The ERT Reports were completed and presented to the Nuclear Safety

     Review Board (NSRB) on March 26-27, 1997.



6.   DLC Substations Department completed testing of the 345 KV Bus

     Backup Timer relays, including tests of the SRU timers with multiple

     inputs, on March 31, 1997.



7.   A review of BVPS switchyard protection drawings to determine if

     additional discrepancies between elementary diagrams and wiring

     diagrams exist was completed March 31, 1997.  Identified

     discrepancies are addressed below under additional corrective

     actions.



Unit 1 EDG Operations



1.   Functional testing of EDG EE-EG-2 undervoltage auto start circuit

     was performed on March 20, 1997.



2.   Functional testing of EDG EE-EG-1 undervoltage auto start circuit

     was performed on March 22, 1997.



3.   An evaluation of the EDG test data and the March 19, 1997 response

     to the trip was finalized March 24, 1997.



Unit 2 AFW Low Flow to "B" Steam Generator



1.   A calibration check of flow instrument 2FWE-FE100B for the "B" AFW

     line was performed on March 19, 1997.



TEXT                                                          PAGE 7 OF 8



2.   Reverse flow leakage was measured on AFW check valves 2FWE-99, 100,

     and 101 on March 20, 1997.



3.   Flow elements 2FWE-FE100B and 2FWE-FE101B and adjacent piping were

     inspected for foreign material with a horoscope on March 21, 1997.



4.   Test pressure gauges were installed at key locations throughout the

     "B" AFW lines and the Motor Driven AFW Pump Full Flow Test was

     performed to determine the location of the restriction on March 22,

     1997.



5.   AFW check valves 2FWE-100, 2FWE-99 and 2FWE-101 were sent to the

     Enertech for further analysis and corrective modifications on March

     23, 1997.



6.   Enertech-modified AFW check valves 2FWT-100, 2FWE-99 and 2FWE-101

     were reinstalled March 27, 1997.



Additional Corrective Actions:



1.   DLC Substations Department will test the 138 KV Bus Backup Timer

     relays, including tests of the SRU timers with multiple inputs,

     within 30 days of achieving 7 days continuous stable operation at

     100% power for both units.



2.   BVPS NED, DLC Power Delivery Support Services Department, and DLC

     Substations Department will review, and, if necessary, revise, the

     post-modification testing practices to ensure that future

     modifications are adequately tested for proper operation by July 1,

     1997.



3.   BVPS NED will review the current switchyard modification and work

     processes to ensure that adequate requirements and design controls

     are in place by July 1, 1997, to prevent a similar design event

     recurrences



4.   DLC Substations Department will provide documentation to BVPS of

     their current training requirements for conducting switchyard work

     activities at BVPS.  An evaluation of this information will be

     conducted by BVPS management and the Training Department to

     determine the level and control of training that would be adequate

     for BVPS switchyard workers by April 30, 1997.



5.   Resolution of identified drawing discrepancies (Dual Unit Trip item

     7, above) will be tracked via the Condition Report process.



REPORTABILITY



An Emergency Notification System (ENS) report was made pursuant to the

requirements of 10CFR50.72(b)(2)(ii), "Any event or condition that

results in manual or automatic actuation of any Engineered Safety Feature

(ESF) including the Reactor Protection System (RPS)..." at 0922 hours on

March 19, 1997.  An update to the ENS notification pursuant to the

requirements of 10CFR50.72(b)(1)(i)(A), "The initiation of any nuclear

plant shutdown required by the plant's Technical Specifications," was

made at 1302 hours on March 19, 1997.  This event is also being reported

herein pursuant to the requirements of 10CFR50.73(a)(2)(iv) as "Any event

or condition that resulted in a manual or automatic actuation of any

Engineered Safety Feature (ESF) including the Reactor Protection System

(RPS)..." and 10CFR50.73(a)(2)(i)(A), "The completion of any nuclear

plant shutdown required by the plant's Technical Specifications."



Additional Information Pursuant to 10CFR Part 21 Reportability



An evaluation of this event, completed on April 24, 1997, has determined

that a substantial safety hazard could be created as the result of the

identified valve defect and that it is, therefore, reportable pursuant to

the requirements of 10CFR Part 21.  ENS Notification of 10CFR21

reportability was made on April 24, 1997, at 1403 hours.



TEXT                                                          PAGE 8 OF 8



A similar failure of AFW check valve 2FWE-100 would have resulted in a

reduction of AFW flow to the "B" steam generator during a postulated

design basis accident (DBA).  The reduction in flow caused by the defect

would have resulted in AFW flows less than analyzed for the Unit 2

Accident Analysis.  Therefore, for the postulated DBAs, the ability to

provide adequate AFW cooling would be adversely affected and the system

may not have performed its safety function.



Component Description:



The component is a nozzle check valve intended for use with water

service.



Supplier:



Enertech

(BW/IP)

2950 Birch Street

Brea, CA 92621



Type:



Enertech "4" Nozzle Check Valve, ANSI Class 6001, Type DRV-Z



Valve Body - Dwg. # PD96227, ASME SA105

Seat - Dwg.  # P1396233, ASTM A479 Type 316



Location and Number of Additional Enertech Nozzle Check Valves in Use at

BVPS Unit 2:



An extent of condition evaluation completed March 28, 1997, has shown

that the nine other Enertech nozzle check valves of this design in

service at Unit 2 (listed below) are not subject to thermal gradients of

the type or of sufficient magnitude to induce the condition observed for

2FWE-100.  Unit 1 does not have Enertech nozzle check valves.



Main Steam Residual Heat Release Check Valves 2 SVS-80, 81, and 82

{BA/V/E334} - Enertech Type DRV-Z, 6 inch - Main Steam Valve Room



Auxiliary Feedwater Check Valves 2FWE-42A, 42B, 43A, 43B, 44A and 44B

{BA/V/E334} - Enertech Type DRV-Z, 6 inch Safeguards Building



SAFETY IMPLICATIONS



Both Units were safely shut down in accordance with applicable

procedures.  Adequate decay heat removal capability was afforded by both

AFW systems during the event.  There were no implications to the health

and safety of the public as a result of this event.



SIMILAR EVENTS



LER 2-97-001-00, "Reactor Trip Due to Main Transformer Ground Protection

Relay," dated February 3, 1997.



ATTACHMENT TO 9705050262                                      PAGE 1 OF 2



Duquesne Light Company   Beaver Valley Power Station

                         P.O.  Box 4

                         Shippingport, PA 15077-0004



RONALD L.  LeGRAND                                         (412) 393-7622

Division Vice President -                              Fax (412) 393-4905

Nuclear Operations and Plant Manager



                                        May 2, 1997

                                        NPD1VPO:0674



Beaver Valley Power Station, Unit No. 1

Docket No.  50-334 License No.  DPR-66

LER 97-005-01



United States Nuclear Regulatory Commission

Document Control Desk

Washington, DC 20555



     In accordance with Appendix A, Beaver Valley Technical

Specifications, the following Licensee Event Report supplement is

submitted:



     LER 97-005-01, 10 CFR 50.73(a)(2)(1), 10 CFR 50.73(a)(2)(iv), 10 CFR

21.21(d)(3)(ii) "Inadvertent Operation of 345 KV Bus Backup Timer Relay

Results "in Dual Unit Reactor Trips."



     This supplement is being submitted to provide additional information

pursuant to the reporting requirements of 10 CFR 21.



                                        R.  L.  LeGrand



Attachment



ATTACHMENT TO 9705050262                                      PAGE 2 OF 2



May 2, 1997

NPD1VFO: 0674

Page 2



cc:  Mr.  H.  J.  Miller, Regional Administrator

     United States Nuclear Regulatory Commission

     Region 1

     475 Allendale Road

     King of Prussia, PA 19406



     Mr.  D.  S.  Brinkman

     BVPS Licensing Project Manager

     United States Nuclear Regulatory Commission

     Washington, DC 20555



     Mr.  David Kern

     BVPS Senior Resident Inspector

     United States Nuclear Regulatory Commission



     MT.  J.  A.  Hultz

     Ohio Edison Company

     76 S.  Main Street

     Akron, OH 44308



     Mr.  Steven Dumek

     Centerior Energy Corporation

     6670 Beta Drive

     Mayfield Valley, OH 44143



     INPO Records Center

     700 Galleria Parkway

     Atlanta, GA 30339-5957



     Mr.  Michael P.  Murphy

     Bureau of Radiation Protection

     Department of Environmental Protection

     RCSOB-13th Floor

     P.O.  Box 8469

     Harrisburg, PA 17105-8569



     Director, Safety Evaluation and Control

     Virginia Electric & Power Company

     5000 Dominion Blvd.

     Innsbrook Technical Center

     Glen Allen, VA 23060



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