Part 21 Report - 1997-332
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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