ML18037A390
| ML18037A390 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 07/12/1993 |
| From: | Kellogg P, Patterson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18036B366 | List: |
| References | |
| 50-259-93-23, 50-260-93-23, 50-296-93-23, NUDOCS 9308050042 | |
| Download: ML18037A390 (30) | |
See also: IR 05000259/1993023
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 30323-0199
Report Nos.:
50-259/93-23,
50-260/93-23,
and 50-296/93-23
Licensee:
Valley Authority
6N 38A Lookout Place
1101 Market Street
Chattanooga,
TN
37402-2801
Docket Nos.:
50-259,
50-260,
and 50-296
License Nos.:
and
Facility Name:
Browns Ferry Units 1,
2,
and
3
Inspection at Browns Ferry Site near Decatur,
Inspection
Conducted:
Hay
15 - June
18,
1993
at
ent
nspector
a
e
lgne
Accompanied
by:
J.
Hunday,
Resident
Inspector
R. Musser,
Resident
Inspector'.
Schnebli,
Resident
Inspector
T. Liu, Intern
Approved by:
au
7
Re ctor
.r.', Secti
n 4A
Division of
eactor Projects
SUMMARY
/~ W3
ate
)gne
Scope:
This routine resident
inspection
included surveillance
observation,
maintenance
observation,
operational
safety
verification, engineered
safety feature
walkdown, configuration
control drawings, modifications, Unit 3 restart activities,
reportable
occurrences,
and action
on previous inspection
findings.
One hour of backshift coverage
was routinely worked during the
work week.
Deep backshift inspections
were conducted daily from
Hay 22,
1993, to June
4,
1993.
930805'0042
930713
ADOCK 05000259
8
PDR,
'
Unit 2 was returned to service this period.
However, several
problems occurred that could have
been prevented
by better
planning.
First, the reactor
was manually tripped after several
unexpected
neutron monitoring instrumentation
responses
occurred
during the startup.
Although,
a pre-existing procedure
existed to
make
an adjustment
in indicated
response,
this was not anticipated
or cross-referred
by the startup procedure.
Second,
the
recirculation
pump shaft seals failed and were replaced.
The
apparent
cause of the failure was due to venting flow up through
the seals
instead of establishing
purge seal
flow down through the
seals first.
Third, the main generator excitor brushes
had to be
replaced
due to excessive
sparking
caused
by inadequate
alignment
and placement of the brushes.
One violation was identified by an
NRC inspector concerning
the
control
room emergency ventilation system valve lineup checklist,
paragraph
six.
Several
valves
were found out of position,
no red
mark existed for damper position,
and
a difference
between
the
A
and
B train checklist.
One deviation with two examples
was identified by an
NRC inspector
concerning
a commitment
made- in the Nuclear Performance
Plan,
Volume 3, with the issuance
of configuration control drawings,
paragraph
seven.
A control
room emergency ventilation drawing was
revised after
a modification and issued
as
an as constructed
drawing instead of a configuration control drawing.
Numerous Unit
1 and Unit 3 drawings
have
been
issued
as configuration control
drawings without
a system
walkdown and resolution of
discrepancies.
One unresolved
item was identified concerning failure to take the
required technical
specification action statement within one-hour
for tripping an inoperable trip channel
input signal,
paragraph
five.
=
Licensee
management
was informed that two licensee
event reports,
one inspector followup item,
and three violations were closed.
REPORT DETAILS
Persons
Contacted
Licensee
Employees:
- 0. Zeringue',
Vice President
J. Scalice,
Plant Manager
J. Rupert,
Engineering
and Modifications Manager
R. Baron, guality and Licensing Manager
D. Nye, Recovery Manager
- H. Herrell, Operations
Manager
J.
Haddox,
Engineering
Manager
- H. Bajestani,
Technical
Support
Manager
A. Sorrell, Radiological
and Chemistry .Manager
- C. Crane,
Maintenance
Manager
- P. Salas,
Licensing Manager
- R. Wells, Compliance
Manager
J.
Corey, Radiological
Control
Manager
J. Brazell, Acting Site Security Manager
Other licensee
employees
or contractors
contacted
included licensed
reactor operators,
auxiliary operators;
craftsmen,
technicians,
and
public safety officers;
and quality assurance,
design,
and engineering
personnel.
NRC Personnel:
R. Crlenjak,
Branch Chief
P. Kellogg, Section Chief
- C. Patterson,
Senior Resident
Inspector
- J. Hunday,
Resident
Inspector
- R. Husser,
Resident
Inspector
- G. Schnebli,
Resident
Inspector
- T. Liu, Intern
- Attended exit interview
and initialisms used throughout this report are listed in the
last paragraph.
Surveillance
Observation
(61726)
The inspectors
observed
and/or reviewed the performance of required SIs.
The inspections
included reviews of the SIs for technical
adequacy
and
conformance to TS, verification of test instrument calibration,
observations
of the conduct of testing,
confirmation of proper removal
from service
and return to service of systems,
and reviews of test data.
The inspectors
also verified that
LCOs were met, testing
was
accomplished
by qualified personnel,
and-the'SIs
were completed within
the required frequency.
The following SIs were reviewed during this
reporting period:
HPCI Flow Test
On May 22,
1993, the inspector
observed portions of the
performance of 2-SI-4.5.E;l.e,
HPCI Flow Rate Test at
150 PSIG.
The test
was being performed to satisfy
TS 4.5.E. l.e and 4.5.H.3
and
as post maintenance
testing for
WO 92-58171-03
which replaced
the booster
pump seal.
During the test
no problems
were
identified with the
new seal;
however,
the
AOP did not stop
operating
when the
HPCI turbine reached
operating
speed.
When the
turbine reaches
rated
speed
the gear driven oil pump supplies the
required lube oil pressure
and the
AOP is designed to
automatically stop.
Troubleshooting
indicated that the pressure
switch that automatically stops the
AOP was out of calibration
high.
This was repaired
under
WO 93-06737-00.
The surveillance
was completed satisfactorily.
Turbine Stop Valve Limit Switch Failure
On June
16,
1993, at approximately 6:37 a.m., during the
performance of surveillance instruction 2-SI-4. 1.A-15(II), the
licensee
determined that the number
one turbine stop valve closure
'PS
function (> 10 per cent valve closure)
was inoperable.
More
specifically,
a half-scram
was expected
and not received while
simultaneously closing the number
one
and three turbine stop
valves.
While in process of troubleshooting. the problem, the
valves were closed individually and the licensee
determined that
the appropriate
relays were being deenergized
for the number three
stop valve but not the number one stop valve.
TS 3. 1.A (Table
3. 1.A) states
that if the minimum number of instrument
channels
per trip system cannot
be met for one trip system,
the inoperable
channels
on the entire trip system shall
be placed in a tripped
condition within one hour.
The licensee
determined that by
pulling fuse 5A-FlOB, the applicable
RPS relays in the 'Bl'rain
of RPS logic would be deenergized
and therefore satisfy the
TS
action statement.
This action was taken at approximately 7: 10
a.m.
At approximately 8:00 a.m. the inspector entered to the Unit
2 control
room to investigate
the licensee's
actions
as they
related to the failed stop valve
RPS function.
While reviewing
the applicable
RPS logic diagrams,
the inspector questioned
the
operations shift if they had taken the appropriate
actions
(removing the fuse) for the 'Al'rain of RPS
as it appeared
that
the number
one stop valve had
an input to this portion of RPS
logic also.
The licensee
investigated
the inspector 's concern
and determined
that
an additional
fuse was also required to be removed.
This
action was taken at approximately 8:32 a.m. or 55 minutes in
excess of the
LCO delineated
in TS 3. 1;A, Table 3. 1.A, note one.
Pending further review, this matter will be tracked
as
URI 260/93-23-01,
Failure to Perform TS Action Within the Required
Time Frame.
No violations or deviations
were identified in the Surveillance
Observa-
tion area.
Maintenance
Observation
(62703)
Plant maintenance activities were observed
and/or reviewed for selected
safety-related
systems
and components
to ascertain
that they were
conducted
in. accordance
with requirements.
The following items were
considered
during these
reviews:
LCOs maintained,
use of approved
procedures,
functional testing and/or calibrations 'were performed prior
to returning components
or systems
to service,
gC records maintained,
activities accomplished
by qualified personnel,
use of properly
certified parts
and materials,
proper
use of clearance
procedures,
and
implementation of radiological controls
as required.
Work documents
(HR,
WR,
and
WO) were reviewed to determine the status of
outstanding jobs
and to assure that prioi ity was assigned
to safety-
related
equipment
maintenance
which might affect plant safety.
The
inspectors
observed
the following maintenance activities during this
reporting period:
'a ~
b.
C.
Recirculation
Pump Shaft Seal
Assembly Replacement
The inspector reviewed HHI-9A, Removal
and Replacement
of Reactor
Coolant Recirculation
Pump Shaft Seal
Assembly
and HHI-9B, Repair
of Reactor Coolant Recirculation
Pump Shaft Seal
Assembly.
These
were reviewed to see if any steps
would have prevented
the seal
failure due to the venting technique
problem discussed
in
paragraph
4.
No procedure
steps
could be found.
Leaking Rel'ief in Seal
Purge Line
During
a routine tour of the reactor building on June 6,
1993, the
inspector identified
a leaking relief valve in the
CRD water
supply to the recirculation
pump seal.
The inspector
inspected
the local
CRD seal
flow meters
because
of high seal
flow
annunciators'in
alarm in the control
room.
The relief valve
associated
with the 'B'ump is 2-68-55& while 2-6&-553 is
associated
with the 'A'ump.
The inlet pi'ping to both reliefs
was warm; however, the relief outlet from the 'B'as
warm while
the 'A'as cold.
This problem was discussed
with the
SOS.
The
licensee verified by use of a pyrometer this condition did exist.
WO 93-07471-00
was performed to determine the problem which
indicated the line to the seal
was not plugged
and the relief
valve was leaking.
Continuous Air Monitor
On June
18,
1993, the inspector observed
maintenance activities
associated
with the continuous air particulate monitor,
2-RM-090-
0057, located in the unit 2-Reactor Building 565 foot elevation.
The controlling document
was
and indicated that the
monitor was spuriously spiking high.
Haintenance
believed the
spikes
were due to electronic noise
induced into the system but
could not pinpoint the location.
The inspector
noted that
maintenance
personnel
were following approved
procedures
and using
qualified test equipment.
Troubleshooting will continue until the
cause is determined.
The inspector
had
no concerns with this
activity.
d.
HPCI Hechanical
Seal
On Hay 17,
1993, during the performance of 2-SI-4.5.E. I.e,
Flow Rate Test at
150 PSIG, Operations
noticed
smoke emitting from
the booster
pump inboard mechanical
seal
area.
The turbine was
tripped
and
WO 92-58171-03
was initiated to troubleshoot
and
repair the damage.
The seal
was disassembled
and,inspected
using
HCI-0-073-PHP002.
It was determined that the seal failed due to
the shaft rubbing the flange bushing which resulted
in high
seal'emperatures
and subsequent
damage.
A new seal
was installed
and
the system restarted
to verify proper temperatures
and vibrations
could be attained.
The inspector
reviewed the work documents
and
noted
no discrepancies.
e.
HV/I Converter Troubleshooting
On June
16,
1993, the inspector
observed
portions of the
licensee's
troubleshooting effort on the
2A recirculation flow
control
system in accordance
with
WO 93-07613-00.
Hore
specifcally,
a ground
was detected
and traced to the HV/I
converter portion of the control circuitry.
Due to problems
described
in paragraph
4d below, the HV/I converter
was replaced
with a converter from Unit 3 and the ground condition cleared.
No violations or deviations
were identified in the Haintenance
Observation
area.
Operational
Safety Verification (71707)
The
NRC inspectors
followed the overall plant status
and any significant
safety matters related to plant operations.
Daily discussions
were held
with plant management
and various
members of the plant operating staff.
The inspectors
made routine visits to the control rooms.
Inspection
observations
included instrument readings,
setpoints
and recordings,
status of operating
systems,
status
and alignments of emergency
standby
systems,
verification of onsite
and offsite power=supplies,
emergency
power sources
available for automatic operation,
the purpose of
temporary tags
on equipment controls
and switches,
alarm
status,
adherence
to procedures,
adherence
to LCOs, nuclear instruments
operability, temporary alterations
in effect; daily journals
and logs,
stack monitor recorder traces,
and control
room manning.
This
inspection activity also included numerous
informal discussions
with
operators
and supervisor s.
General
plant tours were conducted.
Portions of the turbine buildings,
each reactor building,
and general 'plant areas
were visited.
Observations
included valve position
and system alignment,
and
hanger
conditions,
containment isolation alignments,
instrument
readings,
housekeeping,
power supply and breaker alignments,
radiation
"and contaminated
area controls,
tag controls
on e'quipment,
work
activities in progress,
and radiological protection controls.
Informal
discussions
were held with selected
plant personnel
in their functional
areas
during these tours.
a 0
Unit Status
Unit 2 completed the refueling outage this period.
Initial
criticality was
on Hay 25,
1993,
and the main generator
was
initially tied to the grid on June 2,
1993.
'The generator
was
loaded to 160
HW for several
hours to obtain vibration reading for
turbine balancing.
The unit was removed from service
on
June
2,
1993, for addition of a balance
shot.
The unit was tied
to the grid on June 3,
1993, for power escalation.
At the end of
the report period the unit had
been on-line for 14 days.
Three
separate
problems
occurred during the recovery of the unit
that'ould
have
been prevented
by better planning.
1)
Hanual
Scram Downscale
IRHs
Following initial criticality on Hay 25,
1993,
was initiated due to problems
when ranging the
IRHs
from range six to seven.
Several
IRH's unexpectedly
went
downscale.
This caused
a rod withdrawal block.
Control
rods were inserted to reduce
power to range six and one rod
double notched causing
an insert rod block in the
RWN.
Operations
decided to manually scram the reactor at this
time.
The problem was that
an amplifier gain adjustment
needed to be performed
when going from range six to seven.
This
same adjustment
was performed
on the initial startup
for cycle six.
A procedure
already existed to perform this
adjustment,
but was overlooked or not cross referenced
in
the startup procedure.
The licensee is conducting
an
incident investigation of this event.'his will be reviewed
by the inspector
and subsequent
LER closed.
2)
Recirculation
Pump Seal Failure
The second
problem occurred with the recirculation
pump seal
failure.
Both recirculation
pump seals
were replaced during
the outage.
On Nay 27,
1993, the
2A recirculation
pump seal
failed.
The
pump was stopped
and the unit shutdown.
While
in the process of shutting
down the unit, the
2B
recirculation
pump seal
also failed.
The licensee
found
an
estimated
one-half teaspoon of gritty material in the seal.
From discussions
with plant personnel this was attributed to
starting the
pump without CRD purge flow through the seal.
This allowed flow from the recirculation system
up into the
seal
area.
If clean
CRD water had
been flowing into the
seal, this could have
been prevented.
The licensee
revised
2-01-68,
Reactor Recirculation
System,
to establish
seal
purge flow first.
The licensee is submitting
an
LER due to
the plant shutdown.
3)
Excitor Brushes Incorrectly Installed
The third problem occurred
when initially preparing to
synchronize
the main generator to the grid.
The main
turbine was manually tripped. due to excessive
sparking at
the excitor brushes.
The brushes
and housing were not
properly aligned
and metal-to-metal
contact occurred
on the
collector rings.
The brushes
were replaced
and the
collector rings polished.
The licensee is conducting
an II,
II-B-93-032, to review this problem.
All three events
could have
been prevented
by better planning
and
control of maintenance activities for recovery of systems after
the outage.
On May 17,
1993, the licensee
was granted
for the required actions of TS 3.5.8.9.
The time allowed was from
4:00 p.m.
May 17,
1993, until 4:00 a.m.
May 21,
1993.
The
discretion
was necessary
to make repairs
on
an inboard
injection valve.
With the other loop in shutdown cooling neither
loop would 'be capable of providing an automatic
LPCI flow path
as
required
by TS 3.5.8.9.
As compensatory
measures
the licensee
committed to maintain both
loops of CS operable during the repair activity.
The
RHR loop
used for shutdown cooling was capable of being manually realigned
for operation in the
LPCI mode.
Plant operators
reviewed existing
procedures for this realignment..
The inspector confirmed that the conditions of the enforcement
discretion were met.
The valve was repaired
and the
RHR loop
returned to an operable
status within the allotted time.
Drywell Closeout
On May 20,
1993, the inspectors
conducted
a drywell inspection in
preparation
for final closeout
and unit startup.
Particular
attention
was given to loose items that could possibly. end
up in
the suppression
pool,
as described
in Bulletin 93-02,
Debris
Plugging Of Emergency
Core Cooling Suction Strainers.
Items
identified included,
two screws missing
on
a drive motor
connection for SRM C,
unused wire hanging from the overhead,
several
broken light bulbs,
and
a section of drain 'hose.
One
particular item found was
a section of rope laying in one of the
drywell to torus
downcomer vent pipes.
These
items were brought
to the attention of plant management
and were corrected
on
subsequent
entries.
On May 20,
1993, the final drywell inspection
was performed
by the licensee
per 2-GOI-200-2, Drywell Closeout.
Electromagnetic
Interference
Mapping in Control
Room
From May 25 - 27,
1993, during Unit 2 reactor startup,
EMI mapping
surveys
were performed in Unit 1, 2, 3,
and control
room locations
in proximity to the
RBVRMs.
The
same
surveys
were performed
on
Unit 1, Unit 2,
and Unit 3; refuel floor locations in proximity to
the reactor;
and refuel
zone radiation monitors during Unit 2
Cycle
6 refueling outage.
Three types of surveys
were made.
First was the conducted
interference,
second
was the radiated interference,
and third was
the
DC magnetic fields.
Surveying conducted
interference
on the signal leads
arid power
on each monitor involved clamping
on current probes to the
line of interest
and then measuring
the noise
on the lines with a
spectrum analyzer for frequency
domain data.
The range of
frequency monitored for conducted
interference
was
30
HZ to 50
MHZ.
For surveying radiated interference,
antennae
were placed in the
direct vicinity of panel 9-10, (in which the
RBVRMs are located)
in each control
room.
The survey was for both electrical
and
magnetic fields,
and was performed
on both the front and rear of
the panels.
The survey in the rear of the cabinets
was
conservatively
performed with the rear doors
open
and closed .as
an
assurance
that the survey would cover normal activities in and
around the cabinets.
Four antennae
were placed in the direct
vicinity of the
RBVRMs (approximately
1 meter)
and the area
was
monitored with frequency
sweeps.
These
sweeps
were captured
using
a spectrum analyzer.
The following antennae
were used during the
survey:
Loop antenna
for AC magnetic fields - frequency of 30
HZ to
50 KHZ.
Active rod antenna for electrical fields frequency range
of 14 KHZ to 30 MHZ.
Biconical antenna for electrical fields frequency range of
30
MHZ to 300 MHZ.
Time period antenna for electrical fields - frequency range
of 300
MHZ to 1000
MHZ.
DC magnetic fields were also surveyed
in and around the 9-10
cabinets.
This activity involved using
a gauss
meter
and hall
effect probe covering the direct vicinity of the equipment.
The survey results indicated the plant's
ENI environmental
conditions are within the tested
envelope,
which is 65
volts/meter.
The maximum radiated electric field from the
ENI
mapping survey was found to be around
8 volts/meter
when
a plant
hand-held radio was
keyed in Unit I control room.
The inspector
observed portions of the survey conducted,
reviewed
the test results,
and held discussions
with licensee
representatives.
No deficiencies, were identified.
Recirculation
Flow Control
Problems
Following the startup of Unit 2, the licensee
experienced
a number
of problems with the portion of the recirculation flow control
system associated
with the
2A recirculation
pump.
During the
power ascension,
.a problem with the NV/I converter
caused
a ground
to be introduced into the control circuitry.
Another NV/I
converter
was installed
and it exhibited
a similar problem.
Troubleshooting
by the licensee
revealed that
a screw inside the
NV/I converter(s)
had penetrated
the bottom of the chassis
and
penetrated
a circuit card causing the ground.
Both NV/I
'convertors
had
been refurbished
by different vendor s,'et
both had
the identical problems.
The NV/I converter
was replaced with a
converter from Unit 3 and the ground condition cleared.
Another problem experienced
by the licensee
was noise introduced
into the
2A control. system from a failed 75 percent
speed limiter.
The limiter failed such that noise being introduced into the-
control
system
caused
a slight oscillation in the control signal
with a frequency of 20 cycles per minute.
The limiter was
replaced
and noise
was eliminated.
The licensee
has yet to
determine the cause of the limiter's failure.
In addition to the previously mentioned
problems,
a runback signal
to the 75 percent limiter was received during the startup.
However,
because total recirculation flow was less than'5
percent,
no actual
runback occurred.
The two requirements for a
recirculation runback are
one feedpump less than
20 percent flow
and reactor water level less than
27 inches.
Although,
one feed
pump was secured
at the time of the runback signal, reactor water
level did not reach
27 inches
(normal level being approximately
35
inches).
The licensee
suspects
that
an instantaneous
spike
.
downward in a water level signal
from a
F'H control system level
switch may have caused
the runback signal to occur.
The licensee
is monitoring level switch 3-538 and plans to troubleshoot
the
component during the next window of opportunity.
g.
The inspectors will continue to monitor the licensee's
progress
related to the recirculation flow control system.
It appears
that
problems
are continuing to plague the licensee
as they did during
the previous operating cycle.
However, at the end of this
reporting period, the recirculation flow control
system
was
performing adequately.
Expired Welding and Grinding Permit
On June
14,
1993, the inspector noted that
had signed
on
a Grinding and Welding permit which had expired June
11,
1993.
The permit,
1379,
was posted for work in the Unit 3 drywell for
the period of June
7 11,
1993,
and required
a firewatch while
work was being performed.
The inspector notified Operations
who
determined that no work was actually taking place
as described
by
this permit.
Following completion of the work activities the
foreman is to remove the permit and have it canceled.
In this
case
the permit had not yet been
removed.
No specific time
interval is stated for the removal of the permits.
Hissed Appendix
R Required Firewatch
On June 4,
1993, Fire Protection
Impairment Permit (Att. F) Number
93-0014-013,
which was issued for an inoperable Unit 3 Diesel
Generator building carbon dioxide system,
was closed out and the
required
compensatory
measure
was removed.
The compensatory
measure
was
an hourly roving firewatch.
On June
5,
1993, it was
discovered that required post-maintenance
testing
had not been
performed prior to cancelling the compensatory
measure.
A
firewatch was re-established
and
a new Att. F, 93-0248-001,
was
initiated for the impairment.
The required post-maintenance
test
was performed
and completed satisfactorily after which the
C02
system
was declared
and the compensatory
measure
again
canceled.
Problem Evaluation Report
BFPER930082
was generated
by
the 'licensee to document this event.
The inspector will continue
to monitor this activity and evaluate
the licensee's
corrective
actions in the
PER.
This is identified as IFI 296/93-23-04,
Hissed Appendix
R Firewatch.
ESF Walkdown (71710)
During this inspection period the inspector performed
a system
walkdown
of the
CREVs system installed this outage.
Portions of the valve lineup
and the system drawing, 2-47-E2865-4,
were compared to the configuration
existing in the field.
Discrepancies
noted are
as follows:
CREV A and
B damper position, required
by the val.ve lineup is
'HROTTLED.
The procedure
stated that the damper handle
should
be
positioned over the red mark painted
on the duct work.
There
was
no red mark on the duct work.
0
10
b.
Three drain valves
O-DRV-31-7361, for unit A and O-DRV-31-7366,
and 0-DRV-31-7367 for unit B, are required to be closed
by the
valve lineup. The'rawing indicated they should
be open.
An
additional drain valve on unit A, O-DRV-31-7360,
was inadvertently
left out of the valve lineup.
Although the completed valve lineup
indicated these
valves were closed,
the inspector
found them all
open
and the drain pipes capped.
c.
The instrument checklist identified the location of the 0-PDIS-31-
7316,
as the Unit 2 Ventilation Tower.
The location is actually
the
CREV Room,
El 617'.
TS Section 6.8. l.l.a requires that procedures
shall
be implemented
covering procedures
in Appendix A of Regulatory
Guide 1.33
Revision 2, February
1978.
Appendix A of Regulatory
Guide 1.33
includes
procedures for controlling the operation of the Control
Room Emergency Ventilation System.
Operating Instruction,
0-OI-'1,
is the controlling document for this system
and identifies the
required position of the aforementioned
components.
Failure to
maintain the required position of"these
components
is
a violation
of this Operating Instruction
and is identified as
VIO 259,
260,
296/93-23-02,
CREVs Components
Not In Required Position.
Licensee
management
was informed of the findings and they were
corrected.
Several
other system valve lineups were checked
by the
licensee
and similar problems
were not identified.
One violation was identified in the
ESF walkdown area.
Configuration Control Drawings
In IR 93-08 concerns
were raised related to CCDs.
In a site bulletin
issued
Hay 20,
1993,
a caution
was noted for use of Unit 3 and Unit
1
drawings issued
as
CCDs because all discrepancies
had not been resolved.
The inspector
reviewed the Browns Ferry NPP,
Volume 3, Section 2.2.2.3,
Issuance
of CCDs,
and concluded
a deviation from the commitment
had
occurred.
CCDs were to be issued -to replace
as-constructed
drawings
and
as-designed
drawings to reflect the plant configuration
and differences
reconciled.
Two examples
were identified of not meeting the commitments.
One
example
was for the Unit
1 and Unit 3 drawings discussed
above.
The as-
constructed
and as-designed
drawings were simply combined.
No walkdown
was performed of the system to confirm the actual plant configuration.
Also, stated in the caution in the site bulletin was that these
drawings
are being scrubbed
and discrepancies
resolved during the drawing
improvement program
and final clearup during the
SPAE(SPOC
process for
system restoration.
The second
example
was that for a
CREVS drawing discussed
in this report
for a system
walkdown of the
Drawing 2-47E28654
was revised
on
April 21,
1993,
and issued
as
an as-constructed
drawing after major
11
plant modifications.
This again deviated
from the commitment to issue
CCDs after plant modification.
This deviation will be tracked
as
DEV
259,
260, 296/93-23-03,
Issuance of Configuration Control Drawings.
One deviation
was identified in the configuration control drawings area.
Modifications (37700,
37828)
The inspectors
maintained
cognizance of modification activities to
support the restart of Unit 2.
This included reviews of scheduling
and
work control, routine meetings,
and observations
of field activities.
Throughout the observation of modifications being performed in the field
gC inspectors
were observed monitoring and documented verification at
work activities.
a ~
Third Phase of Instrument Tubing Program
Phases
I and II of the instrument tubing program concerning
a lack
of design criteria for seismic Class
I tubing and associated
supports
were implemented prior to restart
from the Unit 2 cycle
5
outage.
Phase III of the program required the licensee to
complete
an engineering evaluation
and necessary
modifications to
meet the final design criteria which were deferred
from
Pre-Restart/Safe
Shutdown
Scope
and are .required in support of the
long term operation of Unit 2.
The engineering
evaluation
was
accomplished
by Stone
and Webster
as documented
in Report
No.
02836-REP-S156,
dated
September
17,
1992.
The required tubing and
support modifications were performed
by
DCN W17283A,
W17285A,
and
W17286A which were completed during the Unit 2 cycle
6 outage.
The inspectors
reviewed the licensing closure
packages
(NCO
860326205
and
NCO 890128001,
the
SWEC engineering
evaluation,
and
the DCN's associated
with issue)
and determined the requirements
of the licensee's
commitment were met.
Cable Installation Issues
Several
cable installation issues
were identified prior to the
Unit 2 cycle
5 restart,
including vertical drop for low voltage
and medium voltage cables,
testing
and tren'ding of Group
2 cables,
and medium voltage cable
bend radius concerns.
The issue concerning vertical drop for medium voltage cables
was
resolved prior to the cycle
5 restart.
The subject cables
were
analyzed
and were justified technically acceptable
or were
replaced
as documented
in CA(R BFP 881066.
The low voltage cables
were evaluated
using the vertical support
requirements
of the General
Engineering Specification
G-38,
Rev.ll,
as
an acceptance criteria for vertical drop.
Bechtel
Engineering
performed walkdowns
on over 400 conduits containing
low voltage cables'.
The results
were documented
in Data
Package
BW001-001.
Those cables
which exceeded
the vertical drop limits
12
C.
d.
were identified as
an exception to G-38.
The Nuclear Engineering
staff prepared calculation
ED-(0000-910143,
Cable Support in
Vertical Conduit, which calculates
the maximum distance of
vertical drop a.particular cable
can withstand without exceeding
static sidewall pressure limits.
Based
on the engineering
evaluation the subject cables
were found to be technically
acceptable
due to the actual vertical drop length -being less in
all cases
than the allowable vertical drop shown in the
calculation tables.
This evaluation
was completed in Hay 1992.
The licensee modified their commitments
concerning
medium voltage
cable
bend radius
and testing
and trending of Group
2 cables
in
letter From TVA to
NRC dated
Harch 17,
1993.
The initial
commitments
were modified to require the replacement
of only one
cable,
PP434-IE,
during the Unit -2 cycle
6 outage,
which was
accomplished
under
DCN W17775.
The letter is currently being
reviewed
by NRR.
The inspectors
reviewed the documentation
associated
with the cable installation issues
discussed
above
and
determined
the licensee
met the requirements
of their commitments.
Pending
NRR approval of the licensee's
Harch 17,
1993, letter this
issue
may be closed.
Core Spray System
In IR 93-18, it was discussed
that the written approval for the
hydrostatic test methodology for a weld repair-on the
CS spray
system
had not been received.
The
NRC approved the hydrostatic
test pressure
in a letter dated
Hay 21,
1993.
No other
open issue
remained with the
CS hydrostatic test.
Completion of Restart
Commitments
In a letter to the
NRC Region II Regional Administrator, dated
Hay 24,
1993, the licensee
informed the
NRC of the completion of
commitments for the Unit 2 cycle 6 outage.
The inspectors
sampled
these
commitments in this IR and
IR 93-18
and concluded that the
licensee
had completed the Unit 2 cycle
6 outage
commitments.
Unit 3 Restart Activities
(30702,
37828,
61726,
62703,
71707)
The inspector
reviewed
and observed
the licensee's
activities involved
with the Unit 3 restart.
This included reviews of procedures,
post-job
activities,
and completed field work; observation of pre-job field work,
in-progress field work, and gA/gC activities; attendance
at restart
craft level, progress
meetings,
program meetings,
and management
meetings;
and periodic discussions
with both
TVA and contractor
personnel, 'skilled craftsmen,
supervisors,
managers
and executives.
The licensee is still working on the Unit 3 Recovery Schedule
which
should
be finalized in the near future.
The inspectors will continue to
follow the progress of the schedule
and will provide copies of it to
NRC
13
management
when issued.
Currently, the work is being scheduled
and
tracked
by a Summer Semester
Schedule
which provides
a three month look
ahead for both maintenance
and modifications.
Progress
on the three
month schedule will be used
as input to more accurately project work
duration
on the long range schedule.
Construction activities are increasing'lightly with the completion of
the Unit 2 cycle
6 refueling outage.
Major activities in progress
include:
CRDR work in the control
room panels;
reactor internals
T Box
repairs; fire protection systems;
seismic
upgrades
and pipe supports.
No violations or deviations
were
identified.'eportable
Occurrences
(92700)
The
LERs listed below wire reviewed to determine if the information
provided met
NRC requirements.
The determinations
included the
verification of compliance with TS and regulatory requirements,
and
addressed
the adequacy of the event description,
the corrective actions
taken,
the existence of potential generic problems,
compliance with
reporting requirements,
and the relative safety significance of each
event.
Additional in-plant reviews
and discussions
with plant
personnel,
as appropriate,
were conducted.
a ~
(CLOSED)
Unplanned
Engineering Safety Feature
Actuations
Due to Loss of Power to Radiation Monitors.
On October
25,
1989, the radiation monitors for the Unit 3 reactor
and refueling zones
experienced
a loss of power and
as designed,
tripped upscale
actuating
numerous
ESFs.
Specifically, the
and the
SBGT systems
were automatically started
and the Refuel
Zone
and Unit 3 Reactor
Zone Ventilation and the Unit 3 Group
6
PCIS system received isolation signals.
The cause of the event
was determined to be the failure of a fuse in the radiation=
monitors power supply.
The initial corrective action performed
was to replace the
radiation monitors power supply.
The final corrective action
committed to in the
LER was to replace the reactor
and refuel
ventilation radiation monitors with monitors having
a revised
logic scheme
and redundant
power supplies.
The licensee .initially
committed to have these corrective actions
performed prior to the
startup of Unit 2 for. cycle 6.
However,
on July 2,
1990, the
licensee
informed the
NRC (via revised
LER) that due to
procurement
lead time, the radiation monitors could not be
replaced until the Unit 2 cycle 6 refueling outage.
The inspector
verified through review of records
and in plant observations
that
the reactor
and refueling zone ventilation exhaust radiation
monitors
had
been replaced
in all three units.
14
b.
(CLOSED)
Compensatory Action Fire Watch Discovered
A Compromising Position Resulting
In A Violation of Technical
Specifications.
This
LER is closed
and the basis discussed
in paragraph
10.c. for
the discussion of VIO 92-37-03.
10.
Action on Previous
Inspection
Findings
(92701,
92702)
a ~
(OPEN) IFI 259,
260, 296/92-30-03, Circuit Breaker Coordination.
On June
1,
1993,
SBGT trains A, B, C,
and
CREVS automatically
started
due to breaker
3D on Shutdown
Board
1B tripping'.
At the
time the breaker tripped it was supplying alternate
power to
Unit -1
RPS.
The licensee
tested
the breaker'and
found it to be
satisfactory.
They then concluded that the spurious trip was
caused
by a design
problem in the breaker's trip device which was
previously identified in November
1992.
The licensee
issued
a
Part
21 report
on November 25,
1992, identifying a defect in
supplied
RHS-9 breaker trip devices with instantaneous
trip
function.
Per
GE, to prevent spurious trips,
a hold-off circuit
ensures
that the fault condition persists for a sufficient
duration
(300 microseconds)
to insure that
a trip is warranted.
Subsequent
testing,
performed
by TVA as part of their
investigation into the cause of spurious
breaker trips,
demonstrated
that the
RHS-9 unit would trip in response
to pulse
widths .of substantially less duration than
300 microseconds if the
current value was sufficiently above the instantaneous
trip
setpoint.
GE agreed with the licensee's
findings as documented
in
GE letter G-ER-3-126,
dated
March 18,
1993.
In this letter
committed to develop
a modified RHS-9 unit for application at
Browns Ferry.
The design
and development
process
is expected to
be completed
by August 1,
1993, with production units available
by
the end of October
1993.
When the licensee identified the defect in the
RHS-9 units, in
October 9,
1992; they performed plant walkdowns to determine
which
breakers utilized the
RHS-9 trip unit.
Of the 39 RMS-9 conversion
kits purchased for use at the facility only'0 were installed,
6
in safety related
equipment
and
4 in non-safety related
equipment.
The
6 installed in safety related
equipment
were located
as
follows:
480V Shutdown
Board
1A (compt.
3D - Units -1
18C Bus A);
480V Shutdown
Board
1A (compt.
5A control air compressor
A);
480V Shutdown
Board 1B,(compt.
3D Unit
1
ISC Bus B); 480V
Shutdown
Board
2A (compt.
5A control air compressor
D); 480V
Shutdown
Board
3A (compt.
2B Unit 3 ISC Bus A); 480V Shutdown
Board
3B (compt.
5B - Unit 3 IKC Bus B).
The licensee. formally
discontinued installation of the
RMS-9 trip devices with the
instantaneous trip function on October 5,
1992,
and performed
an
engineering
evaluation which determined that it was acceptable
to
allow the six breakers listed above to remain- installed.
The
15
inspectors will continue to follow this issue until the redesigned
RMS-'9 units are installed
and proven reliable.
(CLOSED) VIO 260/92-33-01,
Failure to Confirm Drywell
CAN Alarm.
On September
25,
1992,
an immediate action was not taken to
confirm an alarm at 2:55 a.m.
on drywell detection radiation
monitor detector,
2-RH-90-256.
TS Table 3.2.E note
3 requires
that immediate corrective actions will be taken to assess
the
possibility of increased
leakage
whenever
a drywell
CAN alarm is
received.
The sample
was requested
but not analyzed.
At
7:10 a.m., the monitor was declared
and logged
as
inoperable because'he
particulate
channel
was erroneously in
alarm.
A work order was initiated to troubleshoot
and correct the
problem with the channel
in alarm.
Later from 4:00 to 8:00 a.m.
unidentified floor leakage
provided indication of increased
drywell leakage
and Unit 2 was shutdown.
On December
2,
1992, the licensee
denied this violation on the
basis that plant personnel
took immediate action to confirm the
drywell on
CAN alarm.
The staff reviewed the licensee's
response
and concluded the violation occurred
as stated.
The ARP was revised to ensure that the proper samples
are
identified and obtained for specific alarm conditions.
The
inspector
reviewed the closure
package,
the revised
alarm response
procedure,
2-ARP-9-3,
and concluded that the corrective actions
have
been taken to preclude recurrence
of this issue.
(CLOSED) YIO 260/92-33-02,
Inattentive Firewatch
(CLOSED) VIO 259,
260,
296/92-37-,03,
Inattentive Firewatch
On October 2,
1992, the
NRC resident
inspector
observed
a fire
watch
who was inattentive to duty and appeared
to be sleeping.
The inspector
informed Operations
and,the fire watch was replaced.
This was documented
as
VIO 92-33-02.
On November
11,
1992,
a
Technical
Support Supervisor
observed
another fire watch
who was
inattentive to duty and appeared
to be sleeping.
He too was
replaced.
This was documented
as
VIO 92-37-03
and also
as
LER
'96/92005.
Fire watches
in both events
were given disciplinary =action.
New
fire watches
were hired and provided with training on the expec-
tations of management
and the responsibilities of a fire watch.
The inspector verified that the overtime
had
been reduced to
acceptable
amounts
and that the fire watches
were
on their
stations
and alert.
In addition the inspector verified the fire
watches
are rotated hourly from one location to another
and that
the foreman is periodically touring these locations.
16
Exit Interview (30703)
The inspection
scope
and findings were summarized
on June
22,
1993, with
those
persons
indicated in paragraph
1 above.
The inspectors
described
the areas
inspected
and discussed
in detail the inspection findings
listed below.
The licensee
did not identify as proprietary any of the
material
provided to or reviewed
by the inspectors
during this
inspection.
Dissenting
comments
were not received
from the licensee.
The Site Vice President
stated that the efforts on drawings were to make
the drawings reflect the actual plant configuration
as systems
were
returned to service.
The Site Vice President
stated,
additionally, that
the wording in the commitment
needed to be reviewed.
Item Number
Desc i tion and Reference
260/93-23-01
259,
260,
296/93-23-02
259,
260, 296/93-23-03
296/93-23-04
URI, Failure to Perform
TS Action Within
the Required
Time Frame,
paragraph
two.
Not in Required
Position,
paragraph five.
DEV, Issuance
of Configuration Control
Drawings,
paragraph
six.
IFI, Missed Appendix
R firewatch
Licensee
management
was informed that
2 LERs,
1 IFI, and
3 VIOs were
closed.
and Initialisms
BFNP
CAQR
CCD
CFR
DCN
GOI
IFI
Auxiliary Oil
Pump
Alarm Response
Procedure
Browns Ferry Nuclear .Power Plant
Continuous Air Monitor
Condition Adverse to Quality Report
Configuration Control Drawing
Code of Federal
Regulations
Control
Rod Drive System
Control
Room Emergency Ventilation System
Design
Change Notice
Electromagnetic
Interference
Engineered
Safety Feature
General
Operating Instructions
High Pressure
Coolant Injection
Inspector
Followup Item
Intermediate
Range Monitor
17
IR
LCO
LER
HHI
HW
NRC
RBVRH
RH
RWH
SOS
SPAE
SRH
TS
WP
Inspection
Report
In Vessel
Visual Inspection
Limiting Condition for Operation
Licensee
Event Report
Mechanical
Maintenance
Instruction
Maintenance
Request
Megawatt
Nuclear Performance
Plan
Nuclear Regulatory
Commission
Nuclear Reactor Regulation
Operating Instruction
Primary Containment Isolation System
.Pounds
Per Square
Inch Gauge
Quality Assurance
Quality Control
Reactor Building Ventilation Radiation Monitor
Radi aiton Monitor
Residual
Heat
Removal
Reactor Protection
System
Standby
Gas Treatment
System
Surveillance Instruction
Shift Operations
Supervisor
System Plant Acceptance
Evaluation
System Pre-Operational
Checklist
Source
Range Monitor
Stone
L Webster Engineering
Corp.
Technical Specifications
Violation
Work Order
Work Plan
Work Request