ML18038B801
| ML18038B801 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 12/20/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B799 | List: |
| References | |
| 50-259-96-12, 50-260-96-12, 50-296-96-12, NUDOCS 9701150014 | |
| Download: ML18038B801 (42) | |
See also: IR 05000259/1996012
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
'Docket Nos:
'L'icense
Nos:
50-259,:50-260,
50-296
DRP-52,
Report
No:
.
50-259/96-12,
50-260/96-12,
50-296/96-12
Licensee:
Valley Authority (TVA)
Facility:
Browns Ferry Nuclear Plant, Units 1, 2,
and
3
Location:
Cor ner of Shaw and Browns Ferry .Roads
Athens,
35611
e
- Dates:
Inspectors:
Approved by:
October .13
- November 23,
1996
H. Morgan, Acting Senior
Resident
Inspector
J. Star efos,
Resident Inspector
G. Walton, Reactor Engineer
(Paragraph
H1.1)
'S. Sparks,
Project Engineer
(Paragraphs
H4.1,
E8'.1,
M8.1, 02.4)
H. Lesser,
Chief
Reactor
Projects
Branch
6
'Division of Reactor
Projects
Enclosure
2
970ii500i4 9hi220
ADQCK 05000259
8
41
!I
EXECUTIVE SUMMARY
Browns Ferry Nuclear
Plant, Units 1,
2 5 3
NRC Inspection Report 50-259/96-12,
50-260/96-12,
50-296/96-12
This integrated inspection included aspects
of licensee
oper ations,
engineering,
maintenance,
and plant support.
The report covers
a six-week
period of resident inspection
and includes efforts of a regional project
engineer
and
a regional reactor engineer.
erations
On October 29, Unit 2 automatically
scrammed
due to problems with the main
generator excitation system.
The excitation system problem was caused
by a
failure in the alternator-exciter collector brush set/ring.
The licensee
addressed
the failure and responded
properly to the scram (Section 02.1).
~
'On 'November
6. Unit 3 Division I ECCS Inver ter power was lost due to a fuse
failure.
Repairs
were immediately performed,
the fuse was replaced,
the
inverter was subsequently
tested
and placed back into service.
An ECCS
backup power supply is scheduled for installation during the upcoming
Unit 3 outage.
The cause of the inverter failure was not fully determined.
Inspection Followup Item (IFI) 296/96-08-02
discussed
two previous failures
and remains
open.
(Section 02.2).
~
On November 19, during
a tour of the Unit 2 Emergency Diesel
Generator
. (EDG) Auxiliary Board Rooms,
inspectors
discovered that the two EDG
Auxiliary Boar d Room Exhaust
Fans were not running and their switches were
in the
OFF position.
Procedures
required operation of these
fans.
The
inspectors
concluded that licensee
personnel
had failed to follow
procedures
and
an existing procedu're
was inadequate.
A violation (VIO) .50-
296/96-12-01
was identified (Section 02.4).
Naintenance
~
During the inspection period,
a regional reactor engineer
performed
a long-
ter m.lay-up inspection of Unit l.
In-plant storage of equipment
was found
to 'be acceptable,
humidity controls were noted
as adequate
and housekeeping
was also acceptable.
Adequate lay-up control
was observed
(Section, Hl.1).
~
In December
1995,
and January
1996. dielectric pipe couplings failed and
this resulted in large volumes of non-radiological
water spills.
During
the inspection period inspectors revisited planned replacement activities
and noted that such replacements/repairs
were satisfactory
(Section H2.1).
~
During the previous inspection period inspectors identified an increase in
the number of EDG problems
and failures.
A review of some of these
items
was conducted to determine the adequacy of'he licensee's
cause
analyses.
The inspectors
concluded that the failures were isolated
and appeared
not
0
0
to have
a
common tie.
However, the inspectors
continued to review these
issues
and, therefore,
IFI 96-10-04 remains
open (Section H4.1).
~
On November
19 and 21, the inspectors
reviewed licensee
freeze protection
program activities.
The inspectors
found that the circulating water intake
structure
and
RHRSW room freeze protection program items were satisfactory.
Inspection of the freeze protection program continues
(Section H8.2).
En ineerin
~
Following a Unit 2 scram on October 29, the main steam relief valves failed
to operate at setpoint
due to a continuing generic problem of corrosion
bonding of the pilot disc and seat.
The licensee appropriately
removed all
relief valves
and recertified them.
The inspectors
reviewed various
documents related to the event
and valve rebuild, recertification and
testing specifics.
A Non-Cited Violation (NCV) was identified for failure
to evaluate out of tolerance lift reseat
data
(50-260/96-12-02)
(Section
E2.1) .
Plant
Su
ort
, ~
~
On October
19,
a calibration source
was found outside its
designated'torage
location.
This issue
was identified by the licensee
soon after it
had occurred.
Due to both source shielding configuration and its location
the radiological
hazard
was low.
Since the issue
was licensee-identified,
has not been
a prior problem and because it was immediately corrected it
was identified as
an
NCV 50-259,260,296/96-12-04
(Section R4.1).
~
On October
23, inspectors
observed portions of an emergency
preparedness
(EP) exercise.
The inspectors
found the exercise/drill to be challenging,
fast-paced
and positive (Section Pl ~ 1).
0
Summar
of Plant Status
Re rt Details
Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Unit 3 operated at power for the report period.
With the exception of the
period of time noted in the following paragraph,
Unit 2 also operated at rated
power during the report period.
On October 29,
1996, at 3:38 p.m.,
an automatic reactor scram occurred
on
Unit 2 due to main turbine control valve fast closure.
The unit main
generator field collapsed
due to an exciter malfunction,
and the resultant
voltage and cur rent condition caused
generator
backup relays to operate.
The
associated
switchyard breakers
opened
and
a power load imbalance initiated
fast closure of the main turbine control valves.
This resulted in an
automatic reactor
The generator exciter was repaired,
reactor
criticality was achieved
on November 3.
1996,
and the unit was retur ned to
rated
power operations
on November 4,
1996.
On November 6,
1996, the Unit 3
ECCS Division I ATU Inverter failed and was
declared
Appropriate Technical Specification
(TS) Limiting
Condition for Operations
(LCOs) were entered
and on August 6, the licensee
notified the
NRC in accordance
with 10 CFR 50.72.
The inverter was repaired
and declared operable.
On November 8,
1996, Unit 3 power was reduced to 70
percent for control rod pattern adjustments
and condenser
waterbox cleaning
activities.
Unit 3 was returned to full rated
power
on November 9,
1996,
and
operated
at power for the remainder of the reporting period.
I. 0
rations
02
Operational
Status of Facilities and Equipment
02.1
Unit 2 Scram
Due to Hain Generator Exciter Problem
a.
Ins ection Sco
e
71707
93702
The inspectors verified that the licensee
took the appropriate
actions
in response to the Unit 2 automatic reactor scram on October 29,
1996.
b.
Observations
and Findin s
On October
29,
1996, Unit 2 automatically
scrammed
due to a problem with
the main generator excitation system.
The licensee
determined that the
opening of two switchyard breakers
which act as
a backup to the main
generator
breaker
caused
a fast closure of the main turbine control
valves which in turn resulted in the automatic reactor
The
licensee
determined that the system worked as designed;
however, they
planned to review the design to determine if the coordination
between
the backup (switchyard)
breakers
and the main generator
breaker
was in a
preferred condition.
0
0
The main generator excitation system problem was caused
by a failure ini5
the alternator-exciter collector brush set
and ring. The licensee
repaired the exciter collector ring and replaced the brushes.
Unit 3, "---';,
brushes
were also checked
and 3 brushes
were replaced.
The licensee
placed the Unit 2 mode switch to startup
on November 3,
1996 at
3:00 a.m.,
CST and took the reactor critical at 5:45 a.m.,
CST.
The licensee
determined that the loss of exciter output was caused
by '->
insufficient contact
between the brushes
and the positive collector
ring.
This was attributed to the correct
brush replacement criteria
having been inadvertently deleted
from the instruction in 1990 during
a
procedure consolidation project.
The licensee
changed
procedure
EPI-0-
047-TST-001
on October 30,
1996, to reflect the brush inspection/
replacement criteria recommended
by the vendor.
Conclusions
The licensee appropriately addressed
the failure of the exciter brush
set
and ring.
In addition, the licensee's
response to the Unit 2
was satisfactory.
Unit 3 Emer enc
Core Coolin
S stem
Division I Inverter Failure
Ins ection Sco
e
71707
92700
93702
The inspectors
reviewed the actions taken by the licensee in response to
a Unit 3 Division I ECCS
ATU Inverter
power failure.
Observations
and Findin s
On November 6, 1996, the Unit 3 Division I ECCS ATU Inver ter power
was
lost due to
a fuse failure.
This inver ter supplies
power to 2 of 4
channels of drywell pressure
and the reactor water level sensors.
The
sensors
supply both divisions of initiation logic for RHR,
CS,
HPCI,
ADS, and the
EDGs.
Other sensors
for reactor pressure,
containment
and
RCIC are also supplied by this inverter
.
Since the other channels of instrumentation
are powered by the
Division II inverter, the logic of all
ECCS divisions would have been
initiated, if required.
With the exception of RCIC and the Division I
input into the Anticipated Transient Without Scram (ATWS)/Recirculation
Pump Trip (RPT) logic, all systems
would have performed their design
function.
Because this ATWS/RPT logic was inoperable
a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
LCO (TS 3.2.L) was entered.
The Division II ATWS/RPT logic was operable
and
would have performed
as designed.
Approximately eight (8) hours after the inverter
was lost, the fuse was
repaired.
Inverter performance
was tested
and the inver ter performed
satisfactorily.
The
LCO was exited and the inver ter
was placed
back in
service.
All ECCS systems
were restored to pre-event conditions.
.L
r
'%~y
41
0
There have been recent Unit 3
ECCS inver ter failures (Reference
NRC IR
96-08, Section 02.2).
On July 17,
1996, the Unit 3 Division I Inverter
failed due to
a control board
and SCR/Diode failure.
On August 6, 1996,
the 3A inverter
again failed due to a similar circuitry problem.
Conclusions
Licensee analysis to determine the exact cause of these failures is on-
going.
The licensee is implementing
a backup source of uninterruptable
("DC-to-
DC") power to the circuitry.
The inspectors
reviewed
DCN T39853A which
documents installation of this power supply modification in the upcoming
February
1997 Unit 3 outage.
A similar DCN (T39852A) and modification
is being planned for Unit 2 installation during the Fall
1997 Unit 2
outage.
Because
a specific cause of these Unit 3 inverter failures has not yet
been determined
by the licensee,
this issue will remain open
and
continues to be addressed
as Inspection Followup Item (IFI) 296/96-
08-02,
Emergency Core Cooling System Inverter Failure.
Unantici ated Unit 3 A and
B EHC Pressure
Re ulator
Swa
in
Problems
Ins ection Sco
e
71707
92700
The inspectors
reviewed the actions taken by the licensee in response to
two unexpected electrohydraulic control
(EHC) pressure
regulator
swapping events:
Observations
and Findin s
On November 4,
1996, at 10:10 p.m., the Unit 3 "A" Hain Turbine
pressure
regulator
unexpectedly
swapped-over to the "B" pressure
regulator.
At 11:34 p.m., the
B regulator shifted back to the A
regulator.
No system perturbations
were observed during either shifting
evolution.
The operations
group initiated BFPER961500
and work request
(WR) 270073,
was initiated.
On November 5,
1996,
management
tasked
licensee engineering with review of the problem and with determining the
root cause of the unanticipated shift.
No other unexpected shifts
occurred over the next eight days.
On November
12,
1996, at 11:08 p.m.,
a control board operator noticed
that the
B EHC pressure
regulator indicating light was blinking on the
main control panel.
Upon further examination of the problem, the Unit
Supervisor,
control board operator
and the Unit Hanager noticed that the
A EHC indicating light also remained energized.
This indicated that the
A and
B EHC pressure
regulators
were both intermittently regulating
pressure.
However,
as of November 4,
no system
per tur bations
were
observed.
WR f270073 was immediately, upgraded to a priority 2, "high-
risk," work order
(WO) 96-014296-000.
On November 13,
1996 at
6:00 a.m., the
B regulator
had completely taken over pressure
control
0
0
Cl
and the A regulator indicated
a backup control function.
Primary
pressure
control
had fully shifted over to the
B regulator.
Licensee
18C was contacted
and the drift between the A and the
B regulators
was
readjusted to maintain
a licensee-desired
1~r, psi bias between the
regulators.
At the end of the inspection period, licensee
engineering
continued to
investigate the problem and
had requested
and received vendor
assistance.
From November 13-21,
1996, the licensee operations
group
monitored and recorded the desired bias
on a daily basis.
The licensee
then intended to monitor and record this bias
on a weekly basis until
December 21,
1996. If the regulator drift was not excessive,
and if the
drift appeared
manageable,
the monitoring/recording of the bias is to be
performed
as
a quarter ly PH.
Conclusions
The licensee's
troubleshooting activities and increased
monitoring were
appropriate.
EDG Auxiliar
Boar d Room Exhaust
Fans
Ins ection Sco
e
71707
On several
occasions
during the report period, the inspectors
toured
accessible
plant areas in accordance
with guidance presented
in
Observations
and Findin s
The inspectors
toured the Unit 3
EDG Auxiliary Board Rooms on
November 19,
1996,
and observed that
EDG auxiliary board
room exhaust
fan handswitches
3-HS-030-0243
and 3-HS-030-0244
wer e in the
OFF
position,
and the fans were not'running.
These exhaust
fans were for
rooms
3EA and 3EB, respectively.
The inspectors
noted that the room
temperatures
were not elevated.
The inspectors
questioned
the Unit
Hanager
about the correct position of the fans.
On November 20,
inspectors
toured the area again,
and identified that one fan handswitch
was in the
ON position and running, while the other fan handswitch
was
still in the
OFF position and not running.
The inspector s questioned
the Unit 3 Supervisor
on November 20, about why one was
ON and running
and one was in the
OFF position.
On November 22, the inspectors
followed up on the issue with the Unit 3 Reactor
Operator,
who stated
that both fans were in the
ON position and running.
The inspectors
reviewed licensee
procedure
O-OI-30F,
Common and
Building Ventilation, Revision 15.
The purpose of this procedure is to
provide precautions
and limitations, prestartup/standby
readiness
requirements
and procedural
steps for operations of the diesel
generator
and intake building ventilation.
Section 4.0 provides the standby
readiness
requirements for various ventilation systems,
including the
common building ventilation panel.
Section 4.1.2.4 requires that the
system lineup checklists
are current using Attachment
2AS,
Common
Building Ventilation Panel
Lineup Checklist, Unit 3.
Attachment
2A
states that the required position of the diesel Auxiliary Board
Room 3EA
and 3EB exhaust
fan handswitches
3-HS-030-0243
and 3-HS-030-244 is ON.
Note (1) to this requirement states that unless
maintenance is, being
performed,
these
fans should be kept in service to prevent excessive
temperatures
when the diesel
generator
480V auxiliary boards
are
energized.
In addition, this note references
R1.
This
LER was issued
due to an inoperable
Standby
Gas Treatment
system,
due in
part because
the
EDG auxiliary board
room exhaust
fans were not
operating,
resulting in elevated
room temperatures
and causing the
relative humidity control heater circuit breakers to trip.
The licensee
provided corrective action in this
LER that appropriate plant
instructions will be prepared
addressing
the operation of the exhaust
fans for the Diesel Generator Auxiliary Board Room.
Based
on this
information, the inspectors
determined that the required position of
these fan handswitches
is in the
ON position, with the fans in service.
As such, the licensee failed to follow procedure
0-0I-30F.
The inspectors
learned that the handswitch positions for the Unit 2
exhaust
fans are currently verified on
a shiftly basis
as part of 0-GOI-
300-1, Operations
Routine Sheets,
dated
November 15,
1996.
However, the
Unit 3 handswitch positions are not on the routine sheets,
and thus are
not verified to be in the proper position.
The inspectors
consider this
to be the second
example of inadequate
and/or failure to follow
procedures.
On November
22, the licensee
changed
procedure
O-GOI-300-1,
Attachment 15.18, to include the verification of both Unit 3 diesel
auxiliary board
room exhaust
fans.
The inspectors
discussed this issue with plant personnel
on the morning
of November 22,
and determined that no
PER had been initiated to review
this issue,
and the issue
was not logged in the main control
room logs.
Conclusions
The inspectors
concluded that the licensee failed to follow procedure
0-OI-30F in that the diesel auxiliary board
room exhaust
fans were not
in the required position.
This issue is identified as violation 50-
296/96-12-01,
Failure to Ensure Proper Position of EDG Aux Board
Room
Exhaust
Fans.
In addition, procedure
0-GOI-300-1 was found to be
inadequate
in that it did not require verification of the proper
position of the diesel Auxiliary Board
Room 3EA and
3EB exhaust
fans.
This is the second
example of violation 50-296/96-12-01.
In addition, the inspectors
concluded that the licensee did not
demonstrate
the appropriate sensitivity toward
a plant equipment
configuration control issue
when initially identified on November 19.
The inspectors
noted that no
PER was initiated until November 22.
The
licensee did not initially conduct
a thorough extent of condition
review, did not realize that both exhaust
fans were required to be in
the
ON position by procedure
O-OI-30F,
and did not identify that
procedure
0-GOI-300-1 was inadequate.
0
0
08
08.1
6
Hiscellaneous
Operations
Issues
(92901)
(Closed)
LER 50-296/96-005-00:
Reactor
Scram Required by Technical
Specification
Due to Trip of Reactor Recirculation Hotor Generator
Set
3A.
This Licensee
Event Report
(LER) was submitted, due to a plant
shutdown required by Technical Specifications.
Unit 3 experienced
a
trip of the,3A reactor recirculation
pump due to a fault in the
associated
motor-generator
set.
Based
upon the inspection
documented in
NRC IR 96-10, Section 04.1, this
LER is closed.
H1
Conduct of Maintenance
II. Maintenance
H1.1
a.
b.
Unit 1 Lon -Term La -u
Conditions
- Maintenance
Observations/Reviews
Ins ection Sco
e
92050
This portion of the inspection
was conducted to assess
the licensee's
preventative
maintenance
program, including long term lay-up conditions
on Unit 1 components
not required for Unit 2 or
3 operation.
The
inspector evaluated the adequacy of the program based
on the on-site
procedures.
The Unit 1 inspection effort consisted of field
inspections.
transfer controls for transferring equipment
from Unit 1 to
Unit 2,
3 or Sequoyah,
ongoing preventative
maintenance activities and
documentation.
Observations
and Findin s
The field inspections
were conducted in the reactor
building, auxiliary
building and included observation of the off-gas system,
steam jet air
ejector, stator cooling pump A, feedwater
heaters,
control rod drive
pump,
RHR pump, core spray
pump, lube oil cooler heat exchanger,
and
HPCI pump.
The applicable procedure
(SSP-12.52
Plant Lay-up and Preservation
Revision 5) that implemented the Unit 1 lay-up and preventative
maintenance
program
was reviewed.
Documentation of completed
PHs were
reviewed for adequacy
and included documents
1-HTR-068-0000A,
1-HTR-068-
0060B,
1-GEN-068-OOOOB. and 1-PHP-002-056.
The inspector also reviewed
Nuclear
Assurance
and Licensing Assessment
Report NA-BF-96-011, internal
memorandum
dated January
5,
1996, that deleted certain
PH tasks,
and
BFPER951039 that identified problems with the lay-up program.
The in-plant storage of equipment
was found acceptable.
Hotors were
observed to be adequately
covered
and heat
was being applied to the
motor windings.
Piping systems
were observed to be under
adequate
humidity controls for inside surfaces.
Housekeeping in the areas
reviewed were found acceptable.
0
III
The procedure
reviewed
was found acceptable
and implementation of the
preventative
maintenance
inspections
were found acceptable.
Conclusions
The in-plant storage of Unit 1 equipment
was observed to be adequately
controlled and consistent with long term storage
requirements.
The
records being generated
for the storage,
transfer,
and preventative
maintenance activities were adequate
and consistent with record
retention requirements.
Maintenance
and Material Condition of Facil.ities and Equipment
Unit 2 and 3 Dielectric Cou lin
Re airs
-
Re lacement Activit
U date
Ins ection Sco
e
62707
92902
The inspectors
reviewed repair activities associated
with replacement of
various Unit 2 and Unit 3 dielectric couplings.
The inspectors
assured
that activities were conducted in a manner that ensured reliable post-
maintenance
(post-coupling replacement)
operation of affected systems.
Observations
and Findin s
On January
24,
1996,
(Reference
NRC IR 96-03),
a 2-inch condensate
storage
and supply pipe broke spilling about 15.000 gallons of water in
the Unit 2 reactor building.
Operators identified the break to be
a
ipe coupling which. penetrated
the ceiling.
A similar coupling break
ad occurred in December
1995.
The couplings were embedded in concrete,
were made of a resin-type substance
(a dielectric)
and served
as
transition pieces
between existing stainless
steel
and aluminum piping.
Both of the couplings were replaced
and these
systems
were returned to
their normal alignments.
The inspectors
who reviewed these
events
determined that in both cases
no safety-related
equipment
had been
affected.
The inspectors
concluded that in both cases
licensee
responses
to the event were acceptable
considering the location of the
coupling failures and the relative obscurity of the piping.
Licensee
problem evaluation report
BFPER960151
was subsequently
initiated to,
1) identify additional couplings of this type,
2) to
determine if further actions were needed,
and 3) document
and track an
effective program of dielectric coupling repair .
II
0
c.
Conclusions
The inspectors
reviewed
an on-going program of dielectric coupling
replacement/repair
and noted the following:
~
Repairs/replacement
of both Unit 2 and Unit 3 couplings
have been
performed since
Hay 1996.
~
Of the 81 identified/scheduled
for repair,
57 have been replaced
(-701);
14 in the Unit 2 Reactor Building (RB); 42 in the Unit 3
Reactor Building (RB).
~
have been replaced
and by the end of
January
1997 all Unit 2 couplings are scheduled to be replaced.
~
Two Unit 3
EDG couplings are scheduled for replacement
in February
1997.
This replacement will complete the scheduled
program of
dielectric coupling repair.
The inspectors
have noted, during routine tours of the facility that
associated
repair activities have been performed in a satisfactory
manner.
The inspectors
have also noted that on-going repair activities
are proceeding
as scheduled.
t
M4
Maintenance Staff Knowledge and Performance
H4.1
EDG Material Condition Concerns
a.
Ins ection Sco
e
62707
During the previous inspection period, the inspectors identified an
increase in the number of EDG problems
and failures (IFI 50-259,260,296/
96-10-04).
A review of'ome of these
items was performed to determine
the adequacy of the licensee's
cause
analyses.
b.
Observations
and Findin s
The inspectors
reviewed the following issues identified in IFI 96-10-04:
August 30,
1996,
3B EDG air pressure
in header
low-alarm received
without either
air
compressor
star ting.
Discussions with the system engineer
indicated that this failure
could most likely be attributed to painters.
WRs have
been
written to replace all flex hoses
(hydraulic/air ) on Unit 3.
Unit 1 and 2 EDGs do not have these flex hoses.
Replacement
is
planned for completion by the end of 1997.
September
1, 1996.
3C
EDG overspeed trip relay actuated to trip
EDG output breaker; identified during routine surveillance.
0
0
This overspeed trip relay consists of a limit switch which was out
of adjustment
due to vibration.
Licensee corrective action
consisted of relay replacement.
The inspector
reviewed failure
and surveillance test history of EDG overspeed trip relay limit
switches during the past two years,
and noted that there were no
other failures of these switches.
~
September
4,
1996, the 2A EDG oil circulating pump was discovered
to have
a broken coupling.
This was identified by an Assistant
Unit Operator
(AUO) when it was noted that oil temperatures
were
lower than normal.
The inspector
reviewed the failure and surveillance history of the
EDG oil circulating pumps for the previous
2 year period,
and
noted
no similar failures.
~
October
11,
1996,
2A EDG problem identified with start circuit 2
pinion aux relay; identified while the diesel
was inoperable for
two-year maintenance.
The inspector
reviewed the failure history of these relays,
and
determined that the licensee
had previously identified a failure
trend in December
1995
(BFPER951830).
In addition,
BFPER951828
and BFPER951360
were initiated to document increased
failures with
this relay.
The failure mechanism
was due to dried grease
on the
plunger of the timer, resulting in slow response.
In response,
the licensee
conducts
a visual examination of the relays
(approximately
12 per
EDG) during the 2 year
PHs,
and replaces
any
which have excess
accumulation's of grease
on the plunger.
In
addition, solid state relays
have been
used for replacement of
some relays.
The licensee's
review determined that the
October ll, failure was not due to dried grease.
The inspectors
consider
the licensee's
identification of a negative failure trend
for this issue to be good;
c. Conclusions
Of the above
EDG problems originally identified in IFI 96-10-04, the
failures appear to be isolated examples
and do not have
a
common tie.
The licensee's
cause analysis
was adequate
for the above issues,
and
appropriate corrective actions
have been taken or planned in the four
cases
reviewed.
The inspectors will continue to review additional
examples of recent
EDG problems,
and as such this IFI will remain open.
H8
Hiscellaneous
Haintenance
Issues
(92902,
71714,
62707,
40500)
H8.1
(Closed) IFI 50-259,260,296/95-64-11:
Thread Lubricant Effects on
Torque Values.
This issue
concerned
an apparent
discrepancy
between
engineering
guidance
used by maintenance
personnel
in determination of
torque values
when thread lubricant is (and is not) used.
In response,
the licensee
issued
BFPER951122 to review this issue.
The licensee
issued
a revision to HSI-O-OOO-PR0017,
General
Torquing Guide, which
II
0
10
deleted the requirement for utilizing table multiplication factors,
such
as multiplying table values
by 0.9 when fastener
threads
are lubricated.
In addition. the procedure
was revised
such that when there is
a concern
of adequacy or component
damage resulting from the use of the listed
torque value, the table torque value can be increased
or decreased
by 10
percent or torque can be calculated.
The inspectors
consider
licensee
actions for this issue to be appropriate
and this issue is closed.
Im lementation of the Freeze Protection
Pro ram
Ins ection Sco
e
71714
92902
The inspectors
reviewed activities related to implementation of the
licensee's
freeze protection program.
The inspectors
assured that such
activities were conducted in a manner
consistent with procedure
0-GOI-
200-1 Freeze Protection Inspection
and W(596009582000,
Annual Inspection
5 Preventative
Haintenance of Freeze Protection
Systems.
Observations
and Findin s
On November
19 and 21,
1996, the inspectors
toured the residual
heat
removal service water
(RHRSW) building and circulating water intake
structures
and inspected
freeze protection systems.
In the
RHRSW areas
the inspectors
noted that portable heaters
were staged;
however, they
were not yet plugged into their associated
220VAC power supplies.
Operations
and,maintenance
management
personnel told the inspectors that
they would be energizing the space
heaters
when sustained
temperatures
of twenty-five (25) degrees
F or below were being met.
Twenty-nine (29)
degree
F temperatures
were the lowest outside temperatures
experienced
during the inspection period.
The inspectors
also noted that
sample station area thermostats
were properly set for weather conditions
(ON at 40 degrees
F) and they noted that
RWRSW pump motor
space
heaters
and intake piping heat trace
power supplies'ere
energized.
Conclusions
Initial inspector review of freeze protection procedures
and field
activities revealed that the licensee's
current efforts are adequate to
provide necessary
protection to guar d against cold weather conditions.
The inspectors will continue review during the next inspection report
period.
Third-Part
Assessment
of Plant Haintenance Activities
40500
The inspectors
reviewed
an October
24,
1996 Institute of Nuclear Plant
Operations
(INPO) to Site Vice President letter pertaining to an
October
8 to 10,
1996 assessment
of licensee
maintenance activities.
In
general
the results
were not inconsistent with NRC assessments
in this
area.
0
0
III. En ineerin
Engineering Support of Facilities and Equipment
SRV Failed to 0 crate at Set oint
Ins ection Sco
e
37551
71707
Following the October 29, Unit 2 scram,
the licensee identified that the
main steam safety valves should have lifted and failed to do so.
The
inspectors
reviewed licensee
data
(see attachment)
for the
13 SRVs
removed from Unit 2 after the scram.
The inspector s also reviewed
portions of the Safety Parameter
Display System
(SPDS) reactor pressure
data which indicated that reactor pressure
wide range point 3-54 reached
1131 psig -during the event.
The inspectors
reviewed portions of
surveillance instruction O-SI-4.6.D.1,
Bench Test Relief Valves,
Revision 8,
and the associated
urgent intent change
(UIC-10).
Observations
and Findin s
During the Unit 2 Scram on October
29,
1996, reactor
pressure
wide range
instr.ument,point
3-54 indicated
1131 psig.
The licensee
determined that
this pressure, exceeded
the main steam safety/relief valve
(SRV)
setpoints
on 8 of the 13 valves.
Technical Specification
(TS) Safety
Limit 1.2 requires that the pressure
at the lowest point of the reactor
vessel
shall not exceed
1375 psig whenever irradiated fuel is in the
reactor vessel.
TS Limiting Safety System Setting
(LSSS) 2.2 applies to
trip settings of the instruments
and devices
which are provided to
prevent the reactor
system safety limits from being exceeded.
The LSSSs
for the SRVs are as follows:
1105 psig s 11psi
(4 valves)
[1094-1116 psig]
1115 psig s 11psi
(4 valves)
[1104-1126 psig]
1125 psig a 11psi
(5 valves)
[1114-1136 psig]
The licensee
entered cold shutdown conditions
on October
31,
1996, at
2:12 a.m.
[CST].
The licensee
removed all of the 13 SRVs and tested
them at an off-.site contract test facility.
Licensee data
showed that 3
of the
13 SRVs removed from the vessel fell within their acceptable
range.
The licensee's
safety evaluation concluded that the failures
would not have resulted in exceeding the Safety Limit for any abnormal
(LER 96-08).
This is
a well known generic problem that the
licensee
continues to experience.
The licensee
has
documented
the issue
in several
LER's and continues to pursue resolution through the
Owners Group.
The licensee attributed the setpoint drift of the
remaining valves to corrosion bonding of the
SRV pilot disc and seat.
The inspectors
reviewed the surveillance instruction and verified that
the as-left setpoint for the 13 SRVs were within their specific
range.
While discussing the procedure with engineering
personnel
following restart of Unit 2, it was brought to the inspectors attention
that
a por tion of the procedure
had not yet been completed.
The
0
0
0
C.
12
procedure
addresses
certain guidelines which needed to be met. If not
met, it required either
a Technical Operability Evaluation
(TOE) to be
completed
or required the valve to be rebuilt and recertified.
Four of
the valves,
which had been returned to service,
did not meet the
procedural
guideline for percent reseat
and the licensee
had not written
a TOE or rebuilt and recertified the valves prior to installation of the
pilot valve as required by the procedure.
The licensee
subsequently
implemented
UIC-10 on the procedure
which
eliminated the requirement
discussed
previously.
It instead required
that the system engineer
determine acceptability for installation.
In
addition, the acceptance criteria portion of the procedure
was changed
to require that reseat
values outside the approved guideline limits will
be evaluated
by the System Engineer for installation acceptability
and
the evaluation documentation will be included with the SI.
The System Engineering Evaluation that addressed
the four valves which
were outside the reseat
guidance specified in the procedure,
determined
that the margin to reseat is acceptable
from a performance standpoint.
In addition, it appear s that TVA Engineering
was aware that the percent
reseat
values were outside of the acceptance
range
and that it was
determined to be acceptable.
This was noted
on the test data
page that
was supplied to the licensee
by the contr act test facility.
This failure to conduct
a TOE as required by procedure constitutes
a
violation of minor significance
and is being treated
as
a Non-Cited
Violation, consistent with Section IV of the
(NCV 50-260/96-12-02).
Conclusions
E8
E8.1
E8.2
The inspectors
determined that the licensee's
actions, to'bring Unit 2
to cold shutdown,
and remove
and test the 13 SRVs, were appropriate.
Miscellaneous
Engineering Issues
(92902)
(Closed)
LER 296/94-02:
A Deficiency Regarding
Raychem Tubing Used for
Environmental
Qualification Applications.
The licensee
issued this as
a
voluntary LER.
The licensee
reviewed the use of Raychem tubing, type
WCSF-070N, Lot No. N15057,
used to insulate the splice connection of
Conax
ECSA conductors to the conductors of their respective field cables
for Unit 3.
The licensee identified two uses of Lot No. N15057 in
Unit 3,
and no uses
for Unit 2.
The Unit 3 applications
were well
within the revised allowable use range
as specified by the vendor.
The
inspectors
consider
licensee
actions for this issue to be satisfactory
by (1) reviewing if the particular
Lot number of Raychem splices
was
used in Unit 3,
(2) evaluating whether the application was consistent
with vendor
recommendations.
This
LER is closed.
(Closed)
EEI 260/96-05-01:
RCIC Inoperability Following Replacement of
Turbine Exhaust
A predecisional
enforcement
conference
was
held on July 11,
1996.
A Notice of Violation was issued in
0
0
0
13
correspondence
dated August 1, 1996.
Followup to the violation is being
tracked under
NOV ID No. 01013.
E8.3
(Closed)
EEI 260/96-05-02:
Failure to Comply with IST Procedures
for
Testing
RCIC and HPCI Following Turbine Exhaust
Check Valve Replacement.
A predecisional
enforcement
conference
was held on July 11,
1996.
A
Notice of Violation was issued in correspondence
dated August 1.
1996.
Followup to the violation is being tracked
under
NOV ID No. 02014.
E8.4
(Closed)
URI 260/96-04-03:
Shutdown Cooling Low Level Isolation
Bypassed Prior To Cavity Flood-up.
This URI was opened
as the result of
questions
raised by the inspectors
during the Spring 1996 Unit 2
refueling outage.
In a November Office of Nuclear Reactor Regulation
(NRR) letter to the licensee staff,
NRR stated that they had reviewed IR
50-259,260,296/96-04
and that they had also reexamined the following:
~
TVA's 10 CFR 50.59 safety evaluation
and assessment
performed to
support bypassing the isolation function.
~
NUNRC 91-06,
"Guidelines for Industry Actions to Assess
Shutdown
Hanagement".
~
IR 50-259,260,296
which described
an inadvertent loss of reactor
vessel
inventory just prior to Unit 3 restart in November
1995.
~
IR 50-259.260,296/96-300,
documenting initial reactor operator
license examination results
where most candidates
gave incorrect
responses
to a question
on shutdown cooling valve interlocks.
~
A September
6,
1996 TVA submittal requesting
implementation of
improved standard technical specifications
based
upon NUREG-1433,
"Standard Technical Specifications
General Electric Plants
BWR/4".
~
An April 19,
1994 safety evaluation supporting
a TS amendment
which revised
LP coolant injection oper ability requirements
in
shutdown
modes.
Based
upon the review the
NRR staff concluded that TVA's actions to
bypass the isolation, while permissible with existing the TS was
inconsistent with overall industry practice
and
NRC standards.
As a
result of discussions
between
a letter
dated
October 22,
1996,
and committed to revise procedures.
The isolation
function would no longer
be bypassed.
TVA also stated that they would
revise their improved standard technical specification
(ISTS) submittal
to,be consistent with NUREG-1433 requirements for isolation oper ability
in shutdown
modes.
Based
upon this letter
and completion of
commitments,
URI 96-04-03 is closed.
li
0
R4
R4.1
a.
14
IV. Plant Su
rt
Staff Knowledge and Performance in ROC
Co-60 Calibration Source
Found Outside Its Desi nated Stora
e Location
Ins ection Sco
e
71750
b.
C.
The inspectors
reviewed licensee
actions regarding misplacement of a Co-
60 calibration source.
The review included follow-up observation of
areas
near the licensee-designated
radioactive source storage cabinet,
examination of a licensee-initiated
BFPER961412,
review of an October
21,
1996, radiological control
(RADCON) memo and discussions
with RADCON
management
and the Region II RADCON specialist.
Observations
and Findin s
On October 19,
1996,
a Co-60 Area Radiation Honitor (ARH) calibration
source
was found outside its designated
storage location.
A RADCON
technician discovered the source (located inside its own individual
case)
on the floor approximately 2 feet away from its locked source
storage
cabinet location.
The source's
case
was properly labeled
and
the sour ce itself was appropriately tagged
and contained inside of the
shielded
case.
Haximum case contact
dose readings
(from the -150pCu
source)
measured -2.5 mrem/hr.
In a discussion with the inspectors,
RADCON management
indicated that
a
member of their staff had removed the source,
and its source
case,
from
the cabinet in order to get to another
source
case.
The technician did
this in order,to record data listed on the other case.
The technician,
later in his shift, found that he needed
more data from the other
source
case.
After the second
check the technician forgot to place the 150pCu
source
back into its designated
storage locker as
he had done during his
first check.
This event was identified soon after it had occurred,
and due to both
source configuration
and location, the radiological
hazard
was low.
Conclusions
The cause of the event was
a lack of attention detail.
As noted by the
licensee,
handling of'y-product materials
requires strict adherence
to
criteria specified in licensee
procedure
SSP-5.3,
Controlling Byproduct
8 Source Haterial Sources.
As part of the licensee's
corrective actions
in a memorandum
dated October
21,
1996 event details were presented to
all licensee
RADCON staff and management
personnel.
Licensee
management
corrective actions included individual counseling.
This licensee-identified
and corrected violation is being treated
as
a
Non-Cited Violation, consistent with Section VII.B.1 of the
NRC
Enforcement Policy (260,296/96-12-03)
~
0
15
Pl
Conduct of Emergency Preparedness
(EP) Activities
P1.1
EP Trainin
Exercise/Drill
Observations
and Findin s
71750
On October 23,
1996, the inspectors
observed portions of the emergency
preparedness
training drill/exercise.
Through the inspectors'eview of the drill scenario
and observations
in
the Technical
Support Center
(TSC), it was determined that the drill was
challenging
due to the fast pace of the scenario.
In addition, the
initial conditions of. the scenario
had the unit in a refueling outage
which was
a positive exercise for the staff considering Unit 3 will
begin
a refueling outage in February 1997.
X1
Exit Meeting Summary
V. Mana ement Meetin s
The resident inspectors
presented
overall inspection period results to
licensee
management
on November 22,
1996.
The licensee
acknowledged the
findings presented
and the inspectors
asked the licensee
whether
materials
examined during the inspection should be considered
proprietary.
No proprietary information was identified.
Licensee
'PARTIAL LIST OF PERSONS
CONTACTED
T. Abney, Licensing Manager
J. Brazell, Site Security Manager
G. Bugg, Acting Manager,
Radiological Control
and Chemistry
R. Coleman, Acting Radiological Control Hanager
C. Crane, Acting Plant Hanager
J.
Johnson,
Site Quality Assur ance
Hanager
R. Jones,
Operations
Hanager
G. Little, Operations
Superintendent
R. Hachon, Site Vice President,
Br owns Ferry
G. Pier ce,
System Engineering
Hanager
T. Shriver,
Nuclear
Assurance
and Licensing Hanager
K. Singer,
Maintenance
Hanager
H. Williams, Engineering
and Haterials
Hanager
NRC
J. Williams, Browns Ferry Project Hanager
0
16
IP 37551:
IP 62707:
IP 71707:
IP 71750:
IP 92050:
IP 92700:
IP 92901:
IP 92902:
IP 93702:
INSPECTION PROCEDURES
USED
Onsite Engineering
Maintenance
Observations
Plant Operations
Plant Support Activities
Review of Quality Assurance f'r Extended Constrauction
Delays
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
Followup-Plant Operations
Followup-Maintenance
Prompt Onsite Response to Events at Operating
Power Reactors
Opened
ITEMS OPENED
CLOSED
AND DISCUSSED
T~
Item 'Number
Status
50-296/96-12-'Ol
Open
Descri tion and Reference
Failure to Ensure Proper Position of EDG
Aux Board
Room Exhaust
Fans
(Section 02.4)
01013
02014
Closed
Open
Open
RCIC Inoperability Following Replacement
of Turbine Exhaust
Check Valve (Section
E8.2)
Failure to Comply with IST Procedures
for
RCIC and
HPCI (Section E8.3)
~T
Item Number
'Status
50-260/96-12-02
Closed
50-259,260,296/
Closed
96-12-03
LER
50-296/94-002-00
Closed
LER
50-296/96-005-00
Closed
Descr i tion and Reference
SRV Bench Test Procedure
Not Followed
(Section E2.1)
Uncontrolled Radiological
Source
(Section R4.1)
A Deficiency Regarding
Raychem Tubing Used
for Environmental Qualification
Applications (Section
E8. 1)
Reactor
Scram Required by Technical
Specifications
Due to Trip of Reactor
Recirculation Hotor Generator
Set
3A
(Section 08.1)
0
0
0
IFI
50-.259,260,296/
95-64-11
Closed
17
Thread Lubricant Effects on Torque
Values (Section H8.1)
50-260/96-05-01
Closed
50-260/96-05-02
Closed
50-260/96-04-03
Closed
Discussed
~T
Item Number
Status
IFI
50-296/96-08-02
Open
IFI
50-259,260,296/
Open
'96-10-04
RCIC Inoperability Following Replacement
of Turbine Exhaust
(Section E8.3)
Failure to Comply With IST Procedures
for
Testing, RCIC and HPCI Following Exhaust
Check Valve Replacement
(Section E8.3)
SDC Low Level Isolation Bypassed Prior To
Cavity Flood-up (Section E8.4)
Descr i tion and Reference
Emergency Core Cooling System Inverter
Failure (Section 02.2)
EDG Haterial Condition Concerns
(Section H4.1)
0
0
0
Valve
Position
Setpoint
Serial Number
1st
2nd
Setpoint (psig)
3rd
4th
5th
6th
Setpoint
Deviation
Pilot Leakage
( ml / 5 min )
Pre-Leak
Post-Leak
Notes
2-PCV-01-004
1125
1078
1135
1134
1135
0.89
ND
ND
2-P CV-01-005
1115
1017
1240
1161
1121
1120
11.21
ND
ND
2-PCV-01-018
1115
1079
1147
1127
1123
1126
1121
2.87
ND
ND
2-PCV-01-019
1105
1072
1183
1106
1104
1104
1103
1112
7.06
ND
ND
7th: 1098
2-PC V-01-022
1115
1232
1129
1120
1110
1101
1110
1.26
ND
ND
2-PCV-01-023
1105
1084
1169
1115
1112
1110
5.79
ND
ND
2-PCV-01-030
1115
1061
1131
1121
1122
1126
1.43
ND
2-PCV-01-031
1105
1031
1141
1128
1119
1117
3.26
ND
ND
2-PCV-01-034
1105
1060
1163
1108
1105
1105
5.25
ND
ND
2-P CV-01-041
1125
1015
1183
1135
1134
1130
1135
1133
5.16
ND
ND
2-PCV-01-042
1125
1032
1160
1136
1136
1131
3.11
ND
ND
2-P CV-01-179
2-PCV-01-180
1125
1125
1064
1071
1136
1136
1124
1117
1116
1126
1122
1114
1125
0.98
0.98
ND
ND
ND
ND
7th: 1127,
8th: 1122,
9th: 1119
ND - data is not currently available. Willbe obtained from Wyle test report.
Attachment
e
0
'