ML18038B918
| ML18038B918 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 07/17/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B919 | List: |
| References | |
| 50-259-97-07, 50-259-97-7, 50-260-97-07, 50-260-97-7, 50-296-97-07, 50-296-97-7, NUDOCS 9707250142 | |
| Download: ML18038B918 (56) | |
See also: IR 05000259/1997007
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket .Nos:
License Nos:
50-259,
50-260,
50-296
Report Nos:
50-259/97-07,
50-260/97-07,
50-296/97-07
Licensee:
Valley Authority
Facil.ity:
Browns Ferry Nuclear Plant, Units 1,
2 & 3
Location:
Corner .of Shaw and Browns Ferry Roads
Athens,
35611
Dates.
May 11
- June 21,
1997
Inspectors:
Approved by:
L. Wert, Senior
Resident
Inspector
M. Morgan, Resident
Inspector
J. Starefos,
Resident
Inspector
M. Lesser,
Chief
Reactor Projects
Branch
6
Division of Reactor Projects
Enclosure
2
9707250i42 9707i7
ADOCK 05000259
8
0
0
EXECUTIVE SUMMARY
Browns Fer ry.Nuclear Plant, Units 1,
2
8 3
NRC Inspection Report 50-259/97-07,
50-260/97-07,
50-296/97-07
This integrated
inspection included aspects of licensee operations,
engineering,
maintenance,
and,plant support.
The report covers
a six-week
period of resident inspection.
0 erations
NRC inspectors identified that controls
on emergency operating instruction
(EOI) ladders
were not sufficient to ensure that ladders
remained available.
The ladder found at one station
was not sufficient to complete
an emergency
operating instruction task.
The ladders
were not controlled as strongly as
other emergency operating instruction tools.
The inspectors
concluded that
the extensive corrective actions listed in section 01.1 adequately
addressed
the violation and the underlying deficiencies.
The licensee significantly
improved controls on EOI ladders.
(Violation 260,296/97-07-01,
EOI Ladders
Not
Adequately Controlled, Section 01.1)
The licensee's
recent revision of Assistant Unit Operator
(AUO) work
assignments
is a good initiative.
During this period, only a very few
deficient equipment conditions were noted that had not been identified during
AUO rounds.
In addition to the good performance
noted involving an electro-
hydraulic fluid leak, several
other examples
were noted during this report
period in which AUOs identified and reported minor deficiencies.
(Section
02')
Haintenance
Overall conduct of Common Accident Signal testing
was good.
Workers were
particularly cautious regarding
component identification.
The prebriefing was
good, appropriate
issues
were highlighted by the supervisors.
The Test
Director was very important to the successful
implementation of the testing.
Hinor deficiencies involving documentation of step completion
and labeling
issues
are being addressed
by the licensee.
(Section Hl.l)
The inspector
concluded that the licensee
had implemented
good maintenance
controls over the installation of temporary cover s over the spent fuel pools.
(Section Hl.2)
NRC inspectors identified several
examples in which'Foreign Haterial Exclusion
administrative controls were not implemented properly.
No actual
instances of
foreign material introduction were identified.
Although overall
FHE controls
have been strengthened
since
1995, these deficiencies indicate that the
implementation of FHE .administrative controls is not consistent.
(Violation
260,296/97-07-02,
Foreign Haterial Exclusion Controls not Implemented in
Accordance with Procedures,
Section H1.3)
O~
il
il~
A review of a sampling of Inservice Test data indicated that the current
implementation of the program requirements
is adequate.
The licensee is
conducting appropriate monitoring of safety system valve and
pump operability.
(Section H1.4)
Review of the on-going Fire Protection piping replacement
and repair program
is adequate.
Overall, the licensee
has initiated significant actions,
including chemical treatment,
which have improved the overall reliability of
the
FP suppression
systems.
(Section H2.1)
An isolated
case
was identified in which the review for a planned voluntary
entry into a Technical Specification Limiting Condition for Operation
(LCO)
was not thorough.
Licensee
management
expectations
for planning regarding
entry into LCOs for modification work were not met.
The equipment
was not
actually removed from service
and corrective actions
were initiated
immediately.
The licensee
intends to revise procedural
guidance regarding
control of voluntary entry into LCOs.
(Section H3.1)
En ineerin
The licensee
has initiated actions to address
inaccuracies
in the calculations
for spent fuel pool temperature identified during the most recent refueling
outage.
No actual
adverse affects
on important plant equipment
were noted.
Additional review of the licensee's
practices
and the Updated Final Safety
Analysis Report descriptions of spent fuel pool cooling system capacity is
warranted.
(Inspection Followup Item 260,296/97-07-03,
Spent
Fuel
Pool
Cooling System
Heat Removal Capability, Section El.l)
Although engineering
personnel
pursued corrective actions to address
the
postulated
cause of an earlier spent fuel pool cooling pump problem,
a Problem
Evaluation Report was not initiated,
and plant management
was not informed of
the runout problem.
Subsequently,
the
pump failed.
The control
room
operators'ctions
following indications of pump failure did not meet
management
expectations.
Additional
NRC review of this issue will be
conducted
when more information is available
(Unresolved
Item 260/97-07-04,
Failure of Fuel
Pool Cooling Pump, Section E2.1).
Plant
Su
ort
Walkdowns of the protected
area security fencing and inspections of the
Central Alarm Station
and the Secondary
Alarm Station identified no
significant deficiencies.
Security personnel
in the alarm stations
were alert
and attentive to their duties.
(Section S2.1)
V
0
Re rt Details
Summar
of Plant Status.
Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Unit 2 operated at or near full power with the exception of'outine testing
and scheduled
maintenance
and the following power reduction.
On
Hay 22, at approximately.9:00
p.m.,
CDT,
(EHC)
oil leak occurred
on the servo valve for the
number.
2 turbine control valve.
Power was reduced to 70 percent rated thermal
power, the leak was isolated,
and the servo was replaced.
Power
was restored to full rated
power on Hay 23.
Unit 3 operated
at or near full power during the report period with the
exception of routine testing
and scheduled
maintenance
While performing the inspections
discussed
in this report, the inspectors
reviewed the applicable portions of the Updated Final Safety Analysis Report
(UFSAR) that related to most of the areas
inspected.
Section El.l describes
a
review relating to spent fuel pool cooling system capacity during refueling
outages.
An Inspection Followup Item was identified since additional
NRC
review is necessary
to ensure that the
UFSAR description accurately reflects
the licensee's
actual practices.
I.
rations
01
Conduct of Operations
01.1
Emer enc
0 eratin
Instruction Ladders
a.
Ins ection Sco
e
71707
On Hay 27,
1997, while performing a walkdown of the Unit 3 Reactor
Core
Isolation Cooling System,
the inspectors
noted that
an Emergency
Operating Instruction (EOI) ladder was not in its designated
ladder
storage station in the Unit 3 Reactor Building 541'levation.
The
inspectors
subsequently
examined the controls associated
with EOI
ladders throughout the plant.
b.
Observations
and Findin s
On Hay 27,
1997, while performing
a walkdown of the Unit 3 Reactor
Core
Isolation Cooling System,
the inspector noted that the Emergency
Operating Instruction (EOI) ladder
3-RB-541-1, which is required to
perform specific EOI appendix actions
was not in its designated
hanger.
The inspector
noted that
a ladder was available for use in the area
and
that
a scaffold was in place for work in the area
where the ladder would
be needed.
0
The inspector subsequently
examined
EOI Inventory Form No. 0-EOI-000-
0010,
EOI Ladder Stations
(Unit 2/3) which is Attachment
15.22 of
General
Operating Instruction O-GOI-300-1, Operations
Routine Sheets.
The inspector
determined that discrepancies
existed regarding
two of the
eleven
adders
on the inventory form.
The form required
a
10 ft
extension
ladder at ladder station 3-T8-565-1, but
a 10 ft step ladder
'as
found at the location.
A 10 ft step ladder
was also found at ladder
station 3-RB-565-1 which required
a 20 ft extension ladder.
The
licensee
was informed of the problem and promptly initiated
a problem
evaluation report
(PER).
On June
12,
1997, the inspectors
sampled
EOI Appendix actions to
determine if the
10 ft step ladders
would have
been acceptable
to
perform required valve manipulations.
The 10 ft step ladder
which was
previously found in ladder station 3-RB-565-1 was determined to be
inadequate
for performance of 3-EOI APPENDIX-7J, Alternate
RPV [Reactor
Pressure
Vessel] Injection System Lineup HPCI [High Pressure
Coolant
Injection] Using Auxiliary Steam,
Revision 0, step 9c which requires
dispatched
personnel
to slowly open 3-SHV-012-0798,
During the June
12 walkdown, the inspectors
also identified three valves
which were addressed
in the
EOI Appendices which did not have
EOI tags
on the valves.
(These
EOI tags are orange labels
used to facilitate EOI
component identification, valve identification labels were in place.)
The licensee
promptly placed
EOI tags
on the identified valves.
In
addition, the inspectors
reviewed
a draft revision to 0-GOI-300-1
Attachment 15.22 to verify that
a sample of the described
ladders
were
in place.
The inspectors
found that
adder station 2-TB-565-1 had
a
16 ft ladder in place instead of the 20 ft ladder described
by
Attachment 15.22.
The licensee
was informed and promptly placed
a 20 ft
ladder in ladder station 2-TB-565-1.
Although a 20 ft ladder
was more
appropriate,
the inspectors
determined that
a 16 ft. ladder would not
have
been inadequate.
General
Operating Instruction O-GOI-300-1, Operations
Routine Sheets,
Attachment 15.22,
EOI [Emergency Operating Instruction] Tools and
Equipment Inventory Checklist,
dated
May 5,
1997, states that ladders
are secured with GGHKA padlocks at the designated
EOI ladder stations.
Included in Attachment 15.22 is EOI Inventory Form 0-EOI-000-0010
Ladder Stations
(Unit 2/3) which describes,
in part,
a 20 ft Extension
Ladder, in place
and padlocked,
at ladder station 3-RB-565-1, Reactor
Building Elevation 565'.
The inspectors
noted that
EOI ladders
were not as rigidly controlled as
other
designated
EOI tools.
The licensee
also permitted
EOI ladders to
be used for other purposes.
The failure to adequately establish written procedures for EOI ladder
station control
as identified on Hay 27,
1997,
when the required
20 ft
extension
ladder
was not in place
and padlocked in ladder station
3-RB-565-1 is identified as Violation 50-260,296/97-07-01,
EOI Ladders
Not Adequately Controlled.
il~
0
0
The following is
a list of many of the licensee's
corrective actions
as
identified in Problem Evaluation Report
(PER)'FPER970889:
The ladder at ladder station 3-RB-541-1 was returned to proper
location by on-shift Operations
personnel.
This item was completed
Hay 2,
1997.
An item'as
added to Operations Daily Instructions,
reminding on-
shift Operations
personnel
EOI ladder
usage .is to be restrained
to
EOI use only.
This item was completed
Hay 28,
1997.
All EOI ladders,
as addressed
in Procedure
O-GOI-300-1,
Attachment 15.22,
were verified in place, properly stored,
padlocked,
and
a numbered
EOI seal
was placed
on the lock hasp.
This action was completed
June 4, 1997.
A walkdown audit of all Unit 2 and Unit 3 EOI appendices
was
performed by BFN Operations
Support.
This audit field-verified
in-plant component manipulations with the potential
for ladder
use.
This action was completed
June 4,
1997;
One ladder,
Ladder Station 2-RB-565-1 was found to contain
a
24 foot ladder vice a 20 foot ladder
(referenced
as
a
10 foot
extension)
~
The 24 foot ladder
was deemed to be more appropriate.
O-GOI-300-1, Attachment 15.22 will be revised to reference
the
24 foot ladder at this station.
This action was completed with
O-GOI-300-1, Revision 44, issued
June 6,
1997.
The walkdown determined
no new ladders
were required.
This action
was completed
June 4,
1997.
All ladders
had
new signs placed
on the wall at each station,
signifying "FOR EOI
USE ONLY."
These signs were incorporated into
the licensee's
Permanent
Information Posting
(PIP) program
and
will be audited
as part of that program. This action was completed
June 5,
1997.
All ladders
were individually labeled with orange
EOI labels which
were also
added to the PIP program.
This action was completed
June 5,
1997.
O-GOI-300-1, Attachment 15.22 will be revised to include corrected
information identified during walkdowns
and added
EOI seal
number
to audit.
This action was completed with O-GOI-300-1,
Revision 44, issued
June
13,
1997..
Operations
revised all affected Unit 2 and Unit 3 EOI appendices
to reference the potential
use of a ladder for appropriate
steps
and to include designated
ladder in Tools and Equipment Attachment
in each associated
appendix.
This action was completed
June 23,
1997.
0
0
C.
Conclusions
NRC inspectors identified that written procedures
were not adequately
established
to ensure control of EOI ladders.
The inspectors
concluded
that the extensive
and expedient corrective actions listed in. this
section adequately
addressed
the violation and the underlying
'eficiencies.
Controls were significantly improved for EOI ladders.
EOI ladders will be treated similar to other
EOI equipment
and
will
only be used for
EOI purposes.
02
Operational
Status of Facilities and Equipment
02.1
Reactor
Core Isolation Coolin
S stem Walkdown
a.
Ins ection Sco
e
71707
The inspector
conducted
an. inspection of the operational
status of the
Unit 2 and Unit 3 Reactor
Core Isolation Cooling (RCIC) Systems.
b.
Observations
and Findin s
On Hay 28,
1997, the inspector performed
a review of the control
room
position indication for selected significant, valves in the Units 2 and 3
Reactor
Core Isolation Cooling (RCIC) Systems.
The inspectors
also
performed walkdowns of portions of the RCIC systems
on both units.
The
inspector
noted that an Emergency Operating Instruction (EOI) ladder was
not in its designated
ladder storage
station in the Unit 3 Reactor
Building 541'levation
as discussed
in Section 01.1 of this report.
In addition, the inspector performed'
review of outstanding
work order s
on the Unit 2 RCIC system.
The inspector did not identify any
inappropriately delayed maintenance
issues or other problems.
The inspector also verified that
a procedure
step to locally exercise
the RCIC turbine control valve by depressing
the servo approximately
2 inches to ensure
no binding of the control valve stem had been
removed
from Surveillance Instruction (SI) 2/3-SI-4.5.F.1.d,
RCIC System Rated
Flow at Normal Operating Pressure.
The step
was removed from the Unit 2
procedure with the issuance of Revision 27 effective 3/25/97
and from
the Unit 3 procedure with the issuance of Revision 7 effective 3/31/97.
02.2
E ui ment Condition and Watchstandin
Activities
a.
Ins ection Sco
e
71707
The inspectors
examined the condition of important plant equipment
during tours of the plant.
One of the inspectors
also obser ved an
Assistant Unit Operator
(AUO) perform daily rounds of the Unit 3 Reactor
and Turbine Buildings..
0
b.
Observations
and Findin s
On June
12,
1997., the inspector observed
performance of technical
instruction O-TI-165A, Appendix
R Backup Control Test for EECW, section
7.3,
0-FCV-67-22 Test.
The inspector
observed the Assistant Unit
Operator perform several
steps at the breaker
compartment
and noted that
the operator verified the correct components prior to performance of the
action.
The inspector also observed
an independent verification step
and
a second party verification step which were accomplished
in
accordance
with the licensee's verification program.
On June
14,
1997, the inspector
observed
an Assistant Unit Operator
(AUO) perform daily rounds of the Unit 3 Reactor
and Turbine Buildings.
The AUO identified and addressed
discrepancies
appropriately.
As
discussed
in NRC Inspection Report 50-259,260,296/97-05,
the licensee
has recently revised work assignments
to the AUOs with the intent to
reduce interruptions to AUOs while on plant tours
and improve the
effectiveness of the rounds.
Currently one
AUO is assigned to perform
Reactor Building and Turbine Building rounds while another
AUO is
designated
as support.
During the rounds observed
on June
14,
1997, the
inspector
noted that only a single request
was
made of the rounds
which was outside of his assigned
rounds duties.
On Hay 25,
one of'he inspectors
noted that the "A" train Standby
Gas
Treatment
(SBGT) System backdraft
was stuck open.
A 1996 work
request tag for lubrication was attached to the damper.
Apparently, the
had not shut after the train was operated the previous day.
Operations shift management
reported to the inspector that the damper
condition did not adversely affect train operability.
The inspector
noted that the damper condition had not been identified by Operations
personnel
during rounds.
Additionally, the inspector
noted that the Continuous Air Honitor (CAN)
located near the "A" SBGT system
had
a Work Request tag dated February
14,
1997, attached.
The tag stated
"CAN not counting correctly."
The
inspector
conducted additional
review since the tag implied that the
CAH
may be inoperable.
Radiological Controls personnel
consider ed the
CAH
to be operable
since the routine functional test
was completed
satisfactorily.
The inspector subsequently
determined that
a problem in
the
CAN calibration procedure
had resulted in the generation of the work
request
and the
CAH was actually operable.
A Problem Evaluation Report
had been previously initiated to address
the calibration procedure
problem and was modified to included this specific CAN.
The inspector
noted that the calibration procedure did not require that the workers
notify Radiological Controls personnel
when the
CAH could not be
calibrated.
The inspectors
noted that an Electro-Hydraulic
(EHC) fluid leak that
occurred
on the Unit 2 number
2 turbine control valve on Nay 22 was
handled well.
During rounds, the
AUO noted that the
EHC reservoir
level
had. decreased
unexpectedly
and notified the control
room.
Shortly
thereafter,
the low level annunciator
alarmed.
The alarm response
ik
08.1
procedures
were implemented.
Good teamwork between the various work
groups resulted in the source of the leak being identified, isolated,
and repaired very quickly.
Conclusions
The inspectors
concluded that,
although not all deficient conditions
were identified by AUOs during rounds,
the licensee's
recent revision of
AUO work assignments
is
a good initiative.
In addition to the good
performance
noted involving the
EHC leak,
several
other
examples
were
noted during this report period in which AUOs identified and reported
deficient or questionable
conditions.
Hiscellaneous
Operations
Issues
(92901)
Withdrawn
Violation 260/94-14-01
Inadequate
Procedure Controlling
Voluntary Technical Specification
(TS) Limiting Condition for Operation
(LCO) Entries.
This violation addressed
an incident in which the
onshift Shift Technical Advisor (STA) identified that planning efforts
for modification work involving the
3D emergency diesel
generator
had
not addressed
affects
on standby coolant supply from the Bl and
B2
residual
heat
removal service water
(RHRSW) pumps.
The TS
LCO for
standby coolant
(30 days)
had not been entered until about five hours
after the
EDG was removed from service.
The licensee
responded to the violation on July 28,
1994, with a
position that
a violation did not occur .
The licensee did not contest
the underlying issues'ut
stated that the incident involved
noncompliance with a verbal
commitment
made at
a TVA/NRC meeting
on
Hay 10,
1994.
At that meeting,
TVA presented
plans for controlling
Unit 3 recovery activities that would require entry into a Unit 2 TS
LCO.
In an August 26,
1994, letter to TVA, NRC withdrew the violation.
The
letter stated that since the commitment involving the Unit 2
LCO entries
due to Unit 3 work was not
a formal written commitment,
a notice of
deviation will not be issued.
Because
the Unit 3 restart is complete,
many aspects of this issue are
.
no longer pertinent at Browns Ferry.
Section
H3.1 of this report
describes
NRC inspection of TS
LCO entries for any modification work
(not just operating unit affected by restart of a shutdown unit) which
are related to this incident.
Additionally, as described in Inspection
Report 259,260,296/97-04,
detailed
NRC review of the licensee's
controls
over removal of plant equipment
from service
was recently performed.
0
II. Haintenance
H1
Hl.l
a.
b.
Conduct of Haintenance
Survei11ance
Testin
of Unit 1 and Unit 2 Common Accident Si nal
~Lo
1C
Ins ection Sco
e
61726:
The inspectors
monitored the performance of portions of Surveillance
Instruction 1/2-SI-4.9.A.3.a,
Common Accident Signal Logic.
This is a
complex surveillance
which requires several shifts and coordination
between
numerous
workers to complete.
One of the inspectors directly
observed
most of the Division I testing.
Operation of the emergency
diesel
generators
(EDGs) in accordance
with Operating Instruction OI-82,
was observed.
The completed procedure
was reviewed.
The inspectors
also
reviewed applicable plant drawings,
the
and TS to verify that
selected plant equipment
was adequately
addressed
by the testing.
Observations
and Findin s
The inspector noted that the pre-briefing for the testing was good.
Communication issues,
self checking,
and correct second party checking
wer e emphasized
several
times during the briefing.
Deficiencies during
previous testing were also discussed.
It was emphasized that the
testing included operation of equipment in different units.
The test
director clearly explained expectations
during the testing.
During the observed division I testing. the inspector
noted that workers
were cautious regarding correct
component identification and self
checking.
Several
examples
were noted in which the equipment label did
not match the wording used in the test procedure.
In at least
one case,
the workers stopped the test
and requested
additional
guidance to ensure
the correct
component
had been identified. There were more than 30
validation comments submitted by the test personnel.
The Test Director
was instrumental
in ensuring proper coordinatson
between the different work groups
and locations during the test.
The
inspector observed that the director was very familiar with the test
procedure
and equipment involved.
The inspectors
observed
some of the
EDG operations
conducted
as part of
the test.
It was noted that one
AUO did not verify that the
electrical control cabinet exhaust
fan was running.
Subsequent
discussion with the system engineer indicated that proper
operation of
the fans is important to prevent failures in the cabinet
due to
excessive
heat.
The inspectors
informed Operations
management that the
check was not properly performed by the AUO.
0
The inspector
noted that alligator clips were used in several
applications during the test.
Although the workers were careful to
fully attach the clips, this is not
a good practice.
In several
sections of this test,
an alligator clip slipping off of a contact could
have significant effects
such
as
an inadvertent
engineered
safety
features
actuation.
Operating personnel
donned the protective clothing required by General
Operating Instruction 300-2, Electrical,
when racking the 4160V shutdown
board
br eakers to the "test" position.
On several
portions of the test,
the sign off for completion of one step
was not always completed prior to performance of another step.
An
example would be booting several
contacts in a particular re'lay.
Workers would identify the relay,
mark it with orange tape
as expected,
and carefully perform the listed actions. After the steps
associated
with the specific relay were completed,
the workers would sign the
individual steps.
The inspector
noted that the test director was
careful to ensure that each step was, in fact, completed prior to
proceeding.
This practice
has
been observed during other surveillance
tests
and licensee
management
is reviewing the guidance currently set
forth in SSP-2.1,
Site Procedures
Program for signing off steps of
continuous
use procedures.
Revision of some continuous
use procedures
may be appropriate
so that successful
performance of steps is not
impacted by stopping to sign steps.
The inspectors
selected
several
portions of the
common accident
circuitry and verified that the test adequately
addressed
the entire
circuit.
In some cases,
relays
used to actuate portions of the
circuitry are tested
by other test procedures.
The inspectors verified
that those procedures
addressed
the specific relays required.
The
inspectors
also examined the functioning of the
common and pre-accident
circuitry in regards to the
UFSAR descriptions
and drawings.
The
completed test procedure
was reviewed.
No deficiencies
were identified.
Conclusions
Overall conduct of the testing was good.
Workers were particularly
cautious regarding
component identification.
The prebriefing was good
and appropriate
issues
were highlighted by the supervisors.
The
inspector
concluded that the Test Director
was very important to the
successful
implementation of the testing.
Hinor deficiencies involving
documentation of step completion
and labeling issues
are being addressed
by the licensee.
The large
number of validation comments indicate that
worker s are making efforts to improve the quality of the procedure.
ik~
0
0
~
Hl.2
a.
b.
Tem orar
S ent Fuel
Pool Covers
Ins ection Sco e
62707 92902
On May 28 and 29,
one of. the inspectors
reviewed the licensee's
maintenance activities associated
with Work Order
(WO) 97-004237-000,
. Remove Paint on
14WF I-Beams.
This involved removal of loose paint from
overhead
areas
on the refueling floor.
Covers were installed over the
spent fuel pools
(SFPs)
during the activities.
Violation 260/96-13-01
addressed
previous .maintenance
control deficiencies
associated
with
installation of the
SFP covers.
The inspector
reviewed the work
package,
held discussions
with involved workers
and supervisors,
and
inspected
the installed
SFP covers.
Observations
and Findin s
WO 97-004237-000 instructed workers to remove loose paint from the areas
in accordance
with Modification and Addition Instruction MAI-5.7
Painting
and Coating.
The
WO also referenced
Procedure
MSI-0-000-
PR0007, Installation and Re~oval of SFP Covers
and O-TI-264, Scaffolds
and Temporary Platforms.
The work package
contained the latest revision
of both procedures.
The inspector noted that the status of the ongoing
work was accurately indicated by the completed steps
signed off in the
WO.
By discussion with involved workers, the inspector determined that
no lead based paint had been
removed from the beams
so the precautions
required for such paint removal
were not applicable.
The inspector
reviewed the 50.59 safety assessment.
The assessment
was
performed in accordance
with Site Standard Practice
SSP-12.13,
10 CFR 50.59 Evaluations of Changes,
Tests,
and Experiments.
The assessment
focused
on the potential effects of the cover on the ability of the
cooling system to remove decay heat.
The assessment
stated that the
cover was to be installed after the evaporative/convectional
heat losses
from the pool would be insignificant compared to the
SFP cooling heat
exchanger
cooling.
The cover installation procedure
and the work order
contained
steps to require that at least
60 days
had passed
since the
last core offload and the pool was less than
125 degrees
F before the
cover was to be installed.
The inspector noted that the assessment
did
not address
potential effects of the cover on ventilation systems.
Subsequently,
the inspector
was informed by engineering that the cover
material
allowed air to pass through.
The inspector
concluded that
potential effects of the cover s regarding ventilation had been
satisfactorily addressed.
The assessment
adequately
addressed
other
issues
such
as combustible material loading.
The inspector verified that the covers were installed in accordance
with
the work control documents.
The cover
was fastened
as described
and the
ropes utilized were of the material
referenced in the safety assessment.
There was not a significant accumulation of material
on the covers
and
no holes were visible.
During the review, the inspector identified
several
problems associated
with foreign material exclusion practices
on
10
the refueling floor. Those deficiencies
are addressed
in Section Hl.3 of
this report.
c.
Conclusions
The inspector
concluded that the licensee
had developed
and was
- implementing .good maintenance
controls over the process of removing the
paint and installing the
SFP covers.
H1.3
Forei
n Haterial Exclusion
FHE
Practices
a.
Ins ection Sco
e
62707
During routine tours of the facility and observations of maintenance
activities, the inspectors
reviewed Foreign Haterial Exclusion
(FHE)
practices
and associated
documentation.
The inspectors
reviewed the
activities for compliance with Site Standard Practice SSP-12.8,
Foreign
Haterial Exclusion.
b.
Observations
and Findin s
During observation of several
maintenance activities and review of FHE
documentation,
the inspectors identified the following deficiencies:
The
FHE logs for the spent fuel pool areas
were not being
maintained in accordance
with the guidance in SSP-12.8.
FHE
monitors were not numbering the inventory pages properly, not
recording work activities and/or workers,
and not properly
updating the log after activities were completed.
It was
difficult to determine exactly what material
was inside the pool
areas,
particularly on Unit 2.
Step
12 of Section 3;5.A of SSP-12.8
requires that
a baseline
inventory be performed
and the log book reconciled prior to
activation of an
FHE area after it has
been inactive for greater
than seven
days.
In a majority of the cases
examined,
these
actions were not being performed
on the spent fuel pool areas.
Instruction 1.0.C of Appendix
E of SSP-12.8 states that clear
material
or other material
which would be difficult to identify
underwater shall not be used
on the Refuel Floor, unless
specifically authorized
by the refueling floor SRO,
SOS, or
Haintenance
Supervisor.
On Hay 29,
1997, the inspector observed
personnel
handling
a roll of clear plastic wrap material
on the
refueling floor.
The inspector determined that the material
was
being utilized on the refueling floor in support of health physics
activities such
as covering personnel
monitor detector
sensors.
On Hay 28,
1997, during review of WO 97-004237-000
documentation
(see Section H1.2), the inspector identified that Form SSP-62,
FHE
Requirements
Reference
Sheet,
was not filled out as required by
Section 3.2 of SSP-12.8.
Review of the
FHE logs indicated that
0
0
11
the proper levels of FHE controls were implemented in the 'SFP
areas
during the work.
~
On June 2,
1997, during review of WO 97-003911-000
documentation
(1B/1D residual
heat
removal
system heat exchanger cleaning),
the
inspector
identified that Form SSP-62,
FHE Requirements
Reference
Sheet,
was not filled .out properly.
The form indicated that
FHE
controls were required which'were not actually required
and were
not being implemented.
~
During observation of 1B residual
heat
removal
(RHR) heat
exchanger
cleaning,
the inspector
noted that no
FHE covers
had
been installed
on the
RHR service water lines which opened into
the heat exchanger.
Although SSP-12.8
does not contain specific
directions to install covers
on these
openings,
due to their size
and location, they appeared to be vulnerable to foreign material
introduction during the cleaning work.
The inspector discussed
these observations
with the involved workers and
plant management
upon identification.
The licensee's
FHE coordinator
reviewed the refueling floor FHE logs in detail
and initiated Problem
Evaluation Report BFPER970902.
The clear material
was removed from the
area
and BFPER970899
was initiated.
Haintenance
super vision corrected
the SSP-62
form, stopped the
RHR heat exchanger
work, and installed
an
FHE barrier on the
RHRSW piping openings.
Further, the licensee
reviewed
an additional
sampling of WOs and identified only one other
deficient Form-62.
The inspectors
had observed that overall
FHE controls during the recent
Unit 3 refueling outage were strong, with only one specific instance of
poor
FHE practices identified by the inspectors.
(See
IR 97-03)
In October
1994,
and in August 1995,
NRC inspectors identified
FHE
control deficiencies
which were violations of regulatory requirements
(IRs 94-27 and 95-51).
The inspector s reviewed the earlier violations
to determine if the most recent
issues
should be classified
as
a repeat
violation.
The earlier deficiencies
were mainly associated
with the
interior of the suppression
chamber.
Some aspects of the deficiencies
noted
above are similar to previously identified issues in that
implementation of FHE control processes
was not in accordance
with
procedures.
However, in the previous instances,
uncontrolled material
was actually found within, FHE control areas.
Violation 296/95-51-01,
Failure to Properly Control Haterial Within an
FHE Zone, involved torus area
FHE deficiencies.
The corrective actions
included significant programmatic actions to strengthen
the
FHE programs
at BFN. A single point of contact for
FHE issues
was established,
SSP-
12.8 was revised,
and
FHE monitor training was strengthened.
The
inspectors
concluded that the most recent deficiencies
wer e primarily
failures to follow administrative
processes
intended to ensure that
foreign material is properly controlled.
Unlike the previously
O~
0
0
C.
H1.4
a.
b.
12
identified FHE violations, this inspection did not identify any actual
cases of foreign material introduction into open systems.
Conclusions
The failures to follow procedure
SSP-12.8,
FHE Control, represent
a
.violation of 10 CFR 50, Appendix B; Criterion V.
The deficiencies will
be addressed
as Violation 260,296/97-07-02,
Foreign Haterial Exclusion
Controls not Implemented 'in Accordance with Procedures.
No actual
instances of foreign material introduction were involved, but
implementation of effective
FHE controls is important to safe plant
operation.
Although overall
FHE controls have been strengthened
since
1995, the recently identified deficiencies indicate that the
implementation of FHE administrative controls is not consistent.
Licensee Administration of the Inservice Testin
Pro
ram
Ins ection Sco
e
73756 37551
The inspectors
performed
a review of the administration of the IST
program.
In accordance
with guidance
contained in IP73756
and IP37551,
the inspectors
reviewed the general
IST program and test results
of'arious
Residual
Heat Removal
(RHR) and Core Spray
(CS) system
pumps
and
valves.
Observations
and Findin s
During the inspection period, the inspectors
reviewed various aspects of
the licensee's
on-going IST program.
Five randomly selected
pumps
(two
from Unit 2, two from Unit 3 and one from Unit 1) and six randomly
selected
valves (three from Unit 2 and three from Unit 3) were chosen.
Test results
over the past
18 months of operation for the selected
equipment
was evaluated.
The following was indicated in this review:
3A CS Pump Performance
Was tested at least quarterly
Vibr Lvls 0.65 (+/- 0.15) mils
Total
Hd 233.80 (+/- 5.0) psig
2C
RHR Pump Performance
Was tested at least quarterly
Vibr Lvls 0.59 (+/- 0.30) mils
Total
Hd 267.50 (+/- 3.5) psig
1D RHR Pump Performance
Was test at least quarterly
Vibr Lvls 0.42 (+/- 0.20) mils
Total'd 266.20 (+/- 3.0) psig
3B RHR Pump Performance
Was tested at least quarterly
Vibr Lvls 0.65 (+/- 0.20) mils
Total
Hd 257.50 (+/- 2.5) psig
2D CS Pump Performance
Was tested at least quarterly
Vibr Lvls 0.38 (+/- 0.10) mils
Total
Hd 245.50 (+/- 4.5) psig
0
0
0
13
Loop I 'CS Iso Vlv 2-FCV-75-25
Was tested at least quarterly
Hax Closing Time Allowed - 30 sec
Average Closing Time
- 28.6 sec
Hax Opening, Time Allowed.- 30 sec
Average Opening Time
- 28.4 sec
P
3B RHR Pmp Inlet Vlv 3-FCV-74-24
Was tested at least quarter ly
Hax Closing Time Allowed
- 180 sec
Average Closing Time
- 117.8 sec
Hax Opening Time Allowed - 180 sec
Average Opening Time
- 121.1 sec
Loop I CS Iso Vlv 3-FCV-75-25
Was tested at least quarterly
Hax Closing Time Allowed - 30 sec
Average Closing Time
- 28.2 sec
Hax Opening Time Allowed - 30 sec
Average Opening Time 29.2 sec
Loop II CS Iso Vlv 2-FCV-75-53
Was tested at least quarterly
Hax Closing Time Allowed
- 30 sec
Average Closing Time
- '27.6 sec
Hax Opening Time Allowed - 30 sec
Average Opening Time
- '29'.1 sec
L'PCI Outbd Iso Vlv 3-FCV-74.-53
Was tested at least quarterly
Hax Closing Time Allowed
- 40 sec
Average Closing Time
- 33.0 sec
Hax Opening Time Allowed - 40 sec
Average Opening Time
- 32.4 sec
LPCI Outbd Iso Vlv 2-FCV-74-53
Was tested at least quarterly
Hax Closing Time Allowed - 40 sec
Average Closing Time
- 33.7. sec
Hax Opening Time Allowed - 40 sec
Average Opening Time
- 31.4 sec
C.
Overall testing methodology used for the reviewed
pumps
and valves
was
considered to be acceptable
and in accordance
with 10 CFR 50.55a
requirements.
Conclusions
The licensee's
current implementation of the IST progr am requirements is
adequate.
The licensee is conducting appropriate monitoring of safety
system valve and
pump operability.
Maintenance/Material
Condition of Facilities/Equipment
(61726,
62707)
.H2.1
Fire Protection
Pi in
Re air /Re lacement
a.
Ins ection Sco 'e
62707
b.
The inspectors
observed corrective maintenance
repair activities
involving 12-inch
FP piping, replacement
on Unit 3.
Some repairs to 2-
inch
FP hose station piping were also obser ved.
In accordance
with
IP62707, the inspectors
performed field reviews of related piping
replacement
work orders
(WO 96-002856-000
and
WO 97-004887-000).
The
inspectors
also reviewed the overall status of FP piping given that
microbiological-induced
cor rosion (HIC) has
caused
some piping leaks.
Observations
and Findin s
On April 29,
1997, inspectors
obser ved repair activities being performed
on the Unit 3 12-inch
FP piping.
Repairs involved replacement of about
15-feet of 12-inch ASHE (ASA B31.1) standard
carbon steel piping.
The
repair was being performed because microbiologically induced corrosion
had caused
some pin-hole leaks in the piping.
According to the
WO,
il~
14
weldment information and work package,
nominal piping thickness
was
equal to 0.375 inches with a minimum calculated thickness of
0.328 inches
all.owable for the weldment.
The inspectors
noted that
during the original
"new piping to existing piping fit up," the existing
piping edge
was less than the allowable minimum.
A build-up of the
existing piping edge to greater
than 0.328 inches
was completed.
The inspectors
questioned
the licensee
about the actual wall thickness
of the remaining portions of existing fire protection piping.
The
licensee stated that ultrasonic testing of selected
areas of FP piping
had been performed
and that this testing indicated
some thinning of the
pipe walls (lowest points measured
were 0. 197 to 0.220 inches).
The
general
overall average
pipe thickness
was greater than the minimum
allowable, with 0.330 inches
average wall thickness.
The inspectors
also questioned
the licensee
about observed levels of
erosion
and corrosion in the old piping.
The licensee
acknowledged that
while some sediment
and general
corrosion
was found in much of the
piping, the primary concern
was formation of microbiologically induced
corrosion sites (sites that were noted in low flow areas of the
piping).
On Hay 21,
1997, the inspectors
observed the condition of the 2-inch
piping removed from a hose station located in the facility's river water
intake structure.
Repairs
were being performed to replace patching that
had been
used for temporary repair of pin-hole leaks in the piping; 'The
interior of the piping contained
evidence of HIC and general
corrosion.
At one of the HIC sites,
a small through wall leak had occurred.
Given this information, the inspectors
questioned
the licensee
regar ding
confidence that
FP piping would not fail resulting in damage to
important plant equipment.
Additionally, the inspectors
discussed
whether loose corrosion products
or sediment
could potentially block
spray nozzles.
The licensee
has initiated actions to prevent
FP suppression
system
inoperability due to piping failures.
These actions
address
the
problems typically experienced
in raw water suppression
systems.
Several
engineers
described the licensee's
High Pressure
Fire Protection
Pipe- Replacement
Program.
The program addresses
replacement of the
major
above ground high pressure
piping headers
(wet) in the reactor
building, turbine building,
and diesel
generator buildings.
In the last
ten years,
more than one half of the originally installed
FP piping has
been replaced.
The program sets forth priorities for piping replacement.
Piping replacement
recommendations
are scheduled for several
years in
the future.
Host of the applicable piping in the Unit 2 and Unit 3
reactor buildings has
been replaced.
Unit 1 reactor
building piping
replacement is in progress.,
Significant portions of piping in the
turbine building has not been replaced.
il~
15
The inspectors
have noted that when leaks are identified in the
piping, corrective actions are initiated.
The actions include
containment of leakage
and pipe patching
as necessary.
The licensee
stated that experience to date indicates that leaks in above ground
piping have been identified while still small in size (pinholes).
No
catastrophic failures of above ground piping have occurred.
Fire protection personnel
stated that the chemical treatment of the raw
water system which supplies the
FP system
has resulted in improvement in
the system conditions observed
dur ing testing.
For example,
during
flushing of strainers, little or
no material is found within the system.
Previously,
during some testing in previous years,
blockage of some
spray nozzles
had been noted but no longer occurs.
Conclusions
The inspectors
concluded that the on-going
FP piping replacement
and
repair program is adequate.
Overall, the licensee
has initiated
significant actions,
including chemical treatment,
which have improved
the reliability of the
FP suppression
systems.
The inspectors
concluded
that the licensee
has
an adequate
basis to conclude that
a sudden large
leak or rupture of'bove ground piping is not likely.
Haintenance
Procedures
and Documentation
Controls of Voluntar
Entr
Into Technical
S ecification Limitin
Conditions for 0 erations for Hodification Activities
a.
. Ins ection Sco
e
62707 92902
One of the inspectors
reviewed the licensee's
plan to remove
a train of
the Control
Room Emergency Ventilation .(CREV) System from service to
perform maintenance activities.
The inspector
reviewed the scheduled
work activities and the requirements
in Site Standard Practice
SSP-7.1,
Work Control; SSP-6.2,
Haintenance
Hanagement
System;
and SSP-9.3,
Plant
Hodifications and Design Change Control
0
b.
Observations
and Findin s
Early on June 5, 1997, the inspector
reviewed the approved detailed
planned work schedule,
which the licensee
commonly refers to as
a
"fragnet," for CREV 8 train charcoal tray changeout
per O-SI-4.7.E.4.B.
A fragnet is
a detailed schedule
which contains
a timeline of all
scheduled
work activities associated
with a particular system or train
of a system.
Work progress
and status is tracked against the fragnet by
the onshift and work scheduling personnel.
The inspector
noted that
approximately eight hours of the total scheduled
time for the planned
CREV train inoperability was associated
with Stage
4 of Hodification
T39971A (Work Plan 96-012074-002).
This work activity involved changing
the wire type/size
from the moisture element to the moisture transmitter
in flow loop 0-F-31-7213
(CREV B).
The inspector noted that, contrary
to most licensee
fragnets,
the time allotted fot the modification work
0
16
was not scheduled
in parallel with required corrective/preventive
maintenance
or testing.
Section 3.2.3 of SSP-7.1,
Voluntary Entry .into a Technical Specification
(TS) Limiting Condition for Operation
(LCO) for Modifications that
Result in Placing Unit 2 or Unit 3 in an
LCO, contains specific
. requirements for review and concurrence of'uch work during the planning
process.
These include Plant Operations
Review Committee
and Plant
Manager approval.
The work was scheduled to begin on the evening of
June 5.
The inspector questioned
the onshift Shift Technical Advisor
(STA) regarding
how these
requirements
were going to be met in this
case.
Subsequently,
the licensee
removed the modification work from the
fragnet
and performed only the preventive maintenance activity and
necessary testing.
This resulted in the train of CREV being inoperable
for a shorter duration.
The licensee's
work scheduling
group usually
controls the scheduling of such modification activities such that the
work is performed in parallel with required or necessary
maintenance
activities.
A TS
LCO is not typically entered in order to perform
modification work, but such work may be done if the system is rendered
inoperable for some other
work.
As such, the requirements of
Section 3.2.3 of SSP-7. 1 would not require specific review/approval.
The
inspectors
have not identified any similar previous examples.
No violation of regulatory requirements
occurred since the licensee did
not remove the system from service for the modification work.
The
inspector also noted that the SSP-7.1
requirements
do not distinguish
modification work which is corrective in nature.
Corrective maintenance
activities could be performed
as modification work.
Additionally,
Section 3.2.3 of SSP-7.1 refers to form SSP-226 which is entitled
Voluntary Entry Into a TS
LCO for Modifications on a Shutdown Unit That
Result in Placing an Operating Unit in an
LCO.
Apparently,
some of the
review requirements
were developed to ensure that restart
work
activities did not adversely affect an operating unit. At the close of
the inspection report period, the licensee
informed the inspectors that
a new Standard Practice is under development
which will include specific
procedural
guidance for controlling entry into TS LCOs.
Conclusions
The inspectors
concluded that this was
an isolated
case in which the
review for planned voluntary entry into a TS
LCO was not thorough.
Licensee
management
expectations for planning regarding entry into LCOs
for modification work were not met.
The equipment
was not .actually
removed from service
and corrective actions
were initiated immediately
when the inspector
questioned
the planned schedule.
NRC inspection of
Brown Ferry's implementation of the Maintenance
Rule was recently
completed (Inspection Report 259,260,296/97-04)
which included detailed
review of the licensee's
controls over removal of plant equipment
from
service.
No significant deficiencies
were identified. The licensee
il
ik~
M8.1
M8.2
H8.3
17
intends to revise procedural
guidance
regarding control of voluntary
entry into TS LCOs.
Hiscellaneous
Haintenance
Issues
(62707,
92902)
Closed
Violation 260/96-13-01,
Failure to Implement. Licensee-Approved
'ork Controls for Changes to the SFP.
This violation was caused
by a
failure to initiate work control processes
over the installation of
temporary covers over the spent fuel pools.
Section H1.2 describes
a
recent
NRC review of the implementation of work controls over the
covers.
The inspector
concluded that once the maintenance
controls
processes
were initiated, the licensee
implemented
good controls over
the activities.
The inspectors
noted that TVA has taken steps to
increase attention toward maintenance
controls over such activities.
The
violation is closed.
Closed
Licensee
Event
Re oct
Containment
and Hain Steam Isolation Valve Leak Rates
Exceeded
Technical
Specification Limits.
Revision
1 to this
LER provided additional
details regarding the causes
and corrective actions f'r the leak rate
test failures and repetitive problems.
The issues
involved with the
containment
purge valves were addressed
in Inspection Report (IR) 94-32
and Non-cited violation 94-32-01
was issued.
The original
LER was
reviewed
and closed out in IR 96-04'he inspector reviewed revision
1
of the
LER and concluded that no additional
NRC inspection is necessary.
Revision
1 of the
LER is closed.
Closed
Licensee
Event
Re ort
A Residual
Heat
Removal Injection Valve was Inadvertently Closed
as
a Result of
Personnel
Error During Performance of a Troubleshooting
Work Order.
This incident involved a loss of shutdown cooling on Unit 3 prior to
fuel being loaded into the reactor
.
The major deficiency was that
troubleshooting
had not been properly controlled.
The issue
was
reviewed in detail by NRC inspectors
as described in Inspection Report
95-60.
Non-cited violation 95-60-02,
Loss of'hutdown Cooling Flow,
addressed
this issue.
The licensee
has continued to strengthen
troubleshooting controls, with recent
emphasis
given to pre-evolutionary
briefings.
This
LER is closed.
E1'onduct of Engineering
III. En ineerin
El.1
Outa
e Risk and
Hang ement
ORAH
S ent Fuel
Pool
Tem erature
Calculations
a.
Ins ection Sco
e
37551
During the most recent refueling outage,
the resident inspectors
noted
that the licensee's
Outage Risk and Hanagement
(ORAH) program
predictions for the temperature
increase of the fuel pool
and cavity
18
when shutdown cooling
(SDC) was secured
were not accurate.
The
prediction underestimated
the initial heatup rate
and actual
fuel pool
temperatures
increased
faster than predicted.
The inspectors
reviewed
the licensee's
actions to correct the problem.
The inspectors
also
compared the licensee's
refueling outage practices with the applicable
UFSAR descriptions.
b.
Observations
and Findin s
Following Spent
Fuel Pool/Cavity gate installation,
Spent
Fuel
Pool
temperature
increased
at approximately 2 degrees
F per hour, which was
higher than calculated.
The inspector questioned
the licensee
regarding the cause of the
differences
between actual
observed
temperatures
and the predicted or
calculated temperatures.
In response to the inspector 's questioning,
the licensee
determined that this was due to use of improper
differential temperatures
(the calculations
assumed
the pool
was at
a
constant
125 degrees
F).
This caused the calculated
heat
removal rate
to be higher than actual.
The licensee indicated that the model would
be improved.
The inspector
reviewed the licensee's
"outage lessons
learned" to
determine if the calculation problem had been addressed.
Although the
inspector did not find a specific lesson
learned
on the issue,
several
licensee
personnel
stated that the subject
was discussed
at the end of
outage critique.
The inspectors
also asked if any correlation could be made between the
observed
actual
performance of the
SFP cooling heat exchangers
and the
"design capability" referenced
in the
The river was very cool
so
RBCCW temperatures
were well below the
"maximum" temperature
referenced
in UFSAR.
The licensee
responded
by stating that the
"capability" is that the
SFPCS
can keep pool temperatures
below 125
degrees
F when removing the maximum normal heat load from,the pool with
the maximum
Section 10.5.5 of UFSAR,states this. (It should be
noted that supplemental
fuel pool cooling is available to use if
needed.)
The licensee
concluded that the observed
pool temperatures
did
not indicate any, problems with the SFPCS.
During the discussion,
the licensee's
reactor
engineers
discussed
that
calculations
are performed to predict when the pool gates
can be
installed after the fuel is offloaded.
The engineers
indicated that it
was well known that in some cases,
immediately following offload of'/3
of the core to the pool, the gates
could not be installed since
SFPCS
capability would not be high enough to remove the decay heat.
They
indicated that this is one of the primary reasons
for the pool heatup
calculations.
The licensee
does not consider this to be
a "difference"
with the way the
UFSAR describes
SFPCS heat
removal capacity.
The
licensee stated that this is part of the definition of "maximum normal
heat load." It was not clear to the inspectors that the licensee's
practices
are adequately reflected in the
UFSAR description.
The
E2
C.
19
does not imply or state that
some time for decay heat levels to decrease
may be necessary
before the
SFPCS
can maintain the pool temperatures.
Subsequently,
the licensee
provided documentation
which indicated that
as long as
15 days after .shutdown would be required before the
SFPCS
could remove the decay heat with RBCCW at 90 degrees
F..
The inspectors
have previously reviewed the licensee's
application of
the
ORAN programs.
The licensee
has consistently str ict)y controlled
installation and removal of the fuel pool gates.
Conclusions
The licensee
has initiated actions to address
the inaccurate
,temperature
calculations.
Although no actual
adverse effects
on
important plant equipment
have
been noted, additional
review of the
licensee's
practices
and the
UFSAR description involving SFPCS capacity
is warranted.
It was not clear to the inspectors that the actual
practices
are adequately reflected in the
UFSAR description.
Inspection
Followup Item 260,296/97-07-03,
Spent
Fuel
Pool Cooling
System
Heat Removal Capability,
addresses
this issue.
Engineering Support of Facilities and Equipment
E2.1
b.
Failure of the "28" Fuel
Pool Coolin
Pum
Ins ection Sco
e
37551
The inspectors
reviewed the licensee's
actions in response to a problem
involving the 28 fuel pool cooling (FPC)
pump.
Observations
and Findin s
On June 6, 1997, during a routine control
room tour,
one of the
inspectors
observed operator actions in response
to
a spent fuel pool
cooling system problem.
A fuel pool system
abnormal
actuated
and the radwaste
operator
reported that there
was
a problem
with flow through the
FPC demineralizer.
An AUO investigated the
problem and reported that
pump discharge
pressure
(28
pump was
operating)
indicated about
20 psig and local flow indication was zero.
The 28
pump was running with a very high noise level.
The inspector
could hear
the
pump noise over the phone line.
The noise
sounded like
extreme
pump cavitation.
It appeared that the
pump was in runout
conditions.
The inspector
observed that the control
room operator s allowed the
pump
to run for several
minutes while they pursued the cause of the problem.
Their troubleshooting
focused
on the
FPC demineralizer valves
and
controllers.
Subsequently,
the 28 pump was turned off and the 2A pump
was utilized for cooling.
On disassembly,
the 28 pump impeller was.
found to be damaged badly.
An inner portion of the impeller had
0
20
separated
from the rest of the impeller.
At the close of the report
period, additional analysis of the failure was in progress.
The inspectors
reviewed the
FPC system drawings,
UFSAR descriptions,
and
operating procedures.
Discussions
were held with the system engineer
and engineering supervisory personnel.
The inspectors
were informed
that on Harch 26,
1997, the system engineer
had identified that the
pump
was operating in a runout condition.
Instrument mechanics
were
performing work on some level switches
associated. with the
FPC system
and it was believed that this played
a role in the
pump problems.
A lo-
lo fuel pool
skimmer
surge tank level condition had developed
during the
incident. After the incident, vibration monitoring of the 28 pump
indicated that bearing vibrations
had increased to the alert range but
not to a level at which operability would be affected.
Since the demineralizer portions of the Browns Ferry
FPC system are not
seismic,
the deminer alizer bypass
valves are designed to open on a
pump low discharge
pressure
signal.
This allows cooling flow to the
pool to be continued while the demineralizer portion is isolated
from
the pumps.
Engineering
had concluded that the full opening of the
bypass
valves
was causing the
pump to go into runout.
Engineering
had
initiated a work request
about
a month before the June
6 incident to
install stops to prevent the full opening of the demineralizer
bypass
valves.
The inspectors
noted that although the system engineer
and his
supervisor
pursued corrective actions to the problem,
a Problem
Evaluation Report
(PER)
was not initiated to address
the
Har ch 26
incident.
The inspectors
concluded that
a pump experiencing
runout
operation which was suspected
to be caused
by system operation
as it was
designed to operate,
should result in a
PER.
Plant management
was not
aware of the problem until after the subsequent
pump failure.
The inspectors
questioned
engineering
personnel
regarding their analysis
of the Harch 26, problem and the postulated
cause of. the
pump runout.
The inspectors
concluded that the cause of the lo-lo skimmer surge tank
level
had not been conclusively determined.
It also appeared that the
issue
had not been discussed
with other utilities or General Electric.
At the close of the report period, the 1-icensee
was continuing to review
the issues,
including the root cause of the
pump failure and actions to
address
the runout conditions.
PER 970946 addresses
the issues.
This
issue is identified as Unresolved
Item 260/97-07-04,
Fuel
Pool Cooling
Pump Failure. Additional
NRC review is necessary
when additional
information is available.
Conclusions
The control
room operators
actions following indications of pump failure
did not meet management
expectations.
Although engineering
personnel
pursued corrective actions to address
the postulated
cause of the
il
E8
21
Harch 26 incident,
a
PER was not initiated and plant management
was not
informed of the runout problem.
Additional
NRC review of this issue
will be conducted
when additional information is available.
Hiscellaneous
Engineering Issues
(92903)
E8.1
0 en
Ins ection Foll owu
Item
IFI
260/95-41-01
Emergency Diesel
Generator
(EDG) lA Turbocharger
Inspection.
On January
16,
1995, the
EDG was declared
when it failed to go through the proper
shutdown
sequence
after
a stop signal
was initiated.
The
EDG was then
returned to operable status
on January
25.
1995.
Failure of the
planetary gear train initiated the event.
The planetary gears
supply the motive force for the turbocharger for
engine loads less than
70 percent.
At loads greater than
70 percent,
the exhaust
gases
provide the motive force for the turbocharger.
During
the event,
as the engine
was unloaded,
the available
amount of exhaust
gases
decreased'uch
that the turbocharger
should have been
dr iven by
its planetary gears.
Because
the gears
had failed, the turbocharger did
not supply sufficient combustion.air
and, therefore the
EDG shutdown.
The turbocharger
was immediately repaired
and returned to service.
The licensee's initial analysis identified "bending fatigue of a gear
tooth," on the turbocharger
sun gear,
as the most probable
cause of the
failure.
However,
a subsequent
analysis
determined that
the gear failed due to fatigue that was the resul,t of "quench cracking"
that occurred during manufacturing.
Earlier this year (IR 97-01) this
IFI was reviewed
and the inspectors
noted the results of a June
1996,
licensee-performed
metallurgical examination.
The inspectors
reviewed three laboratory reports
693.4A01,
693.A02,
and
693.A04 performed by Haterials Analytical Services,
Atlanta,
Ga. for EDG
gear
crack examination,
sent
from TVA Browns Ferry Nuclear
Plant.
Report 693.A01 identified no cracks.
Reports
693.A02 and A04
identified that the gear failures were due to "quench cracking"
~
The
"quench cracking" allowed fatigue cr acks to propagate until catastrophic
failure of the gear
was presented.
The licensee
sent engineers
to visit
the vendor
(HKW Power Systems,
Inc.) for an inspection
and investigation
of the manufacturing process.
This visit and
a subsequent
licensee-
performed analysis confirmed preliminary conclusions that the "quench
cracks" were
a major contributor to the failures.
During the inspection period, the licensee
determined the root cause of
the failure to be manufacturing defects
and meetings
were held with the
manufacturer.
The manufacturer did not agree with the
licensee's
conclusion that the failures were caused
by manufacturing
defects
such
as quench cracking.
Pending additional review, IFI 260/95-41-01
remains
open.
However,
based
on the cur rent licensee analysis
and documentation,
associated
LERs96-001 (Revisions
0,
1 and 2) are closed.
f
II
E8.2
E8.3
E8.4
E8.5
22
Closed
Licensee
Event
Re orts
LERs
260/95-001-00
95-001-01
and 95-
001-02
Failure That Resulted In Noncompliance With
Technical Specification Limiting Condition For Operation.
Section
E8. I
of this report describes
review of actions performed for IFI 260/95-41-
01,
(EDG)
1A Turbocharger
Inspection.
The
IFI addressed
the
same incident as the
LER.
Pending further review of
'he issue the IFI remains
open.
Based
on the review described in
Section E8.1, the original
LER and the two subsequent
revisions are
closed.
Closed
Unresolved
Item
296/96-03-02,
Appendix
R Instrumentation
Discrepancies.
Inspection Report 96-04 contains
a discussion of a
detailed
NRC review of Appendix R issues.
In the report, the URI was
closed
for. Unit 2.
Violation 260/96-04-01,
Licensee Identified Appendix
R Deficiencies,
was opened to address
the issues.
The inspector
reviewed IR 96-04 and concluded that the concerns
associated
with Unit 3
were addressed
as well.
Due to an administrative oversight,
the URI was
not closed for Unit 3.
The URI is closed for Unit 3.
Closed
Licensee
Event
Re orts
LERs
260/95-008-00
and 95-008-01
Reactor
Zone Isolation Dampers Failed to Close.
The initial LER
addressed
a failure of two secondary
containment isolation dampers to
close
due to sticking solenoid valves.
Revision
1 of the
LER provided
additional details regarding the cause of these
damper failures and two
additional failures which occurred.
The sticking solenoids
were
attributed to a sticky residue
found at the core-plugnut interface in
the valves.
Revision
1 of the
LER states that further investigation is
in progress.
Replacement of solenoid valves with models which have not
exhibited the sticking problem has continued.
Inspection Report 95-64
describes
NRC review of these
issues
and related Information Notice 95-
53 'nspection
Followup Item 260,296/95-64-10,'econdary
Containment
Ventilation Damper Failures,
remains
open pending review of the
licensee's
longterm corrective actions.
The LERs are closed.
Closed
Licensee
Event
Re ort
Reactor
Scrammed
on
Loss of Main Condenser
Vacuum as
a Result of the Steam Jet Air Ejectors
Isolating on
a High Offgas Temperature.
The cause of the air ejector
isolation was traced to the failure of a power supply associated
with
the offgas condenser
water level control instrumentation.
The licensee
completed corrective actions to address
the failure.
The
LER is closed.
IV. Plant Su
rt
S2
S2.1
Status of Security Facilities and Equipment
Securit
Facilit
Observation
and Review
a.
Ins ection Sco
e
71750
On June 20,
1997, the inspector performed
a walkdown of portions of the
protected
area security fencing.
Additionally, the inspectors
toured
the Central
Alarm Station
(CAS) and the Secondary Alarm Station
(SAS)
~
i
23
during routine inspections.
Some of the activities were conducted
during deep backshift hours.
b.
Observations
and Findin s
The inspector discussed
several
observations
regarding the fence
'onditions with security personnel.
All items were adequately
addressed.
No significant problems were identified.
Inspectors
observed security personnel
in the
CAS and
SAS were alert and attentive
-to their duties.
V. Mana ement Meetin s
X1
Exit Meeting Summary
The resident inspectors
presented
inspection findings and results to
licensee
management
on June 24,
1997.
Other meetings to discuss report
,issues
were conducted during the report period.
A formal meeting with
plant management
was conducted
on June 3,
1997.
The licensee
acknowledged the findings presented.
Proprietary information is not
included in this inspection report.
PARTIAL LIST OF PERSONS
CONTACTED
t
Licensee
T. Abney., Licensing Manager
J. Brazell, Site Security Manager
R. Coleman, Acting Radiological Control
Hanager
J.
Corey, Radiological Controls
and Chemistry Manager
T. Cornelius,
and Planning
CD Crane, Site Vice President,
Browns Ferry
R. Greenman,
Training Manager
J.
Johnson,
Site Quality Assurance
Manager
R. Jones,
Assistant Plant Manager
S.
Kane, Acting Site Licensing Supervisor
G. Little, Acting Operations
Manager
K. Singer,
Plant Hanager
J. Schlessel,
Acting Maintenance
Manager
H. Williams, Site Engineering
Manager
INSPECTION PROCEDURES
USED
IP 37551:
Onsite Engineering
IP 40500:
Licensee Self-Assessments
IP 62707:
Maintenance
Observations
IP 61726:
Surveillance Observations
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
IP 73756:.
Inser vice Testing of Pumps
and Valves
t
IP 81502:.
Fitness
For Duty Program
IP 92901:
Foll owup-Pl ant Oper ations
IP 92902:
Followup-Ha'intenance
IP 92903:
Followup-Engineering
IP 93702:
Prompt Onsite Response
to Events at Operating
Power
Reactors
ITEHS OPENED
DISCUSSED
AND CLOSED
OPENED
~T
Item Number
'VIO
50-260,296/97-07-01
Status
Open
Descri tion and Reference
EOI Ladders
Not Adequately
Contr oiled (Section 01.1)
50-260,296/97-07-02
Open
IFI
50-260,296/97-07-03
Open
FHE Administrative Control
Procedures
Not Properly Implemented
(Section Hl ~ 3)
SFP Cool.ing System Heat Removal
Capability (Section E1.1)
50-260/97-07-04
DISCUSSED
~T
Item Number
IFI
260/95-41-01
CLOSED
~T
Item Number
260/94-14-01-
260/96-13-01
LER
296/95-005-00
n
Open
Status
Open
Status
Withdrawn
Closed
Closed
Closed
Failure Of Fuel
Pool Cooling Pump
(Section E2.1)
Descri tion and Reference
EDG lA Turbocharger
Inspection
(Section E8.1)
Descr i tion and Reference
Inadequate
Procedure Controlling
Voluntary Technical Specification
Limiting Condition For Oper ation
Entries (Section 08.1)
Failure To Implement Licensee-
Approved Work Controls For Changes
To The SFP (Section H8.1)
Containment
Penetr ation And Hain
Steam Isolation Valve Leak Rates
'xceeded
Technical Specification
Limits (Section H8.2)
A Residual
Heat Removal Injection
Valve Was Inadvertently Closed As A
Result Of Personnel
Error During
Performance
Of A Troubleshooting
Wor k Order (Section H8.3)
il
LER
260/95-001-01
'296/96-03-02
LER
260/95-008-01
Closed
Closed
Closed
Closed
C,1osed
Closed
Closed
25
DG Turbocharger Failure That
Resulted
In Noncompliance With
Technical Specification Limiting
Condition For
Oper ation
(Section .E8.2)
Appendix
R Instrumentation
Discrepancies
(Section E8.3)
Reactor
Zone Isolation Dampers
Failed To Close (Section E8.4)
Reactor
Scrammed
On Loss Of Hain
Condenser
Vacuum As A Result Of The
Steam Jet Air Ejectors Isolating
On
A,High Offgas Temperature
(Section E8.5)
O~
ik
~
'